Edgar Filing: WESTAR ENERGY INC /KS

WR-09.30.2013-10Q

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, 2013



[ ]	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		127,154,166 shares
(Class)		(Outstanding at October 30, 2013)

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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	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43

PART II. Other Information
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
Signature		46

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GLOSSARY OF TERMS

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



Abbreviation or Acronym		Definition
2012 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2012
AFUDC		Allowance for funds used during construction
BACT		Best Available Control Technology
CAMR		Clean Air Mercury Rule
CCB		Coal combustion byproduct
CO		Carbon monoxide
CO₂		Carbon dioxide
COLI		Corporate-owned life insurance
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
IRS		Internal Revenue Service
JEC		Jeffrey Energy Center
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
MATS		Mercury and Air Toxics Standards
Moody’s		Moody’s Investors Service
MWh		Megawatt hour(s)
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen oxides
NSPS		New Source Performance Standard
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

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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, including with respect to emerging distributed generation technologies,


-	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 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,

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-	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, 2012 (2012 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 2012 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 2012 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.

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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, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,923	$	5,829
Restricted cash	387		573
Accounts receivable, net of allowance for doubtful accounts of $3,073 and $4,916, respectively	266,533		224,439
Fuel inventory and supplies	237,591		249,016
Prepaid expenses	12,780		15,847
Regulatory assets	145,909		114,895
Other	21,149		32,476
Total Current Assets	694,272		643,075
PROPERTY, PLANT AND EQUIPMENT, NET	7,350,935		7,013,765
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	299,312		321,975
OTHER ASSETS:
Regulatory assets	850,423		887,777
Nuclear decommissioning trust	167,548		150,754
Other	243,345		247,885
Total Other Assets	1,261,316		1,286,416
TOTAL ASSETS	$	9,605,835	$	9,265,231
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	250,000	$	—
Current maturities of long-term debt of variable interest entities	27,764		25,942
Short-term debt	52,100		339,200
Accounts payable	178,213		180,825
Accrued dividends	43,199		41,743
Accrued taxes	100,180		58,624
Accrued interest	65,817		77,891
Regulatory liabilities	40,179		37,557
Other	96,643		84,359
Total Current Liabilities	854,095		846,141
LONG-TERM LIABILITIES:
Long-term debt, net	2,968,797		2,819,271
Long-term debt of variable interest entities, net	195,074		222,743
Deferred income taxes	1,296,909		1,197,837
Unamortized investment tax credits	189,140		191,512
Regulatory liabilities	286,475		285,618
Accrued employee benefits	550,037		564,870
Asset retirement obligations	158,904		152,648
Other	69,204		74,336
Total Long-Term Liabilities	5,714,540		5,508,835
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 127,064,039 shares and 126,503,748 shares, respective to each date	635,320		632,519
Paid-in capital	1,669,792		1,656,972
Retained earnings	727,568		606,649
Total Westar Energy, Inc. Shareholders’ Equity	3,032,680		2,896,140
Noncontrolling Interests	4,520		14,115
Total Equity	3,037,200		2,910,255
TOTAL LIABILITIES AND EQUITY	$	9,605,835	$	9,265,231

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Three Months Ended September 30,
	2013			2012
REVENUES	$	694,974		$	695,758
OPERATING EXPENSES:
Fuel and purchased power	178,562			177,506
Operating and maintenance	169,100			149,001
Depreciation and amortization	68,861			65,061
Selling, general and administrative	54,245			54,300
Total Operating Expenses	470,768			445,868
INCOME FROM OPERATIONS	224,206			249,890
OTHER INCOME (EXPENSE):
Investment earnings	2,863			2,729
Other income	12,321			6,115
Other expense	(6,195		)	(6,278		)
Total Other Income	8,989			2,566
Interest expense	45,708			45,017
INCOME BEFORE INCOME TAXES	187,487			207,439
Income tax expense	52,392			66,372
NET INCOME	135,095			141,067
Less: Net income attributable to noncontrolling interests	1,970			1,786
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	133,125		$	139,281
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.04		$	1.10
Diluted earnings per common share	$	1.04		$	1.09
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	127,444,792			126,783,248
Diluted	128,111,472			127,134,524
DIVIDENDS DECLARED PER COMMON SHARE	$	0.34		$	0.33

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Nine Months Ended September 30,
	2013			2012
REVENUES	$	1,810,776		$	1,737,698
OPERATING EXPENSES:
Fuel and purchased power	483,014			452,840
Operating and maintenance	491,132			461,515
Depreciation and amortization	203,305			204,640
Selling, general and administrative	157,668			164,346
Total Operating Expenses	1,335,119			1,283,341
INCOME FROM OPERATIONS	475,657			454,357
OTHER INCOME (EXPENSE):
Investment earnings	8,612			6,456
Other income	29,748			27,242
Other expense	(13,911		)	(14,246		)
Total Other Income	24,449			19,452
Interest expense	135,790			131,886
INCOME BEFORE INCOME TAXES	364,316			341,923
Income tax expense	106,514			107,156
NET INCOME	257,802			234,767
Less: Net income attributable to noncontrolling interests	6,344			5,228
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	251,458			229,539
Preferred dividends	—			1,616
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	251,458		$	227,923
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.97		$	1.79
Diluted earnings per common share	$	1.96		$	1.79
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	127,318,462			126,638,992
Diluted	127,851,477			126,855,386
DIVIDENDS DECLARED PER COMMON SHARE	$	1.02		$	0.99

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	257,802		$	234,767
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	203,305			204,640
Amortization of nuclear fuel	15,270			16,658
Amortization of deferred regulatory gain from sale leaseback	(4,121		)	(4,121		)
Amortization of corporate-owned life insurance	10,442			17,062
Non-cash compensation	6,148			5,482
Net deferred income taxes and credits	107,709			106,730
Stock-based compensation excess tax benefits	(502		)	(1,628		)
Allowance for equity funds used during construction	(9,473		)	(9,096		)
Changes in working capital items:
Accounts receivable	(42,400		)	(40,740		)
Fuel inventory and supplies	13,842			(19,634		)
Prepaid expenses and other	2,992			14,680
Accounts payable	2,088			(7,201		)
Accrued taxes	44,573			40,825
Other current liabilities	(53,042		)	(88,402		)
Changes in other assets	(22,682		)	(1,061		)
Changes in other liabilities	21,159			(15,005		)
Cash Flows from Operating Activities	553,110			453,956
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(557,988		)	(598,426		)
Purchase of securities - trusts	(61,495		)	(18,684		)
Sale of securities - trusts	76,906			19,808
Investment in corporate-owned life insurance	(17,724		)	(18,404		)
Proceeds from investment in corporate-owned life insurance	147,591			16,501
Proceeds from federal grant	876			4,470
Investment in affiliated company	(2,694		)	(6,550		)
Other investing activities	(2,886		)	(30		)
Cash Flows used in Investing Activities	(417,414		)	(601,315		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(287,741		)	(71,544		)
Proceeds from long-term debt	492,572			541,374
Retirements of long-term debt	(100,000		)	(220,563		)
Retirements of long-term debt of variable interest entities	(25,498		)	(7,765		)
Repayment of capital leases	(2,262		)	(1,984		)
Borrowings against cash surrender value of corporate-owned life insurance	57,948			64,479
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(145,418		)	(18,369		)
Stock-based compensation excess tax benefits	502			1,628
Preferred stock redemption	—			(22,567		)
Issuance of common stock	4,526			5,348
Distributions to shareholders of noncontrolling interests	(1,657		)	(3,252		)
Cash dividends paid	(121,875		)	(118,586		)
Other financing activities	(2,699		)	—
Cash Flows (used in) from Financing Activities	(131,602		)	148,199
NET CHANGE IN CASH AND CASH EQUIVALENTS	4,094			840
CASH AND CASH EQUIVALENTS:
Beginning of period	5,829			3,539
End of period	$	9,923		$	4,379

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

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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, 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	—		—			185,604	928		4,420			—			—			5,348
Issuance of stock for compensation and reinvested dividends	—		—			485,073	2,425		4,126			—			—			6,551
Stock redemption	(214,363	)	(21,436		)	—	—		—			—			—			(21,436		)
Tax withholding related to stock compensation	—		—			—	—		(3,318		)	—			—			(3,318		)
Preferred dividends	—		—			—	—		—			(1,616		)	—			(1,616		)
Dividends on common stock ($0.99 per share)	—		—			—	—		—			(126,091		)	—			(126,091		)
Stock compensation expense	—		—			—	—		5,443			—			—			5,443
Tax benefit on stock compensation	—		—			—	—		1,628			—			—			1,628
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

Balance as of December 31, 2012	—		$	—		126,503,748	$	632,519	$	1,656,972		$	606,649		$	14,115		$	2,910,255
Net income	—		—			—	—		—			251,458			6,344			257,802
Issuance of stock	—		—			143,602	718		3,808			—			—			4,526
Issuance of stock for compensation and reinvested dividends	—		—			416,689	2,083		4,850			—			—			6,933
Tax withholding related to stock compensation	—		—			—	—		(2,425		)	—			—			(2,425		)
Dividends on common stock ($1.02 per share)	—		—			—	—		—			(130,539		)	—			(130,539		)
Stock compensation expense	—		—			—	—		6,085			—			—			6,085
Tax benefit on stock compensation	—		—			—	—		502			—			—			502
Deconsolidation of variable interest entity	—		—			—	—		—			—			(14,282		)	(14,282		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(1,657		)	(1,657		)
Balance as of September 30, 2013	—		$	—		127,064,039	$	635,320	$	1,669,792		$	727,568		$	4,520		$	3,037,200

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

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 693,000 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 2012 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 ended September 30, 2013, 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 in 2012 to effect the redemption of all of Westar Energy's preferred stock.

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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, 2013		December 31, 2012
	(In Thousands)
Fuel inventory	$	78,517	$	94,664
Supplies	159,074		154,352
Fuel inventory and supplies	$	237,591	$	249,016

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,
	2013			2012			2013			2012
	(Dollars In Thousands)
Borrowed funds	$	2,964		$	2,132		$	8,132		$	8,091
Equity funds	3,783			2,317			9,473			9,096
Total	$	6,747		$	4,449		$	17,605		$	17,187
Average AFUDC Rates	5.1		%	4.6		%	4.6		%	5.2		%

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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	135,095	$	141,067	$	257,802	$	234,767
Less: Net income attributable to noncontrolling interests	1,970		1,786		6,344		5,228
Net income attributable to Westar Energy, Inc.	133,125		139,281		251,458		229,539
Less: Preferred dividends	—		—		—		1,616
Net income allocated to RSUs	372		397		703		652
Net income allocated to common stock	$	132,753	$	138,884	$	250,755	$	227,271

Weighted average equivalent common shares outstanding – basic	127,444,792		126,783,248		127,318,462		126,638,992
Effect of dilutive securities:
RSUs	46,189		169,900		36,738		151,022
Forward sale agreements	620,491		181,376		496,277		65,372
Weighted average equivalent common shares outstanding – diluted (a)	128,111,472		127,134,524		127,851,477		126,855,386

Earnings per common share, basic	$	1.04	$	1.10	$	1.97	$	1.79
Earnings per common share, diluted	$	1.04	$	1.09	$	1.96	$	1.79

_______________


(a)	We had no antidilutive shares for the three and nine months ended September 30, 2013 and 2012.

Supplemental Cash Flow Information



	Nine Months Ended September 30,
	2013			2012
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	107,512		$	103,461
Interest on financing activities of VIEs	13,865			9,132
Income taxes, net of refunds	(96		)	(4,559		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	68,249			64,947
Property, plant and equipment of VIEs	(14,282		)	—
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock	6,933			6,551
Deconsolidation of VIE	(14,282		)	—
Assets acquired through capital leases	328			9,898

3. RATE MATTERS AND REGULATION

KCC Proceedings

In March 2013 we adjusted our prices to included updated transmission costs as reflected in the transmission formula rate discussed below. The Kansas Corporation Commission (KCC) issued an order in July 2013 approving our adjustment which is expected to increase our annual retail revenues by approximately $11.8 million.

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In May 2013, the KCC issued an order allowing us to adjust our prices to include costs associated with 2012 investments in environmental projects. The new prices were effective in June 2013 and are expected to increase our annual retail revenues by approximately $27.3 million.

In April 2013, we filed with the KCC for an abbreviated rate review to adjust our prices to include $333.4 million of additional investment in the La Cygne Generating Station (La Cygne) environmental upgrades and to reflect cost reductions elsewhere. In September 2013, we reached an agreement with other major parties to the rate review. If the agreement is approved by the KCC, we estimate that the new prices will increase our annual retail revenues by approximately $30.7 million. We expect the KCC to issue an order on our request in late 2013.

FERC Proceedings

Our transmission formula rate that includes projected 2013 transmission capital expenditures and operating costs was effective in January 2013 and is expected to increase our annual transmission revenues by approximately $12.2 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical 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.

•

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.


•	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. Level 3 includes investments in private equity, real estate securities and other alternative investments, 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, alternative investments 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 alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. 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.

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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, 2013				As of December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,102,500	$	3,301,479	$	2,702,500	$	3,178,752
Fixed-rate debt of VIEs	222,126		237,848		247,624		275,341

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Recurring Fair Value Measurements

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



As of September 30, 2013	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	—	$	48,059	$	5,293	$	53,352
International equity	—		30,698		—		30,698
Core bonds	—		16,580		—		16,580
High-yield bonds	—		12,459		—		12,459
Emerging market bonds	—		9,949		—		9,949
Other fixed income	—		4,657		—		4,657
Combination debt/equity/other funds	—		15,839		—		15,839
Alternative investments	—		—		15,569		15,569
Real estate securities	—		—		8,437		8,437
Cash equivalents	8		—		—		8
Total Nuclear Decommissioning Trust	8		138,241		29,299		167,548
Trading Securities (a):
Domestic equity	—		17,402		—		17,402
International equity	—		4,431		—		4,431
Core bonds	—		11,385		—		11,385
Cash equivalents	166		—		—		166
Total Trading Securities	166		33,218		—		33,384
Total Assets Measured at Fair Value	$	174	$	171,459	$	29,299	$	200,932

As of December 31, 2012	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	—	$	56,157	$	4,899	$	61,056
International equity	—		30,041		—		30,041
Core bonds	—		28,350		—		28,350
High-yield bonds	—		8,782		—		8,782
Emerging market bonds	—		6,428		—		6,428
Combination debt/equity fund	—		8,194		—		8,194
Real estate securities	—		—		7,865		7,865
Cash equivalents	38		—		—		38
Total Nuclear Decommissioning Trust	38		137,952		12,764		150,754
Trading Securities:
Domestic equity	—		22,470		—		22,470
International equity	—		5,744		—		5,744
Core bonds	—		15,104		—		15,104
Cash equivalents	166		—		—		166
Total Trading Securities	166		43,318		—		43,484
Total Assets Measured at Fair Value	$	204	$	181,270	$	12,764	$	194,238

_______________


(a)	The decrease in the fair value of trading securities was due to withdrawing $14.8 million.

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The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and nine months ended September 30, 2013.



	Domestic Equity			Alternative Investments		Real Estate Securities			Net Balance
	(In Thousands)
Balance as of June 30, 2013	$	5,014		$	15,234	$	8,161		$	28,409
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	219			335		276			830
Purchases	155			—		72			227
Sales	(95		)	—		(72		)	(167		)
Balance as of September 30, 2013	$	5,293		$	15,569	$	8,437		$	29,299

Balance as of December 31, 2012	$	4,899		$	—	$	7,865		$	12,764
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	416			569		572			1,557
Purchases	290			15,000		212			15,502
Sales	(312		)	—		(212		)	(524		)
Balance as of September 30, 2013	$	5,293		$	15,569	$	8,437		$	29,299

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



	Domestic Equity			Real Estate Securities			Net Balance
	(In Thousands)
Balance as of June 30, 2012	$	4,780		$	7,449		$	12,229
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	(1		)	154			153
Purchases	109			63			172
Sales	—			(63		)	(63		)
Balance as of September 30, 2012	$	4,888		$	7,603		$	12,491

Balance as of December 31, 2011	$	3,931		$	7,095		$	11,026
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	192			508			700
Purchases	777			185			962
Sales	(12		)	(185		)	(197		)
Balance as of September 30, 2012	$	4,888		$	7,603		$	12,491

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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 ended September 30, 2013 and 2012, attributed to level 3 assets and liabilities.



	Three Months Ended September 30, 2013
	Domestic Equity		Alternative Investments		Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Regulatory liabilities	$	125	$	335	$	205	$	665

	Nine Months Ended September 30, 2013
Total unrealized gains (losses) included in:
Regulatory liabilities	$	105	$	569	$	360	$	1,034



	Three Months Ended September 30, 2012
	Domestic Equity			Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Regulatory liabilities	$	(1	)	$	90	$	89

	Nine Months Ended September 30, 2012
Total unrealized gains (losses) included in:
Regulatory liabilities	$	179		$	322	$	501

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Some of our investments in the nuclear decommissioning trust (NDT) and our trading securities portfolio are measured at net asset value and do not have readily determinable fair values. These investments 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, 2013				As of December 31, 2012				As of September 30, 2013
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	5,293	$	2,734	$	4,899	$	1,024	(a)	(a)
Alternative investments	15,569		—		—		—		(b)	(b)
Real estate securities	8,437		—		7,865		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	29,299		2,734		12,764		1,024

Trading Securities:
Domestic equity	17,402		—		22,470		—		Upon Notice	1 day
International equity	4,431		—		5,744		—		Upon Notice	1 day
Core bonds	11,385		—		15,104		—		Upon Notice	1 day
Total Trading Securities	33,218		—		43,318		—
Total	$	62,517	$	2,734	$	56,082	$	1,024

_______________

(a)

This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. One fund has begun to make distributions and we expect the other to begin in 2014. Our initial investment in the third fund occurred in the 3rd quarter of 2013. This fund's term will be 15 years, subject to the General Partner's right to extend the term for up to three additional one-year periods.


(b)	This fund has an initial lock-up period of 24 months. Redemptions are allowed, on a quarterly basis, after 24 months at the sole discretion of the fund's board of directors. A 65-day notice of redemption is required. There is a holdback on final redemptions.

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 and costs of fuel for our generating plants. We strive to manage our customers' and our exposure to the market risks through regulatory, operating and financing activities.

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.

5. 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.

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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 months ended September 30, 2013, we recorded unrealized gain on these investments of $1.2 million and an unrealized loss of $2.6 million for the nine months ended September 30, 2013. For the three and nine months ended September 30, 2012, we recorded unrealized gains of $1.9 million and $3.7 million, respectively.

Available-for-Sale Securities

We hold investments 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, 2013, and December 31, 2012. As of September 30, 2013, the fair value of available-for-sale bond funds was $43.6 million. The NDT did not have investments in debt securities outside of investment funds as of September 30, 2013.

Using the specific identification method to determine cost, we realized no gains or losses on our available-for-sale securities during the three months ended September 30, 2013 or 2012. During the nine months ended September 30, 2013 and 2012, we realized gains of $4.5 million and $0.6 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, 2013, and December 31, 2012.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2013
Domestic equity	$	38,911	$	14,441	$	—		$	53,352	33	%
International equity	26,419		4,432		(153		)	30,698		18	%
Core bonds	16,592		—		(12		)	16,580		10	%
High-yield bonds	11,804		655		—			12,459		7	%
Emerging market bonds	10,641		—		(692		)	9,949		6	%
Other fixed income	4,646		11		—			4,657		3	%
Combination debt/equity/other funds	14,439		1,636		(236		)	15,839		9	%
Alternative investments	15,000		569		—			15,569		9	%
Real estate securities	10,193		—		(1,756		)	8,437		5	%
Cash equivalents	8		—		—			8		<1%
Total	$	148,653	$	21,744	$	(2,849	)	$	167,548	100	%

As of December 31, 2012
Domestic equity	$	53,598	$	7,458	$	—		$	61,056	41	%
International equity	28,248		1,793		—			30,041		20	%
Core bonds	27,309		1,041		—			28,350		19	%
High-yield bonds	8,022		760		—			8,782		6	%
Emerging market bonds	6,080		348		—			6,428		4	%
Combination debt/equity fund	8,074		120		—			8,194		5	%
Real estate securities	9,981		—		(2,116		)	7,865		5	%
Cash equivalents	38		—		—			38		<1%
Total	$	141,350	$	11,520	$	(2,116	)	$	150,754	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, 2013, and December 31, 2012.



	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, 2013
International equity	$	6,065	$	(153	)	$	—	$	—		$	6,065	$	(153	)
Core bonds	16,580		(12		)	—		—			16,580		(12		)
Emerging market bonds	9,949		(692		)	—		—			9,949		(692		)
Combination debt/equity/other funds	5,984		(236		)	—		—			5,984		(236		)
Real estate securities	—		—			8,437		(1,756		)	8,437		(1,756		)
Total	$	38,578	$	(1,093	)	$	8,437	$	(1,756	)	$	47,015	$	(2,849	)

As of December 31, 2012
Real estate securities	$	—	$	—		$	7,865	$	(2,116	)	$	7,865	$	(2,116	)

6. DEBT FINANCING

In August 2013, Westar Energy issued $250.0 million principal amount of first mortgage bonds bearing stated interest of 4.625% and maturing in September 2043.

In June 2013, KGE redeemed two pollution control bond issues with an aggregate principal amount of $100.0 million and stated interest rates of 5.60% and 6.00%.

In March 2013, Westar Energy issued $250.0 million principal amount of first mortgage bonds bearing stated interest of 4.10% and maturing in April 2043. Proceeds from the issuances were used to repay short-term debt, which had been used primarily to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.

7. TAXES

We recorded income tax expense of $52.4 million with an effective income tax rate of 28% for the three months ended September 30, 2013, and income tax expense of $66.4 million with an effective income tax rate of 32% for the same period of 2012. We recorded income tax expense of $106.5 million with an effective income tax rate of 29% for the nine months ended September 30, 2013, and income tax expense of $107.2 million with an effective income tax rate of 31% for the same period of 2012. The decrease in the effective income tax rate for the three months ended September 30, 2013, was due primarily to a decrease in income before income taxes and increases in non-taxable income from corporate-owned life insurance (COLI). The decrease in the effective income tax rate for the nine months ended September 30, 2013, was due primarily to increases in non-taxable income from COLI and the utilization of previously unrecognized capital loss carryforwards to offset realized capital gains.

