Document and Entity Information	9 Months Ended
Document and Entity Information	Sep. 30, 2010	Oct. 20, 2010
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2010
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	Q3
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		111,390,861

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2010	Dec. 31, 2009
CURRENT ASSETS:
Cash and cash equivalents	$ 4,472	$ 3,860
Accounts receivable, net of allowance for doubtful accounts of $4,245 and $5,231, respectively	260,404	216,186
Inventories and supplies, net	201,643	193,831
Energy marketing contracts	21,085	33,159
Taxes receivable		45,200
Deferred tax assets	7,458	7,927
Prepaid expenses	11,809	11,830
Regulatory assets	66,099	97,220
Other	12,802	20,269
Total Current Assets	585,772	629,482
PROPERTY, PLANT AND EQUIPMENT, NET	5,853,270	5,771,740
OTHER ASSETS:
Regulatory assets	730,391	758,538
Nuclear decommissioning trust	119,149	112,268
Energy marketing contracts	10,419	10,653
Other	222,041	242,802
Total Other Assets	1,082,000	1,124,261
TOTAL ASSETS	7,868,959	7,525,483
CURRENT LIABILITIES:
Current maturities of long-term debt	403	1,345
Short-term debt	163,040	242,760
Accounts payable	138,376	112,211
Accrued taxes	71,664	46,931
Energy marketing contracts	16,443	39,161
Accrued interest	66,328	76,955
Regulatory liabilities	31,424	39,745
Other	115,933	123,370
Total Current Liabilities	633,701	682,478
LONG-TERM LIABILITIES:
Long-term debt, net	2,490,734	2,490,734
Obligation under capital leases	8,246	109,300
Deferred income taxes	1,012,410	964,461
Unamortized investment tax credits	153,942	127,777
Regulatory liabilities	136,967	100,963
Deferred regulatory gain from sale-leaseback	98,915	108,532
Accrued employee benefits	414,488	433,561
Asset retirement obligations	124,635	119,519
Energy marketing contracts	185	210
Other	104,246	117,720
Total Long-Term Liabilities	4,824,322	4,572,777
COMMITMENTS AND CONTINGENCIES (See Notes 7 and 8)
TEMPORARY EQUITY	3,459	3,443
Westar Energy Shareholders' Equity:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares	21,436	21,436
Common stock, par value $5 per share; authorized 150,000,000 shares; issued and outstanding 110,833,975 shares and 109,072,000 shares, respectively	554,170	545,360
Paid-in capital	1,373,297	1,339,790
Retained earnings	453,892	360,199
Total Westar Energy Shareholders' Equity	2,402,795	2,266,785
Total Equity	2,407,477	2,266,785
TOTAL LIABILITIES AND EQUITY	7,868,959	7,525,483
Variable Interest Entity, Primary Beneficiary [Member]
CURRENT ASSETS:
PROPERTY, PLANT AND EQUIPMENT, NET	347,917
CURRENT LIABILITIES:
Current maturities of long-term debt	30,090
LONG-TERM LIABILITIES:
Long-term debt, net	279,554
Westar Energy Shareholders' Equity:
Noncontrolling Interests	$ 4,682

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2010	Dec. 31, 2009
Accounts receivable, allowance for doubtful accounts	$ 4,245	$ 5,231
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	110,833,975	109,072,000
Common stock, outstanding	110,833,975	109,072,000

CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
CONSOLIDATED STATEMENTS OF INCOME
REVENUES	$ 644,437	$ 528,534	$ 1,599,448	$ 1,418,113
OPERATING EXPENSES:
Fuel and purchased power	187,877	141,470	458,793	402,622
Operating and maintenance	126,602	130,295	369,584	392,272
Depreciation and amortization	67,918	64,516	201,955	186,544
Selling, general and administrative	50,418	41,920	144,499	143,540
Total Operating Expenses	432,815	378,201	1,174,831	1,124,978
INCOME FROM OPERATIONS	211,622	150,333	424,617	293,135
OTHER INCOME (EXPENSE):
Investment earnings	3,248	3,986	4,350	8,516
Other income	1,897	1,217	3,792	5,627
Other expense	(5,146)	(4,539)	(12,043)	(11,441)
Total Other (Expense) Income	(1)	664	(3,901)	2,702
Interest expense	43,956	41,599	131,862	116,769
INCOME FROM OPERATIONS BEFORE INCOME TAXES	167,665	109,398	288,854	179,068
Income tax expense	51,802	28,256	86,780	48,354
INCOME FROM CONTINUING OPERATIONS			202,074	130,714
Results of discontinued operations, net of tax				32,978
NET INCOME	115,863	81,142	202,074	163,692
Less: Net income attributable to noncontrolling interests	1,119		3,338
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY	114,744	81,142	198,736	163,692
Preferred dividends	242	242	727	727
NET INCOME ATTRIBUTABLE TO COMMON STOCK	114,502	80,900	198,009	162,965
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Basic earnings available from continuing operations			$ 1.77	$ 1.18
Discontinued operations, net of tax				$ 0.30
Basic earnings per common share	$ 1.02	$ 0.73	$ 1.77	$ 1.48
Diluted earnings available from continuing operations			$ 1.76	$ 1.18
Discontinued operations, net of tax				$ 0.30
Diluted earnings per common share	$ 1.01	$ 0.73	$ 1.76	$ 1.48
Average equivalent common shares outstanding	111,706,541	109,753,036	111,387,165	109,542,500
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.31	$ 0.30	$ 0.93	$ 0.90
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	114,744	81,142	198,736	130,714
Results of discontinued operations, net of tax				32,978
Net income	$ 114,744	$ 81,142	$ 198,736	$ 163,692

