Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2010	Feb. 15, 2011	Jun. 30, 2010
Document and Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2010
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	FY
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		113,566,796
Entity Public Float			$ 2,391,619,392
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	Yes

Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
CURRENT ASSETS:
Cash and cash equivalents	$ 928	$ 3,860
Accounts receivable, net of allowance for doubtful accounts of $5,729 and $5,231, respectively	227,700	216,186
Inventories and supplies, net	206,867	193,831
Energy marketing contracts	13,005	33,159
Taxes receivable	16,679	45,200
Deferred tax assets	30,248	7,927
Prepaid expenses	12,413	11,830
Regulatory assets	73,480	97,220
Other	20,289	20,269
Total Current Assets	601,609	629,482
PROPERTY, PLANT AND EQUIPMENT, NET	5,964,439	5,771,740
OTHER ASSETS:
Regulatory assets	787,585	758,538
Nuclear decommissioning trust	126,990	112,268
Energy marketing contracts	9,472	10,653
Other	244,506	242,802
Total Other Assets	1,168,553	1,124,261
TOTAL ASSETS	8,079,638	7,525,483
CURRENT LIABILITIES:
Current maturities of long-term debt	61	1,345
Short-term debt	226,700	242,760
Accounts payable	187,954	112,211
Accrued taxes	45,534	46,931
Energy marketing contracts	9,670	39,161
Accrued interest	77,771	76,955
Regulatory liabilities	28,284	39,745
Other	176,717	123,370
Total Current Liabilities	782,846	682,478
LONG-TERM LIABILITIES:
Long-term debt, net	2,490,871	2,490,734
Obligation under capital leases	7,514	109,300
Deferred income taxes	1,102,625	964,461
Unamortized investment tax credits	101,345	127,777
Regulatory liabilities	135,754	100,963
Deferred regulatory gain from sale-leaseback	97,541	108,532
Accrued employee benefits	483,769	433,561
Asset retirement obligations	125,999	119,519
Energy marketing contracts	10	210
Other	59,364	117,720
Total Long-Term Liabilities	4,882,954	4,572,777
COMMITMENTS AND CONTINGENCIES (See Notes 13 and 15)
TEMPORARY EQUITY (See Note 11)	3,465	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 112,128,068 shares and 109,072,000 shares, respectively	560,640	545,360
Paid-in capital	1,398,580	1,339,790
Retained earnings	423,647	360,199
Total Westar Energy Shareholders' Equity	2,404,303	2,266,785
Total Equity	2,410,373	2,266,785
TOTAL LIABILITIES AND EQUITY	8,079,638	7,525,483
Variable Interest Entity, Primary Beneficiary [Member]
CURRENT ASSETS:
PROPERTY, PLANT AND EQUIPMENT, NET	345,037
CURRENT LIABILITIES:
Current maturities of long-term debt	30,155
LONG-TERM LIABILITIES:
Long-term debt, net	278,162
Westar Energy Shareholders' Equity:
Noncontrolling Interests	$ 6,070

Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2010	Dec. 31, 2009
Accounts receivable, allowance for doubtful accounts	$ 5,729	$ 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	112,128,068	109,072,000
Common stock, outstanding	112,128,068	109,072,000

Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Consolidated Statements of Income
REVENUES	$ 2,056,171	$ 1,858,231	$ 1,838,996
OPERATING EXPENSES:
Fuel and purchased power	583,361	534,864	694,348
Operating and maintenance	520,409	516,930	471,838
Depreciation and amortization	271,937	251,534	203,738
Selling, general and administrative	207,607	199,961	184,427
Total Operating Expenses	1,583,314	1,503,289	1,554,351
INCOME FROM OPERATIONS	472,857	354,942	284,645
OTHER INCOME (EXPENSE):
Investment earnings (losses)	7,026	12,658	(10,453)
Other income	5,369	7,128	29,658
Other expense	(16,655)	(17,188)	(15,324)
Total Other (Expense) Income	(4,260)	2,598	3,881
Interest expense	174,941	157,360	106,450
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	293,656	200,180	182,076
Income tax expense	85,032	58,850	3,936
INCOME FROM CONTINUING OPERATIONS	208,624	141,330	178,140
Results of discontinued operations, net of tax		33,745
NET INCOME	208,624	175,075	178,140
Less: Net income attributable to noncontrolling interests	4,728
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY	203,896	175,075	178,140
Preferred dividends	970	970	970
NET INCOME ATTRIBUTABLE TO COMMON STOCK	202,926	174,105	177,170
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (see Note 2):
Basic earnings available from continuing operations	$ 1.81	$ 1.28	$ 1.69
Discontinued operations, net of tax		$ 0.30
Basic earnings per common share	$ 1.81	$ 1.58	$ 1.69
Diluted earnings available from continuing operations	$ 1.80	$ 1.28	$ 1.69
Discontinued operations, net of tax		$ 0.30
Diluted earnings per common share	$ 1.80	$ 1.58	$ 1.69
Average equivalent common shares outstanding	111,629,292	109,647,689	103,958,414
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.24	$ 1.20	$ 1.16
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	203,896	141,330	178,140
Results of discontinued operations, net of tax		33,745
Net income	$ 203,896	$ 175,075	$ 178,140

Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 208,624	$ 175,075	$ 178,140
Discontinued operations, net of tax		(33,745)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	271,937	251,534	203,738
Amortization of nuclear fuel	25,089	16,161	14,463
Amortization of deferred regulatory gain from sale-leaseback	(5,495)	(5,495)	(5,495)
Amortization of corporate-owned life insurance	20,650	22,116	18,920
Non-cash compensation	11,373	5,133	4,696
Net changes in energy marketing assets and liabilities	(1,284)	8,972	(7,018)
Accrued liability to certain former officers	2,675	2,296	(1,449)
Gain on sale of utility plant and property			(1,053)
Net deferred income taxes and credits	120,169	46,447	35,261
Stock-based compensation excess tax benefits	(641)	(448)	(561)
Allowance for equity funds used during construction	(3,104)	(5,031)	(18,284)
Changes in working capital items:
Accounts receivable	(11,434)	(17,159)	(3,331)
Inventories and supplies	(12,266)	10,466	(11,764)
Prepaid expenses and other	8,475	(10,635)	(52,615)
Accounts payable	30,330	(15,115)	(73,971)
Accrued taxes	27,565	30,493	27,938
Other current liabilities	(80,660)	13,572	(5,732)
Changes in other assets	(42,544)	73,784	29,389
Changes in other liabilities	38,243	(89,516)	(56,382)
Cash Flows from Operating Activities	607,702	478,905	274,890
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(540,076)	(555,637)	(918,958)
Investment in corporate-owned life insurance	(19,162)	(17,724)	(18,720)
Purchase of securities within trust funds	(192,350)	(64,016)	(210,599)
Sale of securities within trust funds	191,603	61,096	221,613
Proceeds from investment in corporate-owned life insurance	2,204	1,748	27,320
Proceeds from sale of plant and property			4,295
Proceeds from federal grant	3,180
Investment in affiliated company	(280)	(818)
Other investing activities	(1,164)	2,920	(11,388)
Cash Flows used in Investing Activities	(556,045)	(572,431)	(906,437)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(16,060)	67,860	(5,100)
Proceeds from long-term debt		347,507	544,715
Retirements of long-term debt	(1,695)	(196,821)	(101,311)
Repayment of capital leases	(2,981)	(10,190)	(9,820)
Borrowings against cash surrender value of corporate-owned life insurance	74,134	10,299	64,255
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(3,430)	(3,531)	(28,634)
Stock-based compensation excess tax benefits	641	448	561
Issuance of common stock, net	54,651	4,587	293,621
Cash dividends paid	(129,146)	(122,937)	(109,579)
Cash Flows (used in) from Financing Activities	(54,589)	97,222	648,708
CASH FLOWS USED IN INVESTING ACTIVITIES OF DISCONTINUED OPERATIONS:
Payment of settlement to former subsidiary		(22,750)
Cash flows used in investing activities of discontinued operations		(22,750)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(2,932)	(19,054)	17,161
CASH AND CASH EQUIVALENTS:
Beginning of period	3,860	22,914	5,753
End of period	928	3,860	22,914
Variable Interest Entity, Primary Beneficiary [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Retirements of long-term debt	(28,610)
Distributions to shareholders of noncontrolling interests	$ (2,093)

Consolidated Statements of Changes in Equity (USD $) In Thousands	Total	Cumulative preferred stock [Member]	Common stock [Member]	Paid-in capital [Member]	Retained earnings [Member]	Accumulated other comprehensive income (loss) [Member]	Noncontrolling interests [Member]
Beginning Balance at Dec. 31, 2007	$ 1,848,480	$ 21,436	$ 477,316	$ 1,085,099	$ 264,477	$ 152
Net income	178,140				178,140
Issuance of common stock, net	303,556		64,240	239,316
Preferred dividends	(970)				(970)
Dividends on common stock	(123,107)				(123,107)
Reclass to temporary equity	1,802			1,802
Amortization of restricted stock	3,941			3,941
Stock compensation and tax benefit	(3,767)			(3,767)
Adjustment to retained earnings - Pension and other post-retirement benefit plans	(495)				(495)
Adjustment to retained earnings - Fair value option					152	(152)
Ending Balance at Dec. 31, 2008	2,207,580	21,436	541,556	1,326,391	318,197
Net income	175,075				175,075
Issuance of common stock, net	14,373		3,804	10,569
Preferred dividends	(970)				(970)
Dividends on common stock	(132,103)				(132,103)
Reclass to temporary equity	(20)			(20)
Amortization of restricted stock	4,524			4,524
Stock compensation and tax benefit	(1,674)			(1,674)
Ending Balance at Dec. 31, 2009	2,266,785	21,436	545,360	1,339,790	360,199
Net income	208,624				203,896		4,728
Issuance of common stock, net	66,039		15,280	50,759
Preferred dividends	(970)				(970)
Dividends on common stock	(139,478)				(139,478)
Reclass to temporary equity	(22)			(22)
Amortization of restricted stock	10,710			10,710
Stock compensation and tax benefit	(2,657)			(2,657)
Consolidation of noncontrolling interests	3,435						3,435
Distributions to shareholders of noncontrolling interests	(2,093)						(2,093)
Ending Balance at Dec. 31, 2010	$ 2,410,373	$ 21,436	$ 560,640	$ 1,398,580	$ 423,647		$ 6,070

Description of Business	12 Months Ended
Description of Business	Dec. 31, 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 Annual Report on Form 10-K 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

12 Months Ended

Dec. 31, 2010

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. Our 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. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.

Use of Management's Estimates

When we prepare our 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, valuation of investments, valuation of our energy marketing portfolio, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and other post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 3, "Rate Matters and Regulation," for additional information regarding our regulatory assets and liabilities.

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

Inventories and Supplies

We state inventories and supplies at average cost.

Property, Plant and Equipment

We record the value of property, plant and equipment, and property, plant and equipment of VIEs at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). 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 to other income (for equity funds) and interest expense (for borrowed funds) the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:


	Year Ended December 31,
	2010		2009		2008
	(Dollars In Thousands)
Borrowed funds		$4,295		$4,857		$20,536
Equity funds		3,104		5,031		18,284

Total		$7,399		$9,888		$38,820


Average AFUDC Rates		2.6%		4.2%		6.4%

We charge maintenance costs and replacement of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over an 18-month operating cycle the incremental maintenance costs incurred for such outages. Normally, when a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.

