WESTAR ENERGY INC /KS - FORM 10-Q

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EX-4.B - EXHIBIT - WESTAR ENERGY INC /KS	wr-06302014x10qexhibit4b.htm
EX-31.A - EXHIBIT - WESTAR ENERGY INC /KS	wr-06302014x10qexhibit31a.htm
EX-32 - EXHIBIT - WESTAR ENERGY INC /KS	wr-06302014x10qexhibit32.htm
EX-31.B - EXHIBIT - WESTAR ENERGY INC /KS	wr-06302014x10qexhibit31b.htm

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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, 2014



[ ]	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		129,690,019 shares
(Class)		(Outstanding at July 30, 2014)

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TABLE OF CONTENTS




PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Cash Flows	9
	Condensed Consolidated Statements of Changes in Equity	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43

PART II. Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	44
Signature		45

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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
2013 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2013
AFUDC		Allowance for funds used during construction
BACT		Best Available Control Technology
BTA		Best Technology Available
CCB		Coal combustion byproduct
CO		Carbon monoxide
CO₂		Carbon dioxide
COLI		Corporate-owned life insurance
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
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
Moody’s		Moody’s Investors Service
MW		Megawatt(s)
MWh		Megawatt hour(s)
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen oxides
NSPS		New Source Performance Standard
PM		Particulate matter
PSD		Prevention of Significant Deterioration
RECA		Retail energy cost adjustment
RSU		Restricted share unit
RTO		Regional transmission organization
S&P		Standard & Poor’s Ratings Services
SO2		Sulfur dioxide
SPP		Southwest Power Pool
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

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FORWARD-LOOKING STATEMENTS

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


-	amount, type and timing of capital expenditures,


-	earnings,


-	cash flow,


-	liquidity and capital resources,


-	litigation,


-	accounting matters,


-	possible corporate restructurings, acquisitions and dispositions,


-	compliance with debt and other restrictive covenants,


-	interest rates and dividends,


-	environmental matters,


-	regulatory matters,


-	nuclear operations, and


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

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


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


-	the difficulty of predicting the amount and timing of changes in demand for electricity, including with respect to emerging competing services and technologies,


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


-	equipment damage from storms and extreme weather,


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


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


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


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


-	the impact of frequently changing laws and regulations relating to air and greenhouse gas (GHG) 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 and operating systems security considerations,


-	changes in accounting requirements and other accounting matters,


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


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

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


-	other circumstances affecting anticipated operations, electricity sales and costs, political, legislative, judicial and regulatory developments at the municipal, state and federal level that can affect us or our industry, including in particular those relating to environmental laws and regulations,


-	the impact of adverse changes in financial markets potentially resulting in the need for additional funding for the nuclear decommissioning and pension trust,


-	cost of fuel used in generation and wholesale electricity prices,


-	conservation and energy efficiency measures which may reduce sales, and


-	other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2013 (2013 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 2013 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 2013 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.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)



	As of		As of
	June 30, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,751	$	4,487
Accounts receivable, net of allowance for doubtful accounts of $4,503 and $4,596, respectively	259,205		250,036
Fuel inventory and supplies	256,521		239,511
Deferred tax assets	41,878		37,954
Prepaid expenses	18,058		15,821
Regulatory assets	136,809		135,408
Other	24,931		23,608
Total Current Assets	748,153		706,825
PROPERTY, PLANT AND EQUIPMENT, NET	7,816,120		7,551,916
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	291,253		296,626
OTHER ASSETS:
Regulatory assets	599,721		620,006
Nuclear decommissioning trust	185,896		175,625
Other	230,099		246,140
Total Other Assets	1,015,716		1,041,771
TOTAL ASSETS	$	9,871,242	$	9,597,138
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	—	$	250,000
Current maturities of long-term debt of variable interest entities	28,098		27,479
Short-term debt	343,300		134,600
Accounts payable	171,162		233,351
Accrued dividends	45,182		43,604
Accrued taxes	76,592		69,769
Accrued interest	55,556		80,457
Regulatory liabilities	54,185		35,982
Other	85,579		80,184
Total Current Liabilities	859,654		955,426
LONG-TERM LIABILITIES:
Long-term debt, net	3,215,805		2,968,958
Long-term debt of variable interest entities, net	166,720		194,802
Deferred income taxes	1,423,021		1,363,148
Unamortized investment tax credits	190,702		192,265
Regulatory liabilities	307,053		293,574
Accrued employee benefits	325,449		331,558
Asset retirement obligations	177,755		160,682
Other	74,140		68,194
Total Long-Term Liabilities	5,880,645		5,573,181
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 129,272,835 shares and 128,254,229 shares, respective to each date	646,364		641,271
Paid-in capital	1,718,017		1,696,727
Retained earnings	756,442		724,776
Total Westar Energy, Inc. Shareholders’ Equity	3,120,823		3,062,774
Noncontrolling Interests	10,120		5,757
Total Equity	3,130,943		3,068,531
TOTAL LIABILITIES AND EQUITY	$	9,871,242	$	9,597,138

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Three Months Ended June 30,
	2014			2013
REVENUES	$	612,668		$	569,589
OPERATING EXPENSES:
Fuel and purchased power	164,779			152,700
SPP network transmission costs	55,533			44,600
Operating and maintenance	101,839			87,999
Depreciation and amortization	70,882			67,597
Selling, general and administrative	62,168			54,477
Taxes other than income tax	34,738			30,704
Total Operating Expenses	489,939			438,077
INCOME FROM OPERATIONS	122,729			131,512
OTHER INCOME (EXPENSE):
Investment earnings	3,175			1,690
Other income	5,658			13,711
Other expense	(2,287		)	(2,354		)
Total Other Income	6,546			13,047
Interest expense	47,303			45,798
INCOME BEFORE INCOME TAXES	81,972			98,761
Income tax expense	26,150			29,310
NET INCOME	55,822			69,451
Less: Net income attributable to noncontrolling interests	2,349			2,263
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	53,473		$	67,188
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.41		$	0.53
Diluted earnings per common share	$	0.40		$	0.52
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	129,363,382			127,311,411
Diluted	131,973,139			127,930,395
DIVIDENDS DECLARED PER COMMON SHARE	$	0.35		$	0.34

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
REVENUES	$	1,241,224		$	1,115,801
OPERATING EXPENSES:
Fuel and purchased power	338,618			304,452
SPP network transmission costs	107,491			88,396
Operating and maintenance	193,629			172,154
Depreciation and amortization	140,992			134,443
Selling, general and administrative	118,653			103,422
Taxes other than income tax	69,571			61,482
Total Operating Expenses	968,954			864,349
INCOME FROM OPERATIONS	272,270			251,452
OTHER INCOME (EXPENSE):
Investment earnings	5,553			5,749
Other income	11,575			17,427
Other expense	(7,952		)	(7,715		)
Total Other Income	9,176			15,461
Interest expense	93,543			90,082
INCOME BEFORE INCOME TAXES	187,903			176,831
Income tax expense	61,111			54,123
NET INCOME	126,792			122,708
Less: Net income attributable to noncontrolling interests	4,365			4,375
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	122,427		$	118,333
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.95		$	0.93
Diluted earnings per common share	$	0.93		$	0.92
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	129,184,767			127,254,250
Diluted	131,778,584			127,735,157
DIVIDENDS DECLARED PER COMMON SHARE	$	0.70		$	0.68