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 202,074	$ 163,692
Discontinued operations, net of tax		(32,978)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	201,955	186,544
Amortization of nuclear fuel	19,657	12,810
Amortization of deferred regulatory gain from sale-leaseback	(4,121)	(4,121)
Amortization of corporate-owned life insurance	15,286	15,746
Non-cash compensation	8,280	3,933
Net changes in energy marketing assets and liabilities	(947)	6,256
Accrued liability to certain former officers	1,959	1,386
Net deferred income taxes and credits	104,133	59,663
Stock-based compensation excess tax benefits	(526)	(359)
Allowance for equity funds used during construction	(1,926)	(4,064)
Changes in working capital items, net of acquisitions and dispositions:
Accounts receivable	(44,207)	(14,317)
Inventories and supplies	(7,298)	4,091
Prepaid expenses and other	23,843	(7,042)
Accounts payable	12,965	(39,006)
Accrued taxes	70,263	28,280
Other current liabilities	(84,095)	74,511
Changes in other assets	25,984	24,485
Changes in other liabilities	(42,912)	(71,469)
Cash Flows from Operating Activities	500,367	408,041
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(369,746)	(460,779)
Investment in corporate-owned life insurance	(18,884)	(17,724)
Purchase of securities within the nuclear decommissioning trust fund	(189,784)	(36,651)
Sale of securities within the nuclear decommissioning trust fund	189,343	34,501
Proceeds from investment in corporate-owned life insurance	1,918	1,596
Other investing activities	(1,760)	1,357
Cash Flows used in Investing Activities	(388,913)	(477,700)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(79,720)	(7,668)
Proceeds from long-term debt		297,507
Retirements of long-term debt	(1,353)	(146,494)
Repayment of capital leases	(1,640)	(9,682)
Borrowings against cash surrender value of corporate-owned life insurance	72,286	8,530
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(3,219)	(3,422)
Stock-based compensation excess tax benefits	526	359
Issuance of common stock, net	28,299	3,279
Cash dividends paid	(96,391)	(91,916)
Cash Flows (used in) from Financing Activities	(110,842)	50,493
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	612	(19,166)
CASH AND CASH EQUIVALENTS:
Beginning of period	3,860	22,914
End of period	4,472	3,748
Variable Interest Entity, Primary Beneficiary [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Retirements of long-term debt	(27,536)
Distributions to shareholders of noncontrolling interests	$ (2,094)

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $) In Thousands	Total	Cumulative preferred stock	Common stock	Paid-in capital	Retained earnings	Noncontrolling interests
Beginning Balance at Dec. 31, 2008	$ 2,207,580	$ 21,436	$ 541,556	$ 1,326,391	$ 318,197
Net income	163,692				163,692
Issuance of common stock, net	10,923		2,931	7,992
Preferred dividends	(727)				(727)
Dividends on common stock	(99,005)				(99,005)
Reclass to Temporary Equity	(17)			(17)
Amortization of restricted stock	3,380			3,380
Stock compensation and tax benefit	(1,845)			(1,845)
Ending Balance at Sep. 30, 2009	2,283,981	21,436	544,487	1,335,901	382,157
Beginning Balance at Dec. 31, 2009	2,266,785	21,436	545,360	1,339,790	360,199
Consolidation of noncontrolling interests	3,435					3,435
Net income	202,074				198,736	3,338
Issuance of common stock, net	37,508		8,810	28,698
Preferred dividends	(727)				(727)
Dividends on common stock	(104,316)				(104,316)
Reclass to Temporary Equity	(16)			(16)
Amortization of restricted stock	7,667			7,667
Stock compensation and tax benefit	(2,842)			(2,842)
Distributions to shareholders of noncontrolling interests	(2,091)					(2,091)
Ending Balance at Sep. 30, 2010	$ 2,407,477	$ 21,436	$ 554,170	$ 1,373,297	$ 453,892	$ 4,682

DESCRIPTION OF BUSINESS	9 Months Ended
DESCRIPTION OF BUSINESS	Sep. 30, 2010
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 686,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. KGE owns a 47% interest in Wolf Creek, a nuclear power plant located near Burlington, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2010

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), reported as a single operating segment, of which we maintain a controlling interest or are the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2009 Form 10-K.

Use of Management's Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, investments, valuation of our energy marketing portfolio, intangible assets, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and other post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year.

