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WR-06.30.2013-10Q

Table of Contents

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 June 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		127,022,030 shares
(Class)		(Outstanding at July 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	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41

PART II. Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
Signature		43

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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,


-	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,


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

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-	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
	June 30, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,973	$	5,829
Restricted cash	451		573
Accounts receivable, net of allowance for doubtful accounts of $3,466 and $4,916, respectively	239,319		224,439
Fuel inventory and supplies	239,497		249,016
Prepaid expenses	16,074		15,847
Regulatory assets	140,653		114,895
Other	24,514		32,476
Total Current Assets	664,481		643,075
PROPERTY, PLANT AND EQUIPMENT, NET	7,255,280		7,013,765
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	301,998		321,975
OTHER ASSETS:
Regulatory assets	866,578		887,777
Nuclear decommissioning trust	159,631		150,754
Other	235,777		247,885
Total Other Assets	1,261,986		1,286,416
TOTAL ASSETS	$	9,483,745	$	9,265,231
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	27,773	$	25,942
Short-term debt	410,000		339,200
Accounts payable	149,680		180,825
Accrued dividends	43,150		41,743
Accrued taxes	74,569		58,624
Accrued interest	49,599		77,891
Regulatory liabilities	42,199		37,557
Other	90,366		84,359
Total Current Liabilities	887,336		846,141
LONG-TERM LIABILITIES:
Long-term debt, net	2,968,642		2,819,271
Long-term debt of variable interest entities, net	195,203		222,743
Deferred income taxes	1,233,893		1,197,837
Unamortized investment tax credits	189,931		191,512
Regulatory liabilities	283,360		285,618
Accrued employee benefits	557,033		564,870
Asset retirement obligations	156,690		152,648
Other	72,007		74,336
Total Long-Term Liabilities	5,656,759		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 126,935,051 shares and 126,503,748 shares, respective to each date	634,675		632,519
Paid-in capital	1,664,525		1,656,972
Retained earnings	637,900		606,649
Total Westar Energy, Inc. Shareholders’ Equity	2,937,100		2,896,140
Noncontrolling Interests	2,550		14,115
Total Equity	2,939,650		2,910,255
TOTAL LIABILITIES AND EQUITY	$	9,483,745	$	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 June 30,
	2013			2012
REVENUES	$	569,589		$	566,262
OPERATING EXPENSES:
Fuel and purchased power	152,700			147,680
Operating and maintenance	163,303			156,470
Depreciation and amortization	67,597			66,299
Selling, general and administrative	54,477			62,711
Total Operating Expenses	438,077			433,160
INCOME FROM OPERATIONS	131,512			133,102
OTHER INCOME (EXPENSE):
Investment earnings (losses)	1,690			(598		)
Other income	13,711			7,537
Other expense	(2,354		)	(2,416		)
Total Other Income	13,047			4,523
Interest expense	45,798			44,823
INCOME BEFORE INCOME TAXES	98,761			92,802
Income tax expense	29,310			28,340
NET INCOME	69,451			64,462
Less: Net income attributable to noncontrolling interests	2,263			1,728
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	67,188			62,734
Preferred dividends	—			1,373
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	67,188		$	61,361
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.53		$	0.48
Diluted earnings per common share	$	0.52		$	0.48
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	127,311,411			126,637,067
Diluted	127,930,395			126,876,536
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)



	Six Months Ended June 30,
	2013			2012
REVENUES	$	1,115,801		$	1,041,940
OPERATING EXPENSES:
Fuel and purchased power	304,452			275,334
Operating and maintenance	322,032			312,514
Depreciation and amortization	134,443			139,579
Selling, general and administrative	103,422			110,046
Total Operating Expenses	864,349			837,473
INCOME FROM OPERATIONS	251,452			204,467
OTHER INCOME (EXPENSE):
Investment earnings	5,749			3,727
Other income	17,427			21,127
Other expense	(7,715		)	(7,969		)
Total Other Income	15,461			16,885
Interest expense	90,082			86,869
INCOME BEFORE INCOME TAXES	176,831			134,483
Income tax expense	54,123			40,783
NET INCOME	122,708			93,700
Less: Net income attributable to noncontrolling interests	4,375			3,442
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	118,333			90,258
Preferred dividends	—			1,616
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	118,333		$	88,642
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.93		$	0.70
Diluted earnings per common share	$	0.92		$	0.70
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	127,254,250			126,566,071
Diluted	127,735,157			126,744,539
DIVIDENDS DECLARED PER COMMON SHARE	$	0.68		$	0.66

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)