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	126,792		$	122,708
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	140,992			134,443
Amortization of nuclear fuel	10,304			8,631
Amortization of deferred regulatory gain from sale leaseback	(2,748		)	(2,748		)
Amortization of corporate-owned life insurance	8,712			4,138
Non-cash compensation	3,945			4,146
Net deferred income taxes and credits	58,097			45,409
Stock-based compensation excess tax benefits	544			(399		)
Allowance for equity funds used during construction	(9,718		)	(5,689		)
Changes in working capital items:
Accounts receivable	(10,586		)	(15,271		)
Fuel inventory and supplies	(16,248		)	11,780
Prepaid expenses and other	(4,891		)	2,396
Accounts payable	(16,199		)	(24,838		)
Accrued taxes	8,293			16,196
Other current liabilities	(32,477		)	(58,624		)
Changes in other assets	1,828			(28,048		)
Changes in other liabilities	16,674			17,080
Cash Flows from Operating Activities	283,314			231,310
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(427,124		)	(398,998		)
Purchase of securities - trusts	(4,410		)	(59,986		)
Sale of securities - trusts	5,552			75,475
Investment in corporate-owned life insurance	(15,903		)	(17,408		)
Proceeds from investment in corporate-owned life insurance	1,773			101,085
Proceeds from federal grant	—			876
Investment in affiliated company	1,418			—
Other investing activities	(1,544		)	(2,362		)
Cash Flows used in Investing Activities	(440,238		)	(301,318		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	208,533			70,617
Proceeds from long-term debt	171,785			245,813
Retirements of long-term debt	(177,500		)	(100,000		)
Retirements of long-term debt of variable interest entities	(27,305		)	(25,474		)
Repayment of capital leases	(1,628		)	(1,539		)
Borrowings against cash surrender value of corporate-owned life insurance	56,577			57,948
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(1,123		)	(100,060		)
Stock-based compensation excess tax benefits	(544		)	399
Issuance of common stock	20,699			2,992
Distributions to shareholders of noncontrolling interests	—			(1,658		)
Cash dividends paid	(84,419		)	(80,886		)
Other financing activities	(1,887		)	—
Cash Flows from Financing Activities	163,188			68,152
NET CHANGE IN CASH AND CASH EQUIVALENTS	6,264			(1,856		)
CASH AND CASH EQUIVALENTS:
Beginning of period	4,487			5,829
End of period	$	10,751		$	3,973

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)



	Westar Energy, Inc. Shareholders
	Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
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	95,841	479		2,513			—			—			2,992
Issuance of stock for compensation and reinvested dividends	335,462	1,677		3,105			—			—			4,782
Tax withholding related to stock compensation	—	—		(2,568		)	—			—			(2,568		)
Dividends on common stock ($0.68 per share)	—	—		—			(87,082		)	—			(87,082		)
Stock compensation expense	—	—		4,104			—			—			4,104
Tax benefit on stock compensation	—	—		399			—			—			399
Deconsolidation of noncontrolling interest	—	—		—			—			(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

Balance as of December 31, 2013	128,254,229	$	641,271	$	1,696,727		$	724,776		$	5,757		$	3,068,531
Net income	—	—		—			122,427			4,365			126,792
Issuance of stock	755,961	3,780		16,919			—			—			20,699
Issuance of stock for compensation and reinvested dividends	262,645	1,313		2,899			—			—			4,212
Tax withholding related to stock compensation	—	—		(1,887		)	—			—			(1,887		)
Dividends on common stock ($0.70 per share)	—	—		—			(90,761		)	—			(90,761		)
Stock compensation expense	—	—		3,903			—			—			3,903
Tax benefit on stock compensation	—	—		(544		)	—			—			(544		)
Other	—	—		—			—			(2		)	(2		)
Balance as of June 30, 2014	129,272,835	646,364		1,718,017			756,442			10,120			3,130,943

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

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 697,000 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 2013 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 (RECA) 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, 2014, are not necessarily indicative of the results to be expected for the full year.

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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, 2014		December 31, 2013
	(In Thousands)
Fuel inventory	$	83,513	$	78,368
Supplies	173,008		161,143
Fuel inventory and supplies	$	256,521	$	239,511

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,
	2014			2013			2014			2013
	(Dollars In Thousands)
Borrowed funds	$	3,213		$	2,583		$	6,944		$	5,168
Equity funds	4,712			2,943			9,718			5,689
Total	$	7,925		$	5,526		$	16,662		$	10,857
Average AFUDC Rates	6.8		%	4.3		%	7.0		%	4.3		%

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,
	2014		2013		2014		2013
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	55,822	$	69,451	$	126,792	$	122,708
Less: Net income attributable to noncontrolling interests	2,349		2,263		4,365		4,375
Net income attributable to Westar Energy, Inc.	53,473		67,188		122,427		118,333
Less: Net income allocated to RSUs	148		196		336		339
Net income allocated to common stock	$	53,325	$	66,992	$	122,091	$	117,994

Weighted average equivalent common shares outstanding – basic	129,363,382		127,311,411		129,184,767		127,254,250
Effect of dilutive securities:
RSUs	164,641		53,570		122,221		45,567
Forward sale agreements	2,445,116		565,414		2,471,596		435,340
Weighted average equivalent common shares outstanding – diluted (a)	131,973,139		127,930,395		131,778,584		127,735,157

Earnings per common share, basic	$	0.41	$	0.53	$	0.95	$	0.93
Earnings per common share, diluted	$	0.40	$	0.52	$	0.93	$	0.92

_______________

(a)We had no antidilutive shares for the three and six months ended June 30, 2014 and 2013.

Supplemental Cash Flow Information



	Six Months Ended June 30,
	2014		2013
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	80,373	$	73,853
Interest on financing activities of VIEs	6,526		7,349
Income taxes, net of refunds	236		(86		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	90,395		56,187
Property, plant and equipment of VIEs	—		(14,282		)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,212		4,782
Deconsolidation of VIE	—		(14,282		)
Assets acquired through capital leases	1,195		326

New Accounting Pronouncements

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, regulatory bodies have issued the following new accounting pronouncement that may affect our accounting and/or disclosure.