Allowance for Funds Used During Construction

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(In Thousands)
Borrowed funds	$	1,133	$	1,003	$	2,825	$	3,849
Equity funds		841		787		1,926		4,064

Total	$	1,974	$	1,790	$	4,751	$	7,913

Average AFUDC Rates		2.7%		3.3%		2.4%		4.3%

Earnings Per Share

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(Dollars In Thousands, Except Per Share Amounts)
Income from continuing operations	$	115,863	$	81,142	$	202,074	$	130,714
Less: Income attributable to noncontrolling interests		1,119		—		3,338		—

Income from continuing operations attributable to Westar Energy		114,744		81,142		198,736		130,714
Less: Preferred dividends		242		242		727		727
Income from continuing operations allocated to RSUs		629		299		1,067		531

Income from continuing operations attributable to common stock	$	113,873	$	80,601	$	196,942	$	129,456

Weighted average equivalent common shares outstanding – basic		111,706,541		109,753,036		111,387,165		109,542,500
Effect of dilutive securities:
Restricted share units		200,480		—		155,903		—
Forward sale agreement		408,393		—		110,519		—
Employee stock options		—		552		74		435

Weighted average equivalent common shares outstanding – diluted (a)		112,315,414		109,753,588		111,653,661		109,542,935

Earnings from continuing operations per common share, basic	$	1.02	$	0.73	$	1.77	$	1.18
Earnings from continuing operations per common share, diluted	$	1.01	$	0.73	$	1.76	$	1.18

(a)	For the three and nine months ended September 30, 2010 and 2009, we did not have any antidilutive shares.

Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2010			2009
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	121,784		$	101,556
Income taxes, net of refunds		(38,017	)		(9,128	)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		30,443			25,939
Property, plant and equipment additions of variable interest entities (a)		356,964			—
Jeffrey Energy Center 8% leasehold interest (a)		(108,706	)		—
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans		13,492			8,803
Debt of variable interest entities (a)		337,951			—
Capital lease for Jeffrey Energy Center 8% leasehold interest (a)		(106,423	)		—
Assets acquired through capital leases		321			1,533


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

New Accounting Pronouncements

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

Consolidation Guidance for Variable Interest Entities

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

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

9 Months Ended

Sep. 30, 2010

Financial And Derivative Instruments, Investments And Risk Management Policies

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

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

During the second quarter of 2010, we changed our investment advisor for the nuclear decommissioning trust (NDT). The transition resulted in the sale of all of our then existing level 1 and level 2 investments and the purchase of other level 2 investments. Level 2 investments, whether in the 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.

We still maintain certain level 3 investments in private equity, high-yield bonds and real estate securities that require significant unobservable market information to measure the fair value of the investments. The fair value of private equity investments is measured by utilizing both market- and income-based models, public company comparables, at cost or at the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; or when other news or events have a material impact on the security. Debt investments for which we apply unobservable information to measure fair value are principally invested in mortgage-backed securities and collateralized loans. Fair value for these investments is determined by using subjective market- and income-based estimates such as projected cash flows and future interest rates. To measure the fair value of real estate securities we use a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

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

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our financial instruments as of September 30, 2010, and December 31, 2009.


	As of September 30, 2010				As of December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,373,373	$	2,719,465	$	2,373,723	$	2,528,456
Fixed-rate debt of variable interest entities		309,644		375,037		—		—

Recurring Fair Value Measurements

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

•

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

•

Level 2 – Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically 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 fuel supply contracts.

The following table provides the amounts and the 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 September 30, 2010
Assets:
Energy Marketing Contracts	$	4,790	$	9,608	$	17,106	$	31,504
Nuclear Decommissioning Trust:
Domestic equity		—		54,551		2,447		56,998
International equity		—		17,760		—		17,760
Core bonds		—		32,027		—		32,027
High-yield bonds		—		9,120		305		9,425
Real estate securities		—		—		2,862		2,862
Cash equivalents		77		—		—		77

Total Nuclear Decommissioning Trust		77		113,458		5,614		119,149

Trading Securities:
Domestic equity		—		19,527		—		19,527
International equity		—		4,959		—		4,959
Core bonds		—		12,286		—		12,286

Total Trading Securities		—		36,772		—		36,772

Total Assets Measured at Fair Value	$	4,867	$	159,838	$	22,720	$	187,425

Liabilities:
Energy Marketing Contracts	$	4,802	$	9,189	$	2,637	$	16,628

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

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

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

Total Trading Securities		—		34,619		—		34,619

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

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

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of September 30, 2010, we had not recorded any right to reclaim cash collateral and had recorded $2.1 million for our obligation to return cash collateral. As of December 31, 2009, we had recorded $0.3 million for our right to reclaim cash collateral and $1.8 million for our obligation to return cash collateral.