	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	122,708		$	93,700
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	134,443			139,579
Amortization of nuclear fuel	8,631			9,026
Amortization of deferred regulatory gain from sale leaseback	(2,748		)	(2,748		)
Amortization of corporate-owned life insurance	4,138			10,921
Non-cash compensation	4,146			3,738
Net deferred income taxes and credits	45,409			33,586
Stock-based compensation excess tax benefits	(399		)	(1,498		)
Allowance for equity funds used during construction	(5,689		)	(6,778		)
Changes in working capital items:
Accounts receivable	(15,271		)	(51,055		)
Fuel inventory and supplies	11,780			(26,830		)
Prepaid expenses and other	2,396			17,368
Accounts payable	(24,838		)	(8,741		)
Accrued taxes	16,196			16,276
Other current liabilities	(58,624		)	(61,894		)
Changes in other assets	(28,048		)	(40,100		)
Changes in other liabilities	17,080			(21,371		)
Cash Flows from Operating Activities	231,310			103,179
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(398,998		)	(417,617		)
Purchase of securities - trusts	(59,986		)	(16,817		)
Sale of securities - trusts	75,475			18,040
Investment in corporate-owned life insurance	(17,408		)	(18,167		)
Proceeds from investment in corporate-owned life insurance	101,085			16,330
Proceeds from federal grant	876			3,289
Investment in affiliated company	—			(4,505		)
Other investing activities	(2,362		)	(343		)
Cash Flows used in Investing Activities	(301,318		)	(419,790		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	70,617			62,107
Proceeds from long-term debt	245,813			541,504
Retirements of long-term debt	(100,000		)	(220,563		)
Retirements of long-term debt of variable interest entities	(25,474		)	(7,736		)
Repayment of capital leases	(1,539		)	(1,287		)
Borrowings against cash surrender value of corporate-owned life insurance	57,948			63,287
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(100,060		)	(18,252		)
Stock-based compensation excess tax benefits	399			1,498
Preferred stock redemption	—			(22,567		)
Issuance of common stock	2,992			3,697
Distributions to shareholders of noncontrolling interests	(1,658		)	(3,252		)
Cash dividends paid	(80,886		)	(78,710		)
Cash Flows from Financing Activities	68,152			319,726
NET CHANGE IN CASH AND CASH EQUIVALENTS	(1,856		)	3,115
CASH AND CASH EQUIVALENTS:
Beginning of period	5,829			3,539
End of period	$	3,973		$	6,654

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	—		—			—	—		—			90,258			3,442			93,700
Issuance of stock	—		—			525,452	2,627		12,274			—			—			14,901
Stock redemption	(214,363	)	(21,436		)	—	—		—			—			—			(21,436		)
Preferred dividends	—		—			—	—		—			(1,616		)	—			(1,616		)
Dividends on common stock ($0.66 per share)	—		—			—	—		—			(84,138		)	—			(84,138		)
Amortization of restricted stock	—		—			—	—		3,004			—			—			3,004
Stock compensation and tax benefit	—		—			—	—		(7,790		)	—			—			(7,790		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(3,252		)	(3,252		)
Balance as of June 30, 2012	—		$	—		126,223,848	$	631,119	$	1,646,991		$	505,720		$	10,284		$	2,794,114

Balance as of December 31, 2012	—		$	—		126,503,748	$	632,519	$	1,656,972		$	606,649		$	14,115		$	2,910,255
Net income	—		—			—	—		—			118,333			4,375			122,708
Issuance of stock	—		—			431,303	2,156		10,552			—			—			12,708
Dividends on common stock ($0.68 per share)	—		—			—	—		—			(87,082		)	—			(87,082		)
Amortization of restricted stock	—		—			—	—		3,326			—			—			3,326
Stock compensation and tax benefit	—		—			—	—		(6,325		)	—			—			(6,325		)
Deconsolidation of variable interest entity	—		—			—	—		—			—			(14,282		)	(14,282		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(1,658		)	(1,658		)
Balance as of June 30, 2013	—		$	—		126,935,051	$	634,675	$	1,664,525		$	637,900		$	2,550		$	2,939,650

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

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 694,000 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 six months ended June 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
	June 30, 2013		December 31, 2012
	(In Thousands)
Fuel inventory	$	88,453	$	94,664
Supplies	151,044		154,352
Fuel inventory and supplies	$	239,497	$	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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Dollars In Thousands)
Borrowed funds	$	2,583		$	2,440		$	5,168		$	5,959
Equity funds	2,943			2,838			5,689			6,778
Total	$	5,526		$	5,278		$	10,857		$	12,737
Average AFUDC Rates	4.3		%	4.9		%	4.3		%	5.4		%