Depreciation

We depreciate utility plant using a straight-line method. These rates are based on an average annual composite basis using group rates that approximated 2.9% in 2010, 3.0% in 2009 and 2.6% in 2008.

Depreciable lives of property, plant and equipment are as follows.


	Years
Fossil fuel generating facilities		7 to 69
Nuclear fuel generating facility		40 to 60
Wind generating facilities		19 to 20
Transmission facilities		15 to 65
Distribution facilities		21 to 70
Other		5 to 35

Nuclear Fuel

We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity, as measured in millions of British thermal units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $48.0 million as of December 31, 2010, and $22.9 million as of December 31, 2009. Cost of nuclear fuel charged to fuel and purchased power expense was $29.2 million in 2010, $20.1 million in 2009 and $18.3 million in 2008.

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance policies.


	As of December 31,
	2010			2009
	(In Thousands)
Cash surrender value of policies	$	1,280,615		$	1,209,304
Borrowings against policies		(1,144,248	)		(1,073,544	)

Corporate-owned life insurance, net	$	136,367		$	135,760

We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.

Revenue Recognition

Electricity Sales

We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We had estimated unbilled revenue of $53.8 million as of December 31, 2010, and $56.6 million as of December 31, 2009.

Energy Marketing Contracts

We account for energy marketing derivative contracts under the fair value method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. With the exception of certain fuel supply and electricity contracts, which we record as regulatory assets or regulatory liabilities, we include the net change in fair value in revenues on our consolidated statements of income. We record the unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The prices we use to value these transactions reflect our best estimate of the fair value of these contracts. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

Normal Purchases and Normal Sales Exception

Determining whether a contract qualifies for the normal purchases and normal sales exception requires that we exercise judgment on whether the contract will physically deliver and requires that we ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal sales are recognized when the underlying physical transaction is completed. Contracts which qualify for the normal purchases and normal sales exception are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and price is not tied to an unrelated underlying derivative.

Allowance for Doubtful Accounts

We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management's judgment.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.

We record deferred tax assets to carry forward into future periods capital losses, operating losses and tax credits. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.

The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, "Taxes," for additional detail on our accounting for income taxes.

Sales Taxes

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect them in our consolidated statements of income.

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 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 income from continuing operations.


	Year Ended December 31,
	2010		2009		2008
	(Dollars In Thousands, Except Per Share Amounts)
Income from continuing operations	$	208,624	$	141,330	$	178,140
Less: Income attributable to noncontrolling interests		4,728		—		—

Income from continuing operations attributable to Westar Energy		203,896		141,330		178,140
Less: Preferred dividends		970		970		970
Income from continuing operations allocated to RSUs		1,259		541		1,346

Income from continuing operations attributable to common stock	$	201,667	$	139,819	$	175,824


Weighted average equivalent common shares outstanding – basic		111,629,292		109,647,689		103,958,414
Effect of dilutive securities:
Restricted share units		140,077		—		—
Forward sale agreements		245,496		—		—
Employee stock options		59		481		728

Weighted average equivalent common shares outstanding – diluted (a)		112,014,924		109,648,170		103,959,142


Earnings from continuing operations per common share, basic	$	1.81	$	1.28	$	1.69
Earnings from continuing operations per common share, diluted	$	1.80	$	1.28	$	1.69

(a)	We did not have any antidilutive shares for the years ended December 31, 2010 and 2009. For the year ended December 31, 2008, potentially dilutive shares not included in the denominator because they are antidilutive totaled 21,300 shares.

Supplemental Cash Flow Information


	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	145,463		$	144,964		$	102,865
Interest on financing activities of VIEs (a)		20,191			—			—
Income taxes, net of refunds		(34,980	)		(7,870	)		(34,905	)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		64,423			21,614			106,219
Property, plant and equipment additions of VIEs (a)		356,964			—			—
Jeffrey Energy Center (JEC) 8% leasehold interest (a)		(108,706	)		—			—
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans		18,777			12,168			11,263
Debt of VIEs (a)		337,951			—			—
Capital lease for JEC 8% leasehold interest (a)		(106,423	)		—			—
Assets acquired through capital leases		910			2,818			4,583

(a)	These transactions result from the consolidation of the VIEs discussed in Note 17, "Variable Interest Entities."

New Accounting Pronouncements

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncement that affected our accounting and disclosure.

Consolidation Guidance for Variable Interest Entities

In June 2009, the 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 17, "Variable Interest Entities," for additional information.

Rate Matters and Regulation

12 Months Ended

Dec. 31, 2010

Rate Matters and Regulation

Rate Matters and Regulation

3. RATE MATTERS AND REGULATION

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.


	As of December 31,
	2010		2009
	(In Thousands)
Regulatory Assets:
Deferred employee benefit costs	$	431,016	$	369,877
Amounts due from customers for future income taxes, net		172,181		183,667
Depreciation		79,770		82,541
Debt reacquisition costs		73,099		79,342
Storm costs		34,741		56,288
Asset retirement obligations		21,546		20,719
Disallowed plant costs		16,354		16,462
Energy efficiency program costs		10,980		1,101
Wolf Creek outage		9,637		19,438
Ad valorem tax		5,680		1,195
Retail energy cost adjustment		—		13,298
Other regulatory assets		6,061		11,830

Total regulatory assets	$	861,065	$	855,758


Regulatory Liabilities:
Removal costs	$	70,342	$	68,078
Nuclear decommissioning		25,467		16,658
Retail energy cost adjustment		16,402		27,488
La Cygne dismantling costs		13,268		—
Fuel supply and electricity contracts		7,800		6,001
Treasury yield hedges		7,711		—
Other post-retirement benefits costs		6,943		3,534
Ad valorem tax		4,934		5,604
Kansas tax credits		3,565		5,351
Other regulatory liabilities		7,606		7,994

Total regulatory liabilities	$	164,038	$	140,708

Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

Deferred employee benefit costs: Includes $407.2 million for pension and other post-retirement benefit obligations and $23.8 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. During 2011, we will amortize to expense approximately $36.3 million of the benefit obligations. At the time of a future rate case, we expect to amortize the excess pension expense as part of resetting base prices. We do not earn a return on this asset.

Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts on which we do not earn a return. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices.

Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.

Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.

Storm costs: We accumulated and deferred for future recovery costs related to restoring our electric transmission and distribution systems from damages sustained during unusually damaging storms. We amortize these costs over periods ranging from three to five years and earn a return on a majority of this asset.

Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 14, "Asset Retirement Obligations." We recover these amounts over the life of the related plant. We do not earn a return on this asset.

Disallowed plant costs: In 1985, the Kansas Corporation Commission (KCC) disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in prices over the useful life of Wolf Creek. We do not earn a return on this asset.

Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.

Wolf Creek outage: Wolf Creek incurs a refueling and maintenance outage approximately every 18 months. The expenses associated with these refueling and maintenance outages are deferred and amortized over the period between such planned outages. We do not earn a return on this asset.

Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.

Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. This item represents the actual cost of fuel consumed in producing electricity and the cost of purchased power in excess of the amounts we have collected from customers. We expect to recover in our prices this shortfall over a one-year period. We do not earn a return on this asset.

Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods, most of which range from three to five years.

Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.

Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.

Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This item represents the difference between the fair value of the assets held in a decommissioning trust and the fair value of our ARO. See Note 5, "Financial Investments and Trading Securities" and Note 14, "Asset Retirement Obligations," for information regarding our nuclear decommissioning trust (NDT) fund and our ARO.

Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.

La Cygne dismantling costs: We are contractually obligated to retire a portion of the La Cygne Generating Station (La Cygne) unit 2. This item represents amounts collected but not yet spent to retire this unit and the obligation will be discharged as we dismantle the unit.

Fuel supply and electricity contracts: We use fair value accounting for some of our fuel supply and electricity contracts. This represents the non-cash net gain position on fuel supply and electricity contracts that are recorded at fair value. Under the RECA, fuel supply contract market gains accrue to the benefit of our customers.

Treasury yield hedges: Represents the effective portion of the gains on treasury yield hedge transactions entered into during 2010. This amount will be amortized to interest expense over the life of the related debt. See Note 4, "Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management – Derivative Instruments – Cash Flow Hedges," for additional information regarding our treasury yield hedge transactions.

Other post-retirement benefits costs: Represents the amount of other post-retirement benefits expense recognized in setting our prices in excess of actual other post-retirement benefits expense. At the time of a future rate case, we expect to credit this excess to customers as part of resetting our base prices.

Ad valorem tax: Represents amounts collected in our prices in excess of actual costs incurred for property taxes. We will refund to customers this excess recovery over a one-year period.

Kansas tax credits: Represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.

Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods, most of which range from one to five years.

KCC Proceedings

On October 29, 2010, the KCC issued an order, effective November 2010, allowing us to recover in our prices $5.8 million of previously deferred amounts associated with various energy efficiency programs.

On June 11, 2010, the KCC issued a final order approving an adjustment to our prices that we made earlier in 2010. The adjustment included 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.

On September 11, 2009, the KCC issued an order, effective January 1, 2009, allowing us to establish a regulatory asset or liability to track the cumulative difference between current year 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 base rates.

On May 29, 2009, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2008. This change went into effect on June 1, 2009, and was expected to increase our annual retail revenues by $32.5 million.

On March 6, 2009, the KCC issued an order allowing us to adjust our prices to include updated transmission costs. This change went into effect on March 13, 2009, and was expected to increase our annual retail revenues by $31.8 million.

On January 21, 2009, the KCC issued an order expected to increase our annual retail revenues by $130.0 million to reflect investments in natural gas generation facilities, wind generation facilities and other capital projects, costs to repair damage to our electrical system, which were previously deferred as a regulatory asset, higher operating costs in general and an updated capital structure. The new prices became effective on February 3, 2009.

On September 18, 2008, the KCC issued an order allowing us to adjust our prices to include updated transmission costs. This change was expected to increase our annual retail revenues by $6.1 million.

On May 29, 2008, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2007. This change went into effect on June 1, 2008, and was expected to increase our annual retail revenues by $22.0 million.

FERC Proceedings

On October 15, 2010, we posted our updated transmission formula rate which includes projected 2011 transmission capital expenditures and operating costs. The updated rate was effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million.

Our transmission formula rate that includes projected 2010 transmission capital expenditures and operating costs became effective January 1, 2010, and was expected to increase our annual transmission revenues by $16.8 million. The transmission formula rate provides the basis for our annual 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.

On December 2, 2008, FERC issued an order approving a settlement of our transmission formula rate that allows us to include our anticipated transmission capital expenditures for the current year in our transmission formula rate, subject to true up. In addition to the true up, we expect to update our transmission formula rate in January of each year to reflect changes in our projected operating costs and investments.

On March 24, 2008, FERC issued an order that granted our requested incentives of an additional 100 basis points above the base allowed return on equity and a 15-year accelerated recovery for an approximately 100 mile, 345 kilovolt transmission line that will run from near Wichita, Kansas, to near Salina, Kansas. We completed construction of the line in August 2010.

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

12 Months Ended

Dec. 31, 2010

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

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

4. 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 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 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 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; and when other news or events have a material impact on the security. Level 3 debt investments 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 December 31, 2010 and 2009.


	Carrying Value				Fair Value
	As of December 31,
	2010		2009		2010		2009
	(In Thousands)
Fixed-rate debt (a)	$	2,373,373	$	2,373,723	$	2,570,648	$	2,528,456
Fixed-rate debt of VIEs		308,317		—		341,328		—

(a)

This amount does not include an equipment financing loan of $0.1 million and $1.4 million in 2010 and
2009, respectively.

Recurring Fair Value Measurements

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


As of December 31, 2010	Level 1		Level 2		Level 3		Total
		(In Thousands)
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 Hedge		—		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

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 December 31, 2010, we had no right to reclaim cash collateral and $0.7 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 years ended December 31, 2010 and 2009.


	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, 2009	$	4,310		$	2,262		$	5,741		$	3,635		$	15,948
Total realized and unrealized gains (losses) included in:
Earnings (a)		(2,585	)		—			—			—			(2,585	)
Regulatory assets		3,311	(b)		—			—			—			3,311
Regulatory liabilities		8,148	(b)		16			367			(586	)		7,945
Purchases, issuances and settlements		(1,369	)		589			(5,803	)		—			(6,583	)

Balance as of December 31, 2010	$	11,815		$	2,867		$	305		$	3,049		$	18,036


Balance as of December 31, 2008	$	44,541		$	2,006		$	—		$	6,028		$	52,575
Total realized and unrealized gains (losses) included in:
Earnings (a)		3,060			—			—			—			3,060
Regulatory assets		(15,382	) (b)		—			—			—			(15,382	)
Regulatory liabilities		(22,750	) (b)		(39	)		1,134			(2,393	)		(24,048	)
Purchases, issuances and settlements		(5,159	)		295			4,607	(c)		—			(257	)

Balance as of December 31, 2009	$	4,310		$	2,262		$	5,741		$	3,635		$	15,948

(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)	We used proceeds from the sale of certain debt investments measured at fair value using level 2 inputs to purchase different debt investments that require significant unobservable inputs in order to measure their fair value.

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 years ended December 31, 2010 and 2009, attributed to level 3 assets and liabilities.


	Year Ended December 31, 2010
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds			Real Estate Securities			Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(1,441	)	$	—		$	—		$	—		$	(1,441	)
Regulatory assets		180	(b)		—			—			—			180
Regulatory liabilities		2,633	(b)		23			(31	)		(586	)		2,039

Total	$	1,372		$	23		$	(31	)	$	(586	)	$	778


	Year Ended December 31, 2009
Total unrealized gains (losses) included in:
Earnings (a)	$	(474	)	$	—		$	—		$	—		$	(474	)
Regulatory assets		(8,545	) (b)		—			—			—			(8,545	)
Regulatory liabilities		(9,634	) (b)		(39	)		1,134			(2,497	)		(11,036	)

Total	$	(18,653	)	$	(39	)	$	1,134		$	(2,497	)	$	(20,055	)

(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 December 31, 2010				As of December 31, 2009				As of December 31, 2010
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency			Length of Settlement
		(In thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	2,867	$	2,523	$	7,579	$	3,111		(a	)		(a	)
High-yield bonds		305		—		5,741		—		(b	)		(b	)
Real estate securities		3,049		—		3,635		—		(c	)		(c	)

Total	$	6,221	$	2,523	$	16,955	$	3,111

Trading Securities:
Domestic equity	$	21,207	$	—	$	18,344	$	—		Upon Notice			1 day
International equity		5,128		—		4,422		—		Upon Notice			1 day
Core bonds		13,077		—		11,853		—		Upon Notice			1 day

Total Trading Securities		39,412		—		34,619		—

Total	$	45,633	$	2,523	$	51,574	$	3,111

(a)

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

(b)	We 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, adverse financial conditions affecting residential and commercial real estate markets have further limited any liquidity associated with this investment.

Nonrecurring Fair Value Measurements

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operations of such assets. In 2010 we did not incur any additional AROs. In 2009 we incurred $21.6 million of additional AROs, including $20.3 million increase in our ARO to reflect revisions to the estimated cost to decommission Wolf Creek. We initially record AROs at fair value for the estimated cost to satisfy the retirement obligation. The fair value is measured by estimating the cost to satisfy the retirement obligation then discounting that value at a risk- and inflation-adjusted rate. To determine the cost to satisfy the retirement obligation, we must estimate the cost of basic inputs such as labor, energy, materials and disposal. To determine the appropriate discount rate, we use inputs such as inflation rates, short and long-term yields for U.S. government securities and our nonperformance risk. Due to the significant unobservable inputs required in our measurement, we have determined that our fair value measurements of our AROs are level 3 in the fair value hierarchy. For additional information on our AROs, see Note 14, "Asset Retirement Obligations."

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 must 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 December 31, 2010, the fair value of the treasury yield hedge transactions was $7.7 million, which we recorded in other assets on our consolidated balance sheet. We also recorded this same amount in long-term regulatory liabilities on our consolidated balance sheet to reflect the effective portion of the gains on these transactions for the year ended 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 and 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 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


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 years ended December 31, 2010 and 2009.


	Year Ended December 31, 2010			Year Ended December 31, 2009
Location	Net Gain Recognized			Net Gain Recognized		Net Loss Recognized
	(In Thousands)
Revenues increase	$	712		$	7,790	$	—
Regulatory assets (decrease) increase		(7,604	)		—		7,064
Regulatory liabilities increase (decrease)		1,799			—		(30,330	)

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

Net Quantity as of

Unit of Measure

December 31, 2010

December 31, 2009

Electricity

MWh

2,791,966

4,147,800

Natural Gas

MMBtu

1,150,000

648,000

Coal

Ton

—

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 generating 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 and maintenance schedule. Our customers' electricity usage also varies based on weather, the economy and numerous other factors.

The wholesale power and fuel markets are volatile. This volatility impacts our costs of purchased power, fuel costs for our generating 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.

Interest Rate Risk

We have entered into numerous fixed and variable rate debt obligations. For details, see Note 9, "Long-Term Debt." We manage our interest rate risk related to these debt obligations by limiting our variable interest rate exposure, utilizing various 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 December 31, 2010 and 2009, was $1.6 million and $1.4 million, respectively, for which we had posted no collateral. If all credit-risk-related contingent features underlying these agreements had been triggered as of December 31, 2010 and 2009, we would have been required to provide to our counterparties $1.6 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 and Trading Securities

12 Months Ended

Dec. 31, 2010

Financial Investments and Trading Securities

Financial Investments and Trading Securities

5. FINANCIAL INVESTMENTS AND TRADING SECURITIES

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 unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the years ended December 31, 2010 and 2009, we recorded unrealized gains on these securities of $4.3 million and $11.3 million, respectively. We recorded an unrealized loss on these securities of $9.5 million for the year ended December 31, 2008.

Available-for-Sale Securities

We hold investments in equity and debt 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 December 31, 2010 and 2009. At December 31, 2010, investments in the NDT fund were allocated 50% to domestic equity, 15% to international equity, 25% to core bonds, 8% to high-yield bonds, 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 December 31, 2010, the fair value of the debt securities in the NDT fund was $41.5 million, held entirely in bond funds.

Using the specific identification method to determine cost, we realized a $13.2 million gain in 2010 and losses of $7.8 million and $20.1 million in 2009 and 2008, respectively, on our available-for-sale securities. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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


			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value
	(In Thousands)
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


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 December 31, 2010 and 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)
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	)


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	)

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2010

Property, Plant and Equipment

Property, Plant and Equipment

6. PROPERTY, PLANT AND EQUIPMENT

The following is a summary of our property, plant and equipment balance.


	As of December 31,
	2010			2009
	(In Thousands)
Electric plant in service	$	8,254,884		$	8,057,793
Electric plant acquisition adjustment		802,318			802,318
Accumulated depreciation		(3,563,566	)		(3,370,805	)

		5,493,636			5,489,306
Construction work in progress		392,701			214,705
Nuclear fuel, net		78,102			67,729

Net property, plant and equipment	$	5,964,439		$	5,771,740

The following is a summary of our property, plant and equipment of VIEs.


	As of December 31,
	2010			2009
	(In Thousands)
Electric plant of VIEs	$	543,593		$	—
Accumulated depreciation of VIEs		(198,556	)		—

Net property, plant and equipment of VIEs	$	345,037		$	—

We recorded depreciation expense on property, plant and equipment of $249.2 million in 2010, $228.6 million in 2009 and $180.8 million in 2008. Approximately $9.7 million of depreciation expense in 2010 was attributable to property, plant and equipment of VIEs.

Joint Ownership of Utility Plants

12 Months Ended

Dec. 31, 2010

Joint Ownership of Utility Plants

Joint Ownership of Utility Plants

7. JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interest in these facilities as of December 31, 2010, is shown in the table below.


		Our Ownership as of December 31, 2010
		In-Service Dates		Investment		Accumulated Depreciation			Construction Work in Progress		Net MW		Ownership Percentage
		(Dollars in Thousands)
La Cygne unit 1	(a)		June 1973	$	284,101	$	(145,356	)	$	48,072		368		50
JEC unit 1	(a)		July 1978		482,582		(195,849	)		8,939		666		92
JEC unit 2	(a)		May 1980		443,128		(187,356	)		48,513		667		92
JEC unit 3	(a)		May 1983		673,567		(251,673	)		883		659		92
Wolf Creek	(b)		Sept. 1985		1,469,700		(733,036	)		71,299		544		47
State Line	(c)		June 2001		111,979		(41,423	)		129		201		40

Total				$	3,465,057	$	(1,554,693	)	$	177,835		3,105

(a)	Jointly owned with Kansas City Power & Light Company (KCPL). Amounts include the consolidated VIE containing an 8% leasehold interest in JEC.

(b)	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

(c)	Jointly owned with Empire District Electric Company.

We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 341 megawatts (MW) of net capacity. The VIE's initial investment in the 50% interest was $392.1 million and accumulated depreciation was $166.0 million as of December 31, 2010. We include these amounts in property, plant and equipment of variable interest entities, net on our consolidated balance sheets. See Note 17, "Variable Interest Entities," for additional information about VIEs.

- Definition

Describes that the entity has a proportionate interest in a jointly owned utility plant. Should include a table showing separately for each interest the amount of plant in service, the accumulated provision for depreciation (if available), the amount of plant under construction, and the proportionate share. The amounts presented may be further subdivided to show amounts applicable to plant subcategories (for example, production, transmission, distribution). Should include statements that the amounts represent the utility's share in each joint plant and that it must provide its own financing. Information concerning two or more generating plants on the same site may be combined. Should state that the utility's share of direct expenses of the joint plants is included in the corresponding operating expenses on its income statement (for example, fuel, maintenance of plant, other operating expense). If the share of direct expenses is charged to purchased power then should disclose the amount so charged and the proportionate amounts charged to specific operating expenses on the records maintained for the joint plants.

+ References+ Details

Short-Term Debt

12 Months Ended

Dec. 31, 2010

Short-Term Debt

Short-Term Debt

8. SHORT-TERM DEBT

Westar Energy has a $730.0 million revolving credit facility with a syndicate of banks that terminates on March 17, 2012. On January 27, 2010, FERC approved our request for authority to issue short-term securities in an aggregate amount up to $1.0 billion including, without limitation, by increasing the size of Westar Energy's revolving credit facility. As of December 31, 2010, we had not yet exercised the increase in our authority. In addition, 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 the revolving credit facility.

The weighted average interest rate on our borrowings under the revolving credit facility was 0.61% and 0.58% as of December 31, 2010, and December 31, 2009, respectively.

Additional information regarding our short-term debt is as follows.


	As of December 31,
	2010			2009
	(Dollars in Thousands)

Weighted average short-term debt outstanding during the year	$	213,041		$	200,547

Weighted daily average interest rates during the year, excluding fees		0.63	%		0.76	%

Our interest expense on short-term debt was $1.9 million in 2010, $2.2 million in 2009 and $9.7 million in 2008.

Long-Term Debt

12 Months Ended

Dec. 31, 2010

Long-Term Debt

Long-Term Debt

9. LONG-TERM DEBT

Outstanding Debt

The following table summarizes our long-term debt outstanding.


	As of December 31,
	2010			2009
	(In Thousands)
Westar Energy
First mortgage bond series:
6.00% due 2014	$	250,000		$	250,000
5.15% due 2017		125,000			125,000
5.95% due 2035		125,000			125,000
5.10% due 2020		250,000			250,000
5.875% due 2036		150,000			150,000
6.10% due 2047		150,000			150,000
8.625% due 2018		300,000			300,000

		1,350,000			1,350,000

Pollution control bond series:
Variable due 2032, 0.60% as of December 31, 2010; 0.48% as of December 31, 2009		45,000			45,000
Variable due 2032, 0.54% as of December 31, 2010; 0.54% as of December 31, 2009		30,500			30,500
5.00% due 2033		57,530			57,760

		133,030			133,260

Other long-term debt:
4.36% equipment financing loan due 2011		61			1,406

KGE
First mortgage bond series:
6.53% due 2037		175,000			175,000
6.15% due 2023		50,000			50,000
6.64% due 2038		100,000			100,000
6.70% due 2019		300,000			300,000

		625,000			625,000

Pollution control bond series:
5.10% due 2023		13,343			13,463
Variable due 2027, 0.54% as of December 31, 2010; 0.64% as of December 31, 2009		21,940			21,940
5.30% due 2031		108,600			108,600
5.30% due 2031		18,900			18,900
Variable due 2032, 0.54% as of December 31, 2010; 0.64% as of December 31, 2009		14,500			14,500
Variable due 2032, 0.54% as of December 31, 2010; 0.64% as of December 31, 2009		10,000			10,000
4.85% due 2031		50,000			50,000
5.60% due 2031		50,000			50,000
6.00% due 2031		50,000			50,000
5.00% due 2031		50,000			50,000

		387,283			387,403

Total long-term debt		2,495,374			2,497,069

Unamortized debt discount (a)		(4,442	)		(4,990	)
Long-term debt due within one year		(61	)		(1,345	)

Long-term debt, net	$	2,490,871		$	2,490,734

Variable Interest Entities
7.77% due 2013 (b)	$	5,095		$	—
6.99% due 2014 (b)		3,237			—
5.92 % due 2019 (b)		31,171			—
5.647% due 2021 (b)		266,393			—

Total long-term debt of variable interest entities		305,896			—

Unamortized debt premium (a)		2,421			—
Long-term debt of variable interest entities due within one year		(30,155	)		—

Long-term debt of variable interest entities, net	$	278,162		$	—

(a)	We amortize debt discounts and premiums to interest expense over the term of the respective issues.

(b)	Portions of our payments related to this debt reduce the principal balances each year until maturity.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGE first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended in June 2009, is limited to a maximum of $3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2010, based on an assumed interest rate of 5.90%, approximately $817.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy's mortgage, except in connection with certain refundings. As of December 31, 2010, approximately $635.0 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in KGE's mortgage.

As of December 31, 2010, we had $121.9 million of variable rate, tax-exempt bonds. Interest rates payable under these bonds are normally set by auctions, which occur every 35 days. However, auctions for these bonds have failed over the past few years, resulting in volatile alternative index-based interest rates for these bonds. With the KCC's approval, on October 15, 2009, KGE refinanced $50.0 million of auction rate bonds at a fixed interest rate of 5.00% and a maturity date of June 1, 2031. We continue to monitor the credit markets and evaluate our options with respect to our remaining auction rate bonds.

On August 3, 2009, Westar Energy repaid $145.1 million principal amount of 7.125% unsecured senior notes with borrowings under Westar Energy's revolving credit facility.

On June 11, 2009, KGE issued $300.0 million principal amount of first mortgage bonds at a discount yielding 6.725%, bearing stated interest at 6.70% and maturing on June 15, 2019. KGE received net proceeds of $297.5 million.

Proceeds from the issuance of first mortgage bonds were used to repay borrowings under Westar Energy's revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes.

Debt Covenants

Some of our debt instruments contain restrictions that require us to maintain leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. We use these ratios solely to determine compliance with our various debt covenants. We were in compliance with these covenants as of December 31, 2010.

Maturities

The principal amounts of our long-term debt maturities as of December 31, 2010, are as follows.


	Long-term debt		Long-term debt of VIEs
Year	(In Thousands)
2011	$	61	$	30,155
2012		—		28,118
2013		—		25,941
2014		250,000		27,479
Thereafter		2,245,313		194,203

Total maturities	$	2,495,374	$	305,896

Interest expense on long-term debt was $144.1 million in 2010, $139.6 million in 2009 and $95.7 million in 2008. Interest expense on long-term debt of VIEs was $18.7 million in 2010.

Taxes

12 Months Ended

Dec. 31, 2010

Taxes

Taxes

10. TAXES

Income tax expense is composed of the following components.


	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Income Tax Expense (Benefit) from Continuing Operations:
Current income taxes:
Federal	$	(32,107	)	$	2,428		$	(16,484	)
State		(3,030	)		9,975			(14,841	)
Deferred income taxes:
Federal		102,568			46,148			35,818
State		20,305			3,003			2,147
Investment tax credit amortization		(2,704	)		(2,704	)		(2,704	)

Income tax expense from continuing operations	$	85,032		$	58,850		$	3,936


Income Tax Expense (Benefit) from Discontinued Operations:
Current income taxes:
Federal	$	—		$	(25,528	)	$	—
State		—			(10,418	)		—
Deferred income taxes:
Federal		—			(20,549	)		—

Income tax expense from discontinued operations	$	—		$	(56,495	)	$	—


Total income tax expense	$	85,032		$	2,355		$	3,936

Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows.


	As of December 31,
	2010		2009
	(In Thousands)

Current deferred tax assets	$	30,248	$	7,927

Non-current deferred tax liabilities		1,102,625		964,461


Net deferred tax liabilities	$	1,072,377	$	956,534

The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.


	As of December 31,
		2010		2009
		(In Thousands)
Deferred tax assets:
Deferred employee benefit costs	$	155,400	$	132,770
Business tax credit carryforwards (a)		134,629		101,347
Deferred gain on sale-leaseback		45,381		47,800
Deferred compensation		40,401		38,198
Accrued liabilities		35,714		35,230
Alternative minimum tax carryforward (b)		34,270		18,406
Deferred state income taxes		14,215		26,093
Disallowed costs		13,357		14,000
Long-term energy contracts		3,720		5,874
Capital loss carryforward (c)		3,527		6,075
Other		29,857		15,161

Total gross deferred tax assets		510,471		440,954
Less: Valuation allowance (c)		59,415		9,710

Deferred tax assets	$	451,056	$	431,244


Deferred tax liabilities:
Accelerated depreciation	$	931,898	$	789,850
Acquisition premium		195,947		203,959
Deferred employee benefit costs		161,035		141,974
Amounts due from customers for future income taxes, net		152,877		165,975
Debt reacquisition costs		23,864		26,046
Deferred state income taxes		16,577		24,882
Storm costs		13,733		22,160
Other		27,502		12,932

Total deferred tax liabilities	$	1,523,433	$	1,387,778


Net deferred tax liabilities	$	1,072,377	$	956,534

(a)

As of December 31, 2010, we had available federal general business tax credits of $18.4 million and state investment tax credits of $116.2 million. The federal general business tax credits were primarily generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These tax credits expire beginning in 2019 and ending in 2025. We believe these tax credits will be fully utilized prior to expiration. The state investment tax credits expire beginning in 2013 and ending in 2019. As we do not expect to realize sufficient state taxable income in the future, a valuation allowance of $51.9 million has been established against the unused credits which have been deferred pursuant to regulatory treatment.

(b)

As of December 31, 2010, we had available alternative minimum tax credit carryforwards of $34.3 million. These tax credits have an unlimited carryforward period.

(c)

As of December 31, 2010, we had a net capital loss of $8.9 million that is available to offset future capital gains. The net capital loss will expire in 2014. As we do not expect to realize any significant capital gains in the future, a valuation allowance of $3.5 million has been established. In addition, a valuation allowance of $4.0 million has been established for certain deferred tax assets related to the write-down of other investments. We also established a valuation allowance of $51.9 million as described in (a) above. The total valuation allowance related to the deferred tax assets was $59.4 million as of December 31, 2010, and $9.7 million as of December 31, 2009.

In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.

Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.


	For the Year Ended December 31,
	2010			2009			2008


Statutory federal income tax rate from continuing operations		35.0	%		35.0	%		35.0	%
Effect of:
Corporate-owned life insurance policies		(6.1	)		(8.2	)		(9.1	)
State income taxes		3.8			4.3			(4.5	)
Production tax credits		(3.4	)		(3.0	)		—
Accelerated depreciation flow through and amortization		2.6			3.7			2.3
Amortization of federal investment tax credits		(0.9	)		(1.4	)		(1.5	)
Capital loss utilization		(0.7	)		(0.4	)		—
AFUDC equity		(0.4	)		(0.9	)		(3.5	)
Liability for unrecognized income tax benefits		(0.2	)		0.2			(15.4	)
Other		(0.7	)		0.1			(1.1	)

Effective income tax rate from continuing operations		29.0	%		29.4	%		2.2	%

We file income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service (IRS) or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities remains open for tax year 2007 and forward with tax year 2009 currently under examination by the IRS.

In November 2010, the IRS commenced an examination of our federal income tax return for tax year 2009. Also in 2010, the IRS commenced and substantially concluded its examination of the federal income tax return we filed for tax year 2008 without significant changes.

In November 2009, the IRS completed its examination of the federal income tax return and the amended federal income tax returns we filed for tax years 1999, 2005, 2006 and 2007. The examination resulted in a tax refund of $34.9 million. The examination results were approved by the Joint Committee on Taxation of the U.S. Congress and accepted by the IRS in April 2010.

In January 2009, we reached a settlement with the 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.

In February 2008, we reached a settlement with the IRS for tax years 1995 through 2002 on issues related principally to the method used to capitalize overheads to electric plant. This settlement resulted in a 2008 net earnings benefit of approximately $39.4 million, including interest, due to the recognition of previously unrecognized income tax benefits.

The amount of unrecognized income tax benefits decreased from $8.4 million at December 31, 2009, to $1.9 million at December 31, 2010. The net decrease in unrecognized income tax benefits for which a liability was not recorded was largely attributable to the reversal of $8.2 million of tax positions due to the completion of the IRS audits and the expiration of the statute of limitation. We do not expect significant changes in the liability for unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows:


	2010			2009			2008
	(In Thousands)
Liability for unrecognized income tax benefits at January 1	$	8,357		$	38,980		$	70,833
Additions based on tax positions related to the current year		608			2,254			4,576
Additions for tax positions of prior years		2,323			—			—
Reductions for tax positions of prior years		(1,241	)		(25,722	)		(3,639	)
Settlements		(8,159	)		(7,155	)		(32,790	)

Liability for unrecognized income tax benefits at December 31		1,888			8,357			38,980
Unrecognized income tax benefits related to amended returns filed in 2007		—			—			53,092

Unrecognized income tax benefits at December 31	$	1,888		$	8,357		$	92,072

The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $1.3 million, $2.1 million and $54.8 million (net of tax) as of December 31, 2010, 2009 and 2008, respectively. Included in the liability for unrecognized income tax benefits balances was $1.3 million, $2.1 million and $1.7 million (net of tax) of tax positions, which if recognized, would favorably impact our effective income tax rates as of December 31, 2010, 2009 and 2008, respectively.

Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. During 2010, 2009 and 2008, we reversed interest expense previously recorded for income tax uncertainties of $1.0 million, $2.4 million and $15.9 million, respectively. As of December 31, 2010 and 2009, we had $0.4 million and $1.4 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. We accrued no tax related penalties at either December 31, 2010, or December 31, 2009.

As of December 31, 2010 and 2009, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2010

Employee Benefit Plans

Employee Benefit Plans

11. EMPLOYEE BENEFIT PLANS

Pension and Other Post-Retirement Benefit Plans

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee's compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain current and retired executive officers. With the exception of one current executive officer, we have discontinued accruing any future benefits under this non-qualified plan.

In accordance with a 2009 KCC order, we expect to fund our pension plan each year at least to a level equal to our current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act (ERISA), as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee's years of service. We fund the portion of net periodic costs for other post-retirement benefits included in our prices.

The following tables summarize the status of our pension and other post-retirement benefit plans.


	Pension Benefits						Post-retirement Benefits
As of December 31,	2010			2009			2010			2009
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	662,495		$	629,238		$	128,998		$	133,881
Service cost		13,926			12,882			1,526			1,529
Interest cost		39,391			38,162			7,083			6,917
Plan participants' contributions		—			—			3,292			3,098
Benefits paid		(29,690	)		(28,526	)		(11,090	)		(9,960	)
Actuarial losses (gains)		60,662			10,692			7,950			(13,063	)
Amendments		676			47			—			6,596

Benefit obligation, end of year	$	747,460		$	662,495		$	137,759		$	128,998


Change in Plan Assets:
Fair value of plan assets, beginning of year	$	404,243		$	310,531		$	74,114		$	52,804
Actual return on plan assets		33,359			83,128			9,849			17,898
Employer contributions		22,400			37,304			10,512			9,951
Plan participants' contributions		—			—			3,147			2,953
Part D Reimbursements		—			—			317			589
Benefits paid		(27,769	)		(26,720	)		(10,955	)		(10,081	)

Fair value of plan assets, end of year	$	432,233		$	404,243		$	86,984		$	74,114


Funded status, end of year	$	(315,227	)	$	(258,252	)	$	(50,775	)	$	(54,884	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,030	)	$	(1,984	)	$	(91	)	$	(121	)
Noncurrent liability		(313,197	)		(256,268	)		(50,684	)		(54,763	)

Net amount recognized	$	(315,227	)	$	(258,252	)	$	(50,775	)	$	(54,884	)


Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss	$	323,924		$	275,417		$	8,458		$	5,481
Prior service cost		5,819			7,872			17,065			19,219
Transition obligation		—			—			8,148			12,060

Net amount recognized	$	329,743		$	283,289		$	33,671		$	36,760



	Pension Benefits						Post-retirement Benefits
As of December 31,	2010			2009			2010			2009
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	747,460		$	662,495		$	—		$	—
Fair value of plan assets		432,233			404,243			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	635,541		$	559,021			—			—
Fair value of plan assets		432,233			404,243			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	137,759		$	128,998

Fair value of plan assets		—			—			86,984			74,114

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate		5.35	%		5.95	%		5.00	%		5.65	%
Compensation rate increase		4.00	%		4.00	%		—			—

We use a measurement date of December 31 for our pension and other post-retirement benefit plans. In addition, we use an interest rate yield curve that is constructed based on the yields of over 500 high-quality, non-callable corporate bonds with maturities between zero and 30 years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of our pension plan and develop a single-point discount rate matching the plan's payout structure.

We amortize prior service cost (benefit) on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor.


	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2010			2009			2008			2010			2009			2008
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	13,926		$	12,882		$	10,102		$	1,526		$	1,529		$	1,446
Interest cost		39,391			38,162			35,792			7,083			6,917			7,637
Expected return on plan assets		(38,384	)		(37,826	)		(40,332	)		(5,197	)		(4,756	)		(4,694	)
Amortization of unrecognized:
Transition obligation, net		—			—			—			3,912			3,912			3,930
Prior service costs		2,729			2,668			2,550			2,154			1,580			1,412
Actuarial loss/(gain), net		17,183			14,263			8,415			321			(38	)		904

Net periodic cost before regulatory adjustment		34,845			30,149			16,527			9,799			9,144			10,635
Regulatory adjustment		(12,167	)		(9,188	)		—			1,868			2,280			—

Net periodic cost	$	22,678		$	20,961		$	16,527		$	11,667		$	11,424		$	10,635


Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain)/loss	$	65,690		$	(34,610	)	$	218,444		$	3,298		$	(26,205	)	$	12,915
Amortization of actuarial (loss)/gain		(17,183	)		(14,263	)		(8,415	)		(321	)		38			(904	)
Current year prior service cost		676			48			1,461			—			6,672			2,681
Amortization of prior service costs		(2,729	)		(2,668	)		(2,550	)		(2,154	)		(1,580	)		(1,412	)
Current year offset of Initial Transition Asset due to plan change		—			—			—			—			(76	)		—
Amortization of transition obligation		—			—			—			(3,912	)		(3,912	)		(3,930	)

Total recognized in regulatory assets	$	46,454		$	(51,493	)	$	208,940		$	(3,089	)	$	(25,063	)	$	9,350


Total recognized in net periodic cost and regulatory assets	$	69,132		$	(30,532	)	$	225,467		$	8,578		$	(13,639	)	$	19,985


Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate		5.95	%		6.10	%		6.25	%		5.65	%		6.05	%		6.10	%
Expected long-term return on plan assets		8.25	%		8.25	%		8.50	%		7.75	%		7.75	%		7.75	%
Compensation rate increase		4.00	%		4.00	%		4.00	%		—			—			—

The estimated amounts that will be amortized from regulatory assets into net periodic cost in 2011 are as follows:


	Pension Benefits		Post- retirement Benefits
	(In Thousands)
Actuarial loss	$	23,967	$	1,016
Prior service cost		1,213		2,156
Transition obligation		—		3,912

Total	$	25,180	$	7,084

We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

The Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act) introduced a prescription drug benefit under Medicare as well as a federal subsidy that will be paid to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. We believe our retiree health care benefit plan is at least actuarially equivalent to Medicare and is, thus, eligible for the federal subsidy. However, due to plan changes effective January 1, 2010, we are no longer entitled to the federal subsidy. As a result, the subsidy did not have an effect on our accumulated post-retirement benefit obligation in 2010 or 2009 and did not impact our net period post-retirement benefit cost in 2010. For 2008, treating the future subsidy under the Medicare Act as an actuarial experience gain, as required by the guidance, decreased the accumulated post-retirement benefit obligation by approximately $4.0 million. The subsidy also decreased net periodic post-retirement benefit cost by approximately $1.9 million in 2009 and $0.5 million in 2008.

For measurement purposes, the assumed annual health care cost growth rates were as follows.


	As of December 31,
	2010	2009

Health care cost trend rate assumed for next year	8.0%	8.0%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0%	5.0%

Year that the rate reaches the ultimate trend rate	2018	2018

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.


	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(In Thousands)

Effect on total of service and interest cost	$	33	$	(30	)
Effect on post-retirement benefit obligation		455		(490	)

Plan Assets

We manage pension and other post-retirement benefit plan assets in accordance with the prudent investor guidelines contained in the ERISA. The plans' investment strategies support the objectives of the funds, which are to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. We delegate the management of our funds to an independent investment advisor who hires and dismisses investment managers in various asset classes based upon performance. The investment advisor strives to diversify investments across classes, sectors and manager style to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. Prohibited investments include loans to the company or its officers and directors as well as investments in the company's debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, we have established restrictions to reduce concentration of risk. For example, for domestic investments, no more than 5% of pension plan assets and 5% of post-retirement benefit plan assets should be invested in the securities of a single issuer, with the exception of the U.S. government and its agencies. In addition, the fund will neither acquire more than 10% of any one issuer nor acquire more than 25% of any single industry. These restrictions do not apply to the purchase of United States Government securities. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

The target allocations for our pension plan assets are about 35% to equity securities, 54% to debt securities and the remaining 11% to other investments such as real estate securities, hedge funds and private equity investments. Our investments in equity securities include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings and private equity investments. Our investments in debt securities include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities include funds invested in commercial and residential real estate properties throughout the U.S. while hedge funds include investments in a number of underlying hedge funds with wide ranging investments, including equity securities of domestic and foreign corporations, U.S. and foreign governments and their agencies, warrants, exchange-traded funds, derivative instruments and private investment funds.

The target allocations for our other post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities. Our investments in equity securities include investments in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of corporate entities, obligations of the U.S. government and its agencies, and cash and cash equivalents.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and other post-retirement benefit plan assets at fair value. See Note 4, "Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management," for a description of the hierarchal framework.

In 2010, we changed our investment advisor for pension assets. As a result, we also changed our investment mix in an attempt to limit the volatility in our benefit obligation. 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 pension investments are held in investment funds that are measured using daily net asset values as reported by the fund managers.

We maintain certain level 3 investments in private equity, high-yield bonds, real estate securities and hedge funds 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. Fair value of Level 3 debt instruments are measured 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. Hedge funds are measured at fair value using net asset values as reported by the underlying hedge fund managers.

The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2010 and 2009.


As of December 31, 2010	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity	$	—	$	117,250	$	11,575	$	128,825
International equity		—		44,834		—		44,834
Core bonds		—		183,361		—		183,361
High-yield bonds		—		28,819		1,200		30,019
Real estate securities		—		—		16,411		16,411
Hedge funds		—		—		25,764		25,764
Cash equivalents		—		3,019		—		3,019

Total Assets Measured at Fair Value	$	—	$	377,283	$	54,950	$	432,233


As of December 31, 2009
Assets:
Domestic equity	$	117,862	$	20,663	$	9,310	$	147,835
International equity		49,122		51,583		—		100,705
Core bonds		—		72,038		—		72,038
High-yield bonds		—		19,055		22,519		41,574
Real estate securities		—		—		14,518		14,518
Commodities		—		20,719		—		20,719
Cash equivalents		—		6,854		—		6,854

Total Assets Measured at Fair Value	$	166,984	$	190,912	$	46,347	$	404,243

The following table provides a reconciliation of pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2010 and 2009.


	Domestic Equity			High-yield Bonds			Real Estate Securities			Hedge Funds		Net Balance
	(In Thousands)
Balance as of December 31, 2009	$	9,310		$	22,519		$	14,518		$	—	$	46,347
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		75			(3,963	)		2,117			864		(907	)
Relating to assets sold during the period		—			4,325			(77	)		—		4,248
Purchases, issuances and settlements		2,190			(21,681	)		(147	)		24,900		5,262

Balance as of December 31, 2010	$	11,575		$	1,200		$	16,411		$	25,764	$	54,950

Balance as of January 1, 2009	$	8,422		$	16,993		$	19,985		$	—	$	45,400
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		(132	)		4,991			(5,643	)		—		(784	)
Relating to assets sold during the period		—			535			176			—		711
Purchases, issuances and settlements		1,020			—			—			—		1,020

Balance as of December 31, 2009	$	9,310		$	22,519		$	14,518		$	—	$	46,347

The following table provides the fair value of our other post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2010 and 2009.


As of December 31, 2010	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity	$	—	$	45,766	$	—	$	45,766
International equity		—		11,280		—		11,280
Core bonds		—		29,938		—		29,938

Total Assets Measured at Fair Value	$	—	$	86,984	$	—	$	86,984

As of December 31, 2009
Assets:
Domestic equity	$	—	$	38,648	$	—	$	38,648
International equity		—		9,674		—		9,674
Core bonds		—		25,792		—		25,792

Total Assets Measured at Fair Value	$	—	$	74,114	$	—	$	74,114

Cash Flows

The following table shows the expected cash flows for our pension and other post-retirement benefit plans for future years.


Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			To/(From) Company Assets			To/(From) Trust			To/(From) Company Assets
	(In Millions)
Expected contributions: 2011	$	49.3		$	2.0		$	10.9		$	0.1

Expected benefit payments:
2011	$	(28.0	)	$	(2.0	)	$	(8.4	)	$	(0.1	)
2012		(29.2	)		(2.0	)		(8.6	)		(0.1	)
2013		(31.0	)		(2.0	)		(9.0	)		(0.1	)
2014		(33.0	)		(2.1	)		(9.5	)		(0.1	)
2015		(35.1	)		(2.1	)		(9.9	)		(0.1	)
2016 – 2020		(217.7	)		(10.0	)		(52.1	)		(0.5	)

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees' contributions in cash up to specified maximum limits. Our contributions to the plans are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $7.4 million in 2010, $6.5 million in 2009 and $6.1 million in 2008.

Stock-Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to five million shares of common stock may be granted under the LTISA Plan. As of December 31, 2010, awards of 4,805,179 shares of common stock had been made under the plan.

All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to ten years. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.


	Year Ended December 31,
	2010		2009		2008
	(In Thousands)
Compensation expense	$	11,321	$	5,080	$	4,619
Income tax benefits related to stock-based compensation arrangements		4,481		2,011		1,830

We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested. There were no modifications of awards during the years ended December 31, 2010, 2009 or 2008.

RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the date of grant. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy's common stock, are paid on these RSUs awarded during the vesting period.

RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2010 valuation, inputs for expected volatility and risk-free interest rates ranged from 25.2% to 30.1% and 0.3% to 1.4%, respectively. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.

During the years ended December 31, 2010, 2009 and 2008, our RSU activity for awards with only service requirements was as follows:


	As of December 31,
	2010					2009					2008
	Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year		368.8		$	21.98		727.4		$	20.86		984.2		$	23.11
Granted		366.4			22.14		83.5			18.33		38.7			25.46
Vested		(118.1	)		24.81		(439.0	)		19.43		(261.3	)		28.11
Forfeited		(16.7	)		22.32		(3.1	)		20.63		(34.2	)		35.49

Nonvested balance, end of year		600.4			21.50		368.8			21.98		727.4			20.86

Total unrecognized compensation cost related to RSU awards with only service requirements was $4.8 million as of December 31, 2010. We expect to recognize these costs over a remaining weighted-average period of 1.9 years. The total fair value of RSUs vested and distributed during the years ended December 31, 2010, 2009 and 2008, was $2.7 million, $8.8 million and $6.2 million, respectively.

During the years ended December 31, 2010, 2009 and 2008, our RSU activity for awards with performance measures was as follows:


	As of December 31,
	2010					2009				2008
	Shares			Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year		—		$	—		—	$	—		—	$	—
Granted		366.0			24.96		—		—		—		—
Vested		(4.5	)		23.32		—		—		—		—
Forfeited		(13.1	)		24.99		—		—		—		—

Nonvested balance, end of year		348.4			24.98		—		—		—		—

Total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million as of December 31, 2010. We expect to recognize these costs over a remaining weighted-average period of 1.6 years. There were no RSUs vested and distributed during the years ended December 31, 2010, 2009 and 2008.

RSU awards that can be settled in cash upon a change in control are classified as temporary equity. As of December 31, 2010 and 2009, we had temporary equity of $3.5 million and $3.4 million, respectively, on our consolidated balance sheets. If we determine that it is probable that these awards will be settled in cash, the awards will be reclassified as a liability.

Stock options granted between 1998 and 2001 are completely vested and have expired. There were no options exercised and all remaining options were forfeited during the year ended December 31, 2010. We currently have no plans to issue new stock option awards.

Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 6,627 shares of common stock for dividends in 2010, 7,106 shares in 2009 and 5,283 shares in 2008. Participants received common stock distributions of 1,198 shares in 2010, 563 shares in 2009 and 530 shares in 2008.

Income tax benefits resulting from the income tax deductions in excess of the related compensation cost recognized in the financial statements is classified as cash flows from financing activities in the consolidated statements of cash flows.

- 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 Employee Benefit Plans

12 Months Ended

Dec. 31, 2010

Wolf Creek Employee Benefit Plans

Wolf Creek Employee Benefit Plans

12. WOLF CREEK EMPLOYEE BENEFIT PLANS

Pension and Other Post-retirement Benefit Plans

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and other post-retirement benefit plans. KGE accrues its 47% share of Wolf Creek's cost of pension and other post-retirement benefits during the years an employee provides service. The following tables summarize the net periodic costs for KGE's 47% share of the Wolf Creek pension and other post-retirement benefit plans.


	Pension Benefits						Post-retirement Benefits
As of December 31,	2010			2009			2010			2009
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	111,033		$	99,536		$	9,574		$	8,852
Service cost		4,144			3,643			179			188
Interest cost		6,941			6,401			519			538
Plan participants' contributions		—			—			554			439
Benefits paid		(2,799	)		(2,273	)		(1,045	)		(1,151	)
Actuarial losses		12,141			3,726			363			708

Benefit obligation, end of year	$	131,460		$	111,033		$	10,144		$	9,574


Change in Plan Assets:
Fair value of plan assets, beginning of year	$	62,516		$	45,201		$	—		$	—
Actual return on plan assets		10,082			12,109			—			—
Employer contribution		6,044			7,310			—			—
Benefits paid		(2,556	)		(2,104	)		—			—

Fair value of plan assets, end of year	$	76,086		$	62,516		$	—		$	—


Funded status, end of year	$	(55,374	)	$	(48,517	)	$	(10,144	)	$	(9,574	)


Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(256	)	$	(253	)	$	(689	)	$	(674	)
Noncurrent liability		(55,118	)		(48,264	)		(9,455	)		(8,900	)

Net amount recognized	$	(55,374	)	$	(48,517	)	$	(10,144	)	$	(9,574	)


Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss	$	39,735		$	34,857		$	3,796		$	3,709
Prior service cost		47			76			—			—
Transition obligation		52			109			115			173

Net amount recognized	$	39,834		$	35,042		$	3,911		$	3,882


	Pension Benefits						Post-retirement Benefits
As of December 31,	2010			2009			2010			2009
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	131,460		$	111,033		$	—		$	—
Fair value of plan assets		76,086			62,516			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	106,684		$	90,157			—			—
Fair value of plan assets		76,086			62,516			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	10,144		$	9,574

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate		5.45	%		6.05	%		4.90	%		5.50	%
Compensation rate increase		4.00	%		4.00	%		—			—

Wolf Creek uses a measurement date of December 31 for its pension and other post-retirement benefit plans. In addition, Wolf Creek uses an interest rate yield curve that is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and 30 years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of Wolf Creek's pension plan and develop a single-point discount rate matching the plan's payout structure.

The prior service cost is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor.


	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2010			2009			2008			2010			2009			2008
	(Dollars in Thousands)
Components of Net Periodic Cost:
Service cost	$	4,144		$	3,643		$	3,421		$	179		$	188		$	203
Interest cost		6,941			6,401			5,680			519			538			517
Expected return on plan assets		(5,453	)		(4,976	)		(4,709	)		—			—			—
Amortization of unrecognized: Transition obligation, net		57			57			57			58			58			58
Prior service costs		29			43			57			—			—			—
Actuarial loss, net		2,636			2,538			1,696			276			257			231

Net periodic cost before regulatory adjustment		8,354			7,706			6,202			1,032			1,041			1,009
Regulatory adjustment		(1,498	)		(945	)		—			—			—			—

Net periodic cost	$	6,856		$	6,761		$	6,202		$	1,032		$	1,041		$	1,009


Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain)/loss	$	7,514		$	(3,407	)	$	21,517		$	363		$	708		$	362
Amortization of actuarial loss		(2,636	)		(2,538	)		(1,696	)		(276	)		(257	)		(231	)
Amortization of prior service cost		(29	)		(43	)		(57	)		—			—			—
Amortization of transition obligation		(57	)		(57	)		(57	)		(58	)		(58	)		(58	)

Total recognized in regulatory assets	$	4,792		$	(6,045	)	$	19,707		$	29		$	393		$	73


Total recognized in net periodic cost and regulatory assets	$	11,648		$	716		$	25,909		$	1,061		$	1,434		$	1,082


Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate		6.05	%		6.15	%		6.15	%		5.50	%		6.05	%		6.05	%
Expected long-term return on plan assets		8.00	%		8.00	%		8.25	%		—			—			—
Compensation rate increase		4.00	%		4.00	%		4.00	%		—			—			—

We estimate that we will amortize the following amounts from regulatory assets into net periodic cost in 2011.


	Pension Benefits		Other Post-retirement Benefits
	(In Thousands)
Actuarial loss	$	3,664	$	281
Prior service cost		16		—
Transition obligation		52		58

Total	$	3,732	$	339

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

For measurement purposes, we assumed annual health care cost growth rates were as follows.


	As of December 31,
	2010		2009
Health care cost trend rate assumed for next year		8.0%		8.0%

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		5.0%		5.0%

Year that the rate reaches the ultimate trend rate		2018		2018

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.


	One-Percentage- Point Increase			One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	(8	)	$	8
Effect on the present value of the projected benefit obligation		(85	)		79

Plan Assets

The Wolf Creek pension plan investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to maximize returns and minimize the risk of large losses. Wolf Creek delegates investment management to specialists in each asset class and, where appropriate, provides the investment managers with specific guidelines, which include allowable and/or prohibited investment types. Prohibited investments include investments in the equity or debt securities of the companies that collectively own Wolf Creek or companies that control such companies, which includes our and KGE securities. Wolf Creek has also established restrictions for certain classes of plan assets including that international equity securities should not exceed 25% of total plan assets, no more than 5% of the market value of the plan assets should be invested in the common stock of one corporation and the equity investment in any one corporation should not exceed 1% of its outstanding common stock. Wolf Creek does not utilize a separate investment trust for the purpose of funding other post-retirement benefits as it does for its pension plan.

The target allocations for Wolf Creek's pension plan assets are 22% to international equity securities, 43% to domestic equity securities, 25% to debt securities, 5% to real estate securities and 5% to commodity investments. The investments in both international and domestic equity securities include investments in large-, mid- and small-cap companies, private equity funds and investment funds with underlying investments similar to those previously mentioned. The investments in debt securities include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies, and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.

Wolf Creek's investments in equity, debt and commodity instruments are recorded at fair value using quoted market prices or valuation models utilizing observable market data when available. A portion of the investments is comprised of real estate securities that require significant unobservable market information to measure the fair value of the investments. Real estate securities are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and other post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement trusts may buy and sell investments resulting in changes within the hierarchy. See Note 4, "Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management," for a description of the hierarchal framework.

The following table provides the fair value of KGE's 47% share of Wolf Creek's pension plan assets and the corresponding level of hierarchy as of December 31, 2010 and 2009.


As of December 31, 2010	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity	$	31,492	$	—	$	—	$	31,492
International equity		9,036		9,597		—		18,633
Core bonds		—		14,156		—		14,156
High-yield bonds		3,319		—		—		3,319
Real estate securities		—		—		3,160		3,160
Commodities		—		4,558		—		4,558
Cash equivalents		1		767		—		768

Total Assets Measured at Fair Value	$	43,848	$	29,078	$	3,160	$	76,086


As of December 31, 2009

Assets:
Domestic equity	$	24,947	$	3,451	$	—	$	28,398
International equity		8,021		4,458		—		12,479
Core bonds		—		11,864		—		11,864
High-yield bonds		3,018		—		—		3,018
Real estate securities		—		—		2,416		2,416
Commodities		—		3,594		—		3,594
Cash equivalents		1		746		—		747

Total Assets Measured at Fair Value	$	35,987	$	24,113	$	2,416	$	62,516

The following table provides a reconciliation of KGE's 47% share of Wolf Creek's pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2010 and 2009.


	Real Estate Securities
	(In Thousands)
Balance as of December 31, 2009	$	2,416
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		393
Relating to assets sold during the period		(2	)
Purchases, issuances and settlements		353

Balance as of December 31, 2010	$	3,160

Balance as of January 1, 2009	$	—
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		(370	)
Relating to assets sold during the period		6
Purchases, issuances and settlements		2,780

Balance as of December 31, 2009	$	2,416

Cash Flows

The following table shows our expected cash flows for KGE's 47% share of Wolf Creek's pension and other post-retirement benefit plans for future years.


Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			To/(From) Company Assets			To/(From) Trust		To/(From) Company Assets
	(In Millions)
Expected contributions: 2011	$	11.0		$	0.2		$	—	$	0.7

Expected benefit payments:
2011	$	(2.7	)	$	(0.2	)	$	—	$	(0.7	)
2012		(3.1	)		(0.2	)		—		(0.7	)
2013		(3.7	)		(0.2	)		—		(0.8	)
2014		(4.2	)		(0.2	)		—		(0.8	)
2015		(4.9	)		(0.2	)		—		(0.8	)
2016 – 2020		(37.8	)		(1.1	)		—		(4.2	)

Savings Plan

Wolf Creek maintains a qualified 401(k) savings plan in which most of its employees participate. They match employees' contributions in cash up to specified maximum limits. Wolf Creek's contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. KGE's portion of the expense associated with Wolf Creek's matching contributions was $1.1 million in 2010, $1.1 million in 2009 and $1.0 million in 2008.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2010

Commitments and Contingencies

Commitments and Contingencies

13. COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel, which is discussed below under "– Purchased Power and Fuel Commitments," that had an unexpended balance of approximately $671.2 million as of December 31, 2010, of which $427.7 million had been committed. The $427.7 million of commitments relates to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2010, was as follows.


	Committed Amount
	(In Thousands)
2011	$	268,496
2012		76,169
2013		47,895
Thereafter		35,164

Total amount committed	$	427,724

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 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. A recent order of the KCC indicated that it may be more appropriate to recover environmental costs at La Cygne 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. Our anticipated capital expenditures at La Cygne for environmental equipment for 2011 through 2013 are $429.1 million.

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), 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.

Our environmental liability for remediation of former manufactured gas sites in Missouri 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 settled this liability.

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.

In January 2004, the EPA notified us that certain projects completed at JEC violated certain requirements of the New Source Review program. In February 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. The settlement requires that we 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 our customers. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In 2009, we recorded as part of the settlement $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and 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.

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant's license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the revised nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval by the KCC of a "funding schedule" prepared by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

The KCC approved Wolf Creek's most recent nuclear decommissioning site study in August 2009. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be $279.0 million. This amount compares to the prior site study estimate of $243.3 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially adversely affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $3.1 million in 2010 and $2.9 million in both 2009 and 2008. We record our investment in the NDT fund at fair value, which approximated $127.0 million as of December 31, 2010, and $112.3 million as of December 31, 2009.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. Our share of the fee, calculated as one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $4.0 million in 2010, $3.7 million in 2009 and $3.5 million in 2008. We include these costs in fuel and purchased power expense on our consolidated statements of income.

In March 2010, the DOE filed a motion to withdraw its application with the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada, which would end the licensing process. An NRC board denied the DOE's motion to withdraw its application in June 2010 and the DOE appealed that decision to the full NRC in early July 2010. The NRC has not yet decided that appeal. The question of the DOE's legal authority to withdraw its license application also is pending in multiple lawsuits filed with a federal appellate court. Oral argument to the court is set for late March 2011. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025 and believes it will be able to expand on-site storage as needed past 2025. We cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.

Nuclear Insurance

We maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear and war. The nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry no longer include industry aggregate limits for non-certified acts, as defined by the Terrorism Risk Insurance Act, of terrorism-related losses, including replacement power costs. An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), our insurance provider, exists for property claims, including accidental outage power costs, for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which has been reauthorized through December 31, 2025, by the Energy Policy Act of 2005, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently approximately $12.6 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million, and the remaining $12.2 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $117.5 million (our share is $55.2 million), payable at no more than $17.5 million (our share is $8.2 million) per incident per year per reactor. Both the total and yearly assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of our worker radiation claims insurance. The next scheduled inflation adjustment is scheduled for August 2013. In addition, Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property Insurance

The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion (our share is $1.3 billion). This insurance is provided by NEIL. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage, decontamination expenses or, if certain requirements are met, including nuclear decommissioning the plant, toward a shortfall in the NDT fund.

Accidental Nuclear Outage Insurance

The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $26.2 million (our share is $12.3 million).

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material adverse affect on our consolidated financial results.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various commitments to obtain nuclear fuel and we have entered into various commitments to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2010, our share of Wolf Creek's nuclear fuel commitments was approximately $45.3 million for uranium concentrates expiring in 2017, $6.9 million for conversion expiring in 2017, $116.6 million for enrichment expiring in 2024 and $44.7 million for fabrication expiring in 2024.

As of December 31, 2010, our coal and coal transportation contract commitments in 2010 dollars under the remaining terms of the contracts were approximately $1.5 billion. The two largest contracts expire in 2013 and 2020, with the remaining contracts expiring at various times through 2020.

As of December 31, 2010, our natural gas transportation contract commitments in 2010 dollars under the remaining terms of the contracts were approximately $179.8 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have purchase power agreements with the owners of two separate wind generation facilities located in Kansas with a combined capacity of 146 MW. The agreements expire in late 2028 and early 2029 and provide for our receipt and purchase of the energy produced at a fixed price per unit of output. We estimate that our annual cost for energy purchased from these wind generation facilities will be approximately $19.5 million.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2010

Asset Retirement Obligations

Asset Retirement Obligations

14. ASSET RETIREMENT OBLIGATIONS

Legal Liability

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (KGE's 47% share), retire our wind generating facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.

The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.


	As of December 31,
	2010			2009
	(In Thousands)
Beginning ARO	$	119,519		$	95,083
Liabilities incurred		—			1,289
Liabilities settled		(738	)		(1,922	)
Accretion expense		7,218			4,727
Increase in nuclear decommissioning ARO liability		—			20,342

Ending ARO	$	125,999		$	119,519

As discussed in Note 13, "Commitments and Contingencies – Nuclear Decommissioning," Wolf Creek filed a nuclear decommissioning study with the KCC in 2009. As a result of the study, we recorded a $20.3 million increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek.

Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We determined that our conditional AROs include the retirement of our wind generation facilities, disposal of asbestos insulating material at our power plants, the remediation of ash disposal ponds and the disposal of PCB-contaminated oil.

We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our wind generation facilities was determined based upon the date each wind generation facility was placed into service.

The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the "National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule."

We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. The ash landfills retirement obligation was determined based upon the date each landfill was originally placed in service.

PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.

Non-Legal Liability – Cost of Removal

We recover in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2010 and 2009, we had $70.3 million and $68.1 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

Legal Proceedings	12 Months Ended
Legal Proceedings	Dec. 31, 2010
Legal Proceedings
Legal Proceedings	15. 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 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. 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 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. We have reclassified about $54.0 million, comprised of various elements of compensation, from other long-term liabilities to other current liabilities on our consolidated balance sheet. We intend to vigorously defend against the counterclaims they filed in the arbitration. 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 also Note 3, "Rate Matters and Regulation," and Note 13, "Commitments and Contingencies."

Common and Preferred Stock

12 Months Ended

Dec. 31, 2010

Common and Preferred Stock

Common and Preferred Stock

16. COMMON AND PREFERRED STOCK

Activity in Westar Energy's stock accounts for each of the three years ended December 31 is as follows:


	Cumulative preferred stock shares		Common stock shares
Balance at December 31, 2007		214,363		95,463,180

Issuance of common stock		—		12,847,955

Balance at December 31, 2008		214,363		108,311,135

Issuance of common stock		—		760,865

Balance at December 31, 2009		214,363		109,072,000

Issuance of common stock		—		3,056,068

Balance at December 31, 2010		214,363		112,128,068

Westar Energy's articles of incorporation, as amended, provide for 150,000,000 authorized shares of common stock. As of December 31, 2010, we had 112,128,068 shares issued and outstanding.

Westar Energy has a direct stock purchase plan (DSPP). Shares sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2010, 2009 and 2008, Westar Energy issued 734,918 shares, 760,865 shares and 592,772 shares, respectively, through the DSPP and other stock-based plans operated under the 1996 LTISA Plan. As of December 31, 2010 and 2009, a total of 2,590,942 shares and 3,196,816 shares, respectively, were available under the DSPP registration statement.

Common Stock Issuance

Through a Sales Agency Financing Agreement entered into with a broker dealer subsidiary of a bank in 2007, Westar Energy sold 1.2 million shares of common stock for $25.0 million in 2010 and 1.1 million shares of common stock for $26.9 million in 2008. Westar Energy did not sell any shares of common stock under this agreement during 2009.

During 2010, Westar Energy entered into two separate forward sale agreements with banks. The use of a forward sale agreement allows Westar Energy the means to minimize equity market uncertainty by pricing a common stock offering under then existing market conditions while mitigating share dilution by postponing the issuance of common stock until funds are needed. Westar Energy is also better able to 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 agreements have no initial fair value. Westar Energy will not receive any proceeds from the sale of common stock under the forward sale agreements until transactions are settled. Upon settlement, Westar Energy will record the forward sale agreements 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 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. The shares under the forward sale agreements were initially priced when the agreements were entered into and are subject to certain fixed pricing adjustments during the term of the agreements. Accordingly, assuming physical share settlement, Westar's net proceeds from the forward sale transactions will represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurs.

Westar Energy entered into one such forward sale agreement on November 4, 2010. Under the terms of the agreement, the bank, as forward seller, borrowed 7.5 million shares of Westar Energy's common stock from third parties and sold them to a group of underwriters for $25.54 per share. Under an over-allotment option included in the agreement, the underwriters purchased approximately 1.0 million additional shares on November 5, 2010, also for $25.54 per share, which increased the total number of shares under the forward sale agreement to approximately 8.5 million shares. The underwriters receive a commission equal to 3.5% of the sales price of all shares sold under the agreement. Westar Energy must settle the forward sale agreement within 18 months of the transaction date. Assuming physical share settlement of this agreement at December 31, 2010, Westar Energy would have received aggregate proceeds of approximately $206.2 million, net of commission, based on an average forward price of $24.32 per share.

On April 2, 2010, Westar Energy entered into a new, three-year Sales Agency Financing Agreement and forward sale agreement. 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. The broker dealer receives 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, and the bank will borrow shares of Westar Energy's common stock from third parties and sell them through its broker dealer. Westar Energy must settle the forward sale transactions within a year of the date each transaction is entered. As of December 31, 2010, Westar Energy had entered into forward sale transactions with respect to an aggregate of approximately 5.4 million shares of common stock. As partial settlement of the forward sale transactions, Westar Energy delivered approximately 0.5 million shares of common stock for proceeds of $10.4 million on October 14, 2010. On December 20, 2010, Westar Energy delivered approximately 0.7 million additional shares for proceeds of $16.0 million as partial settlement of the forward sale transactions. Assuming physical share settlement of the approximately 4.2 million remaining shares of common stock at December 31, 2010, Westar Energy would have received aggregate proceeds of approximately $94.0 million, net of commission, based on an average forward price of $22.16 per share.

On May 29, 2008, Westar Energy entered into an underwriting agreement relating to the offer and sale of 6.0 million shares of its common stock. On June 4, 2008, Westar Energy issued all 6.0 million shares and received $140.6 million in total proceeds, net of underwriting discounts and fees related to the offering.

In 2008, Westar Energy also completed a forward sale agreement entered into in November 2007 by delivering 5.1 million shares of common stock for proceeds of $123.0 million.

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.

Preferred Stock Not Subject to Mandatory Redemption

Westar Energy's cumulative preferred stock is redeemable in whole or in part on 30 to 60 days' notice at our option. The table below shows our redemption amount for all series of preferred stock not subject to mandatory redemption as of December 31, 2010.


Rate	Shares		Principal Outstanding		Call Price			Premium		Total Cost to Redeem
(Dollars in Thousands)
4.500%		121,613	$	12,161		108.0	%	$	973	$	13,134
4.250%		54,970		5,497		101.5	%		82		5,579
5.000%		37,780		3,778		102.0	%		76		3,854

			$	21,436				$	1,131	$	22,567

The provisions of Westar Energy's articles of incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on its common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. If the ratio of the capital represented by Westar Energy's common stock, including premiums on its capital stock and its surplus accounts, to its total capital and its surplus accounts at the end of the second month immediately preceding the date of the proposed payment of dividends, adjusted to reflect the proposed payment (capitalization ratio), will be less than 20%, then the payment of the dividends on its common stock, including the proposed payment, during the 12-month period ending with and including the date of the proposed payment shall not exceed 50% of its net income available for dividends for the 12-month period ending with and including the second month immediately preceding the date of the proposed payment. If the capitalization ratio is 20% or more but less than 25%, then the payment of dividends on its common stock, including the proposed payment, during the 12-month period ending with and including the date of the proposed payment shall not exceed 75% of its net income available for dividends for the 12-month period ending with and including the second month immediately preceding the date of the proposed payment. Except to the extent permitted above, no payment or other distribution may be made that would reduce the capitalization ratio to less than 25%. The capitalization ratio is determined based on the unconsolidated balance sheet for Westar Energy. As of December 31, 2010, the capitalization ratio was greater than 25%.

So long as there are any outstanding shares of Westar Energy preferred stock, Westar Energy shall not without the consent of a majority of the shares of preferred stock or if more than one-third of the outstanding shares of preferred stock vote negatively and without the consent of a percentage of any and all classes required by law and Westar Energy's articles of incorporation, declare or pay any dividends (other than stock dividends or dividends applied by the recipient to the purchase of additional shares) or make any other distribution upon common stock unless, immediately after such distribution or payment the sum of Westar Energy's capital represented by its outstanding common stock and its earned and any capital surplus shall not be less than $10.5 million plus an amount equal to twice the annual dividend requirement on all the then outstanding shares of preferred stock.

- 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

12 Months Ended

Dec. 31, 2010

Variable Interest Entities

Variable Interest Entities

17. 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 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 18, "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 December 31, 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 December 31, 2010	Dollar Amount
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	345,037
Regulatory assets (a)		3,963
Liabilities:
Current maturities of long-term debt of variable interest entities	$	30,155
Accrued interest (b)		5,064
Long-term debt of variable interest entities, net		278,162
(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

12 Months Ended

Dec. 31, 2010

Leases

Leases

18. LEASES

As discussed in Note 17, "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, future commitments under operating leases, minimum annual rental payments under capital leases and recorded capital lease assets have decreased significantly. 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. The rental expense and estimated future commitments under operating leases are as follows.


Year Ended December 31,	Total Operating Leases
	(In Thousands)
Rental expense:
2008	$	38,870
2009		38,096
2010		15,464

Future commitments:
2011	$	12,940
2012		14,192
2013		11,973
2014		9,996
2015		7,879
Thereafter		21,936

Total future commitments	$	78,916

Capital Leases

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

Assets recorded under capital leases are listed below.


	December 31,
	2010			2009
	(In Thousands)
Vehicles	$	12,504		$	18,991
Computer equipment and software		5,551			4,640
JEC 8% interest (a)		—			118,623
Accumulated amortization		(8,744	)		(21,736	)

Total capital leases	$	9,311		$	120,518

(a)

As discussed in Note 17, "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.

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.


Year Ended December 31,	Total Capital Leases
	(In Thousands)
2011	$	2,110
2012		2,213
2013		1,908
2014		1,792
2015		1,391
Thereafter		1,157

		10,571
Amounts representing imputed interest		(1,260	)

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

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

Discontinued Operations - Sale of Protection One, Inc.	12 Months Ended
Discontinued Operations - Sale of Protection One, Inc.	Dec. 31, 2010
Discontinued Operations - Sale of Protection One, Inc.
Discontinued Operations - Sale of Protection One, Inc.	19. DISCONTINUED OPERATIONS — Sale of Protection One, Inc. In January 2009, the Joint Committee on Taxation of the U.S. Congress approved a settlement with the IRS Office of Appeals regarding the re-characterization of a portion of the loss we incurred on the sale of Protection One, Inc. (Protection One), a former subsidiary, from a capital loss to an ordinary loss. The settlement involved a determination of the amount of the net capital loss and net operating loss carryforwards available as of December 31, 2004, to offset income in years after 2004. In March 2009, we filed amended federal income tax returns for years 2005, 2006 and 2007 to claim a portion of the income tax benefits from the net operating loss carryforward. We expect to realize the remainder of the income tax benefits from the net operating loss carryforward in future years. We recorded a non-cash net earnings benefit of approximately $33.7 million, net of $22.8 million we paid Protection One, in discontinued operations in 2009 in recognition of this settlement.

Quarterly Results (Unaudited)

12 Months Ended

Dec. 31, 2010

Quarterly Results (Unaudited)

Quarterly Results (Unaudited)

20. QUARTERLY RESULTS (UNAUDITED)

Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.


2010	First		Second		Third (a)		Fourth
	(In Thousands, Except Per Share Amounts)
Revenues (b)	$	459,830	$	495,181	$	644,437	$	456,723
Net income (b)		31,682		54,530		115,863		6,550
Net income attributable to common stock (b)		30,438		53,069		114,502		4,919

Per Share Data (b):

Basic:
Earnings available	$	0.27	$	0.47	$	1.02	$	0.04

Diluted:
Earnings available	$	0.27	$	0.47	$	1.01	$	0.04

Cash dividend declared per common share	$	0.31	$	0.31	$	0.31	$	0.31

Market price per common share:
High	$	22.78	$	23.93	$	24.64	$	25.90
Low	$	20.56	$	21.08	$	21.22	$	24.21
(a) In the third quarter of 2010, net income and net income attributable to common stock increased compared to the same period last year due principally to warmer than normal weather in our service territory paired with extremely cool weather during the third quarter of 2009. As measured by cooling degree days, the weather during the third quarter of 2010 was 63% warmer than the same period last year and 20% warmer than the 20-year average.
(b) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.


2009	First (a)		Second		Third		Fourth (a)
	(In Thousands, Except Per Share Amounts)
Revenues (b)	$	421,767	$	467,812	$	528,534	$	440,118
Net income (b)		44,164		38,386		81,142		11,384
Results of discontinued operations, net of tax		32,978		—		—		767

Net income attributable to common stock (b)		43,922		38,144		80,900		11,142

Per Share Data (b):

Basic:
Earnings available	$	0.40	$	0.35	$	0.73	$	0.10

Diluted:
Earnings available	$	0.40	$	0.35	$	0.73	$	0.10

Cash dividend declared per common share	$	0.30	$	0.30	$	0.30	$	0.30

Market price per common share:
High	$	21.10	$	19.32	$	21.56	$	22.30
Low	$	14.86	$	16.60	$	17.91	$	18.91
(a) In the first and fourth quarters of 2009, we recognized net earnings benefits from discontinued operations of approximately $33.0 million and $0.8 million, respectively, due to the re-characterization of a portion of the loss we incurred on the sale of Protection One, a former subsidiary, from a capital loss to an ordinary loss.
(b) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

- Definition

This element can be used to disclose the entire quarterly financial data disclosure in the annual financial statements as a single block of text. The disclosure includes a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income (loss) before extraordinary items and cumulative effect of a change in accounting principle and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished. Alternatively, the details of this disclosure can be reported using the elements in this group, or by using other taxonomy elements and applying the appropriate quarterly date and period contexts when creating an instance document. For example, the element for "Interest and Dividend Income, Operating" may be used by financial institutions from the Statement of Income, applying the appropriate quarterly date and period context when creating an instance document.

+ References+ Details

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2010

Schedule II - Valuation and Qualifying Accounts

Schedule II - Valuation and Qualifying Accounts

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (a)			Balance at End of Period
	(In Thousands)
Year ended December 31, 2008
Allowances deducted from assets for doubtful accounts	$	5,721	$	3,580	$	(4,491	)	$	4,810
Year ended December 31, 2009
Allowances deducted from assets for doubtful accounts	$	4,810	$	5,797	$	(5,376	)	$	5,231
Year ended December 31, 2010
Allowances deducted from assets for doubtful accounts	$	5,231	$	8,337	$	(7,839	)	$	5,729

(a)	Deductions are the result of write-offs of accounts receivable.