Evergy Kansas Central 10-Q 2012 Q3 Quarterly report

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, 2012

OR

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

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

Large accelerated filer    X      Accelerated filer    Non-accelerated filer      Smaller reporting company  

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

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

Common Stock, par value $5.00 per share	126,462,407 shares
(Class)	(Outstanding at October 31, 2012)

1

TABLE OF CONTENTS

PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Consolidated Balance Sheets	6
	Consolidated Statements of Income	7
	Consolidated Statements of Cash Flows	9
	Consolidated Statements of Changes in Equity	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	50
PART II. Other Information
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	52
Item 6.	Exhibits	52
Signature		53

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
AFUDC	Allowance for funds used during construction
BACT	Best Available Control Technology
CAMR	Clean Air Mercury Rule
CCB	Coal combustion byproduct
CO	Carbon monoxide
CSAPR	Cross-State Air Pollution Rule
ECRR	Environmental Cost Recovery Rider
EPA	Environmental Protection Agency
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gas
JEC	Jeffrey Energy Center
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
KGE	Kansas Gas and Electric Company
La Cygne	La Cygne Generating Station
MATS	Mercury and Air Toxics Standards
MMBtu	Millions of Btu
Moody’s	Moody’s Investors Service
MW	Megawatt(s)
MWh	Megawatt hour(s)
NAAQS	National Ambient Air Quality Standards
NDT	Nuclear Decommissioning Trust
NOx	Nitrogen oxides
ONEOK	ONEOK, Inc.
OTC	Over-the-counter
PM	Particulate matter
RSU	Restricted share unit
S&P	Standard & Poor’s Ratings Services
SCR	Selective catalytic reduction
SO2	Sulfur dioxide
SPP	Southwest Power Pool
VIE	Variable interest entity
Wolf Creek	Wolf Creek Generating Station

3

FORWARD-LOOKING STATEMENTS

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

- amount, type and timing of capital expenditures,

- earnings,

- cash flow,

- liquidity and capital resources,

- litigation,

- accounting matters,

- possible corporate restructurings, acquisitions and dispositions,

- compliance with debt and other restrictive covenants,

- interest rates and dividends,

- environmental matters,

- regulatory matters,

- nuclear operations, and

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

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

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

- the difficulty of predicting the amount and timing of changes in demand for electricity,

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

- equipment damage from storms and extreme weather,

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

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

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

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

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

- the impact of frequently changing laws and regulations relating to air emissions, water emissions, waste management and other environmental matters,

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

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

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

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

- additional regulation due to Nuclear Regulatory Commission oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek's performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,

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

- homeland and information security considerations,

- changes in accounting requirements and other accounting matters,

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

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

4

- 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, 2011 (2011 Form 10-K), including in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and in other reports we file from time to time with the Securities and Exchange Commission.

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our 2011 Form 10-K. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in our 2011 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

5

PART I.    FINANCIAL INFORMATION

ITEM I.    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

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

	As of		As of
	September 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,379	$	3,539
Restricted cash	836		—
Accounts receivable, net of allowance for doubtful accounts of $3,517 and $7,384, respectively	267,218		226,428
Fuel inventory and supplies	249,285		229,118
Energy marketing contracts	3,346		8,180
Taxes receivable	—		5,334
Deferred tax assets	—		394
Prepaid expenses	13,775		13,078
Regulatory assets	116,547		123,818
Other	22,806		23,696
Total Current Assets	678,192		633,585
PROPERTY, PLANT AND EQUIPMENT, NET	6,856,350		6,411,922
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	324,855		333,494
OTHER ASSETS:
Regulatory assets	889,063		922,272
Nuclear decommissioning trust	148,460		130,270
Other	239,590		251,308
Total Other Assets	1,277,113		1,303,850
TOTAL ASSETS	$	9,136,510	$	8,682,851
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	26,660	$	28,114
Short-term debt	214,756		286,300
Accounts payable	169,306		187,428
Accrued taxes	87,579		52,451
Energy marketing contracts	534		6,353
Accrued interest	71,290		77,437
Regulatory liabilities	40,898		40,857
Other	129,848		148,347
Total Current Liabilities	740,871		827,287
LONG-TERM LIABILITIES:
Long-term debt, net	2,819,118		2,491,109
Long-term debt of variable interest entities, net	242,521		249,283
Deferred income taxes	1,213,816		1,110,463
Unamortized investment tax credits	160,637		164,175
Regulatory liabilities	293,652		230,530
Accrued employee benefits	542,657		592,617
Asset retirement obligations	148,523		142,508
Other	75,950		74,138
Total Long-Term Liabilities	5,496,874		5,054,823
COMMITMENTS AND CONTINGENCIES (See Notes 8 and 9)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding zero shares and 214,363 shares, respective to each date	—		21,436
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 126,369,073 shares and 125,698,396 shares, respective to each date	631,845		628,492
Paid-in capital	1,651,802		1,639,503
Retained earnings	603,048		501,216
Total Westar Energy, Inc. Shareholders’ Equity	2,886,695		2,790,647
Noncontrolling Interests	12,070		10,094
Total Equity	2,898,765		2,800,741
TOTAL LIABILITIES AND EQUITY	$	9,136,510	$	8,682,851

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

6

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,
	2012			2011
REVENUES	$	695,758		$	678,152
OPERATING EXPENSES:
Fuel and purchased power	177,506			199,540
Operating and maintenance	149,001			137,823
Depreciation and amortization	65,061			72,202
Selling, general and administrative	54,300			27,499
Total Operating Expenses	445,868			437,064
INCOME FROM OPERATIONS	249,890			241,088
OTHER INCOME (EXPENSE):
Investment earnings	2,729			2,914
Other income	6,115			3,404
Other expense	(6,278		)	(5,470		)
Total Other Income	2,566			848
Interest expense	45,017			43,844
INCOME BEFORE INCOME TAXES	207,439			198,092
Income tax expense	66,372			61,700
NET INCOME	141,067			136,392
Less: Net income attributable to noncontrolling interests	1,786			1,442
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	139,281			134,950
Preferred dividends	—			242
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	139,281		$	134,708
BASIC AND DILUTED EARNINGS PER AVERGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.10		$	1.15
Diluted earnings per common share	$	1.09		$	1.14
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING	126,783,248			116,806,596
DIVIDENDS DECLARED PER COMMON SHARE	$	0.33		$	0.32

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

7

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
REVENUES	$	1,737,698		$	1,684,763
OPERATING EXPENSES:
Fuel and purchased power	452,840			486,697
Operating and maintenance	461,515			412,429
Depreciation and amortization	204,640			213,551
Selling, general and administrative	164,346			132,233
Total Operating Expenses	1,283,341			1,244,910
INCOME FROM OPERATIONS	454,357			439,853
OTHER INCOME (EXPENSE):
Investment earnings	6,456			6,255
Other income	27,242			8,210
Other expense	(14,246		)	(13,951		)
Total Other Income	19,452			514
Interest expense	131,886			130,681
INCOME BEFORE INCOME TAXES	341,923			309,686
Income tax expense	107,156			94,812
NET INCOME	234,767			214,874
Less: Net income attributable to noncontrolling interests	5,228			4,212
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	229,539			210,662
Preferred dividends	1,616			727
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	227,923		$	209,935
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.79		$	1.82
Diluted earnings per common share	$	1.79		$	1.79
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING	126,638,992			115,208,965
DIVIDENDS DECLARED PER COMMON SHARE	$	0.99		$	0.96

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

8

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	234,767		$	214,874
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	204,640			213,551
Amortization of nuclear fuel	16,658			13,411
Amortization of deferred regulatory gain from sale leaseback	(4,121		)	(4,121		)
Amortization of corporate-owned life insurance	17,062			19,137
Non-cash compensation	5,482			6,834
Net changes in energy marketing assets and liabilities	(133		)	956
Net deferred income taxes and credits	106,730			100,130
Stock-based compensation excess tax benefits	(1,628		)	(1,186		)
Allowance for equity funds used during construction	(9,096		)	(4,448		)
Gain on sale of non-utility investment	—			(7,246		)
Gain on settlement of contractual obligations with former officers	—			(22,039		)
Changes in working capital items:
Accounts receivable	(40,740		)	(27,269		)
Fuel inventory and supplies	(19,634		)	(1,837		)
Prepaid expenses and other	9,571			(36,459		)
Accounts payable	(7,201		)	(14,077		)
Accrued taxes	40,825			38,291
Other current liabilities	(83,160		)	(105,657		)
Changes in other assets	(1,061		)	(15,291		)
Changes in other liabilities	(15,005		)	(29,777		)
Cash Flows from Operating Activities	453,956			337,777
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(598,426		)	(512,675		)
Purchase of securities within trusts	(18,684		)	(41,118		)
Sale of securities within trusts	19,808			39,789
Proceeds from trust	1,527			—
Investment in corporate-owned life insurance	(18,404		)	(19,214		)
Proceeds from investment in corporate-owned life insurance	16,501			869
Proceeds from federal grant	4,470			7,367
Investment in affiliated company	(6,550		)	(1,479		)
Investment in non-utility investments	(433		)	7,246
Other investing activities	(1,124		)	470
Cash Flows used in Investing Activities	(601,315		)	(518,745		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(71,544		)	159,770
Proceeds from long-term debt	541,374			—
Retirements of long-term debt	(220,563		)	(371		)
Retirements of long-term debt of variable interest entities	(7,765		)	(29,019		)
Repayment of capital leases	(1,984		)	(1,645		)
Borrowings against cash surrender value of corporate-owned life insurance	64,479			65,853
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(18,369		)	(3,108		)
Stock-based compensation excess tax benefits	1,628			1,186
Preferred stock redemption	(22,567		)	—
Issuance of common stock	5,348			96,508
Distributions to shareholders of noncontrolling interests	(3,252		)	(1,916		)
Cash dividends paid	(118,586		)	(102,625		)
Cash Flows from Financing Activities	148,199			184,633
NET INCREASE IN CASH AND CASH EQUIVALENTS	840			3,665
CASH AND CASH EQUIVALENTS:
Beginning of period	3,539			928
End of period	$	4,379		$	4,593

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

9

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)

	Westar Energy, Inc. Shareholders
	Cumulative preferred stock shares		Cumulative preferred stock			Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2010	214,363		$	21,436		112,128,068	$	560,640	$	1,398,580		$	423,647		$	6,070		$	2,410,373
Net income	—		—			—	—		—			210,662			4,212			214,874
Issuance of stock	—		—			4,955,695	24,779		85,532			—			—			110,311
Preferred dividends	—		—			—	—		—			(727		)	—			(727		)
Dividends on common stock	—		—			—	—		—			(111,216		)	—			(111,216		)
Transfer from temporary equity	—		—			—	—		3,465			—			—			3,465
Amortization of restricted stock	—		—			—	—		6,176			—			—			6,176
Stock compensation and tax benefit	—		—			—	—		(13,672		)	—			—			(13,672		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(1,916		)	(1,916		)
Balance as of September 30, 2011	214,363		$	21,436		117,083,763	$	585,419	$	1,480,081		$	522,366		$	8,366		$	2,617,668
Balance as of December 31, 2011	214,363		$	21,436		125,698,396	$	628,492	$	1,639,503		$	501,216		$	10,094		$	2,800,741
Net income	—		—			—	—		—			229,539			5,228			234,767
Issuance of stock	—		—			670,677	3,353		15,881			—			—			19,234
Stock redemption	(214,363	)	(21,436		)	—	—		—			—			—			(21,436		)
Preferred dividends	—		—			—	—		—			(1,616		)	—			(1,616		)
Dividends on common stock	—		—			—	—		—			(126,091		)	—			(126,091		)
Amortization of restricted stock	—		—			—	—		4,708			—			—			4,708
Stock compensation and tax benefit	—		—			—	—		(8,290		)	—			—			(8,290		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(3,252		)	(3,252		)
Balance as of September 30, 2012	—		$	—		126,369,073	$	631,845	$	1,651,802		$	603,048		$	12,070		$	2,898,765

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

10

WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 690,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2011 Form 10-K.

Use of Management's Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and nine months endedSeptember 30, 2012, are not necessarily indicative of the results to be expected for the full year.

Restricted Cash

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

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Fuel Inventory and Supplies

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

	As of		As of
	September 30, 2012		December 31, 2011
	(In Thousands)
Fuel inventory	$	102,084	$	86,408
Supplies	147,201		142,710
Total	$	249,285	$	229,118

Allowance for Funds Used During Construction

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Dollars In Thousands)
Borrowed funds	$	2,132		$	1,163		$	8,091		$	4,224
Equity funds	2,317			1,027			9,096			4,448
Total	$	4,449		$	2,190		$	17,187		$	8,672
Average AFUDC Rates	4.6		%	3.2		%	5.2		%	4.0		%

Earnings Per Share

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

Under the two-class method, we reduce net income attributable to common stock by the amount of dividends declared in the current period. We allocate the remaining earnings to common stock and RSUs to the extent that each security may share in earnings as if all of the earnings for the period had been distributed. We determine the total earnings allocated to each security by adding together the amount allocated for dividends and the amount allocated for a participation feature. To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

12

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	141,067	$	136,392	$	234,767	$	214,874
Less: Net income attributable to noncontrolling interests	1,786		1,442		5,228		4,212
Net income attributable to Westar Energy, Inc.	139,281		134,950		229,539		210,662
Less: Preferred dividends	—		242		1,616		727
Net income allocated to RSUs	397		440		652		617
Net income allocated to common stock	$	138,884	$	134,268	$	227,271	$	209,318
Weighted average equivalent common shares outstanding – basic	126,783,248		116,806,596		126,638,992		115,208,965
Effect of dilutive securities:
RSUs	169,900		203,401		151,022		171,003
Forward sale agreements	181,376		1,228,273		65,372		1,585,107
Weighted average equivalent common shares outstanding – diluted (a)	127,134,524		118,238,270		126,855,386		116,965,075
Earnings per common share, basic	$	1.10	$	1.15	$	1.79	$	1.82
Earnings per common share, diluted	$	1.09	$	1.14	$	1.79	$	1.79

_______________

(a) We had no antidilutive shares for the three and nine months endedSeptember 30, 2012 and 2011.

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2012			2011
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	103,461		$	101,146
Interest on financing activities of VIEs	9,132			17,954
Income taxes, net of refunds	(4,559		)	(16,097		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	64,947			86,644
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans	8,676			8,587
Assets acquired through capital leases	9,898			43,199

13

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

Values of Financial and Derivative Instruments

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

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

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

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

We record cash and cash equivalents, short-term borrowings and variable rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.

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

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

14

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our fixed-rate debt.

	As of September 30, 2012				As of December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,702,500	$	3,203,149	$	2,373,063	$	2,623,993
Fixed-rate debt of VIEs	267,972		298,350		275,738		306,027

15

Recurring Fair Value Measurements

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

As of September 30, 2012	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Energy Marketing Contracts	$	—	$	40	$	7,964	$	8,004
Nuclear Decommissioning Trust:
Domestic equity	—		55,664		4,888		60,552
International equity	—		28,622		—		28,622
Core bonds	—		28,134		—		28,134
High-yield bonds	—		8,497		—		8,497
Emerging market bonds	—		6,429		—		6,429
Combination debt/equity fund	—		8,577		—		8,577
Real estate securities	—		—		7,603		7,603
Cash equivalents	46		—		—		46
Total Nuclear Decommissioning Trust	46		135,923		12,491		148,460
Trading Securities:
Domestic equity	—		22,740		—		22,740
International equity	—		5,535		—		5,535
Core bonds	—		15,107		—		15,107
Total Trading Securities	—		43,382		—		43,382
Total Assets Measured at Fair Value	$	46	$	179,345	$	20,455	$	199,846
Liabilities:
Energy Marketing Contracts	$	—	$	90	$	459	$	549
As of December 31, 2011
Assets:
Energy Marketing Contracts	$	—	$	2,401	$	13,330	$	15,731
Nuclear Decommissioning Trust:
Domestic equity	—		53,186		3,931		57,117
International equity	—		22,307		—		22,307
Core bonds	—		20,171		—		20,171
High-yield bonds	—		10,969		—		10,969
Emerging market bonds	—		5,309		—		5,309
Combination debt/equity fund	—		7,251		—		7,251
Real estate securities	—		—		7,095		7,095
Cash equivalents	51		—		—		51
Total Nuclear Decommissioning Trust	51		119,193		11,026		130,270
Trading Securities:
Domestic equity	—		21,175		—		21,175
International equity	—		4,896		—		4,896
Core bonds	—		13,961		—		13,961
Cash equivalents	169		—		—		169
Total Trading Securities	169		40,032		—		40,201
Total Assets Measured at Fair Value	$	220	$	161,626	$	24,356	$	186,202
Liabilities:
Energy Marketing Contracts	$	—	$	2,475	$	3,878	$	6,353
Treasury Yield Hedges	—		34,025		—		34,025
Total Liabilities Measured at Fair Value	$	—	$	36,500	$	3,878	$	40,378

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of September 30, 2012, we had no right to reclaim cash collateral and had recorded $1.6 million for our obligation to return cash collateral. As of December 31, 2011, we had no right to reclaim cash collateral and had recorded $2.9 million for our obligation to return cash collateral.

16

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2012.

	Energy Marketing Contracts, net				Nuclear Decommissioning Trust						Net Balance
					Domestic Equity			Real Estate Securities
	(In Thousands)
Balance as of June 30, 2012	$	6,898			$	4,780		$	7,449		$	19,127
Total realized and unrealized gains (losses) included in:
Earnings (a)	855				—			—			855
Regulatory assets	257			(b)	—			154			411
Regulatory liabilities	547			(b)	(1		)	63			609
Purchases	(865		)		109			(63		)	(819		)
Sales	(139		)		—			—			(139		)
Settlements	(48		)		—			—			(48		)
Balance as of September 30, 2012	$	7,505			$	4,888		$	7,603		$	19,996
Balance as of December 31, 2011	$	9,452			$	3,931		$	7,095		$	20,478
Total realized and unrealized gains (losses) included in:
Earnings (a)	3,027				—			—			3,027
Regulatory assets	(433		)	(b)	—			—			(433		)
Regulatory liabilities	1,495			(b)	192			508			2,195
Purchases	(4,425		)		777			185			(3,463		)
Sales	(1,023		)		(12		)	(185		)	(1,220		)
Settlements	(588		)		—			—			(588		)
Balance as of September 30, 2012	$	7,505			$	4,888		$	7,603		$	19,996

 _______________

(a)Unrealized gains and losses included in earnings are reported in revenues.

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

17

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2011.

	Energy Marketing Contracts, net				Nuclear Decommissioning Trust									Net Balance
					Domestic Equity			High-yield Bonds			Real Estate Securities
	(In Thousands)
Balance as of June 30, 2011	$	10,893			$	3,111		$	—		$	3,296		$	17,300
Total realized and unrealized gains (losses) included in:
Earnings (a)	(886		)		—			—			—			(886		)
Regulatory assets	(375		)	(b)	—			—			—			(375		)
Regulatory liabilities	1,267			(b)	330			—			164			1,761
Purchases	(2,235		)		140			—			3,432			1,337
Sales	1,808				—			—			(56		)	1,752
Settlements	(65		)		—			—			—			(65		)
Balance as of September 30, 2011	$	10,407			$	3,581		$	—		$	6,836		$	20,824
Balance as of December 31, 2010	$	11,815			$	2,867		$	305		$	3,049		$	18,036
Total realized and unrealized gains (losses) included in:
Earnings (a)	(1,152		)		—			—			—			(1,152		)
Regulatory assets	(765		)	(b)	—			—			—			(765		)
Regulatory liabilities	1,801			(b)	229			—			412			2,442
Purchases	(3,307		)		501			—			3,455			649
Sales	1,715				(16		)	(305		)	(80		)	1,314
Settlements	300				—			—			—			300
Balance as of September 30, 2011	$	10,407			$	3,581		$	—		$	6,836		$	20,824

 _______________

(a) Unrealized gains and losses included in earnings are reported in revenues.

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

18

Portions of the gains and losses contributing to changes in net assets in the above tables are unrealized. The following tables summarize the unrealized gains and losses we recorded on our consolidated financial statements during the three and nine months endedSeptember 30, 2012 and 2011, attributed to level 3 assets and liabilities.

	Three Months Ended September 30, 2012
	Energy Marketing Contracts, net				Nuclear Decommissioning Trust
					Domestic Equity			Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(749	)		$	—		$	—	$	(749	)
Regulatory assets	610			(b)	—			—		610
Regulatory liabilities	103			(b)	(1		)	90		192
Total	$	(36	)		$	(1	)	$	90	$	53
	Nine Months Ended September 30, 2012
Total unrealized gains (losses) included in:
Earnings (a)	$	(873	)		$	—		$	—	$	(873	)
Regulatory assets	(34		)	(b)	—			—		(34		)
Regulatory liabilities	(82		)	(b)	179			322		419
Total	$	(989	)		$	179		$	322	$	(488	)

_______________

(a)Unrealized gains and losses included in earnings are reported in revenues.

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

	Three Months Ended September 30, 2011
	Energy Marketing Contracts, net				Nuclear Decommissioning Trust
					Domestic Equity		Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(264	)		$	—	$	—	$	(264	)
Regulatory assets	28			(b)	—		—		28
Regulatory liabilities	590			(b)	330		107		1,027
Total	$	354			$	330	$	107	$	791
	Nine Months Ended September 30, 2011
Total unrealized gains (losses) included in:
Earnings (a)	$	(570	)		$	—	$	—	$	(570	)
Regulatory assets	(233		)	(b)	—		—		(233		)
Regulatory liabilities	1,101			(b)	213		332		1,646
Total	$	298			$	213	$	332	$	843

_______________

(a)Unrealized gains and losses included in earnings are reported in revenues.

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

19

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

	Fair Value as of
	September 30, 2012				Valuation Methodology	Unobservable Inputs	Range of Inputs
	Assets		Liabilities
	(In Thousands)
Electricity - Forwards	$	112	$	97	Discounted cash flow	Basis (MWh)	$0	to	$40
Options	7,852		362		Discounted cash flow	Basis - Electricity (MWh)	$0	to	$5
						Basis - Gas (mmBtu)	$0	to	$0.25
					Option models	Volatility - Electricity	10%	to	120%
						Volatility - Gas	15%	to	55%
						Correlation	35%	to	85%
Total	$	7,964	$	459

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

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

20

Some of our investments in the nuclear decommissioning trust (NDT) and our trading securities portfolio are measured at net asset value, do not have readily determinable fair values and are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.

	As of September 30, 2012				As of December 31, 2011				As of September 30, 2012
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	4,888	$	1,137	$	3,931	$	1,914	(a)	(a)
Real estate securities	7,603		—		7,095		—		(b)	(b)
Total Nuclear Decommissioning Trust	12,491		1,137		11,026		1,914
Trading Securities:
Domestic equity	22,740		—		21,175		—		Upon Notice	1 day
International equity	5,535		—		4,896		—		Upon Notice	1 day
Core bonds	15,107		—		13,961		—		Upon Notice	1 day
Total Trading Securities	43,382		—		40,032		—
Total	$	55,873	$	1,137	$	51,058	$	1,914

_______________

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

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

Derivative Instruments

Cash Flow Hedges

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

Commodity Contracts

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

21

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

Commodity Derivatives Not Designated as Hedging Instruments as of September 30, 2012
Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In Thousands)			(In Thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	3,346	Energy marketing contracts	$	534
Other assets:			Other liabilities:
Other	4,658		Other	15
Total	$	8,004	Total	$	549
Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 2011
Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In Thousands)			(In Thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	8,180	Energy marketing contracts	$	6,353
Other assets:
Other	7,551
Total	$	15,731

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

	Three Months Ended September 30, 2012						Nine Months Ended September 30, 2012
Location	Net Gain Recognized			Net Loss Recognized			Net Gain Recognized			Net Loss Recognized
	(In Thousands)
Revenue	$	1,009		$	—		$	6,031		$	—
Regulatory assets	(513		)	—			(310		)	—
Regulatory liabilities	851			—			—			(1,460		)
	Three Months Ended September 30, 2011						Nine Months Ended September 30, 2011
Revenues	$	—		$	(258	)	$	—		$	(857	)
Regulatory liabilities	—			(8		)	—			(1,215		)

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

		Net Quantity as of
	Unit of Measure	September 30, 2012	December 31, 2011
Electricity	MWh	1,516,634	1,834,253
Natural gas	MMBtu	2,000,000	1,467,500

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

22

Energy Marketing Activities

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

Price Risk

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

Interest Rate Risk

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

Credit Risk

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

We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit risk-related contingent features that were in a liability position as of September 30, 2012, and December 31, 2011, was $0.3 million and $3.1 million, respectively, for which we had posted no collateral, including independent amounts. If all credit-risk-related contingent features underlying these agreements had been triggered as of September 30, 2012, and December 31, 2011, we would have been required to provide to our counterparties $0.2 million and $0.5 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

4. FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments in a trust used to fund retirement benefits that we classify as trading securities. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three and nine months endedSeptember 30, 2012, we recorded unrealized gains of $1.9 million and $3.7 million, respectively, on these securities. We recorded unrealized losses of $4.7 million and $2.6 million, respectively, during the three and nine months endedSeptember 30, 2011.

23

Available-for-Sale Securities

We hold investments in equity, debt and real estate securities in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of September 30, 2012, and December 31, 2011. Under normal circumstances, the core bond fund will invest the majority of its assets in investment grade fixed income securities; however, a portion of its assets may be invested in non-investment grade securities. As of September 30, 2012, the fair value of available-for-sale debt securities in the core, high-yield and emerging market bond funds was $43.1 million. As of September 30, 2012, the NDT did not have investments in debt securities outside of investment funds.

Using the specific identification method to determine cost, we realized no gains or losses on our available-for-sale securities during the three months endedSeptember 30, 2012, and realized gains of $0.6 million during the nine months endedSeptember 30, 2012. During the three and nine months endedSeptember 30, 2011, we realized gains of $0.1 million and $1.3 million, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of September 30, 2012, and December 31, 2011.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2012
Domestic equity	$	51,570	$	8,982	$	—		$	60,552	41	%
International equity	28,078		544		—			28,622		19	%
Core bonds	26,749		1,385		—			28,134		19	%
High-yield bonds	7,880		617		—			8,497		6	%
Emerging market bonds	5,770		659		—			6,429		4	%
Combination debt/equity fund	7,728		849		—			8,577		6	%
Real estate securities	9,847		—		(2,244		)	7,603		5	%
Cash equivalents	46		—		—			46		<1%
Total	$	137,668	$	13,036	$	(2,244	)	$	148,460	100	%
As of December 31, 2011
Domestic equity	$	55,357	$	1,760	$	—		$	57,117	44	%
International equity	24,501		—		(2,194		)	22,307		17	%
Core bonds	19,771		400		—			20,171		16	%
High-yield bonds	11,046		—		(77		)	10,969		8	%
Emerging market bonds	5,301		8		—			5,309		4	%
Combination debt/equity fund	7,524		—		(273		)	7,251		6	%
Real estate securities	9,662		—		(2,567		)	7,095		5	%
Cash equivalents	51		—		—			51		<1%
Total	$	133,213	$	2,168	$	(5,111	)	$	130,270	100	%

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

	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2012
Real estate securities	$	—	$	—		$	7,603	$	(2,244	)	$	7,603	$	(2,244	)
As of December 31, 2011
International equity	$	22,307	$	(2,194	)	$	—	$	—		$	22,307	$	(2,194	)
High-yield bonds	10,969		(77		)	—		—			10,969		(77		)
Combination debt/equity fund	7,251		(273		)	—		—			7,251		(273		)
Real estate securities	—		—			7,095		(2,567		)	7,095		(2,567		)
Total	$	40,527	$	(2,544	)	$	7,095	$	(2,567	)	$	47,622	$	(5,111	)

5. RATE MATTERS AND REGULATION

KCC Proceedings

In September 2012, the Kansas Corporation Commission (KCC) issued a final order approving an adjustment to our prices that we implemented in April 2012. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below and is expected to increase our annual retail revenues by approximately $36.7 million.

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

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

FERC Proceedings

Our transmission formula rate that includes projected 2012 transmission capital expenditures and operating costs was effective in January 2012 and is expected to increase annual transmission revenues by approximately $38.2 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

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6. DEBT FINANCING

In May 2012, Westar Energy issued $300.0 million principal amount of first mortgage bonds at a discount yielding 4.157%, bearing stated interest at 4.125% and maturing in March 2042. These bonds constitute a further issuance of a series of bonds initially issued in March 2012 in the principal amount of $250.0 million, at a discount yielding 4.13%, bearing stated interest at 4.125% and maturing in March 2042. Proceeds from these issuances of $541.4 million were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds, and for working capital and general corporate purposes.

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

7. TAXES

We recorded income tax expense of $66.4 million with an effective income tax rate of 32% for the three months endedSeptember 30, 2012, and income tax expense of $61.7 million with an effective income tax rate of 31% for the same period of 2011. We recorded income tax expense of $107.2 million with an effective income tax rate of 31% for the nine months endedSeptember 30, 2012, and income tax expense of $94.8 million with an effective income tax rate of 31% for the same period of 2011. The increase in the effective income tax rate for the three months ended September 30, 2012, is due primarily to an increase in income before income taxes.

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

As of September 30, 2012, and December 31, 2011, our liability for unrecognized income tax benefits was $2.1 million and $2.5 million, respectively. The net decrease in the liability for unrecognized income tax benefits was largely attributable to tax positions taken with respect to the capitalization of plant related expenditures. We do not expect significant changes in this liability in the next 12 months.

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

As of September 30, 2012, and December 31, 2011, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

8. COMMITMENTS AND CONTINGENCIES

Federal Clean Air Act

We must comply with the federal Clean Air Act, state laws and implementing federal and state regulations that impose, among other things, limitations on pollutants generated from our operations, including sulfur dioxide (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and Environmental Protection Agency (EPA), we are required to install and maintain controls to reduce emissions found to cause or contribute to regional haze.

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Under the federal Clean Air Act, the EPA sets National Ambient Air Quality Standards (NAAQS) for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, CO and SO₂, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Recently the Wichita area exceeded the 8-hour ozone standard and may be designated nonattainment in the future.

In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.

Environmental Projects

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

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

Air Emissions

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

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which requires 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were scheduled to begin January 1, 2012, with further reductions required beginning January 1, 2014.

In December 2011, the EPA published a final supplemental rule to CSAPR requiring five states, including Missouri and Oklahoma, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this rule were scheduled to begin May 1, 2012. Although Kansas was included in the original proposed rule, the final supplemental rule instead called for the EPA to revisit Kansas' status under this supplemental rule once Kansas submitted an ozone state implementation plan.

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In October 2011, we and numerous other parties filed legal challenges to CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. In December 2011, the court issued its ruling to stay CSAPR, including the final supplemental rule, pending judicial review, which delayed CSAPR's implementation. After hearing arguments, a panel of three judges vacated CSAPR in August 2012 and remanded the rule to the EPA for further proceedings. In October 2012, the EPA filed a petition with the court requesting a rehearing before the full court. We cannot at this time predict the outcome of this request. Based on our current and planned environmental controls, if the regulations were to be reinstated or replaced, either partially or in whole, we do not believe the impact on our operations and consolidated financial results would be material.

Greenhouse Gases

Under EPA regulations known as the Tailoring Rule, the EPA is regulating greenhouse gas (GHG) emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs. The programs impose recordkeeping and monitoring requirements and also mandate the implementation of best available control technology (BACT) for projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our operations and consolidated financial results, but we believe the cost of compliance with the regulations could be material.

Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015 net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. During the third quarter of 2012, we began purchasing under 20-year supply contracts the renewable energy produced from approximately 370 MW of additional wind generation, which, together with existing facilities, supply contracts and renewable energy credits, will allow us to satisfy the net renewable generation requirement through 2015 and contribute toward meeting the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and KDHE entered into a consent agreement governing all future work at these sites. Under terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement, ONEOK, Inc. (ONEOK) assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in November 2012.

EPA Consent Decree

As part of the settlement of a lawsuit filed by the Department of Justice on behalf of the EPA, we will install selective catalytic reduction (SCR) equipment on one of three Jeffrey Energy Center (JEC) coal units by the end of 2014, which we estimate will cost approximately $240.0 million. The settlement also requires us to inform the EPA no later than December 31, 2012, whether we plan to install additional SCR equipment on another JEC unit in order to meet the plant-wide emissions limits agreed to in the settlement or whether we can meet the agreed upon emissions limits using other controls on the other two JEC coal units. We believe we can meet the terms of the settlement by installing less expensive NOx reduction equipment rather than additional SCR equipment. We plan to recover the costs to install these systems through our ECRR. Recovery of all or part of such costs remains subject to the approval of our regulators.

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FERC Investigation

A non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008 remains pending. In May 2009, FERC staff alleged that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs, and that we received $14.3 million of unjust profits through such activities. Based on our response to these allegations, 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. Additional communications with FERC staff took place in 2010 through August 2012 resulting in further reductions in the amounts of the alleged unjust profits and the unpaid charges for transmission service. We recorded a liability of $0.5 million as of December 31, 2011, related to the potential settlement of this investigation and the risks of litigating this matter to a final outcome. We increased the liability for this matter to $1.5 million during the three months ended September 30, 2012. Although we continue to believe 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 payments for alleged unjust profits and unpaid transmission costs as well as penalties, the amounts of which could be material.

9. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Note 5, "Rate Matters and Regulation," and Note 8, "Commitments and Contingencies," for additional information.

10. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2012			2011			2012			2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,889		$	4,019		$	514		$	451
Interest cost	9,894			9,958			1,575			1,698
Expected return on plan assets	(8,070		)	(7,772		)	(1,373		)	(1,250		)
Amortization of unrecognized:
Transition obligation, net	—			—			978			978
Prior service costs	153			303			631			631
Actuarial loss, net	8,194			5,915			376			175
Net periodic cost before regulatory adjustment	15,060			12,423			2,701			2,683
Regulatory adjustment (a)	615			(5,640		)	(261		)	308
Net periodic cost	$	15,675		$	6,783		$	2,440		$	2,991

 _______________

(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

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	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2012			2011			2012			2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	14,666		$	12,057		$	1,543		$	1,352
Interest cost	29,683			29,873			4,723			5,095
Expected return on plan assets	(24,212		)	(23,316		)	(4,118		)	(3,751		)
Amortization of unrecognized:
Transition obligation, net	—			—			2,934			2,934
Prior service costs	460			910			1,893			1,893
Actuarial loss, net	24,582			17,744			1,127			527
Net periodic cost before regulatory adjustment	45,179			37,268			8,102			8,050
Regulatory adjustment (a)	(8,635		)	(16,907		)	(12		)	934
Net periodic cost	$	36,544		$	20,361		$	8,090		$	8,984

 _______________

(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

During the nine months endedSeptember 30, 2012 and 2011, we contributed $56.7 million and $50.0 million, respectively, to the Westar Energy pension trust.

11. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2012			2011			2012		2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,516		$	1,239		$	48	$	41
Interest cost	1,884			1,843			103		115
Expected return on plan assets	(1,644		)	(1,476		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			13			14		14
Prior service costs	1			4			—		—
Actuarial loss, net	1,341			896			58		57
Net periodic cost before regulatory adjustment	3,098			2,519			223		227
Regulatory adjustment (a)	(212		)	(660		)	—		—
Net periodic cost	$	2,886		$	1,859		$	223	$	227

 _______________

(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

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	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2012			2011			2012		2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,547		$	3,718		$	144	$	124
Interest cost	5,653			5,527			308		344
Expected return on plan assets	(4,933		)	(4,429		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			39			43		43
Prior service costs	4			12			—		—
Actuarial loss, net	4,024			2,689			175		171
Net periodic cost before regulatory adjustment	9,295			7,556			670		682
Regulatory adjustment (a)	(1,726		)	(1,980		)	—		—
Net periodic cost	$	7,569		$	5,576		$	670	$	682

 _______________

(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

During the nine months endedSeptember 30, 2012 and 2011, we funded $11.9 million and $8.6 million, respectively, of Wolf Creek's pension plan contributions.

12. COMMON AND PREFERRED STOCK

Common Stock

During the nine months endedSeptember 30, 2012, Westar Energy entered into forward sale transactions with respect to an aggregate of approximately 1.4 million shares of common stock pursuant to an existing forward sale agreement. Westar Energy must settle such transactions within 18 months of the date each transaction was entered. Assuming physical share settlement of the forward sale transactions as of September 30, 2012, Westar Energy would have received aggregate proceeds of approximately $38.7 million based on a forward price of $27.61 per share.

Preferred Stock Redemption

In May2012, Westar Energy provided an irrevocable notice of redemption to holders of all of Westar Energy's preferred shares. Accordingly, we reduced preferred equity to zero, recognized the obligation to redeem the preferred shares as a liability and recognized the redemption premium as a preferred stock dividend during the three months ended June 30, 2012. Payment was due to holders of the preferred shares effective July 1, 2012. The table below shows the redemption amounts for all series of preferred stock.

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

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13. VARIABLE INTEREST ENTITIES

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

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

8% Interest in Jeffrey Energy Center

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

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.

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Financial Statement Impact

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIEs described above.

	As of		As of
	September 30, 2012		December 31, 2011
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	324,855	$	333,494
Regulatory assets (a)	5,585		4,915
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,660	$	28,114
Accrued interest (b)	7,342		4,448
Long-term debt of variable interest entities, net	242,521		249,283

_______________

(a) Included in long-term regulatory assets on our consolidated balance sheets.

(b) Included in accrued interest on our consolidated balance sheets.

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

14. LEASES

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 the master lease agreements. The lease terms for vehicles are from two to eight years depending on the type of vehicle. Computer equipment has lease terms of four to five years.

Effective August 2012 we signed an agreement to lease electrical facilities that connect the Ironwood Wind Farm to the transmission system. The agreement extends through August 2032, at which time it may be extended or we may exercise an option to purchase the line. The terms of the agreement meet the criteria of a capital lease; therefore, we recorded an $8.3 million capital lease during the third quarter of 2012.

Assets recorded under capital leases, including the August 2012 lease presented as generation plant, are listed below.

	As of			As of
	September 30, 2012			December 31, 2011
	(In Thousands)
Vehicles	$	12,130		$	14,241
Computer equipment	1,683			1,720
Generation plant	48,346			40,048
Accumulated amortization	(6,453		)	(6,485		)
Total capital leases	$	55,706		$	49,524

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Capital leases 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.

	As of
	September 30, 2012
	(In Thousands)
2012	$	1,616
2013	6,414
2014	6,236
2015	5,663
2016	4,970
Thereafter	81,263
	106,162
Amounts representing imputed interest	(49,245		)
Present value of net minimum lease payments under capital leases	56,917
Less: Current portion	3,001
Total long-term obligation under capital leases	$	53,916

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

INTRODUCTION

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

In Management's Discussion and Analysis, we discuss our operating results for the three and nine months endedSeptember 30, 2012, compared to the same periods of 2011, our general financial condition and significant changes that occurred during 2012. As you read Management's Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Earnings Per Share

Following is a summary of our net income and basic EPS.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011		Change			2012		2011		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to common stock	$	139,281	$	134,708	$	4,573		$	227,923	$	209,935	$	17,988
Earnings per common share, basic	1.10		1.15		(0.05		)	1.79		1.82		(0.03		)

The increases in net income attributable to common stock were due primarily to higher retail prices, including implementing the April 2012 KCC order, and, for the nine months ended September 30, 2012, our having recorded additional corporate-owned life insurance (COLI) benefits. These increases were offset partially by higher operating costs, authorized as part of the April 2012 KCC order, and our having recorded a $7.2 million gain on the sale of a non-utility investment during the third quarter of 2011 for which we did not record a similar gain this year. Also contributing to the higher operating costs was our having reversed $22.0 million of previously accrued liabilities during the third quarter of 2011 as a result of settling litigation. See the discussion under "—Operating Results" below for additional information. In addition, basic EPS decreased as a result of more average equivalent common shares outstanding due primarily to our having issued additional shares in the latter part of 2011 to settle forward sale transactions.

Rate Case Agreement

In April 2012, the KCC issued an order authorizing higher revenues to recover higher expenses primarily for increased tree trimming to enhance reliability and increased pension costs resulting from the consequences of the 2008 financial crisis in accordance with the regulatory mechanism in place to account for such pension costs. As a result of this order, we expect selling, general and administrative expense to increase $32.1 million and the cost of operating and maintaining our distribution system to increase $10.9 million on an annualized basis. In addition, we revised our depreciation rates to reflect changes in the estimated useful lives of some of our depreciable assets. The change in estimate will decrease annual depreciation expense by $43.6 million. However, decreased depreciation expense as a result of lower depreciation rates may be offset by additions to property, plant and equipment.

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Sustainable Cost Reduction Activities

We have been reviewing our operations to identify sustainable cost savings. This review involves process improvements, streamlining organizational structures, and developing other labor and non-labor efficiencies. To date in this ongoing effort, we have identified approximately $16.0 million of anticipated annualized savings and have recorded $4.5 million of expense for the nine months endedSeptember 30, 2012, related to achieving these cost savings.

Current Trends

The following is an update to and is to be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2011 Form 10-K.

Environmental Regulation

Environmental laws and regulations affecting power plants, which relate primarily to discharges into the air, air quality, discharges of effluents into water, the use of water, and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, continue to evolve and have become more stringent and costly over time. We have incurred and will continue to incur significant capital and other expenditures, and may potentially need to limit the use of some of our power plants, to comply with existing and new environmental laws and regulations. While certain of these costs are recoverable through the ECRR and ultimately we expect all such costs to be reflected in the prices we are allowed to charge, we cannot assure that all such costs will be recovered or that they will be recovered in a timely manner. See Note 8 of the Notes to Condensed Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding environmental laws and regulations.

Air Emissions

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

In July 2011, the EPA finalized CSAPR which requires 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were scheduled to begin January 1, 2012, with further reductions required beginning January 1, 2014.

In December 2011, the EPA published a final supplemental rule to CSAPR requiring five states, including Missouri and Oklahoma, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this rule were scheduled to begin May 1, 2012. Although Kansas was included in the original proposed rule, the final supplemental rule instead called for the EPA to revisit Kansas' status under this supplemental rule once Kansas submitted an ozone state implementation plan.

In October 2011, we and numerous other parties filed legal challenges to CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. In December 2011, the court issued its ruling to stay CSAPR, including the final supplemental rule, pending judicial review, which delayed CSAPR's implementation. After hearing arguments, a panel of three judges vacated CSAPR in August 2012 and remanded the rule to the EPA for further proceedings. In October 2012, the EPA filed a petition with the court requesting a rehearing before the full court. We cannot at this time predict the outcome of this request. Based on our current and planned environmental controls, if the regulations were to be reinstated or replaced, either partially or in whole, we do not believe the impact on our operations and consolidated financial results would be material.

Greenhouse Gases

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

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Under EPA regulations known as the Tailoring Rule, the EPA is regulating GHG emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs. The programs impose recordkeeping and monitoring requirements and also mandate the implementation of BACT for projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our operations and consolidated financial results, but we believe the costs to comply with the regulations could be material.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash, which we must handle, dispose of, recycle or process. We recycle some of our ash production, principally by selling to the aggregate industry. In June 2010, the EPA proposed a rule to regulate CCBs, which we believe might curtail or impair our ability to recycle ash. The EPA is expected to issue a final rule in 2013. While we cannot at this time estimate the impact and costs associated with future regulations of CCBs, we believe the impact on our operations and consolidated financial results could be material.

National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets NAAQS for six criteria emissions considered harmful to public health and the environment, including PM, NOx, CO and SO₂, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Recently the Wichita area exceeded the 8-hour ozone standard and may be designated nonattainment in the future.

In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.

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

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

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. The EPA plans to propose revisions to the rules governing such discharges from coal-fired power plants later in 2012 with final action on the proposed rules expected to occur in 2014. Although we cannot at this time determine the timing or impact of any new regulations, more stringent regulations could have a material impact on our operations and consolidated financial results.

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

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Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015, net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. During the third quarter of 2012, we began purchasing under 20-year supply contracts the renewable energy produced from approximately 370 MW of additional wind generation, which, together with existing facilities, supply contracts and renewable energy credits, will allow us to satisfy the net renewable generation requirement through 2015 and contribute toward meeting the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

Wolf Creek Regulation and Operating Costs

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

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our condensed consolidated financial statements, which have been prepared in conformity with the instructions to Form 10-Q and Article 10 of Regulation S-X. Note 2 of the Notes to Condensed Consolidated Financial Statements, "Summary of Significant Accounting Policies," contains a summary of our significant accounting policies, many of which require estimates and assumptions by management. The policies highlighted in our 2011 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2011, through September 30, 2012, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2011 Form 10-K.

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OPERATING RESULTS

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

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

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

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Margins realized from sales based on prevailing market prices generally serve to offset our retail prices and the prices charged to certain wholesale customers taking service under cost-based tariffs.

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

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

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

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Three and Nine Months EndedSeptember 30, 2012, Compared to Three and Nine Months EndedSeptember 30, 2011

Below we discuss our operating results for the three and nine months endedSeptember 30, 2012, compared to the results for the three and nine months endedSeptember 30, 2011. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.

	Three Months Ended September 30,											Nine Months Ended September 30,
	2012			2011			Change			% Change		2012			2011			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	250,757		$	246,756		$	4,001		1.6		$	566,069		$	556,784		$	9,285		1.7
Commercial	194,032			188,070			5,962			3.2		493,814			470,452			23,362			5.0
Industrial	96,656			98,060			(1,404		)	(1.4	)	278,036			268,501			9,535			3.6
Other retail	6,407			(3,304		)	9,711			293.9		1,125			(8,759		)	9,884			112.8
Total Retail Revenues	547,852			529,582			18,270			3.4		1,339,044			1,286,978			52,066			4.0
Wholesale	88,784			101,086			(12,302		)	(12.2	)	228,966			257,195			(28,229		)	(11.0	)
Transmission (a)	49,137			39,075			10,062			25.8		144,480			115,411			29,069			25.2
Other	9,985			8,409			1,576			18.7		25,208			25,179			29			0.1
Total Revenues	695,758			678,152			17,606			2.6		1,737,698			1,684,763			52,935			3.1
OPERATING EXPENSES:
Fuel and purchased power	177,506			199,540			(22,034		)	(11.0	)	452,840			486,697			(33,857		)	(7.0	)
Operating and maintenance	149,001			137,823			11,178			8.1		461,515			412,429			49,086			11.9
Depreciation and amortization	65,061			72,202			(7,141		)	(9.9	)	204,640			213,551			(8,911		)	(4.2	)
Selling, general and administrative	54,300			27,499			26,801			97.5		164,346			132,233			32,113			24.3
Total Operating Expenses	445,868			437,064			8,804			2.0		1,283,341			1,244,910			38,431			3.1
INCOME FROM OPERATIONS	249,890			241,088			8,802			3.7		454,357			439,853			14,504			3.3
OTHER INCOME (EXPENSE):
Investment earnings	2,729			2,914			(185		)	(6.3	)	6,456			6,255			201			3.2
Other income	6,115			3,404			2,711			79.6		27,242			8,210			19,032			231.8
Other expense	(6,278		)	(5,470		)	(808		)	(14.8	)	(14,246		)	(13,951		)	(295		)	(2.1	)
Total Other Income	2,566			848			1,718			202.6		19,452			514			18,938			(b)
Interest expense	45,017			43,844			1,173			2.7		131,886			130,681			1,205			0.9
INCOME BEFORE INCOME TAXES	207,439			198,092			9,347			4.7		341,923			309,686			32,237			10.4
Income tax expense	66,372			61,700			4,672			7.6		107,156			94,812			12,344			13.0
NET INCOME	141,067			136,392			4,675			3.4		234,767			214,874			19,893			9.3
Less: Net income attributable to noncontrolling interests	1,786			1,442			344			23.9		5,228			4,212			1,016			24.1
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	139,281			134,950			4,331			3.2		229,539			210,662			18,877			9.0
Preferred dividends	—			242			(242		)	(100.0	)	1,616			727			889			122.3
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	139,281		$	134,708		$	4,573		3.4		$	227,923		$	209,935		$	17,988		8.6
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.10		$	1.15		$	(0.05	)	(4.3	)	$	1.79		$	1.82		$	(0.03	)	(1.6	)

 _______________

(a) Reflects revenue from an SPP network transmission tariff. For the three and nine months endedSeptember 30, 2012, our SPP network transmission costs were $42.5 million and $124.1 million, respectively. These amounts, less administration costs of $7.0 million and $20.0 million, respectively, were returned to us as revenue. For the three and nine months endedSeptember 30, 2011, our SPP network transmission costs were $33.9 million and $98.6 million, respectively. These amounts, less administration costs of $5.3 million and $13.6 million, respectively, were returned to us as revenue.

(b) Change greater than 1000%.

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Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. For this reason, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. However, we record transmission costs as operating and maintenance expense on our consolidated statements of income. The following table summarizes our gross margin for the three and nine months endedSeptember 30, 2012 and 2011.

	Three Months Ended September 30,										Nine Months Ended September 30,
	2012		2011			Change			% Change		2012		2011			Change			% Change
	(Dollars In Thousands)
REVENUES:
Residential	$	250,757	$	246,756		$	4,001		1.6		$	566,069	$	556,784		$	9,285		1.7
Commercial	194,032		188,070			5,962			3.2		493,814		470,452			23,362			5.0
Industrial	96,656		98,060			(1,404		)	(1.4	)	278,036		268,501			9,535			3.6
Other retail	6,407		(3,304		)	9,711			293.9		1,125		(8,759		)	9,884			112.8
Total Retail Revenues	547,852		529,582			18,270			3.4		1,339,044		1,286,978			52,066			4.0
Wholesale	88,784		101,086			(12,302		)	(12.2	)	228,966		257,195			(28,229		)	(11.0	)
Transmission	49,137		39,075			10,062			25.8		144,480		115,411			29,069			25.2
Other	9,985		8,409			1,576			18.7		25,208		25,179			29			0.1
Total Revenues	695,758		678,152			17,606			2.6		1,737,698		1,684,763			52,935			3.1
Less: Fuel and purchased power expense	177,506		199,540			(22,034		)	(11.0	)	452,840		486,697			(33,857		)	(7.0	)
SPP network transmission costs	42,516		33,887			8,629			25.5		124,142		98,623			25,519			25.9
Gross Margin	$	475,736	$	444,725		$	31,011		7.0		$	1,160,716	$	1,099,443		$	61,273		5.6

The following table reflects changes in electricity sales for the three and nine months endedSeptember 30, 2012 and 2011. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012	2011	Change		% Change		2012	2011	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	2,270	2,372	(102	)	(4.3	)	5,314	5,579	(265	)	(4.7	)
Commercial	2,215	2,232	(17	)	(0.8	)	5,841	5,825	16		0.3
Industrial	1,437	1,528	(91	)	(6.0	)	4,216	4,304	(88	)	(2.0	)
Other retail	20	21	(1	)	(4.8	)	63	66	(3	)	(4.5	)
Total Retail	5,942	6,153	(211	)	(3.4	)	15,434	15,774	(340	)	(2.2	)
Wholesale	2,094	2,122	(28	)	(1.3	)	5,391	5,808	(417	)	(7.2	)
Total	8,036	8,275	(239	)	(2.9	)	20,825	21,582	(757	)	(3.5	)

Gross margin increased for the three and nine months ended September 30, 2012, due primarily to higher retail revenues that were the result of higher prices offset partially by lower retail electricity sales. The lower retail electricity sales were attributable principally to moderate weather, which particularly impacted residential electricity sales, and reduced production for certain industrial customers. As measured by cooling degree days, the weather during the three months ended September 30, 2012, was 9% cooler than the same period of 2011. For the nine months ended September 30, 2012, cooling degree days were similar to last year, but heating degree days were 34% lower than the same period last year.

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Income from operations is the most directly comparable measure to our presentation of gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the three and nine months endedSeptember 30, 2012 and 2011.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2012		2011		Change			% Change		2012		2011		Change			% Change
	(Dollars In Thousands)
Gross margin	$	475,736	$	444,725	$	31,011		7.0		$	1,160,716	$	1,099,443	$	61,273		5.6
Add: SPP network transmission costs	42,516		33,887		8,629			25.5		124,142		98,623		25,519			25.9
Less: Operating and maintenance expense	149,001		137,823		11,178			8.1		461,515		412,429		49,086			11.9
Depreciation and amortization expense	65,061		72,202		(7,141		)	(9.9	)	204,640		213,551		(8,911		)	(4.2	)
Selling, general and administrative expense	54,300		27,499		26,801			97.5		164,346		132,233		32,113			24.3
Income from operations	$	249,890	$	241,088	$	8,802		3.7		$	454,357	$	439,853	$	14,504		3.3

Operating Expenses and Other Income and Expense Items

	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	149,001	$	137,823	$	11,178	8.1	$	461,515	$	412,429	$	49,086	11.9

Operating and maintenance expense increased due principally to:

• higher SPP network transmission costs of $8.6 million and $25.5 million, respectively, most of which is offset with higher revenues;

• increases in property taxes of $4.0 million and $9.3 million, respectively, most of which is offset in retail revenues; and

• for the nine months ended September 30, 2012, higher costs at Wolf Creek of $7.9 million, which were the result primarily of maintenance costs incurred during an unscheduled outage, and higher costs for tree trimming and other reliability activities of $2.7 million.

Partially offsetting the increases for the three months ended September 30, 2012, was a $2.1 million decrease in the amortization of deferred refueling and maintenance outage costs for Wolf Creek. This was attributable principally to moving the next planned refueling and maintenance outage from fall 2012 to the first quarter of 2013, which extended the amortization period for the costs related to the most recent refueling and maintenance outage.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2012		2011		Change			% Change		2012		2011		Change			% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	65,061	$	72,202	$	(7,141	)	(9.9	)	$	204,640	$	213,551	$	(8,911	)	(4.2	)

Depreciation and amortization expense decreased as a result of our having reduced depreciation rates to reflect changes in the estimated useful lives of some of our assets. Partially offsetting this decrease was additional depreciation expense associated primarily with additions at our power plants, including air quality controls, and the addition of transmission facilities.

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	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	54,300	$	27,499	$	26,801	97.5	$	164,346	$	132,233	$	32,113	24.3

Selling, general and administrative expense increased due primarily to:

• our having reversed $22.0 million of previously accrued liabilities during the third quarter of 2011 as a result of settling litigation;

• higher pension and other employee benefit costs of $3.5 million and $15.4 million, respectively;

• our having recorded expense of $2.7 million and $4.5 million, respectively, as a result of sustainable cost reduction activities; and

• for the nine months ended September 30, 2012, a $1.7 million increase in the amortization of previously deferred amounts associated with various energy efficiency programs, which we recover in retail revenues.

Partially offsetting the increases for the nine months ended September 30, 2012, were lower legal fees of $8.7 million. During the nine months ended September 30, 2011, we incurred legal fees related to arbitration and litigation. There were no similar legal fees during the same period of 2012.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2012		2011		Change			% Change		2012		2011		Change		% Change
	(Dollars in Thousands)
Investment earnings	$	2,729	$	2,914	$	(185	)	(6.3	)	$	6,456	$	6,255	$	201	3.2

Investment earnings decreased for the three months ended September 30, 2012, compared to the same period last year due primarily to our having recorded a $7.2 million gain on the sale of a non-utility investment in 2011 for which we did not record similar gains this year. Partially offsetting this decrease was our having recorded gains of $2.0 million on investments in a trust to fund retirement benefits compared to recording losses of $4.7 million on these investments in 2011.

Investment earnings increased for the nine months ended September 30, 2012, compared to the same period last year due principally to improved performance of the trust investments discussed above. During the nine months ended September 30, 2012, we recorded gains of $4.7 million on these investments compared to recording losses of $2.1 million during the same period of 2011. Contributing to the increase was a $1.4 million increase in our equity in the earnings of the Prairie Wind Transmission, LLC joint venture. These increases were offset partially by the $7.2 million gain recorded in 2011 as discussed above.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Other income	$	6,115	$	3,404	$	2,711	79.6	$	27,242	$	8,210	$	19,032	231.8

Other income increased due principally to:

• increases in equity AFUDC of $1.3 million and $4.6 million, respectively, which reflect increased construction activity in 2012;

• our having recorded an additional $0.8 million and $1.2 million, respectively, related to the sale of oil inventory; and

• for the nine months ended September 30, 2012, our having recorded an additional $12.7 million in COLI benefits.

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	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	66,372	$	61,700	$	4,672	7.6	$	107,156	$	94,812	$	12,344	13.0

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

FINANCIAL CONDITION

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

	As of		As of
	September 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	249,285	$	229,118	$	20,167	8.8

Fuel inventory and supplies increased due principally to an $18.5 million increase in coal inventory. Coal inventory volumes increased 28% resulting from less coal being consumed due primarily to decreased production at our coal plants as a result of mild winter weather and scheduled outages.

	As of		As of
	September 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	6,856,350	$	6,411,922	$	444,428	6.9

Property, plant and equipment, net of accumulated depreciation, increased due primarily to our ongoing installation of air quality controls at our power plants.

	As of		As of
	September 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	1,005,610	$	1,046,090	$	(40,480	)	(3.9	)
Regulatory liabilities	334,550		271,387		63,163			23.3
Net regulatory assets	$	671,060	$	774,703	$	(103,643	)	(13.4	)

Regulatory assets decreased due principally to the following reasons:

•a $25.1 million decrease in deferred employee benefit costs;

•a $10.9 million decrease in previously deferred storm costs;

•a $9.9 million decrease in amounts deferred for the Wolf Creek outage; and

•a $5.2 million decrease in amounts previously deferred for fuel expense; however,

•partially offsetting decreases was an $8.7 million increase in amounts deferred for property taxes.

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

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	As of		As of
	September 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Long-term debt, net	$	2,819,118	$	2,491,109	$	328,009	13.2

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

	As of		As of
	September 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,213,816	$	1,110,463	$	103,353	9.3

Net deferred income taxes increased due primarily to the use of bonus and accelerated depreciation methods and deferred net operating losses during the period resulting in increases of $86.4 million and $20.6 million, respectively.

	As of		As of
	September 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Accrued employee benefits	$	542,657	$	592,617	$	(49,960	)	(8.4	)

Accrued employee benefits decreased due primarily to our having contributed $56.7 million to the Westar Energy pension trust and our having funded $11.9 million of Wolf Creek's pension plan contributions.

	As of		As of
	September 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Cumulative preferred stock	$	—	$	21,436	$	(21,436	)	(100.0	)

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy's revolving credit facilities and commercial paper program, and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and temporary borrowings from the commercial paper program and revolving credit facilities. To meet the cash requirements for our capital investments, we expect to use internally generated cash, temporary borrowings from commercial paper issuances and revolving credit facilities, as well as the issuance of debt and equity securities in the capital markets. We also use proceeds from the issuance of securities to repay short-term borrowings, which are principally related to investments in capital equipment, when such balances are of sufficient size and it makes economic sense to do so, and for working capital and general corporate purposes. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in "—Operating Results" above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets.

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Short-Term Borrowings

Westar Energy has entered into a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy's revolving credit facilities described below. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to repay borrowings under Westar Energy's revolving credit facilities, for working capital and/or for other general corporate purposes. As of October 31, 2012, Westar Energy had issued $234.3 million of commercial paper.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million, which terminate on September 29, 2016, and February 18, 2015, respectively. As long as there is no default under the facilities, each may be extended up to an additional two years and the aggregate amount of borrowings under the facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE first mortgage bonds. As of October 31, 2012, $0.5 million were borrowed and $13.8 million of letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date. In addition, total combined borrowings under the commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time.

Debt Financing

In May 2012, Westar Energy issued $300.0 million principal amount of first mortgage bonds at a discount yielding 4.157%, bearing stated interest at 4.125% and maturing in March 2042. These bonds constitute a further issuance of a series of bonds initially issued in March 2012 in the principal amount of $250.0 million, at a discount yielding 4.13%, bearing stated interest at 4.125% and maturing in March 2042. Proceeds from these issuances of $541.4 million were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds, and for working capital and general corporate purposes.

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

Debt Covenants

We remain in compliance with our debt covenants.

Impact of Credit Ratings on Debt Financing

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

In general, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy's revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy's ability to borrow under the credit facilities and commercial paper program are not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

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

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

	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Unsecured Debt Rating	Westar Energy Commercial Paper	Rating Outlook
Moody’s	A3	A3	Baa2	P-2	Stable
S&P	BBB+	BBB+	BBB	A-2	Stable
Fitch	A-	A-	BBB+	F2	Stable

Certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit risk-related contingent features that were in a liability position as of September 30, 2012, and December 31, 2011, was $0.3 million and $3.1 million, respectively, for which we had posted no collateral, including independent amounts. If all credit-risk-related contingent features underlying these agreements had been triggered as of September 30, 2012, and December 31, 2011, we would have been required to provide to our counterparties $0.2 million and $0.5 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Common and Preferred Stock

Common Stock

During the nine months endedSeptember 30, 2012, Westar Energy entered into forward sale transactions with respect to an aggregate of approximately 1.4 million shares of common stock pursuant to an existing forward sale agreement. Westar Energy must settle such transactions within 18 months of the date each transaction was entered. Assuming physical share settlement of the forward sale transactions as of September 30, 2012, Westar Energy would have received aggregate proceeds of approximately $38.7 million based on a forward price of $27.61 per share.

Preferred Stock Redemption

In May2012, Westar Energy provided an irrevocable notice of redemption to holders of all of Westar Energy's preferred shares. Pursuant to Westar Energy's Articles of Incorporation, we deposited cash in a separate account to effect the redemption of all of our preferred stock outstanding. Payment was due to holders of the preferred shares effective July 1, 2012. The table below shows the redemption amounts for all series of preferred stock.

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

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Summary of Cash Flows

	Nine Months Ended September 30,
	2012			2011			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	453,956		$	337,777		$	116,179		34.4
Investing activities	(601,315		)	(518,745		)	(82,570		)	(15.9	)
Financing activities	148,199			184,633			(36,434		)	(19.7	)
Net increase in cash and cash equivalents	$	840		$	3,665		$	(2,825	)	(77.1	)

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having paid approximately $106.5 million less for fuel and purchased power, our having paid $56.3 million in 2011 to settle litigation, and our having received about $55.2 million more from retail customers. Increases were partially offset by our having received approximately $44.1 million less from wholesale customers, our having paid $29.7 million in 2012 to settle treasury yield hedge transactions, our having received $11.5 million less in income tax refunds and our having paid $9.7 million more for pension and post-retirement benefit plan contributions.

Cash Flows used in Investing Activities

Cash flows used in investing activities increased due primarily to our having invested $85.8 million more in additions to property, plant and equipment. Partially offsetting this increased investment was our having received $15.6 million more in proceeds from our investment in COLI.

Cash Flows from Financing Activities

Cash flows from financing activities decreased due primarily to our having repaid $71.5 million of short-term borrowings this year compared to our having borrowed $159.8 million during the nine months ended September 30, 2011. Further decreasing cash flows from financing activities was our having retired $220.2 million more of long-term debt, our having received $91.2 million less from common stock issuances, our having established a $22.6 million restricted cash account to fund the redemption of preferred stock, our having paid $16.0 million more for dividends and our having repaid $15.3 million more for borrowings against the cash surrender value of COLI. Partially offsetting decreases in financing activities was our having received $541.4 million in proceeds from long-term debt issuances and our having retired $21.3 million less of long-term debt of VIEs.

Pension Contribution

During the nine months endedSeptember 30, 2012, we contributed $56.7 million to the Westar Energy pension trust and funded $11.9 million of Wolf Creek's pension plan contributions.

OFF-BALANCE SHEET ARRANGEMENTS

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

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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

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OTHER INFORMATION

Changes in Prices

KCC Proceedings

In September 2012, the KCC issued a final order approving an adjustment to our prices that we implemented in April 2012. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below and is expected to increase our annual retail revenues by approximately $36.7 million.

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

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

FERC Proceedings

Our transmission formula rate that includes projected 2012 transmission capital expenditures and operating costs was effective in January 2012 and is expected to increase annual transmission revenues by approximately $38.2 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

Wolf Creek Outage

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

Fair Value of Energy Marketing Contracts

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

	Fair Value of  Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2011 (a)	$	9,378
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period	(884		)
Changes in fair value of contracts outstanding at the beginning and end of the period	(731		)
Fair value of new contracts entered into during the period	(308		)
Net fair value of contracts outstanding as of September 30, 2012 (b)	$	7,455

_______________

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

(b) Approximately $0.1 million and $4.7 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.

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The sources of the fair values of the financial instruments related to these contracts and the maturity periods of the contracts as of September 30, 2012, are summarized in the following table.

	Fair Value of Contracts at End of Period
Sources of Fair Value	Total Fair Value			Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity Over 5 Years
	(Dollars In Thousands)
Prices provided by other external sources (swaps and forwards)	$	7,896		$	2,822		$	5,074		$	—	$	—
Prices based on option pricing models (options and other) (a)	(441		)	(10		)	(431		)	—		—
Total fair value of contracts outstanding	$	7,455		$	2,812		$	4,643		$	—	$	—

_______________

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including changes in commodity prices, counterparty credit, interest rates, and debt and equity instrument values. From December 31, 2011, to September 30, 2012, no significant changes occurred in our market risk exposure. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our 2011 Form 10-K for additional information.

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 endedSeptember 30, 2012, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.    OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 5, 8 and 9 of the Notes to Condensed Consolidated Financial Statements, "Rate Matters and Regulation," "Commitments and Contingencies" and "Legal Proceedings," respectively, which are incorporated herein by reference.

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ITEM 1A. RISK FACTORS

Security breaches, criminal activity, terrorist attacks and other disruptions to our information technology infrastructure could directly or indirectly interfere with our operations, could expose us or our customers or employees to a risk of loss, and could expose us to liability, regulatory penalties, reputational damage and other harm to our business.

We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. Our technology networks and systems collect and store sensitive data including system operating information, propriety business information belonging to us and third parties, and personal information belonging to our customers and employees.

Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, or other disruptions during software or hardware upgrades, telecommunication failures or natural disasters or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. We cannot accurately assess the probability that a security breach may occur, despite the measures that we take to prevent such a breach, and we are unable to quantify the potential impact of such an event. We can provide no assurance that we will identify and remedy all security or system vulnerabilities or that unauthorized access or error will be identified and remedied.

Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. Our facilities could be direct targets or indirect casualties of such attacks. The effects of such attacks could include disruption to our generation, transmission and distribution systems or to the electrical grid in general, and could increase the cost of insurance coverage or result in a decline in the U.S. economy.

     There were no other material changes in our risk factors from December 31, 2011, through September 30, 2012. For additional information, see our 2011 Form 10-K.

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

In addition to information included in our Form 10-Q filed on August 7, 2012, during the three-month period ended September 30, 2012, Westar Energy entered into forward transactions pursuant to the forward sale agreement dated April 2, 2010, between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on April 2, 2010) and the Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.3 to the Form S-3 filed on April 2, 2010), as amended on May 26, 2010, (filed as Exhibit 1(a) to the Form 10-Q filed on August 7, 2012) and May 9, 2012 (filed as Exhibit 1(b) to the Form 10-Q filed on May 9, 2012), in respect to an aggregate of approximately 0.3 million shares of Westar Energy common stock.

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

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

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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, 2012
31(b)	Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 2012
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2012 (furnished and not to be considered filed as part of the Form 10-Q)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

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

		WESTAR ENERGY, INC.
Date:	November 8, 2012	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

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