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	69,451	$	64,462	$	122,708	$	93,700
Less: Net income attributable to noncontrolling interests	2,263		1,728		4,375		3,442
Net income attributable to Westar Energy, Inc.	67,188		62,734		118,333		90,258
Less: Preferred dividends	—		1,373		—		1,616
Net income allocated to RSUs	196		182		339		265
Net income allocated to common stock	$	66,992	$	61,179	$	117,994	$	88,377

Weighted average equivalent common shares outstanding – basic	127,311,411		126,637,067		127,254,250		126,566,071
Effect of dilutive securities:
RSUs	53,570		190,422		45,567		155,340
Forward sale agreements	565,414		49,047		435,340		23,128
Weighted average equivalent common shares outstanding – diluted (a)	127,930,395		126,876,536		127,735,157		126,744,539

Earnings per common share, basic	$	0.53	$	0.48	$	0.93	$	0.70
Earnings per common share, diluted	$	0.52	$	0.48	$	0.92	$	0.70

_______________


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

Supplemental Cash Flow Information



	Six Months Ended June 30,
	2013			2012
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	73,853		$	68,939
Interest on financing activities of VIEs	7,349			8,281
Income taxes, net of refunds	(86		)	(4,635		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	56,187			37,736
Property, plant and equipment of VIEs	(14,282		)	—
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans	6,316			4,920
Deconsolidation of VIE	(14,282		)	—
Assets acquired through capital leases	326			1,543

3. RATE MATTERS AND REGULATION

KCC Proceedings

In July 2013, the Kansas Corporation Commission (KCC) issued an order allowing us to adjust our prices to include updated transmission costs as reflected in the transmission formula rate discussed below. The new prices were effective in March 2013 and are 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. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $31.7 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 AND DERIVATIVE INSTRUMENTS AND TRADING SECURITIES

Values of Financial and Derivative 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 are 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 June 30, 2013				As of December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,852,500	$	3,094,753	$	2,702,500	$	3,178,752
Fixed-rate debt of VIEs	222,149		245,022		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 June 30, 2013	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	—	$	44,571	$	5,014	$	49,585
International equity	—		28,118		—		28,118
Core bonds	—		16,423		—		16,423
High-yield bonds	—		12,171		—		12,171
Emerging market bonds	—		9,949		—		9,949
Other fixed income	—		4,605		—		4,605
Combination debt/equity/other funds	—		15,377		—		15,377
Alternative investments	—		—		15,234		15,234
Real estate securities	—		—		8,161		8,161
Cash equivalents	8		—		—		8
Total Nuclear Decommissioning Trust	8		131,214		28,409		159,631
Trading Securities (a):
Domestic equity	—		16,812		—		16,812
International equity	—		4,175		—		4,175
Core bonds	—		11,297		—		11,297
Cash equivalents	166		—		—		166
Total Trading Securities	166		32,284		—		32,450
Total Assets Measured at Fair Value	$	174	$	163,498	$	28,409	$	192,081

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 $14.3 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 six months ended June 30, 2013.



	Domestic Equity			Alternative Investments		Real Estate Securities			Net Balance
	(In Thousands)
Balance as of March 31, 2013	$	4,785		$	15,000	$	8,027		$	27,812
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	229			234		134			597
Purchases	72			—		71			143
Sales	(72		)	—		(71		)	(143		)
Balance as of June 30, 2013	$	5,014		$	15,234	$	8,161		$	28,409

Balance as of December 31, 2012	$	4,899		$	—	$	7,865		$	12,764
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	197			234		296			727
Purchases	135			15,000		140			15,275
Sales	(217		)	—		(140		)	(357		)
Balance as of June 30, 2013	$	5,014		$	15,234	$	8,161		$	28,409

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



	Domestic Equity			Real Estate Securities			Net Balance
	(In Thousands)
Balance as of March 31, 2012	$	4,100		$	7,271		$	11,371
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	104			178			282
Purchases	589			62			651
Sales	(13		)	(62		)	(75		)
Balance as of June 30, 2012	$	4,780		$	7,449		$	12,229

Balance as of December 31, 2011	$	3,931		$	7,095		$	11,026
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	193			354			547
Purchases	669			122			791
Sales	(13		)	(122		)	(135		)
Balance as of June 30, 2012	$	4,780		$	7,449		$	12,229

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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 six months ended June 30, 2013 and 2012, attributed to level 3 assets and liabilities.