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Revenue Recognition

In May 2014, the Financial Accounting Standards Board (FASB) issued guidance that addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing, and uncertainty of revenue from contracts with customers. This guidance is effective for fiscal years beginning after December 15, 2016. Early application of the standard is not permitted. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

3. RATE MATTERS AND REGULATION

KCC Proceedings

In June 2014, the Kansas Corporation Commission (KCC) issued an order to adjust our prices to include updated transmission costs as reflected in the transmission formula rate discussed below. The new prices were effective in April 2014 and we estimate this will increase our annual retail revenues by approximately $41.0 million.

In May 2014, the KCC issued an order to adjust our prices to include costs associated with investments to comply with environmental requirements during 2013. New prices were effective in June 2014 and we estimate this will increase our annual retail revenues by approximately $11.0 million.

In December 2013, the KCC issued an order to adjust our prices to include costs incurred for property taxes. New prices were effective in January 2014 and are expected to increase annual retail revenues by approximately $12.7 million.

FERC Proceedings

Our transmission formula rate that includes projected 2014 transmission capital expenditures and operating costs became effective January 2014 and is expected to increase annual transmission revenues by approximately $44.3 million. This updated rate provided the basis for our request to the KCC to adjust our retail prices to include updated transmission costs discussed above.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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


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

•

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


•	Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

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

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

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, 2014				As of December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,105,000	$	3,417,259	$	3,102,500	$	3,294,209
Fixed-rate debt of VIEs	194,377		215,873		221,682		241,241

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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, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	—	$	52,848	$	6,288	$	59,136
International equity	—		33,930		—		33,930
Core bonds	—		18,865		—		18,865
High-yield bonds	—		13,575		—		13,575
Emerging market bonds	—		11,995		—		11,995
Other fixed income	—		4,807		—		4,807
Combination debt/equity/other funds	—		17,920		—		17,920
Alternative investments	—		—		16,446		16,446
Real estate securities	—		—		9,026		9,026
Cash equivalents	196		—		—		196
Total Nuclear Decommissioning Trust	196		153,940		31,760		185,896
Trading Securities:
Domestic equity	—		18,450		—		18,450
International equity	—		4,607		—		4,607
Core bonds	—		12,307		—		12,307
Cash equivalents	168		—		—		168
Total Trading Securities	168		35,364		—		35,532
Total Assets Measured at Fair Value	$	364	$	189,304	$	31,760	$	221,428

As of December 31, 2013	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	—	$	49,957	$	5,817	$	55,774
International equity	—		31,816		—		31,816
Core bonds	—		18,107		—		18,107
High-yield bonds	—		12,902		—		12,902
Emerging market bonds	—		11,055		—		11,055
Other fixed income	—		4,690		—		4,690
Combination debt/equity/other funds	—		17,093		—		17,093
Alternative investments	—		—		15,675		15,675
Real estate securities	—		—		8,511		8,511
Cash equivalents	2		—		—		2
Total Nuclear Decommissioning Trust	2		145,620		30,003		175,625
Trading Securities:
Domestic equity	—		18,075		—		18,075
International equity	—		4,519		—		4,519
Core bonds	—		12,166		—		12,166
Cash equivalents	166		—		—		166
Total Trading Securities	166		34,760		—		34,926
Total Assets Measured at Fair Value	$	168	$	180,380	$	30,003	$	210,551

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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, 2014.



	Domestic Equity			Alternative Investments		Real Estate Securities			Net Balance
	(In Thousands)
Balance as of March 31, 2014	$	5,984		$	16,102	$	8,812		$	30,898
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	447			344		214			1,005
Purchases	46			—		89			135
Sales	(189		)	—		(89		)	(278		)
Balance as of June 30, 2014	$	6,288		$	16,446	$	9,026		$	31,760

Balance as of December 31, 2013	$	5,817		$	15,675	$	8,511		$	30,003
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	609			771		515			1,895
Purchases	96			—		166			262
Sales	(234		)	—		(166		)	(400		)
Balance as of June 30, 2014	$	6,288		$	16,446	$	9,026		$	31,760

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

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Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the three and six months ended June 30, 2014 and 2013, attributed to level 3 assets and liabilities.



	Domestic Equity			Alternative Investments		Real Estate Securities		Net Balance
	(In Thousands)
Three months ended June 30, 2014	$	259		$	344	$	124	$	727
Three months ended June 30, 2013	157			234		62		453
Six months ended June 30, 2014	375			772		349		1,496
Six months ended June 30, 2013	(20		)	234		155		369

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, 2014				As of December 31, 2013				As of June 30, 2014
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	6,288	$	2,587	$	5,817	$	2,683	(a)	(a)
Alternative investments	16,446		—		15,675		—		(b)	(b)
Real estate securities	9,026		—		8,511		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	31,760		2,587		30,003		2,683

Trading Securities:
Domestic equity	18,450		—		18,075		—		Upon Notice	1 day
International equity	4,607		—		4,519		—		Upon Notice	1 day
Core bonds	12,307		—		12,166		—		Upon Notice	1 day
Total Trading Securities	35,364		—		34,760		—
Total	$	67,124	$	2,587	$	64,763	$	2,683

_______________

(a)

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


(b)	This investment 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 market risks through regulatory, operating and financing activities.

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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.

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2014, and December 31, 2013, we measured the fair value of trust assets at $35.5 million and $34.9 million, respectively. 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, 2014, we recorded unrealized gains of $1.1 million and $1.6 million, respectively, on the assets still held. For the three and six months ended June 30, 2013, we recorded unrealized losses of $6.2 million and $3.7 million, respectively, on the assets still held.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2014, and December 31, 2013. As of June 30, 2014, the fair value of available-for-sale bond funds was $49.2 million. The NDT did not have investments in debt securities outside of investment funds as of June 30, 2014.

Using the specific identification method to determine cost, we realized no gains on our available-for-sale securities for the three months ended June 30, 2014 and a gain of $0.1 million for the six months ended June 30, 2014. For the three and six months ended June 30, 2013, we realized gains of $3.2 million and $4.5 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.

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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, 2014, and December 31, 2013.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2014
Domestic equity	$	41,327	$	17,814	$	(5	)	$	59,136	32	%
International equity	27,133		6,797		—			33,930		18	%
Core bonds	18,500		365		—			18,865		10	%
High-yield bonds	12,652		923		—			13,575		7	%
Emerging market bonds	12,262		—		(267		)	11,995		6	%
Other fixed income	4,738		69		—			4,807		3	%
Combination debt/equity/other funds	14,964		3,010		(54		)	17,920		10	%
Alternative investments	15,000		1,446		—			16,446		9	%
Real estate securities	10,434		—		(1,408		)	9,026		5	%
Cash equivalents	196		—		—			196		<1%
Total	$	157,206	$	30,424	$	(1,734	)	$	185,896	100	%

As of December 31, 2013
Domestic equity	$	40,976	$	14,799	$	(1	)	$	55,774	32	%
International equity	26,581		5,266		(31		)	31,816		18	%
Core bonds	18,287		—		(180		)	18,107		10	%
High-yield bonds	12,275		627		—			12,902		7	%
Emerging market bonds	12,207		—		(1,152		)	11,055		6	%
Other fixed income	4,684		6		—			4,690		3	%
Combination debt/equity/other funds	14,964		2,380		(251		)	17,093		10	%
Alternative investments	15,000		675		—			15,675		9	%
Real estate securities	10,268		—		(1,757		)	8,511		5	%
Cash equivalents	2		—		—			2		<1%
Total	$	155,244	$	23,753	$	(3,372	)	$	175,625	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, 2014, and December 31, 2013.