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


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust									Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds			Real Estate Securities			Net Balance
	(In Thousands)
Balance as of June 30, 2010	$	15,933		$	2,547		$	6,122		$	2,772		$	27,374
Total realized and unrealized gains (losses) included in:
Earnings (a)		(11	)		—			—			—			(11	)
Regulatory assets		(644	)(b)		—			—			—			(644	)
Regulatory liabilities		2,191	(b)		(100	)		(15	)		90			2,166
Purchases, issuances and settlements		(2,944	)		—			(5,802	)		—			(8,746	)
Transfers into level 2		(56	)(c)		—			—			—			(56	)

Balance as of September 30, 2010	$	14,469		$	2,447		$	305		$	2,862		$	20,083


Balance as of December 31, 2009	$	4,310		$	2,262		$	5,741		$	3,635		$	15,948
Total realized and unrealized gains (losses) included in:
Earnings (a)		(1,840	)		—			—			—			(1,840	)
Regulatory assets		2,499	(b)		—			—			—			2,499
Regulatory liabilities		7,574	(b)		29			366			(773	)		7,196
Purchases, issuances and settlements		1,926			156			(5,802	)		—			(3,720	)

Balance as of September 30, 2010	$	14,469		$	2,447		$	305		$	2,862		$	20,083

(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.

(c)	The fair value of transfers between levels is measured as of the beginning of the reporting period.

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and nine months ended September 30, 2009.


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Core Bonds		Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds		Real Estate Securities			Trading Securities Core Bonds		Net Balance
	(In Thousands)
Balance as of June 30, 2009	$	2,634		$	1,791		$	4,684	$	3,930		$	10,211	$	23,250
Total realized and unrealized gains (losses) included in:
Earnings (a)		1,748			—			—		—			731		2,479
Regulatory assets		(5,423	)(b)		—			—		—			—		(5,423	)
Regulatory liabilities		1,524	(b)		67			364		(295	)		—		1,660
Purchases, issuances and settlements		2,677			—			—		—			707		3,384

Balance as of September 30, 2009	$	3,160		$	1,858		$	5,048	$	3,635		$	11,649	$	25,350


Balance as of December 31, 2008	$	44,541		$	2,006		$	—	$	6,028		$	—	$	52,575
Total realized and unrealized gains (losses) included in:
Earnings (a)		2,562			—			—		—			1,403		3,965
Regulatory assets		(23,581	)(b)		—			—		—			—		(23,581	)
Regulatory liabilities		(16,131	)(b)		(268	)		751		(2,393	)		—		(18,041	)
Purchases, issuances and settlements		(4,231	)		120			4,297		—			10,246		10,432

Balance as of September 30, 2009	$	3,160		$	1,858		$	5,048	$	3,635		$	11,649	$	25,350

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

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

A portion of the gains and losses contributing to changes in net assets in the above table is unrealized. The following tables summarize the unrealized gains and losses we recorded on our consolidated financial statements during the three and nine months ended September 30, 2010 and 2009, attributed to level 3 assets and liabilities.


	Three Months Ended September 30, 2010
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust									Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds			Real Estate Securities			Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(310	)	$	—		$	—		$	—		$	(310	)
Regulatory assets		(1,834	)(b)		—			—			—			(1,834	)
Regulatory liabilities		(461	)(b)		(100	)		(412	)		90			(883	)

Total	$	(2,605	)	$	(100	)	$	(412	)	$	90		$	(3,027	)


	Nine Months Ended September 30, 2010
Total unrealized gains (losses) included in:
Earnings (a)	$	(490	)	$	—		$	—		$	—		$	(490	)
Regulatory assets		749	(b)		—			—			—			749
Regulatory liabilities		4,765	(b)		35			(31	)		(773	)		3,996

Total	$	5,024		$	35		$	(31	)	$	(773	)	$	4,255

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

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


	Three Months Ended September 30, 2009
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Core Bonds		Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds		Real Estate Securities			Trading Securities Core Bonds		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	219		$	—		$	—	$	—		$	731	$	950
Regulatory assets		4,641	(b)		—			—		—			—		4,641
Regulatory liabilities		(794	)(b)		67			364		(295	)		—		(658	)

Total	$	4,066		$	67		$	364	$	(295	)	$	731	$	4,933


	Nine Months Ended September 30, 2009
Total unrealized gains (losses) included in:
Earnings (a)	$	(434	)	$	—		$	—	$	—		$	1,403	$	969
Regulatory assets		(10,615	)(b)		—			—		—			—		(10,615	)
Regulatory liabilities		(16,791	)(b)		(268	)		751		(2,393	)		—		(18,701	)

Total	$	(27,840	)	$	(268	)	$	751	$	(2,393	)	$	1,403	$	(28,347	)

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

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

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


	As of September 30, 2010				As of December 31, 2009				As of September 30, 2010
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency		Length of Settlement
	(In thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	2,447	$	2,955	$	7,579	$	3,111		(a)		(a)
International equity		—		—		24,736		—
Core bonds		—		—		5,524		—
High-yield bonds		305		—		5,741		—		(b)		(b)
Real estate securities		2,862		—		3,635		—		(c)		(c)

Total Nuclear Decommissioning Trust	$	5,614	$	2,955	$	47,215	$	3,111

Trading Securities:
Domestic equity	$	19,527	$	—	$	18,344	$	—		Upon Notice		1 day
International equity		4,959		—		4,422		—		Upon Notice		1 day
Core bonds		12,286		—		11,853		—		Upon Notice		1 day

Total Trading Securities		36,772		—		34,619		—

Total	$	42,386	$	2,955	$	81,834	$	3,111

(a)

This investment is in long-term private equity funds that do not permit early withdrawal. The funds may begin liquidating in about 6 to 11 years unless the terms of the investments are extended. Our investments in these funds cannot be withdrawn until the underlying investments have been liquidated which may take years from the date of initial liquidation.