	Three Months Ended June 30, 2013
	Nuclear Decommissioning Trust
	Domestic Equity			Alternative Investments		Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Regulatory liabilities	$	157		$	234	$	62	$	453

	Six Months Ended June 30, 2013
Total unrealized gains (losses) included in:
Regulatory liabilities	$	(20	)	$	234	$	155	$	369



	Three Months Ended June 30, 2012
	Nuclear Decommissioning Trust
	Domestic Equity		Real Estate Securities		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Regulatory liabilities	$	91	$	116	$	207

	Six Months Ended June 30, 2012
Total unrealized gains (losses) included in:
Regulatory liabilities	$	180	$	232	$	412

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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 June 30, 2013				As of December 31, 2012				As of June 30, 2013
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	5,014	$	889	$	4,899	$	1,024	(a)	(a)
Alternative investments	15,234		—		—		—		(b)	(b)
Real estate securities	8,161		—		7,865		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	28,409		889		12,764		1,024

Trading Securities:
Domestic equity	16,812		—		22,470		—		Upon Notice	1 day
International equity	4,175		—		5,744		—		Upon Notice	1 day
Core bonds	11,297		—		15,104		—		Upon Notice	1 day
Total Trading Securities	32,284		—		43,318		—
Total	$	60,693	$	889	$	56,082	$	1,024

_______________


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


(b)	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 and six months ended June 30, 2013, we recorded unrealized losses on these investments of $6.2 million and $3.7 million, respectively. For the three and six months ended June 30, 2012, we recorded an unrealized loss of $1.8 million and unrealized gain of $1.8 million respectively.

Available-for-Sale Securities

We hold investments in equity, debt and real estate securities in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2013, and December 31, 2012. As of June 30, 2013, the fair value of available-for-sale bond funds was $43.1 million. The NDT did not have investments in debt securities outside of investment funds as of June 30, 2013.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $3.2 million and $4.5 million, respectively, during the three and six months ended June 30, 2013. During the three and six months ended June 30, 2012, we realized gains of $0.4 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 June 30, 2013, and December 31, 2012.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2013
Domestic equity	$	38,515	$	11,071	$	(1	)	$	49,585	30	%
International equity	26,301		2,299		(482		)	28,118		18	%
Core bonds	16,404		19		—			16,423		10	%
High-yield bonds	11,554		617		—			12,171		8	%
Emerging market bonds	10,462		—		(513		)	9,949		6	%
Other fixed income	4,616		—		(11		)	4,605		3	%
Combination debt/equity/other funds	14,377		1,342		(342		)	15,377		10	%
Alternative investments	15,000		234		—			15,234		10	%
Real estate securities	10,122		—		(1,961		)	8,161		5	%
Cash equivalents	8		—		—			8		<1%
Total	$	147,359	$	15,582	$	(3,310	)	$	159,631	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 June 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 June 30, 2013
Domestic equity	$	1,543	$	(1	)	$	—	$	—		$	1,543	$	(1	)
International equity	5,712		(482		)	—		—			5,712		(482		)
Emerging market bonds	9,949		(513		)	—		—			9,949		(513		)
Other fixed income	4,605		(11		)	—		—			4,605		(11		)
Combination debt/equity/other funds	5,854		(342		)	—		—			5,854		(342		)
Real estate securities	—		—			8,161		(1,961		)	8,161		(1,961		)
Total	$	27,663	$	(1,349	)	$	8,161	$	(1,961	)	$	35,824	$	(3,310	)

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

6. DEBT FINANCING

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 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 $29.3 million with an effective income tax rate of 30% for the three months ended June 30, 2013, and income tax expense of $28.3 million with an effective income tax rate of 31% for the same period of 2012. We recorded income tax expense of $54.1 million with an effective income tax rate of 31% for the six months ended June 30, 2013, and income tax expense of $40.8 million with an effective income tax rate of 30% for the same period of 2012. The decrease in the effective income tax rate for the three months ended June 30, 2013, was due primarily to an increase in non-taxable income from corporate-owned life insurance (COLI).

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.

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

As of June 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 June 30, 2013, or December 31, 2012.

As of June 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 June 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			1,574
Expected return on plan assets	(8,351		)	(8,070		)	(1,672		)	(1,372		)
Amortization of unrecognized:
Transition obligation, net	—			—			81			978
Prior service costs	150			153			631			631
Actuarial loss, net	8,479			8,194			281			376
Net periodic cost before regulatory adjustment	15,263			15,060			1,330			2,701
Regulatory adjustment (a)	783			(2,005		)	717			(278		)
Net periodic cost	$	16,046		$	13,055		$	2,047		$	2,423

_______________


(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
Six Months Ended June 30,	2013			2012			2013			2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	10,710		$	9,777		$	1,014		$	1,029
Interest cost	19,260			19,789			3,004			3,149
Expected return on plan assets	(16,702		)	(16,142		)	(3,345		)	(2,746		)
Amortization of unrecognized:
Transition obligation, net	—			—			162			1,956
Prior service costs	300			307			1,262			1,262
Actuarial loss, net	16,957			16,389			562			752
Net periodic cost before regulatory adjustment	30,525			30,120			2,659			5,402
Regulatory adjustment (a)	1,567			(9,250		)	1,434			40
Net periodic cost	$	32,092		$	20,870		$	4,093		$	5,442

_______________


(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 six months ended June 30, 2013 and 2012, we contributed $17.7 million and $49.4 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 June 30,	2013			2012			2013		2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,708		$	1,516		$	52	$	48
Interest cost	1,891			1,884			103		103
Expected return on plan assets	(1,843		)	(1,644		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			—			—		14
Prior service costs	14			1			—		—
Actuarial loss, net	1,355			1,341			66		58
Net periodic cost before regulatory adjustment	3,125			3,098			221		223
Regulatory adjustment (a)	(203		)	(484		)	—		—
Net periodic cost	$	2,922		$	2,614		$	221	$	223

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(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
Six Months Ended June 30,	2013			2012			2013		2012
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,417		$	3,031		$	104	$	96
Interest cost	3,782			3,769			206		205
Expected return on plan assets	(3,686		)	(3,289		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			—			—		29
Prior service costs	28			3			—		—
Actuarial loss, net	2,710			2,683			132		117
Net periodic cost before regulatory adjustment	6,251			6,197			442		447
Regulatory adjustment (a)	(406		)	(1,514		)	—		—
Net periodic cost	$	5,845		$	4,683		$	442	$	447

_______________


(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 six months ended June 30, 2013 and 2012, we funded $3.7 million and $9.0 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 replaces the prior federal Clean Air Mercury Rule (CAMR) and requires significant reductions in mercury, acid gases and other emissions. Companies impacted by the new standards will have up to three years, or four years with approval from a state environmental regulatory agency, and in certain limited circumstances up to five years, from the effective date to comply. We have obtained approval from our state environmental regulatory agency and expect to be compliant with the new standards by April 2016. We continue to evaluate the new standards and believe that our related investment will be less than $16.0 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 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 addition to forward sale transactions entered into during prior periods, during the six months ended June 30, 2013, Westar Energy entered into transactions with respect to an aggregate of approximately 2.2 million shares of common stock. Westar Energy must settle such transactions within 18 months of the date each transaction was entered. Assuming physical share settlement of the approximately 4.0 million shares associated with all forward sale transactions as of June 30, 2013, Westar Energy would have received aggregate proceeds of approximately $115.8 million based on a forward price of $29.23 per share.

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In March 2013, Westar Energy entered into a new, three-year sales agency financing agreement and master forward sale agreement. The maximum amount that Westar Energy may offer and sell under the agreements is the lesser of an aggregate of $500.0 million or approximately 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 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.

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
	June 30, 2013		December 31, 2012
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	301,998	$	321,975
Regulatory assets (a)	6,330		5,810

Liabilities:
Current maturities of long-term debt of variable interest entities	$	27,773	$	25,942
Accrued interest (b)	3,475		3,948
Long-term debt of variable interest entities, net	195,203		222,743

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(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 six months ended June 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 June 30,						Six Months Ended June 30,
	2013		2012		Change		2013		2012		Change
	(Dollars In Thousands, Except Per Share Amounts)

Net income attributable to common stock	$	67,188	$	61,361	$	5,827	$	118,333	$	88,642	$	29,691
Earnings per common share, basic	0.53		0.48		0.05		0.93		0.70		0.23

Net income attributable to common stock and basic EPS increased due primarily to higher retail prices and lower selling, general and administrative expenses. Our having recorded additional COLI benefits contributed to the increase for the three months ended June 30, 2013, while lower depreciation expense contributed to the increase for the six months ended June 30, 2013. For both periods, lower retail electricity sales, which resulted primarily from cooler weather and reduced demand from certain industrial customers, and higher operating and maintenance expenses served to partially offset the aforementioned items. 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 replaces the prior federal CAMR and requires significant reductions in mercury, acid gases and other emissions. Companies impacted by the new standards will have up to three years, or four years with approval from a state environmental regulatory agency, and in certain limited circumstances up to five years, from the effective date to comply. We have obtained approval from our state environmental regulatory agency and expect to be compliant with the new standards by April 2016. We continue to evaluate the new standards and believe that our related investment will be less than $16.0 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 March 2012, the EPA proposed a New Source Performance Standard (NSPS) that would limit carbon dioxide (CO₂) emissions for new electric generating units. In June 2013, the President issued a memorandum directing the EPA to issue a new proposed NSPS for newly constructed electric generating units by September 30, 2013, and to issue a final order in a timely fashion after considering public comments. 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 standards 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

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 June 30, 2013, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2012 Form 10-K

OPERATING RESULTS

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

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

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

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

Transmission: Reflects transmission revenues, including those based on tariffs with the 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 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 Six Months Ended June 30, 2013, Compared to Three and Six Months Ended June 30, 2012

Below we discuss our operating results for the three and six months ended June 30, 2013, compared to the results for the three and six months ended June 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 June 30,											Six Months Ended June 30,
	2013			2012			Change			% Change		2013			2012			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	165,302		$	176,893		$	(11,591	)	(6.6	)	$	330,678		$	315,311		$	15,367		4.9
Commercial	165,172			170,132			(4,960		)	(2.9	)	313,128			299,782			13,346			4.5
Industrial	92,820			95,960			(3,140		)	(3.3	)	183,745			181,380			2,365			1.3
Other retail	2,228			(2,363		)	4,591			194.3		(944		)	(5,281		)	4,337			82.1
Total Retail Revenues	425,522			440,622			(15,100		)	(3.4	)	826,607			791,192			35,415			4.5
Wholesale	81,783			68,971			12,812			18.6		168,253			140,183			28,070			20.0
Transmission (a)	52,804			49,380			3,424			6.9		104,315			95,343			8,972			9.4
Other	9,480			7,289			2,191			30.1		16,626			15,222			1,404			9.2
Total Revenues	569,589			566,262			3,327			0.6		1,115,801			1,041,940			73,861			7.1
OPERATING EXPENSES:
Fuel and purchased power	152,700			147,680			5,020			3.4		304,452			275,334			29,118			10.6
Operating and maintenance	163,303			156,470			6,833			4.4		322,032			312,514			9,518			3.0
Depreciation and amortization	67,597			66,299			1,298			2.0		134,443			139,579			(5,136		)	(3.7	)
Selling, general and administrative	54,477			62,711			(8,234		)	(13.1	)	103,422			110,046			(6,624		)	(6.0	)
Total Operating Expenses	438,077			433,160			4,917			1.1		864,349			837,473			26,876			3.2
INCOME FROM OPERATIONS	131,512			133,102			(1,590		)	(1.2	)	251,452			204,467			46,985			23.0
OTHER INCOME (EXPENSE):
Investment earnings (losses)	1,690			(598		)	2,288			382.6		5,749			3,727			2,022			54.3
Other income	13,711			7,537			6,174			81.9		17,427			21,127			(3,700		)	(17.5	)
Other expense	(2,354		)	(2,416		)	62			2.6		(7,715		)	(7,969		)	254			3.2
Total Other Income	13,047			4,523			8,524			188.5		15,461			16,885			(1,424		)	(8.4	)
Interest expense	45,798			44,823			975			2.2		90,082			86,869			3,213			3.7
INCOME BEFORE INCOME TAXES	98,761			92,802			5,959			6.4		176,831			134,483			42,348			31.5
Income tax expense	29,310			28,340			970			3.4		54,123			40,783			13,340			32.7
NET INCOME	69,451			64,462			4,989			7.7		122,708			93,700			29,008			31.0
Less: Net income attributable to noncontrolling interests	2,263			1,728			535			31.0		4,375			3,442			933			27.1
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	67,188			62,734			4,454			7.1		118,333			90,258			28,075			31.1
Preferred dividends	—			1,373			(1,373		)	(100.0	)	—			1,616			(1,616		)	(100.0	)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	67,188		$	61,361		$	5,827		9.5		$	118,333		$	88,642		$	29,691		33.5
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.53		$	0.48		$	0.05		10.4		$	0.93		$	0.70		$	0.23		32.9

_______________

(a) Reflects revenue from an SPP network transmission tariff. For the three and six months ended June 30, 2013, our SPP network transmission costs were $44.6 million and $88.4 million, respectively. These amounts, less administration costs of $9.6 million and $18.5 million, respectively, were returned to us as revenue. For the three and six months ended June 30, 2012, our SPP network transmission costs were $42.3 million and $81.6 million, respectively. These amounts, less administration costs of $6.8 million and $13.0 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 six months ended June 30, 2013 and 2012.



	Three Months Ended June 30,									Six Months Ended June 30,
	2013		2012		Change			% Change		2013		2012		Change		% Change
	(Dollars In Thousands)
Revenues	$	569,589	$	566,262	$	3,327		0.6		$	1,115,801	$	1,041,940	$	73,861	7.1
Less: Fuel and purchased power expense	152,700		147,680		5,020			3.4		304,452		275,334		29,118		10.6
SPP network transmission costs	44,600		42,265		2,335			5.5		88,396		81,627		6,769		8.3
Gross Margin	$	372,289	$	376,317	$	(4,028	)	(1.1	)	$	722,953	$	684,979	$	37,974	5.5

The following table reflects changes in electricity sales for the three and six months ended June 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 June 30,						Six Months Ended June 30,
	2013	2012	Change		% Change		2013	2012	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,460	1,629	(169	)	(10.4	)	3,003	3,044	(41	)	(1.3	)
Commercial	1,856	1,977	(121	)	(6.1	)	3,558	3,626	(68	)	(1.9	)
Industrial	1,312	1,418	(106	)	(7.5	)	2,624	2,779	(155	)	(5.6	)
Other retail	21	22	(1	)	(4.5	)	43	42	1		2.4
Total Retail	4,649	5,046	(397	)	(7.9	)	9,228	9,491	(263	)	(2.8	)
Wholesale	2,048	1,604	444		27.7		4,093	3,298	795		24.1
Total	6,697	6,650	47		0.7		13,321	12,789	532		4.2

Gross margin decreased during the three months ended June 30, 2013, compared to the same period of 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 June 30, 2013, was 33% cooler than the same period of 2012, which represents a return to more normal weather. Contributing to the decrease in retail electricity sales was reduced demand from certain industrial customers. We expect this trend to continue through 2013.

Gross margin increased during the six months ended June 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 reasons discussed above for the three month period. The weather during the six months ended June 30, 2013, was 37% cooler than the same period of 2012 as measured by cooling degree days.

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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 six months ended June 30, 2013 and 2012.



	Three Months Ended June 30,									Six Months Ended June 30,
	2013		2012		Change			% Change		2013		2012		Change			% Change
	(Dollars In Thousands)
Gross margin	$	372,289	$	376,317	$	(4,028	)	(1.1	)	$	722,953	$	684,979	$	37,974		5.5
Add: SPP network transmission costs	44,600		42,265		2,335			5.5		88,396		81,627		6,769			8.3
Less: Operating and maintenance expense	163,303		156,470		6,833			4.4		322,032		312,514		9,518			3.0
Depreciation and amortization expense	67,597		66,299		1,298			2.0		134,443		139,579		(5,136		)	(3.7	)
Selling, general and administrative expense	54,477		62,711		(8,234		)	(13.1	)	103,422		110,046		(6,624		)	(6.0	)
Income from operations	$	131,512	$	133,102	$	(1,590	)	(1.2	)	$	251,452	$	204,467	$	46,985		23.0

Operating Expenses and Other Income and Expense Items



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change		% Change	2013		2012		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	163,303	$	156,470	$	6,833	4.4	$	322,032	$	312,514	$	9,518	3.0

Operating and maintenance expense increased due principally to:


•	increases in property taxes of $4.6 million and $9.8 million, respectively, most of which was offset in retail revenues; and


•	higher SPP network transmission costs of $2.3 million and $6.8 million, respectively, most of which was also offset with higher revenues; however,


•	partially offsetting the increases for the six months ended June 30, 2013, were lower costs at Wolf Creek of $4.8 million. Wolf Creek incurred additional costs in 2012 due principally to an unscheduled outage.



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change		% Change	2013		2012		Change			% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	67,597	$	66,299	$	1,298	2.0	$	134,443	$	139,579	$	(5,136	)	(3.7	)

Depreciation and amortization expense decreased during the six months ended June 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 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 June 30,									Six Months Ended June 30,
	2013		2012		Change			% Change		2013		2012		Change			% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	54,477	$	62,711	$	(8,234	)	(13.1	)	$	103,422	$	110,046	$	(6,624	)	(6.0	)

Selling, general and administrative expense decreased due primarily to:


•	lower post-retirement and other employee benefit costs of $6.8 million and $12.8 million, respectively, due principally to restructuring insurance contracts; and


•	lower labor costs of $3.4 million and $4.4 million, respectively, which in part reflect expenses recorded in 2012 related to sustainable cost reduction activities; however,


•	partially offsetting these decreases were higher pension costs of $3.3 million and $12.4 million, respectively, most of which were offset with higher revenues. These increased costs were principally a consequence of the financial crisis and the subsequent low interest rate environment.



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change		% Change	2013		2012		Change			% Change
	(Dollars in Thousands)
Other income	$	13,711	$	7,537	$	6,174	81.9	$	17,427	$	21,127	$	(3,700	)	(17.5	)

Other income increased during the three months ended June 30, 2013, compared to the same period of 2012 due primarily to our having recorded an additional $6.5 million in COLI benefits. The decrease during the six months ended June 30, 2013, was a result principally of our having recorded $2.7 million less in COLI benefits and a $1.1 million decrease in equity AFUDC.



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change		% Change	2013		2012		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	29,310	$	28,340	$	970	3.4	$	54,123	$	40,783	$	13,340	32.7

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

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FINANCIAL CONDITION

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



	As of		As of
	June 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	7,255,280	$	7,013,765	$	241,515	3.4

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
	June 30, 2013		December 31, 2012		Change			% Change
	(Dollars in Thousands)
Property, plant and equipment of variable interest entities, net	$	301,998	$	321,975	$	(19,977	)	(6.2	)

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
	June 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Short-term debt	$	410,000	$	339,200	$	70,800	20.9

Short-term debt increased due to increased issuances of commercial paper. We used proceeds from the issuances of short-term debt securities to fund our capital and on-going operating needs.



	As of		As of
	June 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Long-term debt, net	$	2,968,642	$	2,819,271	$	149,371	5.3

Long-term debt, net, increased due to the issuance of $250.0 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."



	As of		As of
	June 30, 2013		December 31, 2012		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,233,893	$	1,197,837	$	36,056	3.0

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

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	As of		As of
	June 30, 2013		December 31, 2012		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	27,773	$	25,942	$	1,831		7.1
Long-term debt of variable interest entities	195,203		222,743		(27,540		)	(12.4	)
Total long-term debt of variable interest entities	$	222,976	$	248,685	$	(25,709	)	(10.3	)

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.

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 July 30, 2013, Westar Energy had issued $399.1 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 July 30, 2013, no amounts were borrowed and $16.2 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.

Long-term Debt Financing

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%.

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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 July 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

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Summary of Cash Flows



	Six Months Ended June 30,
	2013			2012			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	231,310		$	103,179		$	128,131		124.2
Investing activities	(301,318		)	(419,790		)	118,472			28.2
Financing activities	68,152			319,726			(251,574		)	(78.7	)
Net (decrease) increase in cash and cash equivalents	$	(1,856	)	$	3,115		$	(4,971	)	(159.6	)

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having received $97.8 million more from retail and wholesale customers, our having contributed $39.8 million less to pension and post-retirement benefit plans, our having paid $29.7 million in 2012 to settle treasury yield hedge transactions and our having paid $14.8 million less for fuel and purchased power. 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 $84.8 million more in proceeds from our COLI investment and our having invested $18.6 million less in additions to property, plant and equipment.

Cash Flows from Financing Activities

Cash flows from financing activities decreased due principally to our having received $295.7 million less in proceeds from the issuance of long-term debt and our having repaid $81.8 million more of borrowings against the cash surrender value of COLI. Partially offsetting these decreases was our having retired $120.6 million less of long-term debt in the six months ended June 30, 2013.

Pension Contribution

During the six months ended June 30, 2013, we contributed $17.7 million to the Westar Energy pension trust and funded $3.7 million of Wolf Creek's pension plan contributions.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2012, through June 30, 2013, our off-balance sheet arrangements did not change materially. For additional information, see our 2012 Form 10-K.

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2012, through June 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 July 2013, the KCC issued an order allowing us to adjust our prices to include updated transmission costs as reflected in the transmission formula rate discussed below. The new prices were effective in March 2013 and are 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. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $31.7 million. We expect the KCC to issue an order on our request in late 2013.

FERC Proceedings

Employees

As of July 30, 2013, we had 2,286 employees, 1,257 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 June 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.

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ITEM 4. CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 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 June 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 May 8, 2013, during the three-month period ended June 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 0.9 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.

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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.

ITEM 6. EXHIBITS



31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended June 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 June 30, 2013
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 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:	August 7, 2013	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

WR-06.30.2013-10Q Exhibit 31(a)

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:


1.	I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2013, of Westar Energy, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


a.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	August 7, 2013	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer
			Westar Energy, Inc.
			(Principal Executive Officer)

WR-06.30.2013-10Q Exhibit 31(b)

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:


1.	I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2013, of Westar Energy, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	August 7, 2013	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer
			Westar Energy, Inc.
			(Principal Financial Officer)

WR-06.30.2013-10Q Exhibit 32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Westar Energy, Inc. (the Company) on Form 10-Q for the quarter ended June 30, 2013 (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	August 7, 2013	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer



Date:	August 7, 2013	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer