Edgar Filing: WESTAR ENERGY INC /KS

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)


Kansas		48-0290150
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300
(Address, including Zip Code and telephone number, including area code, of registrant’s principal executive offices)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one:

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.


Common Stock, par value $5.00 per share		111,390,861 shares
(Class)		(Outstanding at October 20, 2010)

TABLE OF CONTENTS


		Page
PART I. Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited)

	Consolidated Balance Sheets		6

	Consolidated Statements of Income		7

	Consolidated Statements of Cash Flows		9

	Consolidated Statements of Changes in Equity		10

	Notes to Condensed Consolidated Financial Statements		11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		46

Item 4.	Controls and Procedures		46

PART II. Other Information

Item 1.	Legal Proceedings		46

Item 1A.	Risk Factors		46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		46

Item 3.	Defaults Upon Senior Securities		47

Item 4.	Removed and Reserved		47

Item 5.	Other Information		47

Item 6.	Exhibits		47

Signature			48

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition
2009 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2009
AFUDC		Allowance for Funds Used During Construction
BACT		Best Available Control Technology
CATR		Clean Air Transport Rule
COLI		Corporate-owned life insurance
EPA		Environmental Protection Agency
EPS		Earnings per share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Investors Service
GAAP		Generally Accepted Accounting Principles
GHG		Greenhouse Gas
IRS		Internal Revenue Service
JEC		Jeffrey Energy Center
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
MMBtu		Millions of British Thermal Units
Moody’s		Moody’s Investors Service
MWh		Megawatt hours
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen Oxide
ONEOK		ONEOK, Inc.
OTC		Over-the-counter
PSD		Prevention of Significant Deterioration program
RECA		Retail Energy Cost Adjustment
RSUs		Restricted share units
S&P		Standard & Poor’s Ratings Group
SCR		Selective catalytic reduction
SPP		Southwest Power Pool
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Form 10-Q are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:

•

amount, type and timing of capital expenditures,

•

earnings,

•

cash flow,

•

liquidity and capital resources,

•

litigation,

•

accounting matters,

•

possible corporate restructurings, acquisitions and dispositions,

•

compliance with debt and other restrictive covenants,

•

interest rates and dividends,

•

environmental matters,

•

regulatory matters,

•

nuclear operations, and

•

the overall economy of our service area and its impact on our customers’ demand for electricity and their ability to pay for service.

What happens in each case could vary materially from what we expect because of such things as:

•

the risk of operating in a heavily regulated industry subject to frequent and uncertain political, legislative, judicial and regulatory developments at any level of government that can affect our revenues and costs,

•

weather conditions and their effect on sales of electricity as well as on prices of energy commodities,

•

equipment damage from storms and extreme weather,

•

economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy,

•

the impact of changes in market conditions on employee benefit liability calculations, as well as actual and assumed investment returns on invested plan assets,

•

the impact of changes in estimates regarding our Wolf Creek Generating Station (Wolf Creek) decommissioning obligation,

•

the ability of our counterparties to make payments as and when due and to perform as required,

•

the existence of or introduction of competition into markets in which we operate,

•

risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated,

•

cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business,

•

availability of generating capacity and the performance of our generating plants,

•

changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown or required modification of nuclear generating facilities,

•

uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal,

•

homeland and information security considerations,

•

wholesale electricity prices,

•

changes in accounting requirements and other accounting matters,

•

changes in the energy markets in which we participate resulting from the development and implementation of real time and next day trading markets, and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations and independent system operators,

•

reduced demand for coal-based energy because of climate impacts and development of alternate energy sources,

•

current and future litigation, regulatory investigations, proceedings or inquiries,

•

other circumstances affecting anticipated operations, electricity sales and costs, and

•

other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K), including in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other reports we file from time to time with the Securities and Exchange Commission.

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our 2009 Form 10-K. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in our 2009 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

PART I. FINANCIAL INFORMATION

ITEM 1.

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, except par values)

(Unaudited)


	September 30, 2010		December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,472	$	3,860
Accounts receivable, net of allowance for doubtful accounts of $4,245 and $5,231, respectively		260,404		216,186
Inventories and supplies, net		201,643		193,831
Energy marketing contracts		21,085		33,159
Taxes receivable		—		45,200
Deferred tax assets		7,458		7,927
Prepaid expenses		11,809		11,830
Regulatory assets		66,099		97,220
Other		12,802		20,269

Total Current Assets		585,772		629,482

PROPERTY, PLANT AND EQUIPMENT, NET		5,853,270		5,771,740

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET (See Note 12)		347,917		—

OTHER ASSETS:
Regulatory assets		730,391		758,538
Nuclear decommissioning trust		119,149		112,268
Energy marketing contracts		10,419		10,653
Other		222,041		242,802

Total Other Assets		1,082,000		1,124,261

TOTAL ASSETS	$	7,868,959	$	7,525,483

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	403	$	1,345
Current maturities of long-term debt of variable interest entities (See Note 12)		30,090		—
Short-term debt		163,040		242,760
Accounts payable		138,376		112,211
Accrued taxes		71,664		46,931
Energy marketing contracts		16,443		39,161
Accrued interest		66,328		76,955
Regulatory liabilities		31,424		39,745
Other		115,933		123,370

Total Current Liabilities		633,701		682,478

LONG-TERM LIABILITIES:
Long-term debt, net		2,490,734		2,490,734
Long-term debt of variable interest entities, net (See Note 12)		279,554		—
Obligation under capital leases		8,246		109,300
Deferred income taxes		1,012,410		964,461
Unamortized investment tax credits		153,942		127,777
Regulatory liabilities		136,967		100,963
Deferred regulatory gain from sale-leaseback		98,915		108,532
Accrued employee benefits		414,488		433,561
Asset retirement obligations		124,635		119,519
Energy marketing contracts		185		210
Other		104,246		117,720

Total Long-Term Liabilities		4,824,322		4,572,777

COMMITMENTS AND CONTINGENCIES (See Notes 7 and 8)
TEMPORARY EQUITY		3,459		3,443

EQUITY:
Westar Energy Shareholders’ Equity:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares		21,436		21,436
Common stock, par value $5 per share; authorized 150,000,000 shares; issued and outstanding 110,833,975 shares and 109,072,000 shares, respectively		554,170		545,360
Paid-in capital		1,373,297		1,339,790
Retained earnings		453,892		360,199

Total Westar Energy Shareholders’ Equity		2,402,795		2,266,785

Noncontrolling Interests		4,682		—

Total Equity		2,407,477		2,266,785

TOTAL LIABILITIES AND EQUITY	$	7,868,959	$	7,525,483

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended September 30,
	2010			2009
REVENUES	$	644,437		$	528,534

OPERATING EXPENSES:
Fuel and purchased power		187,877			141,470
Operating and maintenance		126,602			130,295
Depreciation and amortization		67,918			64,516
Selling, general and administrative		50,418			41,920

Total Operating Expenses		432,815			378,201

INCOME FROM OPERATIONS		211,622			150,333

OTHER INCOME (EXPENSE):
Investment earnings		3,248			3,986
Other income		1,897			1,217
Other expense		(5,146	)		(4,539	)

Total Other (Expense) Income		(1	)		664

Interest expense		43,956			41,599

INCOME FROM OPERATIONS BEFORE INCOME TAXES		167,665			109,398
Income tax expense		51,802			28,256

NET INCOME		115,863			81,142
Less: Net income attributable to noncontrolling interests		1,119			—

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		114,744			81,142
Preferred dividends		242			242

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	114,502		$	80,900

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Basic earnings per common share	$	1.02		$	0.73
Diluted earnings per common share	$	1.01		$	0.73
Average equivalent common shares outstanding		111,706,541			109,753,036
DIVIDENDS DECLARED PER COMMON SHARE	$	0.31		$	0.30
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	$	114,744		$	81,142

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Nine Months Ended September 30,
	2010			2009
REVENUES	$	1,599,448		$	1,418,113

OPERATING EXPENSES:
Fuel and purchased power		458,793			402,622
Operating and maintenance		369,584			392,272
Depreciation and amortization		201,955			186,544
Selling, general and administrative		144,499			143,540

Total Operating Expenses		1,174,831			1,124,978

INCOME FROM OPERATIONS		424,617			293,135

OTHER INCOME (EXPENSE):
Investment earnings		4,350			8,516
Other income		3,792			5,627
Other expense		(12,043	)		(11,441	)

Total Other (Expense) Income		(3,901	)		2,702

Interest expense		131,862			116,769

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		288,854			179,068
Income tax expense		86,780			48,354

INCOME FROM CONTINUING OPERATIONS		202,074			130,714
Results of discontinued operations, net of tax		—			32,978

NET INCOME		202,074			163,692
Less: Net income attributable to noncontrolling interests		3,338			—

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		198,736			163,692
Preferred dividends		727			727

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	198,009		$	162,965

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Basic earnings available from continuing operations	$	1.77		$	1.18
Discontinued operations, net of tax		—			0.30

Basic earnings per common share	$	1.77		$	1.48

Diluted earnings available from continuing operations	$	1.76		$	1.18
Discontinued operations, net of tax		—			0.30

Diluted earnings per common share	$	1.76		$	1.48

Average equivalent common shares outstanding		111,387,165			109,542,500
DIVIDENDS DECLARED PER COMMON SHARE	$	0.93		$	0.90
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	$	198,736		$	130,714
Results of discontinued operations, net of tax		—			32,978

Net income	$	198,736		$	163,692

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	202,074		$	163,692
Discontinued operations, net of tax		—			(32,978	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		201,955			186,544
Amortization of nuclear fuel		19,657			12,810
Amortization of deferred regulatory gain from sale-leaseback		(4,121	)		(4,121	)
Amortization of corporate-owned life insurance		15,286			15,746
Non-cash compensation		8,280			3,933
Net changes in energy marketing assets and liabilities		(947	)		6,256
Accrued liability to certain former officers		1,959			1,386
Net deferred income taxes and credits		104,133			59,663
Stock-based compensation excess tax benefits		(526	)		(359	)
Allowance for equity funds used during construction		(1,926	)		(4,064	)
Changes in working capital items, net of acquisitions and dispositions:
Accounts receivable		(44,207	)		(14,317	)
Inventories and supplies		(7,298	)		4,091
Prepaid expenses and other		23,843			(7,042	)
Accounts payable		12,965			(39,006	)
Accrued taxes		70,263			28,280
Other current liabilities		(84,095	)		74,511
Changes in other assets		25,984			24,485
Changes in other liabilities		(42,912	)		(71,469	)

Cash Flows from Operating Activities		500,367			408,041

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(369,746	)		(460,779	)
Investment in corporate-owned life insurance		(18,884	)		(17,724	)
Purchase of securities within the nuclear decommissioning trust fund		(189,784	)		(36,651	)
Sale of securities within the nuclear decommissioning trust fund		189,343			34,501
Proceeds from investment in corporate-owned life insurance		1,918			1,596
Other investing activities		(1,760	)		1,357

Cash Flows used in Investing Activities		(388,913	)		(477,700	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		(79,720	)		(7,668	)
Proceeds from long-term debt		—			297,507
Retirements of long-term debt		(1,353	)		(146,494	)
Retirements of long-term debt of variable interest entities		(27,536	)		—
Repayment of capital leases		(1,640	)		(9,682	)
Borrowings against cash surrender value of corporate-owned life insurance		72,286			8,530
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(3,219	)		(3,422	)
Stock-based compensation excess tax benefits		526			359
Issuance of common stock, net		28,299			3,279
Distributions to shareholders of noncontrolling interests		(2,094	)		—
Cash dividends paid		(96,391	)		(91,916	)

Cash Flows (used in) from Financing Activities		(110,842	)		50,493

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		612			(19,166	)
CASH AND CASH EQUIVALENTS:
Beginning of period		3,860			22,914

End of period	$	4,472		$	3,748

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)


	Westar Energy Shareholders
	Cumulative preferred stock		Common stock		Paid-in capital			Retained earnings			Noncontrolling interests			Total equity
Balance at December 31, 2008	$	21,436	$	541,556	$	1,326,391		$	318,197		$	—		$	2,207,580

Net income		—		—		—			163,692			—			163,692
Issuance of common stock, net		—		2,931		7,992			—			—			10,923
Preferred dividends		—		—		—			(727	)		—			(727	)
Dividends on common stock		—		—		—			(99,005	)		—			(99,005	)
Reclass to Temporary Equity		—		—		(17	)		—			—			(17	)
Amortization of restricted stock		—		—		3,380			—			—			3,380
Stock compensation and tax benefit		—		—		(1,845	)		—			—			(1,845	)

Balance at September 30, 2009	$	21,436	$	544,487	$	1,335,901		$	382,157		$	—		$	2,283,981

Balance at December 31, 2009	$	21,436	$	545,360	$	1,339,790		$	360,199		$	—		$	2,266,785

Consolidation of noncontrolling interests		—		—		—			—			3,435			3,435
Net income		—		—		—			198,736			3,338			202,074
Issuance of common stock, net		—		8,810		28,698			—			—			37,508
Preferred dividends		—		—		—			(727	)		—			(727	)
Dividends on common stock		—		—		—			(104,316	)		—			(104,316	)
Reclass to Temporary Equity		—		—		(16	)		—			—			(16	)
Amortization of restricted stock		—		—		7,667			—			—			7,667
Stock compensation and tax benefit		—		—		(2,842	)		—			—			(2,842	)
Distributions to shareholders of noncontrolling interests		—		—		—			—			(2,091	)		(2,091	)

Balance at September 30, 2010	$	21,436	$	554,170	$	1,373,297		$	453,892		$	4,682		$	2,407,477

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

WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 686,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. KGE owns a 47% interest in Wolf Creek, a nuclear power plant located near Burlington, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

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

Use of Management’s Estimates

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

Allowance for Funds Used During Construction

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


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

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

Average AFUDC Rates		2.7%		3.3%		2.4%		4.3%

Earnings Per Share

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

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

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


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

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

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

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

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

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

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

Supplemental Cash Flow Information


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


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

New Accounting Pronouncements

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

Consolidation Guidance for Variable Interest Entities

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

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

Values of Financial and Derivative Instruments

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

During the second quarter of 2010, we changed our investment advisor for the nuclear decommissioning trust (NDT). The transition resulted in the sale of all of our then existing level 1 and level 2 investments and the purchase of other level 2 investments. Level 2 investments, whether in the NDT or our trading securities portfolio, are held in investment funds that are measured using daily net asset values as reported by the fund managers.

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

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

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


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

Recurring Fair Value Measurements

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

•

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

•

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

•

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

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


	Level 1		Level 2		Level 3		Total
	(In Thousands)
As of September 30, 2010
Assets:
Energy Marketing Contracts	$	4,790	$	9,608	$	17,106	$	31,504
Nuclear Decommissioning Trust:
Domestic equity		—		54,551		2,447		56,998
International equity		—		17,760		—		17,760
Core bonds		—		32,027		—		32,027
High-yield bonds		—		9,120		305		9,425
Real estate securities		—		—		2,862		2,862
Cash equivalents		77		—		—		77

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

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

Total Trading Securities		—		36,772		—		36,772

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

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

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

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

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

Total Trading Securities		—		34,619		—		34,619

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

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

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

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


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

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


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

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

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

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

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

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


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

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


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

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

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

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

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


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

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


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

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

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

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


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

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


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

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

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

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

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


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

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

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

Total Trading Securities		36,772		—		34,619		—

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

(a)

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

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

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

Derivative Instruments

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

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

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


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

Total	$	31,504	Total	$	16,628

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


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

Total	$	43,812	Total	$	39,371

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


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

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

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

Net Quantity as of

Unit of Measure

September 30, 2010

December 31, 2009

Electricity

MWh

3,613,160

4,147,800

Natural Gas

MMBtu

2,095,000

648,000

Coal

Tons

750,000

3,500,000

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

Energy Marketing Activities

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

Price Risk

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

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

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

Credit Risk

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

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

4. FINANCIAL INVESTMENTS

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

Trading Securities

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

Available-for-Sale Securities

We hold investments in debt and equity securities in a trust fund for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of September 30, 2010, and December 31, 2009. At September 30, 2010, investments in the NDT fund were allocated 48% to domestic equity, 15% to international equity, 27% to core bonds, 8% to high-yield bonds, 2% to real estate securities and less than one percent to cash equivalents. The core bond fund is limited to ensure that at least 80% of funds are invested in investment grade U.S. corporate and government fixed income securities, including mortgage-backed securities. As of September 30, 2010, the fair value of the debt securities in the NDT fund was $41.5 million, held entirely in closed end funds and bond mutual funds.

Using the specific identification method to determine cost, we realized losses on our available-for-sale securities of $0.3 million during the three months ended September 30, 2010, and gains of $13.2 million during the nine months ended September 30, 2010. During the three and nine months ended September 30, 2009, we realized gains of $0.5 million and losses of $8.2 million, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the costs and fair values of investments in the NDT fund as of September 30, 2010, and December 31, 2009.


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

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

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

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

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


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

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

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

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

5. RATE MATTERS AND REGULATION

KCC Proceedings

On June 11, 2010, the Kansas Corporation Commission (KCC) issued a final order approving an adjustment to our prices that we made earlier this year. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million.

On May 25, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2009. The new prices were effective June 1, 2010, and are expected to increase our annual retail revenues by $13.8 million.

On January 27, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in natural gas and wind generation facilities. The new prices were effective February 2010 and are expected to increase our annual retail revenues by $17.1 million.

FERC Proceedings

Our transmission formula rate that includes projected 2010 transmission capital expenditures and operating costs became effective January 1, 2010, and is expected to increase our annual transmission revenues by $16.8 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

On January 12, 2010, the Federal Energy Regulatory Commission (FERC) issued an order accepting our request to implement a cost-based formula rate for electricity sales to wholesale customers. The use of a cost-based formula rate allows us to annually adjust our prices to reflect changes in our cost of service. The cost-based formula rate was effective December 1, 2009.

6. TAXES

We recorded income tax expense of $51.8 million with an effective income tax rate of 31% for the three months ended September 30, 2010, and income tax expense of $28.3 million with an effective income tax rate of 26% for the same period of 2009; and income tax expense of $86.8 million with an effective income tax rate of 30% for the nine months ended September 30, 2010, and income tax expense of $48.4 million with an effective income tax rate of 27% for the same period of 2009. The increases in the effective income tax rate for the three and nine months ended September 30, 2010, were due primarily to increased income from continuing operations before income taxes.

In January 2009, we reached a settlement with the Internal Revenue Service (IRS) for tax years 2003 and 2004 that included a determination of the amount of the net capital loss and net operating loss carryforwards available from the sale of a former subsidiary in 2004. This settlement resulted in our recording in 2009 a net earnings benefit from discontinued operations of approximately $33.7 million, net of $22.8 million paid to the former subsidiary under the sale agreement. We recorded $33.0 million of this benefit in the nine months ended September 30, 2009.

In March 2010, the IRS commenced its examination of our federal income tax return for tax year 2008. We expect the IRS to complete this examination during the fourth quarter of 2010 without any significant assessment.

In October 2010, we were notified that the IRS will commence an examination of our federal income tax return for tax year 2009 in the fourth quarter of 2010.

At September 30, 2010, and December 31, 2009, our liability for unrecognized income tax benefits was $3.3 million and $8.4 million, respectively. The net decrease in the liability for unrecognized income tax benefits was attributable primarily to the recognition of $5.8 million of unrecognized income tax benefits due to the completion of the IRS examination of tax years 1999, 2005, 2006 and 2007.

As of September 30, 2010, and December 31, 2009, we had $0.6 million and $1.4 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. We had no tax related penalties accrued at either September 30, 2010, or December 31, 2009.

As of September 30, 2010, and December 31, 2009, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

7. COMMITMENTS AND CONTINGENCIES

Environmental Projects

We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could materially change depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce net productivity of plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments.

The environmental cost recovery rider allows for the more timely inclusion in our prices the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our retail prices to recognize increased operating and maintenance costs, however, we must still file a general rate case with the KCC.

We have an agreement with the Kansas Department of Health and Environment (KDHE) to install new equipment to reduce regulated emissions from our generating fleet. The projects are designed to meet requirements of the Clean Air Visibility Rule and significantly reduce plant emissions.

While an earlier issued Environmental Protection Agency (EPA) rule on mercury was vacated by a U.S. Court of Appeals ruling, the Obama administration has indicated that it intends to enact stricter, technology-based regulations on mercury emissions. Our costs to comply with mercury emission requirements could be material.

Environmental Law Update

In May 2010, the EPA finalized new regulations, known as the tailoring rule, under which it intends to begin regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations will be implemented pursuant to two Federal Clean Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions will be required to implement best available control technology (BACT). The EPA has yet to issue regulations defining BACT. There have already been introduced significant legal challenges to this new regulation. As a result of this and other uncertainties, we cannot predict the impact of the tailoring rule on our consolidated financial results, but it could be material.

In July 2010, the EPA proposed the Clean Air Transport Rule (CATR), which would require 31 states, including Kansas, and the District of Columbia to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from power plants. Such emissions would be required to be reduced in two phases beginning in 2012, with further reductions projected to be required in 2014. The EPA expects the CATR to be finalized in the spring of 2011. There are a number of uncertainties relating to this proposed rule, including whether it will be finalized and how the states will implement the requirements. As a result, we cannot determine the impact this rule will have on our consolidated financial results, but it could be material.

EPA Lawsuit

Under Section 114(a) of the Federal Clean Air Act, the EPA has been conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to the New Source Review permitting program or New Source Performance Standards. These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could reasonably have been expected to result in a significant net increase in emissions. The New Source Review program requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center (JEC) violated certain requirements of the New Source Review program. On February 4, 2009, the Department of Justice, on behalf of the EPA, filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. On January 25, 2010, we announced a settlement of the lawsuit. The settlement was filed with the court, seeking its approval, and on March 26, 2010, the court entered an order approving the settlement without changes. The settlement provides for us to install a selective catalytic reduction (SCR) system on one of the three JEC coal units by the end of 2014. We have not yet engineered this project; however, our preliminary estimate of the cost of this SCR is approximately $200.0 million. This amount could materially increase or decrease depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, a second SCR system would be installed on another JEC coal unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge our customers. We will also invest $5.0 million over six years in environmental mitigation projects that we will own and $1.0 million in environmental mitigation projects that will be owned by a qualifying third party. We have also paid a $3.0 million civil penalty.

FERC Investigation

We continue to respond to a non-public investigation by FERC of our use of transmission service between July 2006 and February 2008. On May 7, 2009, FERC staff advised us that it had preliminarily concluded that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. On March 4, 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and potentially could alter the manner in which we are permitted to buy and sell energy and use transmission service.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas and Missouri. We and the KDHE entered into a consent agreement governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, Inc. (ONEOK), the current owner of some of the sites, ONEOK assumed total liability for remediation of seven sites, and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million. We have sole responsibility for remediation with respect to three sites.

Our environmental liability for remediation of sites associated with assets we divested many years ago had been limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of those assets. In June 2010, the purchaser agreed to reduce our maximum liability to $2.5 million, which reflects our share of the purchaser’s expected remediation costs. We have paid $1.5 million of such costs.

8. LEGAL PROCEEDINGS

In late 2002, one of our executive officers resigned and another was placed on administrative leave from their positions. Our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment. As of September 30, 2010, we had accrued liabilities of $79.8 million for compensation not yet paid to them and $6.9 million for legal fees and expenses they have incurred. As of December 31, 2009, we had accrued liabilities of $77.6 million for compensation not yet paid to them and $6.8 million for legal fees and expenses they have incurred. The arbitration was stayed in August 2004 pending final resolution of criminal charges filed by the United States Attorney’s Office against them in U.S. District Court in the District of Kansas. In August 2010, these criminal charges were dismissed and subsequently the stay of the arbitration was lifted. We intend to vigorously defend against the counterclaims they filed in the arbitration. The arbitration proceedings are confidential pursuant to the terms of the employment agreements with the officers. We are unable to predict the timing and ultimate impact of this matter on our consolidated financial statements.

We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect on our consolidated financial statements.

See also Note 5, “Rate Matters and Regulation,” and Note 7, “Commitments and Contingencies.”

9. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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

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


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

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

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


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

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

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

During the nine months ended September 30, 2010 and 2009, we contributed $22.4 million and $37.3 million, respectively, to the Westar Energy pension trust.

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

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


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

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

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


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

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

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

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

11. COMMON STOCK ISSUANCE

During the nine months ended September 30, 2010, Westar Energy sold 1.2 million shares of common stock for $25.0 million through a 2007 Sales Agency Financing Agreement with a broker dealer subsidiary of a bank. Westar Energy used the proceeds from the issuance of common stock to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes.

On April 2, 2010, Westar Energy entered into a new, three-year Sales Agency Financing Agreement and forward sale agreement with the same bank and its broker dealer subsidiary. The maximum amount that Westar Energy may offer and sell under the agreements is the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the Sales Agency Financing Agreement, Westar Energy may offer and sell shares of its common stock from time to time through the broker dealer subsidiary, as agent. Westar Energy will pay the broker dealer a commission equal to 1% of the sales price of all shares sold under the agreement.

In addition, under the terms of the Sales Agency Financing Agreement and forward sale agreement, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, with the bank borrowing shares of Westar Energy’s common stock from third parties and selling them through the broker dealer. The use of a forward sale agreement allows Westar Energy the means to minimize equity market uncertainty by pricing a common stock offering under then existing market conditions while postponing the issuance of common stock until funds are needed. Through this approach, Westar Energy is able to better match the timing of its financing needs with its capital investment and regulatory plans. The forward sale transactions are entered into at market prices; therefore, the forward sale agreement has no initial fair value. Westar Energy will not receive any proceeds from the sale of common stock under the forward sale agreement until the transactions are settled, which must occur within a year of the date each transaction is entered. Upon settlement, Westar Energy will record the forward sale agreement within equity. Except in specified circumstances or events that would require physical share settlement, Westar Energy is able to elect to settle any forward sale transactions by means of a physical share, cash or net share settlement, and is also able to elect to settle the forward sale transactions in whole, or in part, earlier than the stated maturity dates. Currently, Westar Energy anticipates settling the forward sale transactions through physical share settlement and expects to use the proceeds to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes. While the shares are initially priced by the bank at a fixed price, because of the fixed contractual terms, Westar Energy’s net proceeds from the forward sale transactions, assuming physical share settlement, will vary depending on the time of settlement.

As of September 30, 2010, Westar Energy had entered into forward sale transactions with respect to an aggregate of approximately 5.4 million shares of common stock. Assuming physical share settlement of these transactions at September 30, 2010, Westar Energy would have received aggregate proceeds of approximately $120.9 million based on an average forward price of $22.39 per share.

12. VARIABLE INTEREST ENTITIES

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

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

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

Railcars

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

Financial Statement Impact

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


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

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

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

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

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

13. LEASES

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

Operating Leases

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

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


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

Total future commitments	$	83,110	$	487,569

Capital Leases

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

Assets recorded under capital leases are listed below.


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

Total capital leases	$	10,135		$	120,518

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


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

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

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

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Certain matters discussed in Management’s Discussion and Analysis are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals.

INTRODUCTION

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central United States under the regulation of the KCC and FERC.

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2010 and our operating results for the three and nine months ended September 30, 2010 and 2009. As you read Management’s Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Earnings Per Share

We reported basic EPS of $1.02 for the three months ended September 30, 2010, compared to basic EPS of $0.73 for the same period of 2009. For the nine months ended September 30, 2010 and 2009, we reported basic EPS of $1.77 and $1.48, respectively. Basic EPS for the nine months ended September 30, 2009, however, included $0.30 of earnings attributable to discontinued operations.

Weather

After experiencing extremely cool weather during the third quarter of 2009, we experienced warmer than normal weather in our service territory during the three months ended September 30, 2010. As measured by cooling degree days, the weather during this period was 63% warmer than the same period last year and 20% warmer than the 20-year average. During the nine months ended September 30, 2010, the weather was 45% warmer than the same period last year and 26% warmer than the 20-year average. The warmer weather was the key contributor to the increase in retail electricity sales for both the three and nine months ended September 30, 2010.

Increase in Income from Continuing Operations

Income from continuing operations for the three and nine months ended September 30, 2010, increased $34.7 million and $71.4 million, respectively, compared to the same periods last year due primarily to higher retail revenues. The increase in retail revenues was due principally to higher electricity sales that were the result primarily of warmer weather as discussed above.

Current Trends

From time to time we update current trends discussed in our 2009 Form 10-K. The following is to be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2009 Form 10-K.

Increasing Operating Expenses

We anticipate our operating expenses will increase in future periods due to higher costs to comply with increased regulation from various federal and state agencies and higher costs to maintain our aging generating facilities.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with the instructions to Form 10-Q and Article 10 of Regulation S-X. Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted in our 2009 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2009, through September 30, 2010, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2009 Form 10-K.

OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent upon classification.

Other retail: Sales of electricity for lighting public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. This category also includes changes in valuations of contracts for the sale of such electricity that have yet to settle. Margins realized from these electricity sales generally serve to offset our retail prices.

Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes energy marketing transactions unrelated to the production of our generating assets, changes in valuations of related contracts and fees we earn for marketing services that we provide for third parties.

Electric utility revenues are impacted by things such as rate regulation, fuel costs, customer conservation efforts, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use, as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among our residential customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather.

Three and Nine Months Ended September 30, 2010, Compared to Three and Nine Months Ended September 30, 2009

Below we discuss our operating results for the three and nine months ended September 30, 2010, compared to the results for the three and nine months ended September 30, 2009. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)												(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	235,383		$	179,012		$	56,371			31.5		$	530,220		$	447,970		$	82,250			18.4
Commercial		179,884			156,509			23,375			14.9			443,892			410,031			33,861			8.3
Industrial		90,462			81,936			8,526			10.4			242,612			223,422			19,190			8.6
Other retail		(3,404	)		(58	)		(3,346	)		(b	)		(10,463	)		(18,322	)		7,859			42.9

Total Retail Revenues		502,325			417,399			84,926			20.3			1,206,261			1,063,101			143,160			13.5
Wholesale		94,117			70,383			23,734			33.7			255,865			221,779			34,086			15.4
Transmission (a)		35,554			32,833			2,721			8.3			108,497			100,902			7,595			7.5
Other		12,441			7,919			4,522			57.1			28,825			32,331			(3,506	)		(10.8	)

Total Revenues		644,437			528,534			115,903			21.9			1,599,448			1,418,113			181,335			12.8

OPERATING EXPENSES:
Fuel and purchased power		187,877			141,470			46,407			32.8			458,793			402,622			56,171			14.0
Operating and maintenance		126,602			130,295			(3,693	)		(2.8	)		369,584			392,272			(22,688	)		(5.8	)
Depreciation and amortization		67,918			64,516			3,402			5.3			201,955			186,544			15,411			8.3
Selling, general and administrative		50,418			41,920			8,498			20.3			144,499			143,540			959			0.7

Total Operating Expenses		432,815			378,201			54,614			14.4			1,174,831			1,124,978			49,853			4.4

INCOME FROM OPERATIONS		211,622			150,333			61,289			40.8			424,617			293,135			131,482			44.9

OTHER INCOME (EXPENSE):
Investment earnings		3,248			3,986			(738	)		(18.5	)		4,350			8,516			(4,166	)		(48.9	)
Other income		1,897			1,217			680			55.9			3,792			5,627			(1,835	)		(32.6	)
Other expense		(5,146	)		(4,539	)		(607	)		(13.4	)		(12,043	)		(11,441	)		(602	)		(5.3	)

Total Other (Expense) Income		(1	)		664			(665	)		(100.2	)		(3,901	)		2,702			(6,603	)		(244.4	)

Interest expense		43,956			41,599			2,357			5.7			131,862			116,769			15,093			12.9

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		167,665			109,398			58,267			53.3			288,854			179,068			109,786			61.3
Income tax expense		51,802			28,256			23,546			83.3			86,780			48,354			38,426			79.5

INCOME FROM CONTINUING OPERATIONS		115,863			81,142			34,721			42.8			202,074			130,714			71,360			54.6
Results of discontinued operations, net of tax		—			—			—			—			—			32,978			(32,978	)		(100.0	)

NET INCOME		115,863			81,142			34,721			42.8			202,074			163,692			38,382			23.4
Less: Net income attributable to noncontrolling interests		1,119			—			1,119			(b	)		3,338			—			3,338			(b	)

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		114,744			81,142			33,602			41.4			198,736			163,692			35,044			21.4
Preferred dividends		242			242			—			—			727			727			—			—

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	114,502		$	80,900		$	33,602			41.5		$	198,009		$	162,965		$	35,044			21.5

BASIC EARNINGS PER SHARE:
Earnings available from continuing operations	$	1.02		$	0.73		$	0.29			39.7		$	1.77		$	1.18		$	0.59			50.0
Discontinued operations, net of tax		—			—			—			—			—			0.30			(0.30	)		(100.0	)

Earnings per common share	$	1.02		$	0.73		$	0.29			39.7		$	1.77		$	1.48		$	0.29			19.6

(a)

Transmission: Reflects revenue derived from an SPP network transmission tariff. For the three months ended September 30, 2010, our SPP network transmission costs were $30.7 million. This amount, plus an additional $0.3 million, was returned to us as revenue. For the three months ended September 30, 2009, our SPP network transmission costs were $25.8 million with an administration cost of $2.9 million retained by the SPP. For the nine months ended September 30, 2010, our SPP network transmission costs were $86.7 million. This amount, less $7.4 million retained by the SPP as administration cost, was returned to us as revenue. For the nine months ended September 30, 2009, our SPP network transmission costs were $79.3 million with an administration cost of $10.5 million retained by the SPP.

(b)	Change greater than 1000%.

Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power needed to serve customers. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with a minimal impact on net income. For this reason, we believe gross margin, although a non-GAAP measurement, is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues less the sum of fuel and purchased power costs and SPP network transmission costs. Transmission costs reflect the costs of providing network transmission service. Accordingly, in calculating gross margin, we recognize the net value of this transmission activity as shown in the table immediately following. However, we record transmission costs as operating and maintenance expense on our consolidated statements of income. The following table summarizes our gross margin for the three and nine months ended September 30, 2010 and 2009.


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)												(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	235,383		$	179,012		$	56,371			31.5		$	530,220		$	447,970		$	82,250			18.4
Commercial		179,884			156,509			23,375			14.9			443,892			410,031			33,861			8.3
Industrial		90,462			81,936			8,526			10.4			242,612			223,422			19,190			8.6
Other retail		(3,404	)		(58	)		(3,346	)		(b	)		(10,463	)		(18,322	)		7,859			42.9

Total Retail Revenues		502,325			417,399			84,926			20.3			1,206,261			1,063,101			143,160			13.5
Wholesale		94,117			70,383			23,734			33.7			255,865			221,779			34,086			15.4
Transmission		35,554			32,833			2,721			8.3			108,497			100,902			7,595			7.5
Other		12,441			7,919			4,522			57.1			28,825			32,331			(3,506	)		(10.8	)

Total Revenues		644,437			528,534			115,903			21.9			1,599,448			1,418,113			181,335			12.8
Less: Fuel and purchased power expense		187,877			141,470			46,407			32.8			458,793			402,622			56,171			14.0
SPP network transmission costs		30,682			25,791			4,891			19.0			86,746			79,311			7,435			9.4

Gross Margin	$	425,878		$	361,273		$	64,605			17.9		$	1,053,909		$	936,180		$	117,729			12.6

The following table reflects changes in electricity sales for the three and nine months ended September 30, 2010 and 2009. No electricity sales are shown for transmission or other as they are unrelated to the amount of electricity we sell.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change			% Change
	(Thousands of MWh)								(Thousands of MWh)
ELECTRICITY SALES:
Residential		2,351		1,869		482		25.8		5,563		4,944		619			12.5
Commercial		2,218		2,007		211		10.5		5,793		5,522		271			4.9
Industrial		1,483		1,402		81		5.8		4,166		3,921		245			6.2
Other retail		23		22		1		4.5		65		66		(1	)		(1.5	)

Total retail		6,075		5,300		775		14.6		15,587		14,453		1,134			7.8
Wholesale		2,304		2,011		293		14.6		6,804		6,578		226			3.4

Total		8,379		7,311		1,068		14.6		22,391		21,031		1,360			6.5

Gross margin increased for the three and nine months ended September 30, 2010, compared to the same periods last year due principally to increases in total retail revenues that were the result primarily of higher electricity sales. Retail electricity sales increased due primarily to the effects of warmer weather as discussed above, which particularly impacted residential electricity sales, and improved economic conditions. While weather also affects commercial and industrial customers, those electricity sales are not as sensitive to weather as residential electricity sales. Some of our commercial and industrial customers continue to experience increased orders and production, although not to levels experienced prior to the economic downturn. Partially offsetting the increase in total retail revenues for the nine months ended September 30, 2010, was a decrease in other revenues due principally to our having settled forward contracts for the sale of electricity on favorable terms during the nine months ended September 30, 2009. We did not record similar settlements during the same period this year.

Income from operations is the most directly comparable measure to gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the three and nine months ended September 30, 2010 and 2009.


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010		2009		Change			% Change			2010		2009		Change			% Change
	(Dollars In Thousands)										(Dollars In Thousands)
Gross margin	$	425,878	$	361,273	$	64,605			17.9		$	1,053,909	$	936,180	$	117,729			12.6
Add: SPP network transmission costs		30,682		25,791		4,891			19.0			86,746		79,311		7,435			9.4
Less: Operating and maintenance expense		126,602		130,295		(3,693	)		(2.8	)		369,584		392,272		(22,688	)		(5.8	)
Depreciation and amortization expense		67,918		64,516		3,402			5.3			201,955		186,544		15,411			8.3
Selling, general and administrative expense		50,418		41,920		8,498			20.3			144,499		143,540		959			0.7

Income from operations	$	211,622	$	150,333	$	61,289			40.8		$	424,617	$	293,135	$	131,482			44.9

Operating Expenses and Other Income and Expense Items


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010		2009		Change			% Change			2010		2009		Change			% Change
	(Dollars In Thousands)
Operating and maintenance expense	$	126,602	$	130,295	$	(3,693	)		(2.8	)	$	369,584	$	392,272	$	(22,688	)		(5.8	)

Operating and maintenance expense decreased for the three and nine months ended September 30, 2010, compared to the same periods last year due primarily to reductions of $5.1 million and $15.3 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities.” For the nine months ended September 30, 2010, a $5.0 million reduction in our maximum liability for environmental remediation costs associated with assets we divested many years ago also contributed to the decrease. Partially offsetting the aforementioned decreases for the three and nine months ended September 30, 2010, were higher SPP network transmission costs of $4.9 million and $7.4 million, respectively, which were offset partially by higher transmission revenues of $2.7 million and $7.6 million, respectively.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change		% Change
	(Dollars In Thousands)
Depreciation and amortization expense	$	67,918	$	64,516	$	3,402		5.3	$	201,955	$	186,544	$	15,411		8.3

Depreciation and amortization expense increased for the three months ended September 30, 2010, compared to the same period last year due primarily to depreciation expense associated with a higher plant balance. For the nine months ended September 30, 2010, depreciation and amortization expense increased primarily to reflect the addition of wind generation facilities, new generating plant, air quality controls at our power plants and other general plant additions. In addition, during the three and nine months ended September 30, 2010, we recorded additional depreciation expense of $1.6 million and $4.6 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities.”


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change		% Change
	(Dollars In Thousands)
Selling, general and administrative expense	$	50,418	$	41,920	$	8,498		20.3	$	144,499	$	143,540	$	959		0.7

Selling, general and administrative expense increased for the three months ended September 30, 2010, compared to the same period last year due principally to higher pension and other employee benefits costs of $8.0 million. The higher pension costs were attributable primarily to our having recorded a lower credit to expense in accordance with a September 2009 KCC order allowing us to establish a regulatory asset or liability for the cumulative difference between pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. During the three months ended September 30, 2010 and 2009, we recorded credits to expense of $2.0 million and $5.1 million, respectively. The 2009 credit reflected the cumulative difference for the entire nine month period due to the timing of the KCC order.


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010		2009		Change			% Change			2010		2009		Change			% Change
	(Dollars In Thousands)
Investment earnings	$	3,248	$	3,986	$	(738	)		(18.5	)	$	4,350	$	8,516	$	(4,166	)		(48.9	)

Investment earnings decreased for the three and nine months ended September 30, 2010, compared to the same periods last year due principally to our having recorded lower gains on investments held in a trust to fund retirement benefits. During the three and nine months ended September 30, 2010, we recorded gains on these investments of $3.2 million and $2.2 million, respectively. We recorded gains on these investments of $4.0 million and $6.9 million, respectively, during the same periods of 2009.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change			% Change
	(Dollars In Thousands)
Other income	$	1,897	$	1,217	$	680		55.9	$	3,792	$	5,627	$	(1,835	)		(32.6	)

Other income decreased for the nine months ended September 30, 2010, compared to the same period last year due principally to a $2.1 million decrease in equity AFUDC. The decrease in equity AFUDC reflects reduced construction activity due to the completion of large construction projects.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change		% Change
	(Dollars In Thousands)
Interest expense	$	43,956	$	41,599	$	2,357		5.7	$	131,862	$	116,769	$	15,093		12.9

Interest expense increased for the three and nine months ended September 30, 2010, compared to the same periods last year due primarily to our having recorded additional interest expense of $3.1 million and $9.7 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities.” Contributing to the increase for the nine months ended September 30, 2010, was interest on additional debt issued in 2009 to fund capital investments and our having recorded $1.0 million less for capitalized interest as a result of completing large construction projects.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010		2009		Change		% Change		2010		2009		Change		% Change
	(Dollars In Thousands)
Income tax expense	$	51,802	$	28,256	$	23,546		83.3	$	86,780	$	48,354	$	38,426		79.5

Income tax expense increased for the three and nine months ended September 30, 2010, compared to the same periods last year due principally to higher income from continuing operations before income taxes.

FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of September 30, 2010, compared to December 31, 2009.

As a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” we recorded property, plant and equipment of variable interest entities, net, of $347.9 million, current maturities of long-term debt of variable interest entities of $30.1 million and long-term debt of variable interest entities, net, of $279.6 million.

Tax receivable decreased $45.2 million due principally to the receipt of $34.9 million from the IRS related to the settlement of tax years 1999 and 2004 through 2007. In addition, we received $11.8 million from the Kansas Department of Revenue in connection with our 2006 and 2007 tax years.

The fair market value of net energy marketing contracts increased $10.4 million to $14.9 million at September 30, 2010. This was due primarily to the fair value measurement of a fuel supply contract having increased by $9.5 million. Increasing the fair value measurement of this fuel supply contract was the settlement of a $5.9 million net loss position during the period. The portion of this fuel supply contract that was outstanding the entire period increased $3.6 million due to increases in the market price of coal. Changes in the fair value measurements of our fuel supply contracts have an inverse change in net regulatory assets.

Regulatory assets, net of regulatory liabilities, decreased $86.9 million to $628.1 million at September 30, 2010, from $715.0 million at December 31, 2009. Total regulatory assets decreased $59.3 million due primarily to the $16.9 million amortization of deferred storm costs, $13.3 million decrease in previously deferred fuel expense and $11.6 million decrease in deferred employee benefit costs. Regulatory liabilities increased $27.6 million due primarily to an $18.5 million increase in removal costs for amounts included in our prices, but not yet spent to remove retired assets, and a $12.7 million increase resulting from the consolidation of VIEs. Increases in regulatory liabilities were offset partially by a $14.7 million decrease in our refund obligation related to the RECA.

Short-term debt was $79.7 million lower than at December 31, 2009, due principally to increased cash receipts from customers, the above mentioned tax refund and lower capital spending.

Deferred income taxes increased $47.9 million from December 31, 2009, to September 30, 2010, due primarily to the use of accelerated depreciation methods, including $33.5 million resulting from the extension of the bonus depreciation tax provisions permitted by the Small Business Jobs Act of 2010.

Unamortized investment tax credits increased $26.2 million due principally to incentives we earned related to investments in plant within the state of Kansas.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy’s revolving credit facility and access to capital markets. We believe we will have sufficient cash to meet our day-to-day requirements including, among other items, funding our operations, making interest payments and paying dividends. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in “– Operating Results” above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the banking and capital markets.

Capital Resources

As of October 20, 2010, Westar Energy had a $730.0 million revolving credit facility under which $140.0 million had been borrowed and an additional $20.7 million of letters of credit had been issued.

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 our revolving credit facility. We have not yet exercised the increase in our authority.

Common Stock Issuance

On October 14, 2010, Westar Energy delivered approximately 0.5 million shares of common stock and received proceeds of $10.4 million as partial settlement of the forward sale transactions discussed above.

Cash Flows from Operating Activities

Operating activities provided $500.4 million of cash in the nine months ended September 30, 2010, compared with cash provided of $408.0 million during the same period of 2009. This increase was due primarily to our having received $191.3 million more in customer receipts and our having received $28.9 million more in net tax refunds. Also contributing to the increase was a change in the classification of cash flows as a result of our having consolidated our interest in La Cygne unit 2 as a VIE as discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” which resulted in a $17.0 million increase, and our having contributed $15.1 million less to the Westar Energy pension trust, Westar Energy post-retirement benefit plan and Wolf Creek pension trust. Partially offsetting these increases was our having paid $99.8 million more for fuel and purchased power and our having paid $61.9 million more for interest on corporate-owned life insurance (COLI) policies, which was the result of a policy change in the second quarter of 2009 under which we no longer pay interest on such policies in advance.

Cash Flows used in Investing Activities

Investing activities used $388.9 million of cash in the nine months ended September 30, 2010, compared to $477.7 million during the same period of 2009. We spent $369.7 million in the nine months ended September 30, 2010, and $460.8 million in the same period of 2009 on additions to property, plant and equipment.

Cash Flows (used in) from Financing Activities

Financing activities used $110.8 million of cash in the nine months ended September 30, 2010, compared to $50.5 million of cash provided from financing activities in the same period of 2009. In the nine months ended September 30, 2010, borrowings against the cash surrender value of COLI provided $72.3 million and proceeds from the issuance of common stock provided $28.3 million. We used cash to pay $96.4 million in dividends, repay $79.7 million of short-term debt and repay $28.9 million of long-term debt. In the nine months ended September 30, 2009, proceeds from long-term debt provided $297.5 million and we used cash to repay $146.5 million of long-term debt and to pay $91.9 million in dividends. The decrease in cash provided from financing activities was due primarily to a reduction in our financing needs as a result of our having completed large construction projects.

Debt Covenants

We remain in compliance with the debt covenants described in our 2009 Form 10-K.

Impact of Credit Ratings on Debt Financing

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

In general, less favorable credit ratings make borrowing more difficult and costly. Under Westar Energy’s revolving credit facility our cost of borrowing is determined in part by credit ratings. However, Westar Energy’s ability to borrow under the revolving credit facility is not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical financial ratios, such as total debt to total capitalization and funds from operations to total debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices

On June 1, 2010, and May 19, 2010, respectively, Fitch and Moody’s revised their outlooks for Westar Energy and KGE credit ratings to positive from stable. Additionally, on April 27, 2010, S&P upgraded its credit ratings for Westar Energy’s and KGE’s first mortgage bonds/senior secured debt from BBB to BBB+. S&P also upgraded its credit rating for Westar Energy’s unsecured debt from BBB- to BBB and changed its outlook for the ratings from positive to stable.

As of October 20, 2010, our ratings with the agencies and the outlooks for these ratings are as shown in the table below.


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

Certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of September 30, 2010, and December 31, 2009, was $1.7 million and $1.4 million, respectively, for which we had posted no collateral as of either date. If all credit-risk-related contingent features underlying these agreements had been triggered as of September 30, 2010, or December 31, 2009, we would have been required to provide to our counterparties $0.9 million and $0.1 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Pension Contribution

During the nine months ended September 30, 2010, we contributed $22.4 million to the Westar Energy pension trust and funded $5.1 million of Wolf Creek’s pension plan contribution.

OFF-BALANCE SHEET ARRANGEMENTS

Other than the consolidation of VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” from December 31, 2009, through September 30, 2010, there have been no material changes in our off-balance sheet arrangements. For additional information, see our 2009 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2009, through September 30 2010, there have been no material changes outside the ordinary course of business in our contractual obligations and commercial commitments. For additional information, see our 2009 Form 10-K.

OTHER INFORMATION

Environmental Law Update

In May 2010, the EPA finalized new regulations, known as the tailoring rule, under which it intends to begin regulating GHG emissions from certain stationary sources in January 2011. The regulations will be implemented pursuant to two Federal Clean Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as PSD. Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions will be required to implement BACT. The EPA has yet to issue regulations defining BACT. There have already been introduced significant legal challenges to this new regulation. As a result of this and other uncertainties, we cannot predict the impact of the tailoring rule on our consolidated financial results, but it could be material.

In July 2010, the EPA proposed the CATR, which would require 31 states, including Kansas, and the District of Columbia to reduce emissions of sulfur dioxide and NOx from power plants. Such emissions would be required to be reduced in two phases beginning in 2012, with further reductions projected to be required in 2014. The EPA expects the CATR to be finalized in the spring of 2011. There are a number of uncertainties relating to this proposed rule, including whether it will be finalized and how the states will implement the requirements. As a result, we cannot determine the impact this rule will have on our consolidated financial results, but it could be material.

For additional information, see “Item 1. Business—Environmental Matters” in our 2009 Form 10-K.

Increases in Prices

KCC Proceedings

On June 11, 2010, the KCC issued a final order approving an adjustment to our prices that we made earlier this year. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million.

FERC Proceedings

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

Fair Value of Energy Marketing and Fuel Contracts

The table below shows the fair value of energy marketing contracts outstanding as of September 30, 2010.


	Fair Value of Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2009 (a)	$	4,441
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		5,516
Changes in fair value of contracts outstanding at the beginning and end of the period		4,255
Fair value of new contracts entered into during the period		664

Fair value of contracts outstanding as of September 30, 2010 (b)	$	14,876

(a) Approximately $7.6 million and $6.0 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.

(b) Approximately $0.4 million and $10.1 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.

The sources of the fair values of the financial instruments related to these contracts and the maturity periods for the contracts as of September 30, 2010, are summarized in the following table.


	Fair Value of Contracts at End of Period
Sources of Fair Value	Total Fair Value			Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity Over 5 Years
	(In Thousands)
Prices actively quoted (futures)	$	(11	)	$	(11	)	$	—		$	—		$	—
Prices provided by other external sources (swaps and forwards)		15,412			4,748			7,714			2,950			—
Prices based on option pricing models (options and other) (a)		(525	)		(95	)		(290	)		(140	)		—

Total fair value of contracts outstanding	$	14,876		$	4,642		$	7,424		$	2,810		$	—

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

New Accounting Pronouncements

Consolidation Guidance for Variable Interest Entities

In June 2009, FASB issued guidance that amends 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 is effective for annual reporting periods beginning after November 15, 2009. We adopted the guidance effective January 1, 2010, and, as a result, began consolidating certain VIEs that hold assets we lease. See Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” for additional information.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including changes in commodity prices, debt and equity instrument values and interest rates. From December 31, 2009, to September 30, 2010, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2009 Form 10-K for additional information.

ITEM 4.

CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting during the three months ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Information on other legal proceedings is set forth in Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies – EPA Lawsuit – FERC Investigation” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 1A.

RISK FACTORS

There were no material changes in our risk factors from December 31, 2009, through September 30, 2010. For additional information, see our 2009 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In addition to information previously included in one or more Current Reports on Form 8-K, during the three-month period ended September 30, 2010, Westar Energy entered into forward sale transactions pursuant to the forward sale agreement, dated April 2, 2010, between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on April 2, 2010) and the Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.3 to the Form S-3 filed on April 2, 2010) in respect to an aggregate of approximately 0.4 million shares of Westar Energy common stock.

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

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

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.

REMOVED AND RESERVED

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS


31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 2010

31(b)		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 2010

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2010 (furnished and not to be considered filed as part of the Form 10-Q)

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		WESTAR ENERGY, INC.

Date:	October 28, 2010	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle,
			Executive Vice President and Chief Financial Officer