(b)	We expect to completely settle this fund in the second quarter of 2011.

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

Derivative Instruments

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

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

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


Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In thousands)			(In thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	21,085	Energy marketing contracts	$	16,443
Other assets:			Long-term liabilities:
Energy marketing contracts		10,419	Energy marketing contracts		185

Total	$	31,504	Total	$	16,628

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 2009


Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In thousands)			(In thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	33,159	Energy marketing contracts	$	39,161
Other assets:			Long-term liabilities:
Energy marketing contracts		10,653	Energy marketing contracts		210

Total	$	43,812	Total	$	39,371

The following table presents how changes in the fair value of commodity derivative instruments affected our consolidated financial statements for the three and nine months ended September 30, 2010 and 2009.


	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
Location	Net Gain Recognized			Net Loss Recognized			Net Gain Recognized			Net Loss Recognized
	(In thousands)
Revenues increase (decrease)	$	1,212		$	—		$	—		$	(597	)
Regulatory assets decrease		(43	)		—			(7,197	)		—
Regulatory liabilities (decrease) increase		—			(877	)		4,051			—

	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
Revenues increase	$	3,148		$	—		$	5,665		$	—
Regulatory assets increase		—			1,917			—			10,195
Regulatory liabilities increase (decrease)		2,551			—			—			(27,831	)

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

Net Quantity as of

Unit of Measure

September 30, 2010

December 31, 2009

Electricity

MWh

3,613,160

4,147,800

Natural Gas

MMBtu

2,095,000

648,000

Coal

Tons

750,000

3,500,000

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

Energy Marketing Activities

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

Price Risk

We use various types of fuel, including coal, natural gas, uranium, diesel and oil, to operate our plants and purchase power to meet customer demand. We are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates that could affect our consolidated financial results including cash flows. We manage our exposure to these market risks through our regular operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

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

The wholesale power and fuel markets are volatile. This volatility impacts our costs of purchased power, fuel costs for our power plants and our participation in energy markets. We trade various types of fuel primarily to reduce exposure related to the volatility of commodity prices. A significant portion of our coal requirements is purchased under long-term contracts to hedge much of the fuel exposure for customers. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service.

Credit Risk

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

We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of September 30, 2010, and December 31, 2009, was $1.7 million and $1.4 million, respectively, for which we had posted no collateral as of either date. If all credit-risk-related contingent features underlying these agreements had been triggered as of September 30, 2010, or December 31, 2009, we would have been required to provide to our counterparties $0.9 million and $0.1 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

FINANCIAL INVESTMENTS

9 Months Ended

Sep. 30, 2010

FINANCIAL INVESTMENTS

FINANCIAL INVESTMENTS

4. FINANCIAL INVESTMENTS

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

Trading Securities

We have debt and equity investments in a trust used to fund retirement benefits that we classify as trading securities. We include any unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. During the three and nine months ended September 30, 2010, we recorded unrealized gains on these securities of $3.2 million and $2.2 million, respectively. We recorded unrealized gains on these securities of $3.8 million and $10.1 million, respectively, during the three and nine months ended September 30, 2009.

Available-for-Sale Securities

We hold investments in debt and equity securities in a trust fund for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of September 30, 2010, and December 31, 2009. At September 30, 2010, investments in the NDT fund were allocated 48% to domestic equity, 15% to international equity, 27% to core bonds, 8% to high-yield bonds, 2% to real estate securities and less than one percent to 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 September 30, 2010, the fair value of the debt securities in the NDT fund was $41.5 million, held entirely in closed end funds and bond mutual funds.

Using the specific identification method to determine cost, we realized losses on our available-for-sale securities of $0.3 million during the three months ended September 30, 2010, and gains of $13.2 million during the nine months ended September 30, 2010. During the three and nine months ended September 30, 2009, we realized gains of $0.5 million and losses of $8.2 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 costs and fair values of investments in the NDT fund as of September 30, 2010, and December 31, 2009.


			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value
	(In Thousands)
As of September 30, 2010:
Domestic equity	$	57,818	$	—	$	(820	)	$	56,998
International equity		17,196		564		—			17,760
Core bonds		30,476		1,551		—			32,027
High-yield bonds		8,935		490		—			9,425
Real estate securities		6,206		—		(3,344	)		2,862
Cash equivalents		77		—		—			77

Total	$	120,708	$	2,605	$	(4,164	)	$	119,149

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

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

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


	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2010:
Domestic equity	$	56,541	$	(820	)	$	—	$	—		$	56,541	$	(820	)
Real estate securities		—		—			2,862		(3,344	)		2,862		(3,344	)

Total	$	56,541	$	(820	)	$	2,862	$	(3,344	)	$	59,403	$	(4,164	)

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

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

RATE MATTERS AND REGULATION	9 Months Ended
RATE MATTERS AND REGULATION	Sep. 30, 2010
RATE MATTERS AND REGULATION
RATE MATTERS AND REGULATION	5. RATE MATTERS AND REGULATION KCC Proceedings On June 11, 2010, the Kansas Corporation Commission (KCC) issued a final order approving an adjustment to our prices that we made earlier this year. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million. On May 25, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2009. The new prices were effective June 1, 2010, and are expected to increase our annual retail revenues by $13.8 million. On January 27, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in natural gas and wind generation facilities. The new prices were effective February 2010 and are expected to increase our annual retail revenues by $17.1 million. FERC Proceedings Our transmission formula rate that includes projected 2010 transmission capital expenditures and operating costs became effective January 1, 2010, and is expected to increase our annual transmission revenues by $16.8 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above. On January 12, 2010, the Federal Energy Regulatory Commission (FERC) issued an order accepting our request to implement a cost-based formula rate for electricity sales to wholesale customers. The use of a cost-based formula rate allows us to annually adjust our prices to reflect changes in our cost of service. The cost-based formula rate was effective December 1, 2009.

TAXES	9 Months Ended
TAXES	Sep. 30, 2010
TAXES
TAXES	6. TAXES We recorded income tax expense of $51.8 million with an effective income tax rate of 31% for the three months ended September 30, 2010, and income tax expense of $28.3 million with an effective income tax rate of 26% for the same period of 2009; and income tax expense of $86.8 million with an effective income tax rate of 30% for the nine months ended September 30, 2010, and income tax expense of $48.4 million with an effective income tax rate of 27% for the same period of 2009. The increases in the effective income tax rate for the three and nine months ended September 30, 2010, were due primarily to increased income from continuing operations before income taxes. In January 2009, we reached a settlement with the Internal Revenue Service (IRS) for tax years 2003 and 2004 that included a determination of the amount of the net capital loss and net operating loss carryforwards available from the sale of a former subsidiary in 2004. This settlement resulted in our recording in 2009 a net earnings benefit from discontinued operations of approximately $33.7 million, net of $22.8 million paid to the former subsidiary under the sale agreement. We recorded $33.0 million of this benefit in the nine months ended September 30, 2009. In March 2010, the IRS commenced its examination of our federal income tax return for tax year 2008. We expect the IRS to complete this examination during the fourth quarter of 2010 without any significant assessment. In October 2010, we were notified that the IRS will commence an examination of our federal income tax return for tax year 2009 in the fourth quarter of 2010. At September 30, 2010, and December 31, 2009, our liability for unrecognized income tax benefits was $3.3 million and $8.4 million, respectively. The net decrease in the liability for unrecognized income tax benefits was attributable primarily to the recognition of $5.8 million of unrecognized income tax benefits due to the completion of the IRS examination of tax years 1999, 2005, 2006 and 2007. As of September 30, 2010, and December 31, 2009, we had $0.6 million and $1.4 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. We had no tax related penalties accrued at either September 30, 2010, or December 31, 2009. As of September 30, 2010, and December 31, 2009, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

COMMITMENTS AND CONTINGENCIES	9 Months Ended
COMMITMENTS AND CONTINGENCIES	Sep. 30, 2010
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	7. COMMITMENTS AND CONTINGENCIES Environmental Projects We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could materially change depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce net productivity of plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments. The environmental cost recovery rider allows for the more timely inclusion in our prices the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our retail prices to recognize increased operating and maintenance costs, however, we must still file a general rate case with the KCC. We have an agreement with the Kansas Department of Health and Environment (KDHE) to install new equipment to reduce regulated emissions from our generating fleet. The projects are designed to meet requirements of the Clean Air Visibility Rule and significantly reduce plant emissions. While an earlier issued Environmental Protection Agency (EPA) rule on mercury was vacated by a U.S. Court of Appeals ruling, the Obama administration has indicated that it intends to enact stricter, technology-based regulations on mercury emissions. Our costs to comply with mercury emission requirements could be material. Environmental Law Update In May 2010, the EPA finalized new regulations, known as the tailoring rule, under which it intends to begin regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations will be implemented pursuant to two Federal Clean Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions will be required to implement best available control technology (BACT). The EPA has yet to issue regulations defining BACT. There have already been introduced significant legal challenges to this new regulation. As a result of this and other uncertainties, we cannot predict the impact of the tailoring rule on our consolidated financial results, but it could be material. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR), which would require 31 states, including Kansas, and the District of Columbia to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from power plants. Such emissions would be required to be reduced in two phases beginning in 2012, with further reductions projected to be required in 2014. The EPA expects the CATR to be finalized in the spring of 2011. There are a number of uncertainties relating to this proposed rule, including whether it will be finalized and how the states will implement the requirements. As a result, we cannot determine the impact this rule will have on our consolidated financial results, but it could be material. EPA Lawsuit Under Section 114(a) of the Federal Clean Air Act, the EPA has been conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to the New Source Review permitting program or New Source Performance Standards. These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could reasonably have been expected to result in a significant net increase in emissions. The New Source Review program requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center (JEC) violated certain requirements of the New Source Review program. On February 4, 2009, the Department of Justice, on behalf of the EPA, filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. On January 25, 2010, we announced a settlement of the lawsuit. The settlement was filed with the court, seeking its approval, and on March 26, 2010, the court entered an order approving the settlement without changes. The settlement provides for us to install a selective catalytic reduction (SCR) system on one of the three JEC coal units by the end of 2014. We have not yet engineered this project; however, our preliminary estimate of the cost of this SCR is approximately $200.0 million. This amount could materially increase or decrease depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, a second SCR system would be installed on another JEC coal unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge our customers. We will also invest $5.0 million over six years in environmental mitigation projects that we will own and $1.0 million in environmental mitigation projects that will be owned by a qualifying third party. We have also paid a $3.0 million civil penalty. FERC Investigation We continue to respond to a non-public investigation by FERC of our use of transmission service between July 2006 and February 2008. On May 7, 2009, FERC staff advised us that it had preliminarily concluded that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. On March 4, 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and potentially could alter the manner in which we are permitted to buy and sell energy and use transmission service. Manufactured Gas Sites We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas and Missouri. We and the KDHE entered into a consent agreement governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, Inc. (ONEOK), the current owner of some of the sites, ONEOK assumed total liability for remediation of seven sites, and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million. We have sole responsibility for remediation with respect to three sites. Our environmental liability for remediation of sites associated with assets we divested many years ago had been limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of those assets. In June 2010, the purchaser agreed to reduce our maximum liability to $2.5 million, which reflects our share of the purchaser's expected remediation costs. We have paid $1.5 million of such costs.

LEGAL PROCEEDINGS	9 Months Ended
LEGAL PROCEEDINGS	Sep. 30, 2010
LEGAL PROCEEDINGS
LEGAL PROCEEDINGS	8. LEGAL PROCEEDINGS In late 2002, one of our executive officers resigned and another was placed on administrative leave from their positions. Our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment. As of September 30, 2010, we had accrued liabilities of $79.8 million for compensation not yet paid to them and $6.9 million for legal fees and expenses they have incurred. As of December 31, 2009, we had accrued liabilities of $77.6 million for compensation not yet paid to them and $6.8 million for legal fees and expenses they have incurred. The arbitration 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 intend to vigorously defend against the counterclaims they filed in the arbitration. The arbitration proceedings are confidential pursuant to the terms of the employment agreements with the officers. We are unable to predict the timing and ultimate impact of this matter on our consolidated financial statements. We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect on our consolidated financial statements. See also Note 5, "Rate Matters and Regulation," and Note 7, "Commitments and Contingencies."

INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

9 Months Ended

Sep. 30, 2010

INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

9. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2010			2009			2010			2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	3,481		$	3,790		$	381		$	343
Interest cost		9,848			9,503			1,771			1,206
Expected return on plan assets		(9,596	)		(9,518	)		(1,299	)		(1,174	)
Amortization of unrecognized:
Transition obligation, net		—			—			978			968
Prior service costs		682			669			539			390
Actuarial loss (gain), net		4,296			3,567			80			(667	)

Net periodic cost before regulatory adjustment		8,711			8,011			2,450			1,066
Regulatory adjustment		(3,119	)		(6,891	)		444			1,710

Net periodic cost	$	5,592		$	1,120		$	2,894		$	2,776


	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2010			2009			2010			2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	10,444		$	9,662		$	1,144		$	1,147
Interest cost		29,544			28,621			5,312			5,188
Expected return on plan assets		(28,788	)		(28,369	)		(3,898	)		(3,567	)
Amortization of unrecognized:
Transition obligation, net		—			—			2,934			2,934
Prior service costs		2,047			2,001			1,616			1,185
Actuarial loss (gain), net		12,887			10,697			241			(29	)

Net periodic cost before regulatory adjustment		26,134			22,612			7,349			6,858
Regulatory adjustment		(9,357	)		(6,891	)		1,331			1,710

Net periodic cost	$	16,777		$	15,721		$	8,680		$	8,568

During the nine months ended September 30, 2010 and 2009, we contributed $22.4 million and $37.3 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

9 Months Ended

Sep. 30, 2010

WOLF CREEK INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

WOLF CREEK INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2010			2009			2010		2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	1,036		$	976		$	45	$	40
Interest cost		1,735			1,669			130		139
Expected return on plan assets		(1,363	)		(1,365	)		—		—
Amortization of unrecognized:
Transition obligation, net		14			15			14		14
Prior service costs		7			10			—		—
Actuarial loss, net		659			710			69		75

Net periodic cost before regulatory adjustment		2,088			2,015			258		268
Regulatory adjustment		(394	)		(709	)		—		—

Net periodic cost	$	1,694		$	1,306		$	258	$	268


	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2010			2009			2010		2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	3,108		$	2,733		$	134	$	141
Interest cost		5,206			4,801			390		404
Expected return on plan assets		(4,090	)		(3,732	)		—		—
Amortization of unrecognized:
Transition obligation, net		42			43			43		43
Prior service costs		22			32			—		—
Actuarial loss, net		1,976			1,903			207		193

Net periodic cost before regulatory adjustment		6,264			5,780			774		781
Regulatory adjustment		(1,182	)		(709	)		—		—

Net periodic cost	$	5,082		$	5,071		$	774	$	781

During the nine months ended September 30, 2010 and 2009, we funded $5.1 million and $7.3 million, respectively, of Wolf Creek's pension plan contribution.

COMMON STOCK ISSUANCE	9 Months Ended
COMMON STOCK ISSUANCE	Sep. 30, 2010
COMMON STOCK ISSUANCE
COMMON STOCK ISSUANCE	11. COMMON STOCK ISSUANCE During the nine months ended September 30, 2010, Westar Energy sold 1.2 million shares of common stock for $25.0 million through a 2007 Sales Agency Financing Agreement with a broker dealer subsidiary of a bank. Westar Energy used the proceeds from the issuance of common stock to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes. On April 2, 2010, Westar Energy entered into a new, three-year Sales Agency Financing Agreement and forward sale agreement with the same bank and its broker dealer subsidiary. The maximum amount that Westar Energy may offer and sell under the agreements is the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the Sales Agency Financing Agreement, Westar Energy may offer and sell shares of its common stock from time to time through the broker dealer subsidiary, as agent. Westar Energy will pay the broker dealer a commission equal to 1% of the sales price of all shares sold under the agreement. In addition, under the terms of the Sales Agency Financing Agreement and forward sale agreement, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, with the bank borrowing shares of Westar Energy's common stock from third parties and selling them through the broker dealer. The use of a forward sale agreement allows Westar Energy the means to minimize equity market uncertainty by pricing a common stock offering under then existing market conditions while postponing the issuance of common stock until funds are needed. Through this approach, Westar Energy is able to better match the timing of its financing needs with its capital investment and regulatory plans. The forward sale transactions are entered into at market prices; therefore, the forward sale agreement has no initial fair value. Westar Energy will not receive any proceeds from the sale of common stock under the forward sale agreement until the transactions are settled, which must occur within a year of the date each transaction is entered. Upon settlement, Westar Energy will record the forward sale agreement within equity. Except in specified circumstances or events that would require physical share settlement, Westar Energy is able to elect to settle any forward sale transactions by means of a physical share, cash or net share settlement, and is also able to elect to settle the forward sale transactions in whole, or in part, earlier than the stated maturity dates. Currently, Westar Energy anticipates settling the forward sale transactions through physical share settlement and expects to use the proceeds to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes. While the shares are initially priced by the bank at a fixed price, because of the fixed contractual terms, Westar Energy's net proceeds from the forward sale transactions, assuming physical share settlement, will vary depending on the time of settlement. As of September 30, 2010, Westar Energy had entered into forward sale transactions with respect to an aggregate of approximately 5.4 million shares of common stock. Assuming physical share settlement of these transactions at September 30, 2010, Westar Energy would have received aggregate proceeds of approximately $120.9 million based on an average forward price of $22.39 per share.

- Definition

This element is used to capture the complete disclosure pertaining to an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation. Stock by Class includes common, convertible and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued and outstanding.

+ References+ Details

VARIABLE INTEREST ENTITIES

9 Months Ended

Sep. 30, 2010

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

12. VARIABLE INTEREST ENTITIES

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

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

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

Railcars

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

Financial Statement Impact

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


As of September 30, 2010	Dollar Amount
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	347,917
Regulatory assets (a)		3,719

Liabilities:
Current maturities of long-term debt of variable interest entities	$	30,090
Accrued interest (b)		733
Long-term debt of variable interest entities, net		279,554

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

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

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

- 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.

+ References+ Details

LEASES

9 Months Ended

Sep. 30, 2010

LEASES

LEASES

13. LEASES

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

Operating Leases

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

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


Total Operating Leases	September 30, 2010		December 31, 2009
	(In Thousands)
2010	$	4,153	$	49,181
2011		12,964		48,450
2012		14,189		50,453
2013		11,936		46,698
2014		9,986		43,195
Thereafter		29,882		249,592

Total future commitments	$	83,110	$	487,569

Capital Leases

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

Assets recorded under capital leases are listed below.


	September 30, 2010			December 31, 2009
	(In Thousands)
Vehicles	$	16,257		$	18,991
Computer equipment and software		4,961			4,640
Jeffrey Energy Center 8% interest		—			118,623
Accumulated amortization		(11,083	)		(21,736	)

Total capital leases	$	10,135		$	120,518

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


Total Capital Leases	September 30, 2010			December 31, 2009
	(In Thousands)
2010	$	2,548		$	17,685
2011		2,009			14,776
2012		1,747			11,540
2013		1,914			7,256
2014		974			7,037
Thereafter		1,741			111,547

		10,933			169,841
Amounts representing imputed interest		(798	)		(51,606	)

Present value of net minimum lease payments under capital leases		10,135			118,235
Less current portion		1,889			8,935

Total long-term obligation under capital leases	$	8,246		$	109,300