	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, 2014
Domestic equity	$	105	$	(5	)	$	—	$	—		$	105	$	(5	)
Emerging market bonds	—		—			11,995		(267		)	11,995		(267		)
Combination debt/equity/other funds	—		—			6,463		(54		)	6,463		(54		)
Real estate securities	—		—			9,026		(1,408		)	9,026		(1,408		)
Total	$	105	$	(5	)	$	27,484	$	(1,729	)	$	27,589	$	(1,734	)

As of December 31, 2013
Domestic equity	$	59	$	(1	)	$	—	$	—		$	59	$	(1	)
International equity	6,244		(31		)	—		—			6,244		(31		)
Core bonds	18,107		(180		)	—		—			18,107		(180		)
Emerging market bonds	11,055		(1,152		)	—		—			11,055		(1,152		)
Combination debt/equity/other funds	6,283		(251		)	—		—			6,283		(251		)
Real estate securities	—		—			8,511		(1,757		)	8,511		(1,757		)
Total	$	41,748	$	(1,615	)	$	8,511	$	(1,757	)	$	50,259	$	(3,372	)

6. DEBT FINANCING

In July 2014, KGE issued $250.0 million in aggregate principal amount of first mortgage bonds bearing stated interest at 4.30% per annum and maturing July 2044, the proceeds of which were used in July 2014 to retire Westar Energy first mortgage bonds in an aggregate principal amount of $250.0 million and stated interest of 6.00% per annum.

In May 2014, Westar Energy issued $180.0 million in aggregate principal amount of first mortgage bonds bearing stated interest at 4.10% per annum and maturing April 2043. These bonds constitute a further issuance of a series of bonds initially issued in March 2013 in an aggregate principal amount of $250.0 million. Proceeds from this issuance were used in June 2014 to redeem three KGE pollution control bond series with an aggregate principal amount of $177.5 million and stated interest rates of 5.30% and 5.00% per annum.

In February 2014, Westar Energy extended the term of the $270.0 million revolving credit facility to February 2017, provided that $20.0 million of this facility will terminate in February 2016. So long as there is no default under the facility, Westar Energy may increase the aggregate amount of borrowings under the facility to $400.0 million, subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of June 30, 2014, and December 31, 2013, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

7. TAXES

We recorded income tax expense of $26.2 million with an effective income tax rate of 32% for the three months ended June 30, 2014, and income tax expense of $29.3 million with an effective income tax rate of 30% for the same period of 2013. We recorded income tax expense of $61.1 million with an effective income tax rate of 33% for the six months ended June 30, 2014, and income tax expense of $54.1 million with an effective income tax rate of 31% for the same period of 2013. The increases in the effective income tax rates for the three and six months ended June 30, 2014, were due primarily to less non-taxable income from corporate-owned life insurance (COLI).

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As of June 30, 2014, and December 31, 2013, unrecognized income tax benefits totaled $2.5 million and $1.7 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of June 30, 2014, and December 31, 2013, we had $0.2 million accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2014, or December 31, 2013.

As of June 30, 2014, and December 31, 2013, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Effective January 1, 2014, we adopted new regulations released by the Internal Revenue Service (IRS) and the U. S. Treasury Department regarding deduction and capitalization of expenditures related to tangible property, including the tax treatment of, among other things, materials and supplies and the determination of whether expenditures with respect to tangible property are a deductible repair or must be capitalized, and re-proposed regulations regarding dispositions of property under the Modified Accelerated Cost Recovery System. We continue to evaluate the new regulations, but do not expect them to have a material impact on our consolidated financial results.

Additionally, also effective January 1, 2014, we implemented new accounting guidance regarding the presentation of an unrecognized tax benefit. An unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, similar tax loss, or a tax credit carryforward. To the extent that such deferred tax assets are not available to settle any additional income taxes that would result from the disallowance of a tax position at the reporting date, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. We adopted this guidance with retrospective application to prior periods and it did not have a material impact on our consolidated financial statements.

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8. PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2014			2013			2014			2013
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,055		$	5,355		$	345		$	507
Interest cost	10,400			9,630			1,588			1,502
Expected return on plan assets	(9,109		)	(8,351		)	(1,644		)	(1,672		)
Amortization of unrecognized:
Transition obligation, net	—			—			—			81
Prior service costs	131			150			631			631
Actuarial loss, net	4,840			8,479			(185		)	281
Net periodic cost before regulatory adjustment	10,317			15,263			735			1,330
Regulatory adjustment (a)	4,002			783			1,124			717
Net periodic cost	$	14,319		$	16,046		$	1,859		$	2,047

_______________


(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,	2014			2013			2014			2013
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	8,110		$	10,710		$	691		$	1,014
Interest cost	20,800			19,260			3,175			3,004
Expected return on plan assets	(18,219		)	(16,702		)	(3,288		)	(3,345		)
Amortization of unrecognized:
Transition obligation, net	—			—			—			162
Prior service costs	262			300			1,262			1,262
Actuarial loss, net	9,681			16,957			(371		)	562
Net periodic cost before regulatory adjustment	20,634			30,525			1,469			2,659
Regulatory adjustment (a)	8,003			1,567			2,247			1,434
Net periodic cost	$	28,637		$	32,092		$	3,716		$	4,093

_______________


(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, 2014 and 2013, we contributed $19.0 million and $17.7 million, respectively, to the Westar Energy pension trust.

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9. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2014			2013			2014		2013
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,424		$	1,708		$	43	$	52
Interest cost	2,117			1,891			116		103
Expected return on plan assets	(2,021		)	(1,843		)	—		—
Amortization of unrecognized:
Prior service costs	14			14			—		—
Actuarial loss, net	747			1,355			41		66
Net periodic cost before regulatory adjustment	2,281			3,125			200		221
Regulatory adjustment (a)	501			(203		)	—		—
Net periodic cost	$	2,782		$	2,922		$	200	$	221

_______________


(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,	2014			2013			2014		2013
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,847		$	3,417		$	87	$	104
Interest cost	4,235			3,782			232		206
Expected return on plan assets	(4,042		)	(3,686		)	—		—
Amortization of unrecognized:
Prior service costs	29			28			—		—
Actuarial loss, net	1,493			2,710			82		132
Net periodic cost before regulatory adjustment	4,562			6,251			401		442
Regulatory adjustment (a)	1,002			(406		)	—		—
Net periodic cost	$	5,564		$	5,845		$	401	$	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, 2014, we did not fund the Wolf Creek pension plan, and during the six months ended June 30, 2013, we funded $3.7 million 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, acid gases and GHG.

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 Environmental Protection Agency (EPA) approved Kansas State Implementation Plan, 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. The Kansas Department of Health and Environment (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 and it may have a material impact on our operations and/or consolidated financial results.

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/or consolidated financial results.

Cross-State Air Pollution Rule

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce emissions of SO₂, NOx and fine particles. In April 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia Circuit that had vacated CSAPR and remanded CSAPR back to them for further proceedings consistent with the U.S. Supreme Court decision. The timeline for further proceedings related to CSAPR by the U.S. Court of Appeals for the District of Columbia Circuit is unknown at this time. In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to lift the CSAPR stay. The original effective dates under CSAPR presented compliance challenges for us, but while CSAPR was stayed, we installed various emission controls at our generation facilities and have projects for additional controls in progress or planned. When CSAPR is reinstated, the EPA is expected to establish new effective dates for compliance with the reduced emission levels required by the rule. We are unable to determine the full impact of reinstatement of CSAPR until the U.S. Court of Appeals for the District of Columbia Circuit and the EPA take further action, the timing for which is unknown.

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 approximately $610.0 million of the projected capital investment associated with the environmental upgrades at La Cygne Generating Station (La Cygne). In November 2013, the KCC issued an order allowing us to adjust our prices to include the investment in the La Cygne environmental upgrades through June 30, 2013, and to reflect cost reductions elsewhere. The new prices are expected to increase our annual retail revenues by approximately $30.7 million. To change our prices to collect increased operating and maintenance costs, we must file a general rate review with the KCC.

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Greenhouse Gases

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 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 required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. In June 2014, the U.S. Supreme Court ordered that the EPA can no longer treat GHG as a pollutant for purposes of defining major emitting facilities and modifications to major emitting facilities under the Prevention of Significant Deterioration (PSD) and Title V Operating Permit Programs. In essence, this ruling invalidates the above mentioned Tailoring Rule, however, it still allows the EPA to apply BACT for GHG in situations where applicability is triggered for another PSD regulated pollutant. We cannot at this time determine the impact of these regulations on our future operations and consolidated financial results as the rule has not been finalized, but we believe the cost of compliance with the regulations could be material.

Water

In May 2014, the EPA issued final standards for cooling intake structures at power plants to protect aquatic life. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven Best Technology Available (BTA) options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for LaCygne and Wolf Creek plants. We are currently evaluating the rule's impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but do not expect it to 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 retail 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. With our agreement to purchase the energy produced from 200 megawatts (MW) of installed design capacity of additional wind generation beginning in late 2016, we expect to meet the increased requirements through 2020. 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 equipment on one of three Jeffrey Energy Center (JEC) coal units to be completed by the end of 2014, which we estimate will cost approximately $230.0 million. We are installing less expensive NOx reduction equipment on the other two units to satisfy other terms of the settlement. We plan to complete these projects in 2014 and have begun to recover the costs to install these systems through our ECRR, but additional recovery remains subject to the approval of our regulators.

Storage of Spent Nuclear Fuel

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.

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.

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12. COMMON STOCK

During the six months ended June 30, 2014, Westar Energy issued 0.7 million shares of common stock with a physical settlement amount of $18.3 million to settle certain forward sale transactions pursuant to a master forward sale confirmation entered into in 2010. Under that agreement Westar Energy must settle any forward transaction within 18 months of the date of the transaction. Assuming physical share settlement of the approximately 11.4 million shares associated with all outstanding forward sale transactions as of June 30, 2014, Westar Energy would have received aggregate proceeds of approximately $330.9 million based on a weighted-average forward price of $29.11 per share. In July 2014, Westar Energy issued 0.3 million shares with a physical settlement amount of approximately $9.1 million pursuant to a master forward sale confirmation entered into in 2010.

13. VARIABLE INTEREST ENTITIES

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

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

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

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Railcars

We lease railcars from a 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 agreement 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 agreement is greater than the fixed amount. We have determined that we will renew the lease when the initial contract expires in November 2014. Upon renewal of the lease contract, we will no longer be the primary beneficiary of the VIE and, accordingly, will deconsolidate the trust.

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, 2014		December 31, 2013
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	291,253	$	296,626
Regulatory assets (a)	7,365		6,792

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,098	$	27,479
Accrued interest (b)	2,962		3,472
Long-term debt of variable interest entities, net	166,720		194,802

_______________

(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.

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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 U. S. 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, 2014, compared to the same periods of 2013, our general financial condition and significant changes that occurred during 2014. 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,
	2014		2013		Change			2014		2013		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	53,473	$	67,188	$	(13,715	)	$	122,427	$	118,333	$	4,094
Earnings per common share, basic	0.41		0.53		(0.12		)	0.95		0.93		0.02

Net income attributable to common stock and basic EPS for the three months ended June 30, 2014, decreased compared to the same period in 2013 due primarily to our having recorded approximately $10.0 million less in COLI benefits. Also contributing to this decrease was higher operating and maintenance costs at our generating plants. These decreases were partially offset by higher retail prices.

Net income attributable to common stock and basic EPS for the six months ended June 30, 2014, increased slightly compared to the same period in 2013 due primarily to higher retail prices resulting from investments we made in our transmission infrastructure and air quality controls at our power plants, higher electricity sales, and increased energy marketing margins. Higher operating expense and lower COLI benefits largely offset these increases.

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 2013 Form 10-K.

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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.

Greenhouse Gases

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 required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. In June 2014, the U.S. Supreme Court ordered that the EPA can no longer treat GHG as a pollutant for purposes of defining major emitting facilities and modifications to major emitting facilities under the PSD and Title V Operating Permit Programs. In essence, this ruling invalidates the above mentioned Tailoring Rule, however, it still allows the EPA to apply BACT for GHG in situations where applicability is triggered for another PSD regulated pollutant. We cannot at this time determine the impact of these regulations on our future operations and consolidated financial results as the rule has not been finalized, but we believe the cost of compliance with the regulations could be material.

Additionally, in January 2014, the EPA re-proposed a New Source Performance Standard (NSPS) that would limit carbon dioxide (CO₂₎ emissions for new coal and natural gas fueled electric generating units. A final rule is expected in 2014. In addition, the EPA issued proposed CO₂ emissions rules for existing, modified and reconstructed power plants in June 2014, and EPA is expected to finalize such rules by June 2015 and require states to submit their implementation plans to the EPA by June 2016. Under the June 2014 proposed power plant rules for existing plants, called the Clean Power Plan, states would be required to meet CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030. Moreover, we could be required to make efficiency improvements to our existing facilities, among other things. We are currently evaluating the proposed rules for new, existing, modified and reconstructed electric generating units, but believe these rules if finalized in their current form would likely have a material impact on our operations, future generation plans and/or results of operations.

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. We recycle some of our ash production, principally by selling to the aggregate industry. In 2010, the EPA proposed a rule to regulate CCBs, which we believe might impair our ability to recycle ash or require additional CCB handling, processing and storage equipment, or both. The EPA has agreed to issue a final rule by December 2014. 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/or consolidated financial results could be material.

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 the EPA at five-year intervals. The 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.

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Cross-State Air Pollution Rule

In 2011, the EPA finalized the CSAPR requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce emissions of SO₂, NOx and fine particles. In April 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia Circuit that had vacated CSAPR and remanded CSAPR back to them for further proceedings consistent with the U.S. Supreme Court decision. The timeline for further proceedings related to CSAPR by the U.S. Court of Appeals for the District of Columbia Circuit is unknown at this time. In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to lift the CSAPR stay. The original effective dates under CSAPR presented compliance challenges for us, but while CSAPR was stayed, we installed various emission controls at our generation facilities and have projects for additional controls in progress or planned. When CSAPR is reinstated, the EPA is expected to establish new effective dates for compliance with the reduced emission levels required by the rule. We are unable to determine the full impact of reinstatement of CSAPR until the U.S. Court of Appeals for the District of Columbia Circuit and the EPA take further action, the timing for which is unknown.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants are expected to be issued by the EPA in September 2015. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.

In June 2014, the EPA along with the U.S. Army Corps of Engineers issued a proposed rule defining the Waters of the United States. This rulemaking has the potential to impact all programs under the Federal CWA. Expansion of regulated waterways is possible based on initial review of the proposal. Impacts may exist in several permitting programs. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.

Renewable Energy Standard

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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 2013 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2013, through June 30, 2014, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2013 Form 10-K.

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OPERATING RESULTS

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

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

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

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Revenues from these sales are either included in the RECA or used in the determination of base rates at the time of our next general rate case.

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

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

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

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Three and Six Months Ended June 30, 2014, Compared to Three and Six Months Ended June 30, 2013

Below we discuss our operating results for the three and six months ended June 30, 2014, compared to the results for the three and six months ended June 30, 2013. 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,
	2014			2013			Change			% Change		2014			2013			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	175,671		$	165,302		$	10,369		6.3		$	367,958		$	330,678		$	37,280		11.3
Commercial	178,194			165,172			13,022			7.9		339,294			313,128			26,166			8.4
Industrial	106,984			92,820			14,164			15.3		201,480			183,745			17,735			9.7
Other retail	(3,033		)	2,228			(5,261		)	(236.1	)	(11,557		)	(944		)	(10,613		)	(b)
Total Retail Revenues	457,816			425,522			32,294			7.6		897,175			826,607			70,568			8.5
Wholesale	82,434			81,783			651			0.8		193,047			168,253			24,794			14.7
Transmission (a)	63,700			52,804			10,896			20.6		125,166			104,315			20,851			20.0
Other	8,718			9,480			(762		)	(8.0	)	25,836			16,626			9,210			55.4
Total Revenues	612,668			569,589			43,079			7.6		1,241,224			1,115,801			125,423			11.2
OPERATING EXPENSES:
Fuel and purchased power	164,779			152,700			12,079			7.9		338,618			304,452			34,166			11.2
SPP network transmission costs	55,533			44,600			10,933			24.5		107,491			88,396			19,095			21.6
Operating and maintenance	101,839			87,999			13,840			15.7		193,629			172,154			21,475			12.5
Depreciation and amortization	70,882			67,597			3,285			4.9		140,992			134,443			6,549			4.9
Selling, general and administrative	62,168			54,477			7,691			14.1		118,653			103,422			15,231			14.7
Taxes other than income tax	34,738			30,704			4,034			13.1		69,571			61,482			8,089			13.2
Total Operating Expenses	489,939			438,077			51,862			11.8		968,954			864,349			104,605			12.1
INCOME FROM OPERATIONS	122,729			131,512			(8,783		)	(6.7	)	272,270			251,452			20,818			8.3
OTHER INCOME (EXPENSE):
Investment earnings	3,175			1,690			1,485			87.9		5,553			5,749			(196		)	(3.4	)
Other income	5,658			13,711			(8,053		)	(58.7	)	11,575			17,427			(5,852		)	(33.6	)
Other expense	(2,287		)	(2,354		)	67			2.8		(7,952		)	(7,715		)	(237		)	(3.1	)
Total Other Income	6,546			13,047			(6,501		)	(49.8	)	9,176			15,461			(6,285		)	(40.7	)
Interest expense	47,303			45,798			1,505			3.3		93,543			90,082			3,461			3.8
INCOME BEFORE INCOME TAXES	81,972			98,761			(16,789		)	(17.0	)	187,903			176,831			11,072			6.3
Income tax expense	26,150			29,310			(3,160		)	(10.8	)	61,111			54,123			6,988			12.9
NET INCOME	55,822			69,451			(13,629		)	(19.6	)	126,792			122,708			4,084			3.3
Less: Net income attributable to noncontrolling interests	2,349			2,263			86			3.8		4,365			4,375			(10		)	(0.2	)
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	53,473		$	67,188		$	(13,715	)	(20.4	)	$	122,427		$	118,333		$	4,094		3.5
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.41		$	0.53		$	(0.12	)	(22.6	)	$	0.95		$	0.93		$	0.02		2.2
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.40		$	0.52		$	(0.12	)	(23.1	)	$	0.93		$	0.92		$	0.01		1.1

_______________

(a) Includes revenue from an SPP network transmission tariff corresponding to our SPP network transmission costs. For the three and six months ended June 30, 2014, these costs, less administration fees of $12.8 million and $24.8 million, respectively, were returned to us as revenue. For the three and six months ended June 30, 2013, these costs, less administration fees of $9.6 million and $18.5 million, respectively, were returned to us as revenue.

(b) Change greater than 1,000%.

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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. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP regional transmission organization (RTO). As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, 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. The following table summarizes our gross margin for the three and six months ended June 30, 2014 and 2013.



	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change		% Change	2014		2013		Change		% Change
	(Dollars In Thousands)
Revenues	$	612,668	$	569,589	$	43,079	7.6	$	1,241,224	$	1,115,801	$	125,423	11.2
Less: Fuel and purchased power expense	164,779		152,700		12,079		7.9	338,618		304,452		34,166		11.2
SPP network transmission costs	55,533		44,600		10,933		24.5	107,491		88,396		19,095		21.6
Gross Margin	$	392,356	$	372,289	$	20,067	5.4	$	795,115	$	722,953	$	72,162	10.0

The following table reflects changes in electricity sales for the three and six months ended June 30, 2014 and 2013. 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,
	2014	2013	Change		% Change		2014	2013	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,416	1,460	(44	)	(3.0	)	3,125	3,003	122		4.1
Commercial	1,842	1,856	(14	)	(0.8	)	3,602	3,558	44		1.2
Industrial	1,447	1,312	135		10.3		2,786	2,624	162		6.2
Other retail	21	21	—		—		42	43	(1	)	(2.3	)
Total Retail	4,726	4,649	77		1.7		9,555	9,228	327		3.5
Wholesale	2,004	2,048	(44	)	(2.1	)	4,481	4,093	388		9.5
Total	6,730	6,697	33		0.5		14,036	13,321	715		5.4

Gross margin increased for the three months ended June 30, 2014, compared to the same period in 2013 due primarily to higher retail revenues. The higher retail revenues were due primarily to higher prices resulting from investments we made in our transmission infrastructure and air quality controls at our power plants and to a lesser extent to more electricity sales resulting from increased sales to certain large industrial customers.

Gross margin increased during the six months ended June 30, 2014 , compared to the same period of 2013 due principally to higher retail revenues. The higher retail revenues were mostly a result of higher prices that were due to the same reasons as discussed above for the three month period and due also to more electricity sales resulting principally from cooler winter weather, which particularly impacts residential and commercial electricity sales. As measured by heating degree days, the weather during the three months ended March 31, 2014 was 12% cooler than the same period in 2013. Also contributing to the increase in gross margin was increased energy marketing margins of $11.1 million due to pricing conditions in the wholesale markets in which we buy and sell power primarily during the three months ended March 31, 2014.

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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, 2014 and 2013.



	Three Months Ended June 30,									Six Months Ended June 30,
	2014		2013		Change			% Change		2014		2013		Change		% Change
	(Dollars In Thousands)
Gross margin	$	392,356	$	372,289	$	20,067		5.4		$	795,115	$	722,953	$	72,162	10.0
Less: Operating and maintenance expense	101,839		87,999		13,840			15.7		193,629		172,154		21,475		12.5
Depreciation and amortization expense	70,882		67,597		3,285			4.9		140,992		134,443		6,549		4.9
Selling, general and administrative expense	62,168		54,477		7,691			14.1		118,653		103,422		15,231		14.7
Taxes other than income tax	34,738		30,704		4,034			13.1		69,571		61,482		8,089		13.2
Income from operations	$	122,729	$	131,512	$	(8,783	)	(6.7	)	$	272,270	$	251,452	$	20,818	8.3

Operating Expenses and Other Income and Expense Items



	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change		% Change	2014		2013		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	101,839	$	87,999	$	13,840	15.7	$	193,629	$	172,154	$	21,475	12.5

Operating and maintenance expense increased for the three and six months ended June 30, 2014 compared to the same period of 2013, due principally to:


•	higher operating and maintenance costs at our coal fired plants of $9.2 million and $7.0 million, respectively, due primarily to a planned outage at JEC; and,


•	higher costs at Wolf Creek of $4.3 million and $11.4 million, respectively, attributable to a planned maintenance outage.



	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change		% Change	2014		2013		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	70,882	$	67,597	$	3,285	4.9	$	140,992	$	134,443	$	6,549	4.9

Depreciation and amortization expense increased during the three and six months ended June 30, 2014, compared to the same periods of 2013 due to plant additions, including air quality controls, and transmission facilities as well as increased amortization related primarily to implementing new software systems.

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	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change		% Change	2014		2013		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	62,168	$	54,477	$	7,691	14.1	$	118,653	$	103,422	$	15,231	14.7

Selling, general and administrative expense increased for the three and six months ended June 30, 2014, compared to 2013 periods due primarily to:


•	higher employee benefit costs of $4.5 million and $7.8 million, respectively, due partially to the restructuring of insurance contracts in the same period last year, which resulted in a benefit in that period;


•	an increase in fees of $0.9 million and $2.3 million, respectively, related primarily to implementing new software systems; and,


•	an increase in the allowance for uncollectible accounts of $2.0 million for the six month period due primarily to higher prices and cooler winter weather.



	Three Months Ended June 30,							Six Months Ended June 30,
	2.014		2.013		Change		% Change	2014		2013		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	34,738	$	30,704	$	4,034	13.1	$	69,571	$	61,482	$	8,089	13.2

Taxes other than income tax increased for the three and six months ended June 30, 2014 compared to 2013 periods due primarily to increases of $3.5 million and $6.8 million, respectively, in property tax expense. These changes are offset in retail revenues.



	Three Months Ended June 30,									Six Months Ended June 30,
	2014		2013		Change			% Change		2014		2013		Change			% Change
	(Dollars in Thousands)
Other income	$	5,658	$	13,711	$	(8,053	)	(58.7	)	$	11,575	$	17,427	$	(5,852	)	(33.6	)

Other income decreased due primarily to our having recorded approximately $10.0 million in lower COLI benefits during the three and six month periods ending June 30, 2014 compared to 2013. This decrease was partially offset by our having recorded $1.8 million and $4.0 million, respectively, more in equity AFUDC.



	Three Months Ended June 30,									Six Months Ended June 30,
	2014		2013		Change			% Change		2014		2013		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	26,150	$	29,310	$	(3,160	)	(10.8	)	$	61,111	$	54,123	$	6,988	12.9

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

The increase for the six month period was 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, 2014, compared to December 31, 2013.



	As of		As of
	June 30, 2014		December 31, 2013		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	256,521	$	239,511	$	17,010	7.1

Inventory increased due principally to a $11.9 million increase in materials and supplies due mostly to support environmental upgrades at JEC and La Cygne as well as increases in material for transmission and substation equipment and a $5.9 million increase in coal inventory.



	As of		As of
	June 30, 2014		December 31, 2013		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	736,530	$	755,414	$	(18,884	)	(2.5	)
Regulatory liabilities	361,238		329,556		31,682			9.6
Net regulatory assets	$	375,292	$	425,858	$	(50,566	)	(11.9	)

Total regulatory assets decreased due primarily to the following reasons:


•	a $20.6 million decrease in deferred employee benefit costs;


•	an $8.2 million decrease in amounts deferred for Wolf Creek refueling outages;


•	a $3.1 million decrease in amounts deferred for energy efficiency costs; and,


•	a $2.5 million decrease in amounts due from customers for future income taxes; however,


•	partially offsetting these decreases was a $16.0 million increase in amounts previously deferred for fuel expense.

Total regulatory liabilities increased due primarily to the following reasons:


•	a $17.8 million increase in our refund obligation related to the RECA;


•	a $12.7 million increase in jurisdictional AFUDC; and.


•	the fair value measurement of our NDT assets increasing $10.3 million; however,


•	partially offsetting these increases was a $5.9 million decrease in amounts collected but not yet spent to dispose of plant assets.



	As of		As of
	June 30, 2014		December 31, 2013		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	7,816,120	$	7,551,916	$	264,204	3.5

Property, plant and equipment, net of accumulated depreciation, increased due primarily to plant additions for air quality controls, and additional transmission facilities.

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	As of		As of
	June 30, 2014		December 31, 2013		Change		% Change
	(Dollars in Thousands)
Short-term debt	$	343,300	$	134,600	$	208,700	155.1

Short-term debt increased due to increases in issuances of commercial paper used primarily to purchase capital equipment and for working capital and general corporate purposes.



	As of		As of
	June 30, 2014		December 31, 2013		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt	$	—	$	250,000	$	(250,000	)	(100.0	)
Long-term debt, net	3,215,805		2,968,958		246,847			8.3
Total long-term debt	$	3,215,805	$	3,218,958	$	(3,153	)	(0.1	)

At June 30, 2014, Westar Energy first mortgage bonds in an aggregate principal amount of $250.0 million with a maturity date of July 1, 2014, were reclassified as long-term debt from current maturities of long-term debt due to the July 2014 issuance of $250.0 million in aggregate principal amount of KGE first mortgage bonds maturing July 2044. The proceeds were used to redeem the Westar Energy first mortgage bonds in an aggregate principal amount of $250.0 million with a maturity date of July 1, 2014.



	As of		As of
	June 30, 2014		December 31, 2013		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	28,098	$	27,479	$	619		2.3
Long-term debt of variable interest entities	166,720		194,802		(28,082		)	(14.4	)
Total long-term debt of variable interest entities	$	194,818	$	222,281	$	(27,463	)	(12.4	)

Total long-term debt of variable interest entities decreased due to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $27.1 million.



	As of		As of
	June 30, 2014		December 31, 2013		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,423,021	$	1,363,148	$	59,873	4.4

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



	As of		As of
	June 30, 2014		December 31, 2013		Change		% Change
	(Dollars in Thousands)
Asset retirement obligations	$	177,755	$	160,682	$	17,073	10.6

Asset retirement obligations increased due primarily to a $12.6 million revision for remediation of ash disposal ponds.

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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. When such balances are of sufficient size and it makes economic sense to do so, we also use proceeds from the issuance of long-term debt and equity securities to repay short-term borrowings, which are principally related to investments in capital equipment and the redemption of bonds 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, 2014, Westar Energy had issued $355.1 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, and in February 2014, Westar Energy extended the term of the $270.0 million credit facility to February 2017, provided that $20.0 million of this facility will terminate in February 2016. As long as there is no default under the facility, the $730.0 million facility may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million 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, 2014, no amounts were borrowed and $16.0 million in 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

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.

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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 is not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

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

In January 2014, Moody's upgraded its ratings for Westar Energy and KGE first mortgage bonds to A2 from A3. In April 2014, S&P upgraded its ratings for Westar Energy and KGE first mortgage bonds to A from A-. In June 2014, Fitch revised its rating for Westar Energy's and KGE's outlook to positive from stable. As of July 30, 2014, 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	A2	A2	P-2	Stable
S&P	A	A	A-2	Stable
Fitch	A-	A-	F2	Positive

Common Stock

Summary of Cash Flows



	Six Months Ended June 30,
	2014			2013			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	283,314		$	231,310		$	52,004		22.5
Investing activities	(440,238		)	(301,318		)	(138,920		)	(46.1	)
Financing activities	163,188			68,152			95,036			139.4
Net increase (decrease) in cash and cash equivalents	$	6,264		$	(1,856	)	$	8,120		437.5

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having received $96.6 million more from retail and wholesale customers partially offset by our having paid $40.6 million more for fuel and purchased power.

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Cash Flows used in Investing Activities

Cash flows used in investing activities increased due primarily to our having received $99.3 million less in proceeds from our investment in corporate owned life insurance (COLI) and our having invested $28.1 million more in additions to property, plant and equipment.

Cash Flows from Financing Activities

Cash flows from financing activities increased due principally to our having issued $137.9 million more of commercial paper during the six months ended June 30, 2014, compared to the same period in 2013. Also contributing to the increase was our having repaid $98.9 million less for borrowings against the cash surrender value of COLI. Partially offsetting these increases was our having retired $77.5 million more in long-term debt during the six months ended June 30, 2014, as well as receiving $74.0 million less proceeds from issuing long-term debt this year compared to the previous year.

Pension Contribution

During the six months ended June 30, 2014, we contributed $19.0 million to the Westar Energy pension trust. No payments were made to fund the Wolf Creek pension plan during the same period.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2013, through June 30, 2014, our off balance sheet arrangements did not change materially. For additional information, see our 2013 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2013, through June 30, 2014, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2013 Form 10-K.

OTHER INFORMATION

Changes in Prices

KCC Proceedings

In July 2014, we, KCC staff and consumer advocate, joined in a request filed with the KCC to defer depreciation expense and carrying costs related to our capital investment associated with environmental upgrades at La Cygne until new retail prices become effective in a general rate case to be filed in March 2015 pursuant to an agreed upon schedule. The parties requested the order be issued by the end of the third quarter of 2014.

In June 2014, the KCC issued an order to adjust our prices to include updated transmission costs as reflected in the transmission formula rate discussed below. The new prices were effective in April 2014 and we estimate this will increase our annual retail revenues by approximately $41.0 million.

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FERC Proceedings

Our transmission formula rate that includes projected 2014 transmission capital expenditures and operating costs became effective in January 2014 and is expected to increase our annual transmission revenues by approximately $44.3 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs discussed above.

New Accounting Pronouncements

Revenue Recognition

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, 2013, to June 30, 2014, no significant changes occurred in our market risk exposure. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our 2013 Form 10-K for additional information.

ITEM 4. CONTROLS AND PROCEDURES

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

There were no changes in our internal control over financial reporting during the three months ended June 30, 2014, 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.

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ITEM 1A. RISK FACTORS

There were no material changes in our risk factors from December 31, 2013, through June 30, 2014. For additional information, see our 2013 Form 10-K.

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

None.

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



4(a)		Purchase Agreement among Kansas Gas and Electric Company and Barclays Capital, Inc., J.P. Morgan Securities LLC and Mitsubishi UFJ Securities (USA), Inc., as representatives of the Initial Purchaser named therein, dated June 25, 2014 (filed as Exhibit 1.1 to the Form 8-K filed on June 27, 2014)
4(b)		Sixty-First Supplemental Indenture, dated as of July 2, 2014, by and among Kansas Gas and Electric Company and the Bank of New York Mellon Trust Company, N.A., as Trustee
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, 2014
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, 2014
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2014 (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 6, 2014	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

WESTAR ENERGY INC /KS - FORM 10-Q - August 6, 2014

Attached files

WESTAR ENERGY INC /KS Reports