The Internal Revenue Service (IRS) has examined our federal income tax return filed for tax year 2010 and the amended federal income tax returns we filed for tax years 2007, 2008 and 2009. The examination results, which were approved by the Joint Committee on Taxation of the U.S. Congress and accepted by the IRS in April 2013, did not have a significant impact on our consolidated statements of income or cash flows.

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On September 13, 2013, the IRS and United States Treasury Department released final and re-proposed tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property, including the tax treatment of, among other things, materials and supplies, dispositions of property under the Modified Accelerated Cost Recovery System, general asset accounts and the determination of whether expenditures with respect to tangible property are a deductible repair or must be capitalized. The regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted in earlier years under certain circumstances. The IRS is expected to issue transition guidance during the fourth quarter of 2013 that provides the procedures for taxpayers to change their method of accounting to comply with the regulations. We intend to adopt the guidance effective January 1, 2014. We continue to evaluate what impact the adoption of the regulations will have on our consolidated financial statements. As of this date, we do not expect the adoption of the regulations to have a material impact on our consolidated financial statements.

As of September 30, 2013, and December 31, 2012, our liability for unrecognized income tax benefits was $1.6 million and $1.2 million, respectively. We do not expect significant changes in this liability in the next 12 months.

As of September 30, 2013, and December 31, 2012, we had $0.2 million accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either September 30, 2013, or December 31, 2012.

As of September 30, 2013, and December 31, 2012, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

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8. 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,	2013			2012			2013			2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,355		$	4,889		$	507		$	514
Interest cost	9,630			9,894			1,502			1,575
Expected return on plan assets	(8,351		)	(8,070		)	(1,673		)	(1,373		)
Amortization of unrecognized:
Transition obligation, net	—			—			81			978
Prior service costs	150			153			631			631
Actuarial loss, net	8,478			8,194			281			376
Net periodic cost before regulatory adjustment	15,262			15,060			1,329			2,701
Regulatory adjustment (a)	784			615			717			(261		)
Net periodic cost	$	16,046		$	15,675		$	2,046		$	2,440

_______________


(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.



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2013			2012			2013			2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	16,065		$	14,666		$	1,521		$	1,543
Interest cost	28,890			29,683			4,505			4,723
Expected return on plan assets	(25,053		)	(24,212		)	(5,018		)	(4,118		)
Amortization of unrecognized:
Transition obligation, net	—			—			244			2,934
Prior service costs	451			460			1,893			1,893
Actuarial loss, net	25,435			24,582			843			1,127
Net periodic cost before regulatory adjustment	45,788			45,179			3,988			8,102
Regulatory adjustment (a)	2,351			(8,635		)	2,151			(12		)
Net periodic cost	$	48,139		$	36,544		$	6,139		$	8,090

_______________


(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 ended September 30, 2013 and 2012, we contributed $27.5 million and $56.7 million, respectively, to the Westar Energy pension trust.

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9. 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,	2013			2012			2013		2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,709		$	1,516		$	52	$	48
Interest cost	1,890			1,884			103		103
Expected return on plan assets	(1,843		)	(1,644		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			—			—		14
Prior service costs	15			1			—		—
Actuarial loss, net	1,355			1,341			66		58
Net periodic cost before regulatory adjustment	3,126			3,098			221		223
Regulatory adjustment (a)	(203		)	(212		)	—		—
Net periodic cost	$	2,923		$	2,886		$	221	$	223

_______________


(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.



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2013			2012			2013		2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,126		$	4,547		$	155	$	144
Interest cost	5,672			5,653			309		308
Expected return on plan assets	(5,530		)	(4,933		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			—			—		43
Prior service costs	44			4			—		—
Actuarial loss, net	4,065			4,024			199		175
Net periodic cost before regulatory adjustment	9,377			9,295			663		670
Regulatory adjustment (a)	(609		)	(1,726		)	—		—
Net periodic cost	$	8,768		$	7,569		$	663	$	670

_______________


(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 ended September 30, 2013 and 2012, we funded $7.6 million and $11.9 million, respectively, of Wolf Creek's pension plan contributions.

10. 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 emissions 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, operate 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 certain emissions considered harmful to public health and the environment, including two classes of PM, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel 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. KDHE proposed to designate portions of the Kansas City area nonattainment for the eight-hour ozone standard, which has the potential to impact our operations. The EPA has not acted on KDHE's proposed designation of the Kansas City area and it is uncertain when, or if, such a designation might occur. The Wichita area also exceeded the eight-hour ozone standard and could be designated nonattainment in the future potentially impacting our operations.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. By the end of 2014, the EPA anticipates making final attainment/nonattainment designations under this rule and expects to issue a final implementation rule. We are currently evaluating the rule, however, we cannot at this time predict the impact it may have on our operations or consolidated financial results, but it could be material.

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 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 cost associated with our approximately $610.0 million share of the projected capital investment associated with the $1.2 billion of environmental upgrades at La Cygne. We therefore must file for a general review of our rates or an abbreviated rate review with the KCC in order to collect these costs. The KCC approved our request to file an abbreviated rate review to collect a portion of these costs. For additional information regarding our abbreviated rate review, see Note 3, "Rate Matters and Regulation." To change our prices to collect increased operating and maintenance costs, we must file a general rate review with the KCC.

Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In 2012, the EPA's Mercury and Air Toxics Standards (MATS) for power plants became effective, which replaced the prior federal Clean Air Mercury Rule (CAMR) and requires significant reductions in mercury, acid gases and other emissions. We expect to be compliant with the new standards by April 2016 as approved by our state environmental regulatory agency. We continue to evaluate the new standards and believe that our related investment will be approximately $17.0 million.

Additionally, in March 2013, the EPA finalized updates to certain emission limits for new power plants under MATS. We are currently evaluating these updates; however, because of environmental upgrades we have made and continue to make at our power plants to comply with regional haze requirements and the EPA consent decree discussed below, we believe the EPA's updates will have an immaterial impact on our future generation plans.

In 2011 the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 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 required to begin January 2012, with further reductions required beginning January 2014.

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In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR and remanded the rule to the EPA to promulgate a replacement. In October 2012, the EPA filed a petition with the circuit court requesting a rehearing before the full court, which was declined in January 2013. The EPA subsequently petitioned the U.S. Supreme Court to review the circuit court's ruling and the petition was granted in June 2013. We cannot at this time predict the outcome of the U.S. Supreme Court's review; however, based on our current and planned environmental controls, if the regulations were to be reinstated or replaced, either in part or in whole, we do not believe the impact on our operations and consolidated financial results would be material.

Greenhouse Gases

Under regulations known as the Tailoring Rule, the EPA regulates greenhouse gas (GHG) emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs which 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 future 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. With our existing wind generation facilities, supply contracts and renewable energy credits, we are able to satisfy the net renewable generation requirement through 2015 and we are on track to meet the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

EPA Consent Decree

As part of a 2010 settlement of a lawsuit filed by the Department of Justice on behalf of the EPA, we are installing selective catalytic reduction (SCR) equipment on one of three Jeffrey Energy Center (JEC) coal units to be completed by the end of 2014, which we estimate will cost approximately $240.0 million. The settlement also required that we determine whether we needed to install additional SCR equipment on another JEC unit or if we can meet agreed upon plant-wide NOx emissions reduction limits using other controls. We have informed the EPA that 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 complete these projects in 2014 and to recover the costs to install the equipment through our ECRR, but such recovery remains subject to the approval of our regulators.

11. 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 3, "Rate Matters and Regulation," and Note 10, "Commitments and Contingencies," for additional information.

12. COMMON STOCK

In September 2013, Westar Energy entered into two forward sale agreements with banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy's common stock from third parties and sold them to a group of underwriters for $31.15 per share. Under over-allotment options included in the agreements, the underwriters purchased in the fourth quarter an additional 0.9 million shares, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under the agreement. Westar Energy must settle such transactions within 24 months.

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In March 2013, Westar Energy entered into a new, three-year sales agency financing agreement and master forward sale agreement similar to the sales agency financing agreement and forward sale agreements entered into in April 2010. The maximum amount that Westar Energy may offer and sell under the March 2013 agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the March 2013 sales agency financing agreement and master forward sale agreement, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, and the bank will borrow shares of Westar Energy's common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements. Westar Energy must settle the forward sale transactions within 18 months of the date each transaction is entered. Under the terms of March 2013 agreements and April 2010 agreements, during the nine months ended September 30, 2013 Westar Energy entered into transactions with respect to an aggregate of approximately 2.5 million shares of common stock resulting in 4.2 million shares that could be settled as of September 30, 2013.

Assuming physical share settlement of the approximately 12.2 million shares associated with all forward sale transactions as of September 30, 2013, Westar Energy would have received aggregate proceeds of approximately $362.7 million based on a forward price of $29.72 per share.

The forward sale transactions are entered into at market prices; therefore, the forward sale agreements have no initial fair value. Westar Energy will not receive any proceeds from the sale of common stock under the forward sale agreements until transactions are settled. Upon settlement, Westar Energy will record the forward sale agreements within equity. Except in specified circumstances or events that would require physical share settlement, Westar Energy is able to elect to settle any forward sale transactions by means of physical share, cash or net share settlement, and is also able to elect to settle the forward sale transactions in whole, or in part, earlier than the stated maturity dates. Currently, Westar Energy anticipates settling the forward sale transactions through physical share settlement. The shares under the forward sale agreements are initially priced when the transactions are entered into and are subject to certain fixed pricing adjustments during the term of the agreements. Accordingly, assuming physical share settlement, Westar Energy's net proceeds from the forward sale transactions will represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurs.

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.

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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

We leased railcars from an unrelated trust to transport coal to some of our power plants. We consolidated the trust as a VIE until the agreement expired in May 2013. As a result of deconsolidating the trust, property, plant and equipment of VIEs, net, and noncontrolling interests decreased $14.3 million.

We also lease railcars from another unrelated trust under an agreement that expires in November 2014. 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 railcars and lease them to us, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of this 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 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 trust that could potentially be significant if the fair value of the railcars at the end of the agreements is greater than the fixed amount. Our agreement with this trust also includes renewal options during which time we would pay a fixed amount of rent. We have the potential to receive benefits from the trust during the renewal period if the fixed amount of rent is less than the amount we would be required to pay under a new agreement.

Financial Statement Impact

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



	As of		As of
	September 30, 2013		December 31, 2012
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	299,312	$	321,975
Regulatory assets (a)	6,540		5,810

Liabilities:
Current maturities of long-term debt of variable interest entities	$	27,764	$	25,942
Accrued interest (b)	230		3,948
Long-term debt of variable interest entities, net	195,074		222,743

_______________

(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 recorded no gain or loss upon initial consolidation of the VIEs or upon deconsolidation of the rail car VIE.

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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 Federal Energy Regulatory Commission (FERC).

In Management's Discussion and Analysis, we discuss our operating results for the three and nine months ended September 30, 2013, compared to the same period of 2012, our general financial condition and significant changes that occurred during 2013. 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,
	2013		2012		Change			2013		2012		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to common stock	$	133,125	$	139,281	$	(6,156	)	$	251,458	$	227,923	$	23,535
Earnings per common share, basic	1.04		1.10		(0.06		)	1.97		1.79		0.18

Net income attributable to common stock and basic EPS for the three months ended September 30, 2013, decreased due primarily to cooler weather, reduced demand from industrial customers and increased operating and maintenance costs at our power plants. Decreases were partially offset by recording additional COLI benefits and higher prices.

Net income attributed to common stock and basic EPS for the nine months ended September 30, 2013, increased due primarily to higher prices, recording additional COLI proceeds and lower selling, general and administrative expenses. Lower electricity sales as a result of cooler weather and reduced demand for electricity served to partially offset the aforementioned increases. See the discussion under "—Operating Results" below for additional information.

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 2012 Form 10-K.

Environmental Regulation

Environmental laws and regulations affecting our operations, which relate primarily to air quality, water quality, 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 10 of the Notes to Condensed Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding environmental laws and regulations.

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Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In 2012, the EPA's MATS for power plants became effective, which replaced the prior federal CAMR and requires significant reductions in mercury, acid gases and other emissions. We expect to be compliant with the new standards by April 2016 as approved by our state environmental regulatory agency. We continue to evaluate the new standards and believe that our related investment will be approximately $17.0 million.

In 2011, the EPA finalized CSAPR requiring 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 required to begin January 2012, with further reductions required beginning January 2014.

Greenhouse Gases

In September 2013, the EPA proposed a New Source Performance Standard (NSPS) that would limit carbon dioxide (CO₂) emissions for new coal and natural gas fueled generating units. The proposal would limit CO₂ emissions to 1,000 lbs per megawatt hour(s) MWh generated for larger natural gas units and 1,100 lbs per MWh generated for smaller natural gas units and coal units. The proposal has been challenged in the Supreme Court. The EPA was also directed to issue proposed standards addressing CO₂ emissions for modified, reconstructed and existing power plants by June 1, 2014, issue final rules by June 1, 2015, and require that states submit their implementation plans to the EPA no later than June 30, 2016. We cannot at this time determine the impact of such proposals on our operations and consolidated financial results, but we believe the costs to comply could be material.

Under regulations known as the Tailoring Rule, the EPA regulates GHG emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs which 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 future 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, recycle, process or dispose of. We recycle some of our ash production, principally by selling to the aggregate industry. In 2010, the EPA proposed a rule to regulate CCBs at the federal level, which we believe might impair our ability to recycle ash or require additional CCB handling, processing and storage equipment, or both. The EPA is expected to issue a final rule in 2014 or sooner. 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.

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National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including two classes of PM, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel 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 EPA at five-year intervals. KDHE proposed to designate portions of the Kansas City area nonattainment for the eight-hour ozone standard. The EPA has not acted on KDHE's proposed designation of the Kansas City area and it is uncertain when, or if, such a designation might occur. The Wichita area also exceeded the eight-hour ozone standard and could be designated nonattainment in the future potentially impacting our operations.

In September 2011, the President instructed the EPA not to implement the 2008 Ozone Standard since a new NAAQS for ozone is due to be proposed in 2013 and finalized in 2014. We are waiting on this new standard and cannot at this time predict the impact it may have on our operations, but it could be material.

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.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. In April 2013, the EPA proposed revisions to the rules governing such discharges from fossil fueled power plants. Final action on the proposed rules is expected to occur in 2014. Although we cannot at this time determine the impact of the final regulations, more stringent regulations could have a material impact on our operations and consolidated financial results.

In 2011, the EPA issued a proposed rule that would set stricter technology standards for cooling water intake structures at power plants over concerns about impacts to aquatic life. We are currently evaluating the proposed rule as well as recent nationally-issued information requests 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.

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. With our existing wind generation facilities, supply contracts and renewable energy credits, we are able to satisfy the net renewable generation requirement through 2015. We have requested proposals to purchase additional renewable energy generation capacity to meet the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

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 2012 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.

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From December 31, 2012, through September 30, 2013, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2012 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 these sales serve to offset retail prices through either the retail energy cost adjustment or at the time of our next general rate case.

Transmission: Reflects transmission revenues, including those based on tariffs with the Southwest Power Pool (SPP).

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

Electric utility revenues are impacted by things such as rate regulation, fuel costs, technology, customer behavior, 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 and commercial customers, and to a lesser extent industrial 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 Ended September 30, 2013, Compared to Three and Nine Months Ended September 30, 2012

Below we discuss our operating results for the three and nine months ended September 30, 2013, compared to the results for the three and nine months ended September 30, 2012. 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,
	2013			2012			Change			% Change		2013			2012			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	237,984		$	250,757		$	(12,773	)	(5.1	)	$	568,662		$	566,069		$	2,593		0.5
Commercial	199,921			194,032			5,889			3.0		513,049			493,814			19,235			3.9
Industrial	98,410			96,656			1,754			1.8		282,155			278,036			4,119			1.5
Other retail	3,849			6,407			(2,558		)	(39.9	)	2,905			1,125			1,780			158.2
Total Retail Revenues	540,164			547,852			(7,688		)	(1.4	)	1,366,771			1,339,044			27,727			2.1
Wholesale	94,496			88,784			5,712			6.4		262,749			228,966			33,783			14.8
Transmission (a)	52,410			49,137			3,273			6.7		156,725			144,480			12,245			8.5
Other	7,904			9,985			(2,081		)	(20.8	)	24,531			25,208			(677		)	(2.7	)
Total Revenues	694,974			695,758			(784		)	(0.1	)	1,810,776			1,737,698			73,078			4.2
OPERATING EXPENSES:
Fuel and purchased power	178,562			177,506			1,056			0.6		483,014			452,840			30,174			6.7
Operating and maintenance	169,100			149,001			20,099			13.5		491,132			461,515			29,617			6.4
Depreciation and amortization	68,861			65,061			3,800			5.8		203,305			204,640			(1,335		)	(0.7	)
Selling, general and administrative	54,245			54,300			(55		)	(0.1	)	157,668			164,346			(6,678		)	(4.1	)
Total Operating Expenses	470,768			445,868			24,900			5.6		1,335,119			1,283,341			51,778			4.0
INCOME FROM OPERATIONS	224,206			249,890			(25,684		)	(10.3	)	475,657			454,357			21,300			4.7
OTHER INCOME (EXPENSE):
Investment earnings (losses)	2,863			2,729			134			4.9		8,612			6,456			2,156			33.4
Other income	12,321			6,115			6,206			101.5		29,748			27,242			2,506			9.2
Other expense	(6,195		)	(6,278		)	83			1.3		(13,911		)	(14,246		)	335			2.4
Total Other Income	8,989			2,566			6,423			250.3		24,449			19,452			4,997			25.7
Interest expense	45,708			45,017			691			1.5		135,790			131,886			3,904			3.0
INCOME BEFORE INCOME TAXES	187,487			207,439			(19,952		)	(9.6	)	364,316			341,923			22,393			6.5
Income tax expense	52,392			66,372			(13,980		)	(21.1	)	106,514			107,156			(642		)	(0.6	)
NET INCOME	135,095			141,067			(5,972		)	(4.2	)	257,802			234,767			23,035			9.8
Less: Net income attributable to noncontrolling interests	1,970			1,786			184			10.3		6,344			5,228			1,116			21.3
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	133,125			139,281			(6,156		)	(4.4	)	251,458			229,539			21,919			9.5
Preferred dividends	—			—			—			—		—			1,616			(1,616		)	(100.0	)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	133,125		$	139,281		$	(6,156	)	(4.4	)	$	251,458		$	227,923		$	23,535		10.3
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.04		$	1.10		$	(0.06	)	(5.5	)	$	1.97		$	1.79		$	0.18		10.1

_______________

(a) Reflects revenue from an SPP network transmission tariff. For the three and nine months ended September 30, 2013, our SPP network transmission costs were $45.3 million and $133.7 million, respectively. These amounts, less administration costs of $10.3 million and $28.8 million, respectively, were returned to us as revenue. For the three and nine months ended September 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.

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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 ended September 30, 2013 and 2012.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013		2012		Change			% Change		2013		2012		Change		% Change
	(Dollars In Thousands)
Revenues	$	694,974	$	695,758	$	(784	)	(0.1	)	$	1,810,776	$	1,737,698	$	73,078	4.2
Less: Fuel and purchased power expense	178,562		177,506		1,056			0.6		483,014		452,840		30,174		6.7
SPP network transmission costs	45,315		42,516		2,799			6.6		133,711		124,142		9,569		7.7
Gross Margin	$	471,097	$	475,736	$	(4,639	)	(1.0	)	$	1,194,051	$	1,160,716	$	33,335	2.9

The following table reflects changes in electricity sales for the three and nine months ended September 30, 2013 and 2012. 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,
	2013	2012	Change		% Change		2013	2012	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	2,073	2,270	(197	)	(8.7	)	5,075	5,314	(239	)	(4.5	)
Commercial	2,163	2,215	(52	)	(2.3	)	5,722	5,841	(119	)	(2.0	)
Industrial	1,396	1,437	(41	)	(2.9	)	4,020	4,216	(196	)	(4.6	)
Other retail	22	20	2		10.0		64	63	1		1.6
Total Retail	5,654	5,942	(288	)	(4.8	)	14,881	15,434	(553	)	(3.6	)
Wholesale	2,366	2,094	272		13.0		6,460	5,391	1,069		19.8
Total	8,020	8,036	(16	)	(0.2	)	21,341	20,825	516		2.5

Gross margin decreased for the three months ended September 30, 2013, compared to the same period in 2012 due primarily to lower retail revenues that were the result of decreased retail electricity sales. The lower retail electricity sales were attributable principally to cooler weather, which particularly impacts residential and commercial electricity sales. As measured by cooling degree days, the weather during the three months ended September 30, 2013, was 16% cooler than the same period of 2012, which represents a return to more normal weather. Contributing also to the decrease in retail electricity sales was reduced demand from industrial customers. We expect the trend of lower industrial sales to continue for the remainder of 2013. Offsetting decreases were higher prices.

Gross margin increased during the nine months ended September, 30, 2013, compared to the same period of 2012 due principally to higher retail revenues resulting from increased prices. The higher prices were offset in part by lower retail electricity sales that were due to the same reason discussed above for the three month period. The weather during the nine months ended September 30, 2013, was 24% cooler than the same period of 2012 as measured by cooling degree days, which also represents a return to more normal weather.

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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 ended September 30, 2013 and 2012.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013		2012		Change			% Change		2013		2012		Change			% Change
	(Dollars In Thousands)
Gross margin	$	471,097	$	475,736	$	(4,639	)	(1.0	)	$	1,194,051	$	1,160,716	$	33,335		2.9
Add: SPP network transmission costs	45,315		42,516		2,799			6.6		133,711		124,142		9,569			7.7
Less: Operating and maintenance expense	169,100		149,001		20,099			13.5		491,132		461,515		29,617			6.4
Depreciation and amortization expense	68,861		65,061		3,800			5.8		203,305		204,640		(1,335		)	(0.7	)
Selling, general and administrative expense	54,245		54,300		(55		)	(0.1	)	157,668		164,346		(6,678		)	(4.1	)
Income from operations	$	224,206	$	249,890	$	(25,684	)	(10.3	)	$	475,657	$	454,357	$	21,300		4.7

Operating Expenses and Other Income and Expense Items



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change		% Change	2013		2012		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	169,100	$	149,001	$	20,099	13.5	$	491,132	$	461,515	$	29,617	6.4

Operating and maintenance expense increased due principally to:


•	increases in property taxes of $3.6 million and $13.3 million, respectively, most of which was offset in retail revenues;


•	higher SPP network transmission costs of $2.8 million and $9.6 million, respectively, most of which was also offset with higher revenues;


•	higher tree trimming costs of $3.0 million and $3.3 million, respectively, which are offset with increased prices as agreed to in our last general rate case;


•	higher operating and maintenance costs at our coal fired power plants of approximately $5.9 million and $6.0 million, respectively; and,


•	for the three months ended, higher costs at Wolf Creek of $4.2 million, due principally to higher amortization of refueling outage costs and recognition of costs incurred during an unscheduled maintenance outage in 2013.



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change		% Change	2013		2012		Change			% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	68,861	$	65,061	$	3,800	5.8	$	203,305	$	204,640	$	(1,335	)	(0.7	)

Depreciation and amortization expense decreased during the nine months ended September 30, 2013, compared to the same period of 2012 as a result of our having reduced depreciation rates in mid 2012 to reflect changes in the estimated useful lives of some of our assets. Partially offsetting this decrease and the primary driver to the increase for the three months ended September 30, 2013, compared to the same period in 2012, 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,
	2013		2012		Change			% Change		2013		2012		Change			% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	54,245	$	54,300	$	(55	)	(0.1	)	$	157,668	$	164,346	$	(6,678	)	(4.1	)

Selling, general and administrative expense for the nine months ended September 30, 2013 decreased due primarily to:


•	lower post-retirement and other employee benefit costs of $11.7 million due principally to restructuring insurance contracts; and


•	lower labor costs of $6.7 million, which in part reflect expenses recorded in 2012 related to sustainable cost reduction activities; however,


•	partially offsetting these decreases were higher pension costs of $12.8 million, most of which were offset with higher revenues. These increased pension costs were principally a consequence of the 2008 financial market downturn and the subsequent low interest rate environment.



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change		% Change	2013		2012		Change		% Change
	(Dollars in Thousands)
Other income	$	12,321	$	6,115	$	6,206	101.5	$	29,748	$	27,242	$	2,506	9.2

Other income increased during the three and nine months ended September 30, 2013, compared to the same periods of 2012 due primarily to our having recorded an additional $7.5 million and $4.9 million, respectively, in COLI benefits. Further contributing to the increase for the three months ended September 30, 2013, was our having recorded $1.5 million more in equity AFUDC. Offsetting increases for both the three and nine month periods was our having recorded a $2.3 million benefit related to the sale of oil inventory in 2012.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013		2012		Change			% Change		2013		2012		Change			% Change
	(Dollars in Thousands)
Income tax expense	$	52,392	$	66,372	$	(13,980	)	(21.1	)	$	106,514	$	107,156	$	(642	)	(0.6	)

Income tax expense decreased for the three month period due principally to lower income before income taxes.

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FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of September 30, 2013, compared to December 31, 2012.



	As of		As of
	September 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	7,350,935	$	7,013,765	$	337,170	4.8

Property, plant and equipment, net of accumulated depreciation, increased due primarily to additions at our power plants, including air quality controls, and the addition of transmission facilities.



	As of		As of
	September 30, 2013		December 31, 2012		Change			% Change
	(Dollars in Thousands)
Property, plant and equipment of variable interest entities, net	$	299,312	$	321,975	$	(22,663	)	(7.0	)

Property, plant and equipment of variable interest entities, net of accumulated depreciation, decreased due to deconsolidating a rail car lease as discussed in Note 13 of the Notes to Condensed Consolidated Financial Statements, "Variable Interest Entities," and depreciation.



	As of		As of
	September 30, 2013		December 31, 2012		Change			% Change
	(Dollars in Thousands)
Short-term debt	$	52,100	$	339,200	$	(287,100	)	(84.6	)

Short-term debt decreased due to decreased issuances of commercial paper. Proceeds from the issuances of long-term debt were used to repay short-term debt, which had been used primarily to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.



	As of		As of
	September 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Current maturities of long-term debt	$	250,000	$	—	$	250,000
Long-term debt, net	2,968,797		2,819,271		149,526		5.3
Total long-term debt	$	3,218,797	$	2,819,271	$	399,526	14.2

Total long-term debt, net, increased due to the issuance of $500.0 million principal amount of first mortgage bonds. This increase was partially offset by our redemption of two pollution control bond issues with an aggregate principle amount of $100.0 million. Both the issuance and redemptions are further discussed in Note 6 of the Notes to Condensed Consolidated Financial Statements, "Debt Financing."

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	As of		As of
	September 30, 2013		December 31, 2012		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	27,764	$	25,942	$	1,822		7.0
Long-term debt of variable interest entities	195,074		222,743		(27,669		)	(12.4	)
Total long-term debt of variable interest entities	$	222,838	$	248,685	$	(25,847	)	(10.4	)

Total long-term debt of variable interest entities decreased due to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $25.4 million.



	As of		As of
	September 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,296,909	$	1,197,837	$	99,072	8.3

Long-term deferred income tax liabilities increased due primarily to the use of bonus and accelerated depreciation methods during the period.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy's commercial paper program and revolving credit facilities, 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 short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings, and proceeds from 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, 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.

Short-Term Borrowings

Westar Energy has a commercial paper program pursuant to which it may issue 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 30, 2013, Westar Energy had issued $34.5 million of commercial paper.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. In July 2013, Westar Energy extended the term of the $730.0 million facility to September 2017, while the other facility terminates in February 2016. As long as there is no default under the facilities, each facility may be extended an additional year 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. Total combined borrowings under the revolving credit facilities and the commercial paper program may not exceed $1.0 billion at any given time. As of October 30, 2013, no amounts were borrowed and $12.8 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.

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Long-term Debt Financing

In August 2013, Westar Energy issued $250.0 million principal amount of first mortgage bonds bearing stated interest of 4.625% and maturing in September 2043.

In June 2013, KGE redeemed two pollution control bond series with an aggregate principal amount of $100.0 million and stated interest rates of 5.60% and 6.00%.

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.

In February 2013, S&P revised its criteria for rating utility first mortgage bonds and, as a result, upgraded its ratings for Westar Energy and KGE first mortgage bonds/senior secured debt to A- from BBB+. Additionally, in April 2013, S&P affirmed its ratings for Westar Energy and KGE and raised its outlook to positive from stable.

As of October 30, 2013, 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 Commercial Paper	Rating Outlook
Moody’s	A3	A3	P-2	Stable
S&P	A-	A-	A-2	Positive
Fitch	A-	A-	F2	Stable

Common Stock

In September 2013, Westar Energy entered into two forward sale agreements with banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy's common stock from third parties and sold them to a group of underwriters for $31.15 per share. Under over-allotment options included in the agreements, the underwriters purchased in the fourth quarter an additional 0.9 million shares, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under the agreements. Westar Energy must settle such transactions within 24 months.

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In March 2013, Westar Energy entered into a new, three-year sales agency financing agreement and master forward sale agreement similar to the sales agency financing agreement and forward sale agreements entering in to in April 2010. The maximum amount that Westar Energy may offer and sell under the March 2013 agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the March 2013 sales agency financing agreement and master forward sale agreement, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, and the bank will borrow shares of Westar Energy's common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements. Westar Energy must settle the forward sale transactions within 18 months of the date each transaction is entered. Under the terms of the March 2013 agreements and and April 2010 agreements, during the nine months ended September 2013, Westar Energy entered into transactions with respect to an aggregate of approximately 2.5 million shares of common stock resulting in 4.2 million shares that could be settled as of September 2013.

Assuming physical share settlement of the approximately 12.2 million shares associated with these forward sale transactions as of September 30, 2013, Westar Energy would have received aggregate proceeds of approximately $362.7 million based on a forward price of $29.72 per share. These amounts do not include the additional 0.9 million shares that the underwriters purchased in the fourth quarter.

Summary of Cash Flows



	Nine Months Ended September 30,
	2013			2012			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	553,110		$	453,956		$	99,154		21.8
Investing activities	(417,414		)	(601,315		)	183,901			30.6
Financing activities	(131,602		)	148,199			(279,801		)	(188.8	)
Net (decrease) increase in cash and cash equivalents	$	4,094		$	840		$	3,254		387.4

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having received $68.1 million more from retail and wholesale customers, our having contributed $37.6 million less to pension and post-retirement benefit plans, our having paid $29.7 million in 2012 to settle treasury yield hedge transactions, our having paid $13.8 million less for fuel and purchased power and our having received $13.1 million more in COLI proceeds. Partially offsetting these increases was our having paid $31.2 million more for the planned Wolf Creek refueling and maintenance outage.

Cash Flows used in Investing Activities

Cash flows used in investing activities decreased due primarily to our having received $131.1 million more in proceeds from our COLI investment and our having invested $40.4 million less in additions to property, plant and equipment.

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Cash Flows from Financing Activities

Cash flows from financing activities decreased due principally to our having borrowed $216.2 million less under our commercial paper program, our having repaid $127.0 million more of borrowings against the cash surrender value of COLI and our having received $48.8 million less in proceeds from the issuance of long-term debt. Partially offsetting these decreases was our having retired $120.6 million less of long-term debt in the nine months ended September 30, 2013.

Pension Contribution

During the nine months ended September 30, 2013, we contributed $27.5 million to the Westar Energy pension trust and funded $7.6 million of Wolf Creek's pension plan contributions.

OFF-BALANCE SHEET ARRANGEMENTS

As discussed under "—Common Stock" above and in Note 12 of the Notes to Consolidated Financial Statements, "Common Stock," Westar Energy entered into two separate forward sale agreements with banks in 2013. The forward sale agreements are off-balance sheet arrangements. We also have off-balance sheet arrangements in the form of operating leases and letters of credit entered into in the ordinary course of business. We did not have any additional off-balance sheet arrangements as of September 30, 2013.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2012, through September 30, 2013, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2012 Form 10-K.

OTHER INFORMATION

Changes in Prices

KCC Proceedings

In March 2013 we adjusted our prices to included updated transmission costs as reflected in the transmission formula rate discussed below. The KCC issued an order in July 2013 approving our adjustment which is expected to increase our annual retail revenues by approximately $11.8 million.

In April 2013, we filed with the KCC for an abbreviated rate review to adjust our prices to include $333.4 million of additional investment in the La Cygne environmental upgrades and to reflect cost reductions elsewhere. In September 2013, we reached an agreement with other major parties to the rate review. If the agreement is approved by the KCC, we estimate that the new prices will increase our annual retail revenues by approximately $30.7 million. We expect the KCC to issue an order on our request in late 2013.

FERC Proceedings

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Tangible Property Regulations

The regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted in earlier years under certain circumstances. The IRS is expected to issue transition guidance during the fourth quarter of 2013 that provides the procedures for taxpayers to change their method of accounting to comply with the regulations.

We intend to adopt the guidance effective January 1, 2014. We continue to evaluate what impact the adoption of the regulations will have on our consolidated financial statements. As of this date, we do not expect the adoption of the regulations to have a material impact on our consolidated financial statements.

Employees

As of October 30, 2013, we had 2,279 employees, 1,251 of which were covered under a contract with Locals 304 and 1523 of the International Brotherhood of Electrical Workers. The initial term of this contract expired June 30, 2013; however, provisions of the contract cause it to remain in force on a year-to-year basis unless either party provides a notice of termination. With neither party having provided such notice, the contract remains in effect until at least June 30, 2014. We are currently in negotiations to extend the contract.

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, 2012, to September 30, 2013, no significant changes occurred in our market risk exposure. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our 2012 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.

We have begun implementing a new Enterprise Resource Planning (ERP) system that will change our business and financial transaction processes. As of July 1, 2013, we implemented aspects of the system dedicated to financial, accounting and supply chain functions. This implementation represents a change in our internal control over financial reporting. In connection with this implementation, we have updated our internal controls over financial reporting, as necessary, to accommodate modifications to our business processes and accounting procedures. We expect to implement additional ERP functions; accordingly, we will update our internal controls over financial reporting, as necessary, to accommodate further modifications to such processes and procedures.

There were no other changes in our internal control over financial reporting during the three months ended September 30, 2013, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 3, 10 and 11 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.

ITEM 1A. RISK FACTORS

There were no material changes in our risk factors from December 31, 2012, through September 30, 2013. For additional information, see our 2012 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, 2013, during the three-month period ended September 30, 2013, Westar Energy entered into forward transactions pursuant to the forward sale agreement dated March 21, 2013, between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on March 22, 2013) and the Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.1 to the Form 8-K filed on March 22, 2013) in respect to an aggregate of approximately 0.2 million shares of Westar Energy common stock.

In connection with the forward transactions, Westar Energy did not receive any proceeds from the sale of borrowed shares of its common stock by BNY Mellon Capital Markets, LLC. Westar Energy 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 Energy 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 Energy common stock sold by BNY Mellon Capital markets, LLC to hedge the forward transactions were sold pursuant to an effective Westar Energy registration statement (registration No. 333-187398) filed on March 20, 2013.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. Based on new guidance from the SEC, we may also use the Investor Relations section of our website (http://www.WestarEnergy.com, under “Investors”) to communicate with investors about our company. It is possible that the financial and other information we post there could be deemed to be material information. The information on our website is not part of this document.

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ITEM 6. EXHIBITS



1(a)		Underwriting Agreement, dated as of August 12, 2013, among Westar Energy, Inc. and Mitsubishi UFJ Securities (USA), Inc., UBS Securities LLC and Wells Fargo Securities LLC (filed as Exhibit 1.1 to the Form 8-K filed on August 12, 2013)
1(b)		Underwriting Agreement, dated September 24, 2013, among J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, Citigroup Global Markets Inc. and UBS Securities LLC, as representatives of the underwriters named therein, J.P. Morgan Securities LLC, in its capacity as agent for an affiliate of JPMorgan Chase Bank, National Association, London Branch, Wells Fargo Securities, LLC, in its capacity as agent for Wells Fargo Bank, National Association and Westar Energy, Inc. (filed as Exhibit 1.1 to the Form 8-K filed on September 27, 2013)
4		Form of Forty-Fourth Supplemental Indenture, dated as of August 19, 2013, by and between Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on August 12, 2013)
10.1(a)		Confirmation of Forward Sale Transaction, dated September 24, 2013, between JPMorgan Chase Bank, National Association, London Branch and Westar Energy, Inc. (Filed as Exhibit 10.1 to the Form 8-K filed on September 27, 2013)
10.1(b)		Confirmation of Forward Sale Transaction, dated September 24, 2013, between Wells Fargo Bank, National Association and Westar Energy, Inc. (Filed as Exhibit 10.2 to the Form 8-K filed on September 27, 2013)
10.1(c)		Confirmation of Additional Forward Sale Transaction, dated October 16, 2013, between JPMorgan Chase Bank, National Association, London Branch and Westar Energy, Inc. (Filed as Exhibit 10.1 to the Form 8-K filed on October 17, 2013)
10.1(d)		Confirmation of Additional Forward Sale Transaction, dated October 16, 2013, between Wells Fargo Bank, National Association and Westar Energy, Inc. (Filed as Exhibit 10.2 to the Form 8-K filed on October 17, 2013)
23.1(a)		Consent of Larry D. Irick (included in his opinion filed as Exhibit 5.1 to the Form 8-K filed on August 12, 2013)
23.1(b)		Consent of Larry D. Irick (included in his opinion filed as Exhibit 5.1 to the Form 8-K filed on September 27, 2013)
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, 2013
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, 2013
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2013 (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 7, 2013	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer