10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2016

OR

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

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Common Stock, par value $5.00 per share	141,734,848 shares
(Class)	(Outstanding at July 27, 2016)

1

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	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
PART II. Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
Signature		46

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2015 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2015
AFUDC	Allowance for funds used during construction
ASU	Accounting Standard Update
CAA	Clean Air Act
CCB	Coal combustion byproducts
CO	Carbon monoxide
CO2	Carbon dioxide
COLI	Corporate-owned life insurance
CPP	Clean Power Plan
CWA	Clean Water Act
DOE	Department of Energy
DOJ	Department of Justice
EPA	Environmental Protection Agency
EPS	Earnings per share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gas
Great Plains Energy	Great Plains Energy Incorporated
JEC	Jeffrey Energy Center
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health & Environment
KGE	Kansas Gas and Electric Company
La Cygne	La Cygne Generating Station
Merger	Pending acquisition of Westar Energy, Inc. by Great Plains Energy Incorporated
Missouri Commission	Public Service Commission of the State of Missouri
Moody’s	Moody’s Investors Service
NAAQS	National Ambient Air Quality Standards
NAV	Net Asset Value
NDT	Nuclear Decommissioning Trust
NOx	Nitrogen oxides
NRC	Nuclear Regulatory Commission
PM	Particulate matter
PPB	Parts per billion
RECA	Retail energy cost adjustment
ROE	Return on equity
RSU	Restricted share unit
RTO	Regional transmission organization
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
TFR	Transmission Formula Rate
VIE	Variable interest entity
Wolf Creek	Wolf Creek Generating Station

3

FORWARD-LOOKING STATEMENTS

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

- the pending acquisition (merger) of Westar Energy, Inc. by Great Plains Energy Incorporated (Great Plains Energy),

- 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:

- risks related to operating in a heavily regulated industry that is subject to unpredictable political, legislative, judicial and regulatory developments, which can impact our operations, results of operations, and financial condition,

- the difficulty of predicting the magnitude and timing of changes in demand for electricity, including with respect to emerging competing services and technologies and conservation and energy efficiency measures,

- the impact of weather conditions, including as it relates to sales of electricity and 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 and funding obligations, 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 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 (NRC) 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

4

following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations (RTOs) and independent system operators,

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

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

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

- certain risks and uncertainties associated with the merger, including, without limitation, those related to:

- receipt of approval from our shareholders and shareholders of Great Plains Energy;

- the timing of, and the conditions imposed by, regulatory approvals required for the merger;

- the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement or could otherwise cause the failure of the merger to close;

- the failure of Great Plains Energy to obtain any financing necessary to complete the merger;

- the outcome of any legal proceedings, regulatory proceedings or enforcement matters that have been or may be instituted in connection with the merger;

- the receipt of an unsolicited offer from another party to acquire our assets or capital stock (or those of Great Plains Energy) that could interfere with the proposed merger;

- the timing to consummate the proposed transaction;

- disruption from the proposed transaction making it more difficult to maintain relationships with customers, employees, regulators or suppliers;

- the diversion of management time and attention on the transaction;

- the amount of costs, fees, expenses and charges related to the merger; and

- the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations) that could adversely affect our participation in the merger; and

- other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2015 (2015 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 (SEC), including the proxy statement and other materials that we have filed or will file with the SEC in connection with the merger.

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 2015 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 2015 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

5

PART I.    FINANCIAL INFORMATION

ITEM I.    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

	As of		As of
	June 30, 2016		December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,213	$	3,231
Accounts receivable, net of allowance for doubtful accounts of $5,093 and $5,294, respectively	298,841		258,286
Fuel inventory and supplies	299,465		301,294
Prepaid expenses	17,994		16,864
Regulatory assets	87,256		109,606
Other	33,099		27,860
Total Current Assets	741,868		717,141
PROPERTY, PLANT AND EQUIPMENT, NET	8,800,698		8,524,902
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	263,072		268,239
OTHER ASSETS:
Regulatory assets	734,844		751,312
Nuclear decommissioning trust	189,179		184,057
Other	241,081		260,015
Total Other Assets	1,165,104		1,195,384
TOTAL ASSETS	$	10,970,742	$	10,705,666
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	125,000	$	—
Current maturities of long-term debt of variable interest entities	26,842		28,309
Short-term debt	177,000		250,300
Accounts payable	178,374		220,969
Accrued dividends	52,767		49,829
Accrued taxes	95,084		83,773
Accrued interest	41,969		71,426
Regulatory liabilities	33,634		25,697
Other	90,841		106,632
Total Current Liabilities	821,511		836,935
LONG-TERM LIABILITIES:
Long-term debt, net	3,387,696		3,163,950
Long-term debt of variable interest entities, net	111,230		138,097
Deferred income taxes	1,655,825		1,591,430
Unamortized investment tax credits	208,318		209,763
Regulatory liabilities	247,916		267,114
Accrued employee benefits	455,923		462,304
Asset retirement obligations	280,507		275,285
Other	87,065		88,825
Total Long-Term Liabilities	6,434,480		6,196,768
COMMITMENTS AND CONTINGENCIES (See Notes 4, 11 and 12)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,691,017 shares and 141,353,426 shares, respective to each date	708,455		706,767
Paid-in capital	2,008,491		2,004,124
Retained earnings	978,187		945,830
Total Westar Energy, Inc. Shareholders’ Equity	3,695,133		3,656,721
Noncontrolling Interests	19,618		15,242
Total Equity	3,714,751		3,671,963
TOTAL LIABILITIES AND EQUITY	$	10,970,742	$	10,705,666

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

6

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended June 30,
	2016			2015
REVENUES	$	621,448		$	589,563
OPERATING EXPENSES:
Fuel and purchased power	118,630			140,080
SPP network transmission costs	55,227			57,352
Operating and maintenance	85,619			82,739
Depreciation and amortization	84,226			76,759
Selling, general and administrative	75,724			63,663
Taxes other than income tax	48,407			37,494
Total Operating Expenses	467,833			458,087
INCOME FROM OPERATIONS	153,615			131,476
OTHER INCOME (EXPENSE):
Investment earnings	2,280			1,634
Other income	3,382			15,121
Other expense	(2,908		)	(2,633		)
Total Other Income	2,754			14,122
Interest expense	39,683			45,516
INCOME BEFORE INCOME TAXES	116,686			100,082
Income tax expense	40,542			33,839
NET INCOME	76,144			66,243
Less: Net income attributable to noncontrolling interests	3,804			2,533
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	72,340		$	63,710
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.51		$	0.47
Diluted earnings per common share	$	0.51		$	0.46
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,033,842			135,939,197
Diluted	142,497,335			137,412,152
DIVIDENDS DECLARED PER COMMON SHARE	$	0.38		$	0.36

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

7

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Six Months Ended June 30,
	2016			2015
REVENUES	$	1,190,898		$	1,180,370
OPERATING EXPENSES:
Fuel and purchased power	218,688			295,561
SPP network transmission costs	115,987			114,164
Operating and maintenance	163,377			167,819
Depreciation and amortization	167,866			151,345
Selling, general and administrative	132,179			119,082
Taxes other than income tax	97,375			75,365
Total Operating Expenses	895,472			923,336
INCOME FROM OPERATIONS	295,426			257,034
OTHER INCOME (EXPENSE):
Investment earnings	4,296			4,113
Other income	12,860			17,935
Other expense	(8,451		)	(8,345		)
Total Other Income	8,705			13,703
Interest expense	80,114			89,814
INCOME BEFORE INCOME TAXES	224,017			180,923
Income tax expense	79,165			61,517
NET INCOME	144,852			119,406
Less: Net income attributable to noncontrolling interests	6,927			4,716
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	137,925		$	114,690
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.97		$	0.85
Diluted earnings per common share	$	0.97		$	0.84
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,013,344			134,177,136
Diluted	142,361,347			136,329,603
DIVIDENDS DECLARED PER COMMON SHARE	$	0.76		$	0.72

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

8

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30,
	2016			2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	144,852		$	119,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	167,866			151,345
Amortization of nuclear fuel	16,831			10,085
Amortization of deferred regulatory gain from sale leaseback	(2,748		)	(2,748		)
Amortization of corporate-owned life insurance	8,819			9,042
Non-cash compensation	4,778			4,241
Net deferred income taxes and credits	75,334			54,740
Allowance for equity funds used during construction	(5,247		)	(2,041		)
Changes in working capital items:
Accounts receivable	(40,555		)	998
Fuel inventory and supplies	2,140			(31,307		)
Prepaid expenses and other	7,126			(40,195		)
Accounts payable	(21,364		)	(2,873		)
Accrued taxes	16,272			16,893
Other current liabilities	(62,434		)	(65,908		)
Changes in other assets	1,848			(9,712		)
Changes in other liabilities	15,163			21,046
Cash Flows from Operating Activities	328,681			233,012
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(503,631		)	(334,905		)
Purchase of securities - trusts	(39,603		)	(9,980		)
Sale of securities - trusts	41,201			10,263
Investment in corporate-owned life insurance	(14,648		)	(14,845		)
Proceeds from investment in corporate-owned life insurance	24,171			1,192
Investment in affiliated company	(655		)	—
Other investing activities	(2,798		)	(653		)
Cash Flows used in Investing Activities	(495,963		)	(348,928		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(73,300		)	49,500
Proceeds from long-term debt	396,577			—
Proceeds from long-term debt of variable interest entities	162,048			—
Retirements of long-term debt	(50,000		)	(125,000		)
Retirements of long-term debt of variable interest entities	(190,355		)	(27,925		)
Repayment of capital leases	(401		)	(1,721		)
Borrowings against cash surrender value of corporate-owned life insurance	54,910			56,622
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(22,921		)	(899		)
Issuance of common stock	1,354			256,394
Distributions to shareholders of noncontrolling interests	(2,551		)	(1,076		)
Cash dividends paid	(101,137		)	(89,035		)
Other financing activities	(4,960		)	(3,234		)
Cash Flows from Financing Activities	169,264			113,626
NET CHANGE IN CASH AND CASH EQUIVALENTS	1,982			(2,290		)
CASH AND CASH EQUIVALENTS:
Beginning of period	3,231			4,556
End of period	$	5,213		$	2,266

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

9

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands, Except Per Share Amounts)

(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, 2014	131,687,454	$	658,437	$	1,781,120		$	855,299		$	6,451		$	3,301,307
Net income	—	—		—			114,690			4,716			119,406
Issuance of stock	9,208,267	46,041		210,353			—			—			256,394
Issuance of stock for compensation and reinvested dividends	282,897	1,415		4,117			—			—			5,532
Tax withholding related to stock compensation	—	—		(3,234		)	—			—			(3,234		)
Dividends declared on common stock ($0.72 per share)	—	—		—			(99,169		)	—			(99,169		)
Stock compensation expense	—	—		4,196			—			—			4,196
Tax benefit on stock compensation	—	—		1,178			—			—			1,178
Distributions to shareholders of noncontrolling interests	—	—		—			—			(1,076		)	(1,076		)
Other	—	—		(69		)	—			(1		)	(70		)
Balance as of June 30, 2015	141,178,618	$	705,893	$	1,997,661		$	870,820		$	10,090		$	3,584,464
Balance as of December 31, 2015	141,353,426	$	706,767	$	2,004,124		$	945,830		$	15,242		$	3,671,963
Net income	—	—		—			137,925			6,927			144,852
Issuance of stock	28,674	143		1,211			—			—			1,354
Issuance of stock for compensation and reinvested dividends	308,917	1,545		3,396			—			—			4,941
Tax withholding related to stock compensation	—	—		(4,960		)	—			—			(4,960		)
Dividends declared on common stock ($0.76 per share)	—	—		—			(108,894		)	—			(108,894		)
Stock compensation expense	—	—		4,720			—			—			4,720
Distribution to shareholders of noncontrolling interests	—	—		—			—			(2,551		)	(2,551		)
Cumulative effect of accounting change - stock compensation	—	—		—			3,326			—			3,326
Balance as of June 30, 2016	141,691,017	$	708,455	$	2,008,491		$	978,187		$	19,618		$	3,714,751

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

10

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 704,000 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) for the United States of America 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 condensed 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 2015 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 ongoing 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 endedJune 30, 2016, are not necessarily indicative of the results to be expected for the full year.

11

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, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	107,397	$	113,438
Supplies	192,068		187,856
Fuel inventory and supplies	$	299,465	$	301,294

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,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,338		$	552		$	4,347		$	2,581
Equity funds	2,783			90			5,247			2,041
Total	$	5,121		$	642		$	9,594		$	4,622
Average AFUDC Rates	4.2		%	1.2		%	4.6		%	3.2		%

Earnings Per Share

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

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 issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

12

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,144	$	66,243	$	144,852	$	119,406
Less: Net income attributable to noncontrolling interests	3,804		2,533		6,927		4,716
Net income attributable to Westar Energy, Inc.	72,340		63,710		137,925		114,690
Less: Net income allocated to RSUs	156		141		290		257
Net income allocated to common stock	$	72,184	$	63,569	$	137,635	$	114,433
Weighted average equivalent common shares outstanding – basic	142,033,842		135,939,197		142,013,344		134,177,136
Effect of dilutive securities:
RSUs	463,493		121,234		348,003		127,999
Forward sale agreements	—		1,351,721		—		2,024,468
Weighted average equivalent common shares outstanding – diluted (a)	142,497,335		137,412,152		142,361,347		136,329,603
Earnings per common share, basic	$	0.51	$	0.47	$	0.97	$	0.85
Earnings per common share, diluted	$	0.51	$	0.46	$	0.97	$	0.84

_______________

(a) We had no antidilutive securities for the three and six months endedJune 30, 2016 and 2015.

Supplemental Cash Flow Information

	Six Months Ended June 30,
	2016			2015
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	70,697		$	82,297
Interest on financing activities of VIEs	4,150			5,651
Income taxes, net of refunds	(77		)	126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	71,830			66,861
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,941			5,532
Assets acquired through capital leases	392			1,102

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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, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accounting and/or disclosure.

Leases

In February 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-02 which requires lessees to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. We are evaluating the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated financial statements.

Stock-based Compensation

In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.

Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits and expense. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying condensed consolidated statements of cash flows for the six months ended June 30, 2015, as $1.2 million higher than as previously reported, and cash flows from financing activities as $1.2 million lower than as previously reported.

Financial Instruments

In May 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 5, “Financial Instruments and Trading Securities.”

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which 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 was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We are continuing to analyze the new standard and 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.

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3. PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock.

The closing of the merger is subject to customary conditions including, among others, approval by our shareholders and the shareholders of Great Plains Energy and receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger.

On July 14, 2016, Great Plains Energy filed a registration statement on Form S-4 with the SEC. The registration statement includes a preliminary proxy statement that, once finalized, will be sent to our shareholders in connection with the special meeting of our shareholders to be held to vote to approve the merger.

The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If Great Plains Energy terminates the merger agreement because our board of directors changes its recommendation, if we terminate the merger agreement to enter into an acquisition agreement with a superior proposal, or if our shareholders vote and do not give approval and we enter into an acquisition proposal within 12 months of termination of the merger agreement, we must pay Great Plains Energy a termination fee of $280.0 million.

If the merger agreement is terminated under other circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. If we terminate the merger agreement because the Great Plains Energy board of directors changes its recommendation, Great Plains Energy must pay us a termination fee of $180.0 million. If either party terminates the merger agreement because the end date occurred or Great Plains Energy shareholders’ approval was not acquired, and it has either been publicly disclosed that Great Plains Energy has entered into an alternative acquisition proposal, or an acquisition proposal was entered into within 12 months after the termination of the merger agreement, Great Plains Energy must pay us a termination fee of $180.0 million. If Great Plains Energy shareholders’ meeting was held and completed, but approval was not obtained, and the termination fee described above is not payable by Great Plains Energy, Great Plains Energy must pay us a termination fee of $80.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three months ended June 30, 2016, we incurred approximately $7.8 million of merger-related expenses, which is included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to coincide with the closing of the merger.

We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies,” andNote 12, “Legal Proceedings,” for more information on legal matters.

4. RATE MATTERS AND REGULATION

KCC Proceedings

In December 2015, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million.

In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR), along with the reduced return on equity (ROE) as described below. The

15

updated prices were retroactively effective April 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $7.0 million. As of June 30, 2016, we have recorded a regulatory liability of $4.0 million for our estimated refund obligation from the refund effective date of April 2016 through June 2016.

FERC Proceedings

In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO.

The updated prices were retroactively effective January 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million. This increase also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation during the three months ended June 30, 2016. As of June 30, 2016, we have a remaining refund obligation of $8.1 million which is included in current regulatory liabilities on our balance sheet.

5. 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. In addition, we measure certain investments that do not have a readily determinable fair value at NAV, which are not included in the fair value hierarchy. Further explanation of these levels and NAV is summarized below.

• 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 liquid investments in funds which have a readily determinable fair value calculated using daily NAVs, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments 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.

• Net Asset Value - Investments that do not have a readily determinable fair value are measured at NAV. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments.

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.

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

	As of June 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,865,914	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,963		154,097		166,271		179,030

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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, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	—		$	50,856	$	—	$	5,944	$	56,800
International equity funds	—		34,560		—		—		34,560
Core bond fund	—		27,509		—		—		27,509
High-yield bond fund	—		16,557		—		—		16,557
Emerging markets bond fund	—		15,342		—		—		15,342
Combination debt/equity/other funds	—		12,277		—		—		12,277
Alternative investments fund	—		—		—		16,386		16,386
Real estate securities fund	—		—		—		9,500		9,500
Cash equivalents	248		—		—		—		248
Total Nuclear Decommissioning Trust	248		157,101		—		31,830		189,179
Trading Securities:
Domestic equity funds	—		17,782		—		—		17,782
International equity fund	—		4,220		—		—		4,220
Core bond fund	—		11,935		—		—		11,935
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		33,937		—		—		34,093
Total Assets Measured at Fair Value	$	404	$	191,038	$	—	$	31,830	$	223,272
As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	—	$	6,050	$	56,922
International equity funds	—		33,595		—		—		33,595
Core bond fund	—		25,976		—		—		25,976
High-yield bond fund	—		15,288		—		—		15,288
Emerging markets bond fund	—		13,584		—		—		13,584
Combination debt/equity/other funds	—		11,343		—		—		11,343
Alternative investments fund	—		—		—		16,439		16,439
Real estate securities fund	—		—		—		10,823		10,823
Cash equivalents	87		—		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		—		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		—		17,876
International equity fund	—		4,430		—		—		4,430
Core bond fund	—		11,423		—		—		11,423
Cash equivalents	159		—		—		—		159
Total Trading Securities	159		33,729		—		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	—	$	33,312	$	217,945

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Some of our investments in the Nuclear Decommissioning Trust (NDT) are measured at NAV 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, 2016				As of December 31, 2015				As of June 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,944	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	16,386		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,500		—		10,823		—		Quarterly	65 days
Total	$	31,830	$	3,689	$	33,312	$	1,948

_______________

(a) This investment is in four 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. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b) 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 from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

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

6. FINANCIAL INVESTMENTS

We report 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 that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.1 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months endedJune 30, 2016, we recorded an unrealized gain of $0.6 million on assets still held. For the six months endedJune 30, 2016, we recorded an unrealized gain of $1.1 million on assets still held. For the three months ended June 30, 2015, we recorded no unrealized gain or loss on assets still held. For the six months ended June 30, 2015, we recorded an unrealized gain of $0.7 million on assets still held.

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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, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a gain of$0.1 million during the three months endedJune 30, 2016, and a loss of$1.4 million during the six months endedJune 30, 2016. We realized a loss of $0.6 million for the three months endedJune 30, 2015, and a loss of $0.5 million for the six months endedJune 30, 2015. 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, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds	$	49,844	$	6,965	$	(9	)	$	56,800	30	%
International equity funds	33,935		1,201		(576		)	34,560		18	%
Core bond fund	26,882		627		—			27,509		15	%
High-yield bond fund	17,405		—		(848		)	16,557		9	%
Emerging market bond fund	16,145		—		(803		)	15,342		8	%
Combination debt/equity/other funds	9,003		3,274		—			12,277		6	%
Alternative investment fund	15,000		1,386		—			16,386		9	%
Real estate securities fund	9,500		—		—			9,500		5	%
Cash equivalents	248		—		—			248		<1%
Total	$	177,962	$	13,453	$	(2,236	)	$	189,179	100	%
As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	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 ofJune 30, 2016, and December 31, 2015.

	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, 2016:
Domestic equity funds	$	861	$	(9	)	$	—	$	—		$	861	$	(9	)
International equity funds	—		—			7,426		(576		)	7,426		(576		)
High-yield bond fund	—		—			16,557		(848		)	16,557		(848		)
Emerging market bond fund	—		—			15,342		(803		)	15,342		(803		)
Total	$	861	$	(9	)	$	39,325	$	(2,227	)	$	40,186	$	(2,236	)
As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

7. DEBT FINANCING

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of$162.1 millionin outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from5.647% to 2.398%. See Note 13, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

8. TAXES

We recorded income tax expense of $40.5 million with an effective income tax rate of 35% for the three months endedJune 30, 2016, and income tax expense of $33.8 million with an effective income tax rate of 34% for the same period of 2015. We recorded income tax expense of $79.2 million with an effective income tax rate of 35% for the six months endedJune 30, 2016, and income tax expense of $61.5 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three and six months ended June 30, 2016, was due primarily to an increase in income before income taxes.

As of June 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $3.0 million and $2.9 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

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As of June 30, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2016, or December 31, 2015.

As of June 30, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

9. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,921			10,753			1,393			1,422
Expected return on plan assets	(10,663		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			114			114
Actuarial loss (gain), net	5,146			8,053			(280		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,225			(210		)	338
Regulatory adjustment (a)	3,306			1,534			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,759		$	(696	)	$	1,351

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

 _______________

(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 endedJune 30, 2016 and 2015, we contributed $11.2 million and $19.4 million, respectively, to the Westar Energy pension trust.

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10. 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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	32		$	34
Interest cost	2,414			2,254			82			79
Expected return on plan assets	(2,430		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,089			1,482			(4		)	1
Net periodic cost before regulatory adjustment	2,774			3,388			110			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,257		$	3,084		$	110		$	114

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,374		$	3,797		$	64		$	69
Interest cost	4,828			4,508			163			157
Expected return on plan assets	(4,861		)	(4,522		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,178			2,965			(8		)	1
Net periodic cost before regulatory adjustment	5,547			6,776			219			227
Regulatory adjustment (a)	966			(608		)	—			—
Net periodic cost	$	6,513		$	6,168		$	219		$	227

 _______________

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

During the six months endedJune 30, 2016 and 2015, we funded $3.2 million and $2.5 million of Wolf Creek’s pension plan contributions, respectively.

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11. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Rule

In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (NOx) emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

Under the federal Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide (CO) and sulfur dioxide (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.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, Kansas Department of Health and Environment (KDHE) recommended a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We are working with KDHE to determine the impact of this proposed designation. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

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In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review.  Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay.  In February 2016, the U.S. Supreme Court granted the stay request. In May 2016, the U.S. Court of Appeals for the D.C. Circuit decided to forego the normal three judge panel to review the CPP and to conduct the review en banc. At the same time, the Court scheduled oral arguments for September 2016. In June 2016, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

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 were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology 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 La Cygne and Wolf Creek. 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 we do not expect it to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results.

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. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material.

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SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results, but it could be material.

Storage of Spent Nuclear Fuel

In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.

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.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the Federal Power Act.

Department of Justice Proceedings

At any time before or after the merger, the Department of Justice (DOJ) or the Federal Trade Commission could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the merger or seeking divestiture of substantial assets of Great Plains Energy, the Company or their respective subsidiaries. Private parties and state attorneys general may also bring an action under the antitrust laws under certain circumstances. On June 23, 2016, the DOJ sent a letter to us and Great Plains Energy informing the parties that it had opened an investigation into the proposed transaction and requested that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

12. 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 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information.

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Pending Merger

Following the announcement of the merger agreement, two putative class action complaints and one putative derivative action complaint challenging the merger were filed on behalf of purported Westar Energy shareholders in the District Court of Shawnee County, Kansas.

The first complaint, filed on June 13, 2016, is captioned Smith v. Westar Energy, Inc., et al., Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that we and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration undervalues Westar Energy, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourages third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, our CEO will reap significant personal financial gain. The complaint seeks, among other remedies, a declaration that the action may be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement (to the extent already implemented), a directive to the members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

The second complaint, filed on June 14, 2016, is captioned Miller v. Westar Energy, Inc., et al., Case No. 2016-CV-000458. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration deprives our shareholders of fair consideration for their shares, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, an order to permit the action to be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement, a directive to defendants to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

Counsel for plaintiffs in the Smith matter and the Miller matter have filed an unopposed motion for consolidation and appointment of lead counsel. The defendants believe that the claims asserted against them in both class action lawsuits are without merit and intend to vigorously defend against such claims.

The third complaint, filed on July 5, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action is brought on behalf of our shareholders and names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as the nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals. The complaint seeks, among other remedies, an order to permit the action to be maintained as a derivative action, enjoining direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement (to the extent already implemented), imposing a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The defendants intend to seek dismissal of this complaint at the appropriate time.

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13. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 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 and (2) 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 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 7, “Debt Financing,” for additional information.

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Financial Statement Impact

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

	As of		As of
	June 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	263,072	$	268,239
Regulatory assets (a)	9,758		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,230		138,097

_______________

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

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

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

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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 to customers in Kansas under the regulation of the KCC. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas under the regulation of FERC. We have contracts for the sale or purchase of wholesale electricity with other utilities.

In Management’s Discussion and Analysis, we discuss our operating results for the three and six months endedJune 30, 2016, compared to the same periods of 2015, our general financial condition and significant changes that occurred during 2016. 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

Proposed Merger with Great Plains Energy

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock. For more information, see Note 3 of the Notes to Condensed Consolidated Financial Statements, “Pending Merger.”

Earnings Per Share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016		2015		Change		2016		2015		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	72,340	$	63,710	$	8,630	$	137,925	$	114,690	$	23,235
Earnings per common share, basic	0.51		0.47		0.04		0.97		0.85		0.12

Net income and basic EPS increased for the three and six months ended June 30, 2016, compared to the same periods in 2015, due primarily to higher prices and lower interest expense. Higher retail sales due to warmer weather during the three months ended June 30, 2016, also contributed to the increase. A decrease in corporate-owned life insurance (COLI) benefits and merger-related expenses in 2016 partially offset these increases. Additional shares issued in 2015 also impacted 2016 EPS. Had we not issued those shares, EPS would have been approximately $0.02 and $0.05 higher in 2016, respective to the three and six month periods. See the discussion under “—Operating Results” below for additional information.

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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 2015 Form 10-K.

Environmental Regulation

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have become more stringent over time and are expensive to implement. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and consolidated financial results, including those relating to:

• further regulation of GHGs by the EPA, including regulations pursuant to the CPP and future legislation that could be proposed by the U.S. Congress;

• various proposed and expected regulations governing air emissions including those relating to NAAQS (particularly those relating to PM, NOx, ozone, CO and SO₂) and the Cross-State Air Pollution Rule;

• the definition of Waters of the United States for purposes of the CWA; and,

• the regulation of CCB.

See Note 11 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies,” for additional information on environmental matters.

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 the use of estimates and assumptions by management. The policies highlighted in our 2015 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, 2015, through June 30, 2016, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2015 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 include lighting for public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities and RTOs, 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 determinations of base rates at the time of our next general rate review.

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

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes 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 EndedJune 30, 2016, Compared to Three and Six Months EndedJune 30, 2015

Below we discuss our operating results for the three and six months endedJune 30, 2016, compared to the results for the three and six months endedJune 30, 2015. 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,
	2016			2015			Change			% Change		2016			2015			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	202,838		$	173,677		$	29,161		16.8		$	382,128		$	354,970		$	27,158		7.7
Commercial	188,197			175,994			12,203			6.9		353,870			337,300			16,570			4.9
Industrial	108,004			103,151			4,853			4.7		208,702			199,630			9,072			4.5
Other retail	(16,502		)	(7,660		)	(8,842		)	(115.4	)	(30,884		)	(7,122		)	(23,762		)	(333.6	)
Total Retail Revenues	482,537			445,162			37,375			8.4		913,816			884,778			29,038			3.3
Wholesale	66,687			74,828			(8,141		)	(10.9	)	134,099			161,584			(27,485		)	(17.0	)
Transmission	66,620			61,295			5,325			8.7		130,535			119,880			10,655			8.9
Other	5,604			8,278			(2,674		)	(32.3	)	12,448			14,128			(1,680		)	(11.9	)
Total Revenues	621,448			589,563			31,885			5.4		1,190,898			1,180,370			10,528			0.9
OPERATING EXPENSES:
Fuel and purchased power	118,630			140,080			(21,450		)	(15.3	)	218,688			295,561			(76,873		)	(26.0	)
SPP network transmission costs	55,227			57,352			(2,125		)	(3.7	)	115,987			114,164			1,823			1.6
Operating and maintenance	85,619			82,739			2,880			3.5		163,377			167,819			(4,442		)	(2.6	)
Depreciation and amortization	84,226			76,759			7,467			9.7		167,866			151,345			16,521			10.9
Selling, general and administrative	75,724			63,663			12,061			18.9		132,179			119,082			13,097			11.0
Taxes other than income tax	48,407			37,494			10,913			29.1		97,375			75,365			22,010			29.2
Total Operating Expenses	467,833			458,087			9,746			2.1		895,472			923,336			(27,864		)	(3.0	)
INCOME FROM OPERATIONS	153,615			131,476			22,139			16.8		295,426			257,034			38,392			14.9
OTHER INCOME (EXPENSE):
Investment earnings	2,280			1,634			646			39.5		4,296			4,113			183			4.4
Other income	3,382			15,121			(11,739		)	(77.6	)	12,860			17,935			(5,075		)	(28.3	)
Other expense	(2,908		)	(2,633		)	(275		)	(10.4	)	(8,451		)	(8,345		)	(106		)	(1.3	)
Total Other Income	2,754			14,122			(11,368		)	(80.5	)	8,705			13,703			(4,998		)	(36.5	)
Interest expense	39,683			45,516			(5,833		)	(12.8	)	80,114			89,814			(9,700		)	(10.8	)
INCOME BEFORE INCOME TAXES	116,686			100,082			16,604			16.6		224,017			180,923			43,094			23.8
Income tax expense	40,542			33,839			6,703			19.8		79,165			61,517			17,648			28.7
NET INCOME	76,144			66,243			9,901			14.9		144,852			119,406			25,446			21.3
Less: Net income attributable to noncontrolling interests	3,804			2,533			1,271			50.2		6,927			4,716			2,211			46.9
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	72,340		$	63,710		$	8,630		13.5		$	137,925		$	114,690		$	23,235		20.3
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.51		$	0.47		$	0.04		8.5		$	0.97		$	0.85		$	0.12		14.1
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.51		$	0.46		$	0.05		10.9		$	0.97		$	0.84		$	0.13		15.5

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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 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 endedJune 30, 2016 and 2015.

	Three Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2016		2015		Change			% Change
	(Dollars In Thousands)
Revenues	$	621,448	$	589,563	$	31,885		5.4		$	1,190,898	$	1,180,370	$	10,528		0.9
Less: Fuel and purchased power expense	118,630		140,080		(21,450		)	(15.3	)	218,688		295,561		(76,873		)	(26.0	)
SPP network transmission costs	55,227		57,352		(2,125		)	(3.7	)	115,987		114,164		1,823			1.6
Gross Margin	$	447,591	$	392,131	$	55,460		14.1		$	856,223	$	770,645	$	85,578		11.1

The following table reflects changes in electricity sales for the three and six months endedJune 30, 2016 and 2015. 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,
	2016	2015	Change		% Change		2016	2015	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,492	1,386	106		7.6		2,889	2,940	(51	)	(1.7	)
Commercial	1,875	1,835	40		2.2		3,533	3,567	(34	)	(1.0	)
Industrial	1,391	1,408	(17	)	(1.2	)	2,693	2,732	(39	)	(1.4	)
Other retail	19	22	(3	)	(13.6	)	40	41	(1	)	(2.4	)
Total Retail	4,777	4,651	126		2.7		9,155	9,280	(125	)	(1.3	)
Wholesale	1,696	2,046	(350	)	(17.1	)	3,570	4,617	(1,047	)	(22.7	)
Total	6,473	6,697	(224	)	(3.3	)	12,725	13,897	(1,172	)	(8.4	)

Gross margin increased for the three months ended June 30, 2016, compared to the same period in 2015, due primarily to higher retail prices, which increased approximately 5.5%, and higher retail sales. The higher retail sales were attributable principally to warmer spring weather, which particularly impacts residential and commercial electricity sales. Partially offsetting the higher retail sales was lower industrial sales due to a few of our larger chemical and oil pipeline customers who experienced weaker global demand for their products. During the three months ended June 30, 2016, compared to the same period in 2015, there were approximately 10% more cooling degree days.     

Gross margin increased during the six months ended June 30, 2016, compared to the same period of 2015, due primarily to higher retail prices, which increased approximately 4.7%, partially offset by lower sales. The lower retail sales were attributable principally to milder winter weather, which particularly impacts residential and commercial electricity sales. Also contributing to lower retail sales was lower industrial sales due to a few of our larger chemical and oil pipeline customers who experienced weaker global demand for their products. During the six months ended June 30, 2016, compared to the same period in 2015, there were approximately 12% fewer heating degree days, which occurred primarily during the beginning of the year.

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Income from operations, which is calculated and presented in accordance with GAAP in our consolidated statements of income, is the most directly comparable measure to our presentation of gross margin, which is a non-GAAP measure. 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 endedJune 30, 2016 and 2015.

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change			% Change
	(Dollars In Thousands)
Gross margin	$	447,591	$	392,131	$	55,460	14.1	$	856,223	$	770,645	$	85,578		11.1
Less: Operating and maintenance expense	85,619		82,739		2,880		3.5	163,377		167,819		(4,442		)	(2.6	)
Depreciation and amortization expense	84,226		76,759		7,467		9.7	167,866		151,345		16,521			10.9
Selling, general and administrative expense	75,724		63,663		12,061		18.9	132,179		119,082		13,097			11.0
Taxes other than income tax	48,407		37,494		10,913		29.1	97,375		75,365		22,010			29.2
Income from operations	$	153,615	$	131,476	$	22,139	16.8	$	295,426	$	257,034	$	38,392		14.9

Operating Expenses and Other Income and Expense Items

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change			% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	85,619	$	82,739	$	2,880	3.5	$	163,377	$	167,819	$	(4,442	)	(2.6	)

Operating and maintenance expense increased for the three months ended June 30, 2016, compared to the same period in 2015, due primarily to:

• higher operating and maintenance costs at our coal fired plants of $5.2 million, due primarily to scheduled outages; however,

• partially offsetting this increase was a $1.7 million decrease in operating and maintenance costs related to retiring three generating units in late 2015.

Operating and maintenance expense decreased for the six months endedJune 30, 2016, compared to the same period in 2015, due primarily to:

• lower distribution maintenance expense of $4.0 million due partially to focusing our labor resources on capital improvements in 2016 as part of a plan to improve long-term reliability; and

• a $3.7 million decrease in operating and maintenance costs related to retiring three generating units in late 2015; however,

• partially offsetting these decreases was higher operating and maintenance costs at our coal fired plants of $5.0 million, due primarily to scheduled outages.

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	84,226	$	76,759	$	7,467	9.7	$	167,866	$	151,345	$	16,521	10.9

Depreciation and amortization expense increased during the three and six months endedJune 30, 2016, compared to the same periods in 2015, due primarily to air quality control additions at La Cygne.

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	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	75,724	$	63,663	$	12,061	18.9	$	132,179	$	119,082	$	13,097	11.0

Selling, general and administrative expense increased during the three and six months endedJune 30, 2016, compared to the same periods in 2015, due primarily to $7.8 million of merger-related expenses in 2016, higher employee benefit costs of $1.7 million for the three months ended June 30, 2016, and an increase in outside services primarily related to technology services of $2.1 million for the six months ended June 30, 2016.

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	48,407	$	37,494	$	10,913	29.1	$	97,375	$	75,365	$	22,010	29.2

Taxes other than income tax increased for the three and six months endedJune 30, 2016, compared to the same periods in 2015, due primarily to increases of $11.2 million and $22.7 million, respectively, in property tax expense. These increases are mostly offset in retail revenues.

	Three Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2016		2015		Change			% Change
	(Dollars in Thousands)
Other income	$	3,382	$	15,121	$	(11,739	)	(77.6	)	$	12,860	$	17,935	$	(5,075	)	(28.3	)

Other income decreased for the three and six months endedJune 30, 2016, compared to the same periods in 2015, due primarily to:

• recording lower COLI benefits of $13.8 million and $7.3 million, respectively; however,

• partially offsetting this decrease was an increase in equity AFUDC of $2.7 million and $3.2 million, respectively.

	Three Months Ended June 30,									Six Months Ended June 30,
	2016		2015		Change			% Change		2016		2015		Change			% Change
	(Dollars in Thousands)
Interest expense	$	39,683	$	45,516	$	(5,833	)	(12.8	)	$	80,114	$	89,814	$	(9,700	)	(10.8	)

Interest expense decreased for the three and six months endedJune 30, 2016, compared to the same periods in 2015, due primarily to:

• a decrease in interest expense on long-term debt of $3.1 million and $6.6 million, respectively, due primarily to refinancing long-term debt;

• a decrease in interest expense on long-term debt of VIEs of $1.5 million and $2.6 million, respectively, due primarily to refinancing long-term debt of VIEs; and

• an increase in debt AFUDC of $1.8 million for both periods.

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	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	40,542	$	33,839	$	6,703	19.8	$	79,165	$	61,517	$	17,648	28.7

Income tax expense increased for the three and six months endedJune 30, 2016, compared to the same periods in 2015, due principally to higher income before income taxes.

FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of June 30, 2016, compared to December 31, 2015.

	As of		As of
	June 30, 2016		December 31, 2015		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	822,100	$	860,918	$	(38,818	)	(4.5	)
Regulatory liabilities	281,550		292,811		(11,261		)	(3.8	)
Net regulatory assets	$	540,550	$	568,107	$	(27,557	)	(4.9	)

Total regulatory assets decreased due primarily to the following items:

• a $18.0 million decrease in deferred employee benefit costs;

• a $11.0 million decrease in amounts deferred for property taxes;

• a $9.4 million decrease in amounts due from customers for future income taxes; and

• a $7.7 million decrease in amounts deferred for Wolf Creek refueling and maintenance outages; however,

• partially offsetting these decreases was a $4.0 million increase in unrecovered amounts related to the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.

Total regulatory liabilities decreased due to spending $21.8 million more than collected for the cost to remove retired plant assets; partially offsetting this decrease was a FERC settlement approval that resulted in a $12.1 million estimated refund obligation that was previously accrued in other current liabilities. See Note 4 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of the FERC settlement.

	As of		As of
	June 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	8,800,698	$	8,524,902	$	275,796	3.2

Property, plant and equipment, net of accumulated depreciation, increased due primarily to the construction of Western Plains Wind Farm and plant additions for capital improvements as part of a plan to improve long-term reliability.

	As of		As of
	June 30, 2016		December 31, 2015		Change			% Change
	(Dollars in Thousands)
Short-term debt	$	177,000	$	250,300	$	(73,300	)	(29.3	)

Short-term debt decreased due principally to Westar Energy issuing $350.0 million in principal amount of first mortgage bonds, partially offset by issuances of commercial paper primarily used to fund capital expenditures, such as the construction of Western Plains Wind Farm. See Note 7 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing.”

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	As of		As of
	June 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Current maturities of long-term debt	$	125,000	$	—	$	125,000	—
Long-term debt, net	3,387,696		3,163,950		223,746		7.1
Total long-term debt	$	3,512,696	$	3,163,950	$	348,746	11.0

Total long-term debt increased due to Westar Energy issuing $350.0 million in principal amount of first mortgage bonds. See Note 7 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing.”

	As of		As of
	June 30, 2016		December 31, 2015		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309	$	(1,467	)	(5.2	)
Long-term debt of variable interest entities	111,230		138,097		(26,867		)	(19.5	)
Total long-term debt of variable interest entities	$	138,072	$	166,406	$	(28,334	)	(17.0	)

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 $28.3 million.

	As of		As of
	June 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,655,825	$	1,591,430	$	64,395	4.0

Deferred income taxes increased due primarily to the utilization of previously deferred net operating losses during the period.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy’s commercial paper program and revolving credit facilities and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings, and proceeds from the issuance of debt and equity securities in the capital markets. 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.

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Short-Term Borrowings

Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy’s revolving credit facilities. 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 redeem debt on an interim basis, for working capital and/or for other general corporate purposes. As of July 27, 2016, Westar Energy had $192.5 million of commercial paper issued and outstanding.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. The $730.0 million facility will expire in September 2019, $20.7 million of which will expire in September 2017. The $270.0 million credit facility will expire February 2017. As long as there is no default under the facilities, 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 27, 2016, no amounts were borrowed and $13.2 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

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of $162.1 million in outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 13 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

Debt Covenants

We were in compliance with our debt covenants as of June 30, 2016.

Impact of Credit Ratings on Debt Financing

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

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

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

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As of July 27, 2016, 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	A-2	Negative

_______________

(a) In May 2016, following the public announcement of the proposed merger with Great Plains Energy, S&P revised its outlook for Westar Energy and KGE to negative from stable.

Summary of Cash Flows

	Six Months Ended June 30,
	2016			2015			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	328,681		$	233,012		$	95,669		41.1
Investing activities	(495,963		)	(348,928		)	(147,035		)	(42.1	)
Financing activities	169,264			113,626			55,638			49.0
Net change in cash and cash equivalents	$	1,982		$	(2,290	)	$	4,272		(186.6	)

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having paid $68.9 million less for coal and natural gas and $24.6 million less for the Wolf Creek refueling outage, receiving $18.7 million more from retail customers,paying $13.1 million less for interest and receiving $6.2 million more in COLI proceeds. Partially offsetting these increases was our having received $35.7 million less for wholesale power salesand transmission services.

Cash Flows used in Investing Activities

Cash flows used in investing activities increased due primarily to our having invested $168.7 million more in additions to property, plant and equipment. Partially offsetting this increase was our having received $23.0 million more from our investment in COLI.

Cash Flows from Financing Activities

Cash flows from financing activities increased due principally to our having issued $396.6 million more in long-term debt, issuing $162.0 million more in long-term debt of VIEs and redeeming $75.0 million less in long-term debt. Partially offsetting these increases was our having issued $255.0 million less in common stock, redeeming $162.4 million more in long-term debt of VIEs, issuing $122.8 million less in commercial paper, repaying $22.0 million more for borrowings against the cash surrender value of COLI and paying $12.1 million more in dividends

Pension Contribution

During the six months endedJune 30, 2016, we contributed $11.2 million to the Westar Energy pension trust. We funded $3.2 million of Wolf Creek’s pension plan contributions during the same period.

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OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2015, through June 30, 2016, our off-balance sheet arrangements did not change materially. For additional information, see our 2015 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2015, through June 30, 2016, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2015 Form 10-K.

OTHER INFORMATION

Changes in Prices

See Note 4 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” for information on our prices.

New Accounting Pronouncements

See Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for information on accounting pronouncements.    

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, 2015, to June 30, 2016, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2015 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, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC 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 Exchange 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 endedJune 30, 2016, 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 4, 11 and 12 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

     Except as indicated below, there were no material changes in our risk factors from December 31, 2015, through June 30, 2016. For additional information, see our 2015 Form 10-K.

We cannot provide any assurance that the merger will be completed.

The closing of the merger is subject to certain conditions, including, among others, (i) approval of our shareholders representing a majority of the outstanding shares of our common stock, (ii) approval of Great Plains Energy shareholders representing a majority of the votes cast at the Great Plains Energy shareholders meeting, (iii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iv) receipt of all required regulatory approvals, including from the FERC, the NRC and the KCC (provided that such approvals do not result in a material adverse effect on Great Plains Energy and its subsidiaries after giving effect to the merger), (v) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the merger, (vi) the effectiveness of the Great Plains Energy registration statement on Form S-4 that was filed with the SEC, (vii) the approval of the listing of the Great Plains Energy common stock to be issued in the merger, (viii) the absence of any material adverse effect with respect to us and our subsidiaries and (ix) subject to certain materiality exceptions, the accuracy of the representations and warranties of, and compliance and covenants by, each of the parties to the merger agreement.

Although we and Great Plains Energy have agreed in the merger agreement to use our reasonable best efforts to take, or cause to be taken, all actions, and do, or cause to be done, and assist and cooperate with the other parties in doing, all things necessary to cause the conditions to the closing of the merger to be satisfied or to effect the closing of the merger as promptly as reasonably practicable, the conditions to the merger may not be satisfied and the merger agreement could be terminated. In addition, satisfying the conditions to the merger may take longer than, and could cost more than, we and Great Plains Energy expect. The occurrence of any of these events individually or in combination may adversely affect the benefits that we and Great Plains Energy expect to achieve from the merger and the trading price of our common stock.

The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company.

Completion of the merger is conditioned upon the expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and the receipt of consents, orders, approvals or clearances, as required, from, among others, the FERC, the NRC and the KCC (provided that such approvals do not result in a material adverse effect on Great Plains Energy and its subsidiaries after giving effect to the merger).

In June 2016, the DOJ sent a letter to us and Great Plains Energy requesting that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

In addition, the Public Service Commission of the State of Missouri (Missouri Commission) has opened an investigation to determine whether it has jurisdiction over the merger. The outcome of that proceeding cannot be determined at this time. If the Missouri Commission has jurisdiction over the merger, approval of the Missouri Commission also will be required in order to consummate the merger. A substantial delay in obtaining satisfactory approvals or the imposition of unfavorable terms or conditions in connection with such approvals could adversely affect the business, financial condition or results of operations of us or Great Plains Energy or may result in the termination of the merger agreement.

Failure to complete the merger could negatively affect the trading price of our common stock and our future business and financial results.

Completion of the merger is not assured and is subject to risks and, if the merger is not completed, it could negatively affect the trading price of our common stock and our future business and financial results, and we will be subject to several risks, including the following:

• we may be liable for damages to Great Plains Energy under the terms and conditions of the merger agreement;

• negative reactions from the financial markets, including declines in the price of our common stock due to the fact that the current price may reflect a market assumption that the merger will be completed;

42

• us possibly having to pay Great Plains Energy a termination fee of $280.0 million if the merger agreement is terminated under certain circumstances, including because our board of directors changes its recommendation to shareholders, under certain circumstances; and

• the attention of our management will have been diverted to the merger rather than our operations and pursuit of other opportunities.

The anticipated benefits of combining the companies may not be realized.

We entered into the merger agreement with the expectation that the merger would result in various benefits, including, among other things, synergies, cost savings and operating efficiencies. However, the achievement of the anticipated benefits of the merger, including the synergies, cannot be assured or may take longer than expected. In addition, the combined company may not be able to integrate our operations with Great Plains Energy’s existing operations without encountering difficulties, including inconsistencies in standards, systems and controls, and without diverting management’s focus and resources from ordinary business activities and opportunities. Any of the foregoing could have a material adverse effect on the combined company.

Developments in the utility industry, including changes in regulation and increased competition, could adversely affect the combined company’s financial condition and results of operations.

We and Great Plains Energy, and certain of their respective subsidiaries, are regulated at the federal and state level, and have been and will continue to be affected by legislative and regulatory developments. These developments could have a material adverse effect on us, Great Plains Energy or, following the completion of the merger, the combined company.

The costs and burdens associated with complying with legal and regulatory requirements may have a material adverse effect on us, Great Plains Energy or, following the completion of the merger, the combined company. Potential legislative changes or regulatory changes may also weaken the financial condition of, or increase the volatility of results of operations for, and have a material adverse effect on us, Great Plains Energy or, following the completion of the merger, the combined company.

We will incur significant transaction and transition costs in connection with the merger.

We and Great Plains Energy expect to incur significant transaction and transition costs in connection with the consummation of the merger and the subsequent integration of the companies. Prior to consummation of the merger, we may also incur additional costs to maintain employee morale and to retain key employees. Great Plains Energy will also incur significant fees and expenses relating to the financing arrangements in connection with the merger. These expenses could reduce or eliminate the savings that we expect to achieve from the merger, and accordingly, any net benefits may not be achieved in the near term or at all. These transaction and transition expenses may result in significant charges taken against earnings by us prior to completion of the merger and by the combined company following the completion of the merger.

We will be subject to business uncertainties and contractual restrictions while the merger is pending, which could adversely affect our business.

Uncertainty about the impact of the merger, including on employees and customers, may have an adverse effect on us and Great Plains Energy and, consequently, on the combined company. These uncertainties may impair our and Great Plains Energy’s ability to attract, retain and motivate personnel, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships with us and/or Great Plains Energy. If employees depart, our business or the combined company’s business could be harmed. In addition, the merger agreement restricts us, without the consent of Great Plains Energy, from taking specified actions until we complete the merger or the merger agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business.

43

Pending litigation against us and Great Plains Energy could result in an injunction preventing the consummation of the merger or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

Following the announcement of the merger agreement, two lawsuits were filed in the District Court of Shawnee County, Kansas, against Westar Energy, the members of our board of directors and Great Plains Energy, alleging breaches of various fiduciary duties by the members of our board of directors in connection with the proposed merger and alleging that we and Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. A third lawsuit was filed in the District Court of Shawnee County, Kansas, against the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, alleging breaches of various fiduciary duties by members of our board of directors in connection with the proposed merger and alleging that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. Among other remedies, the plaintiffs in each case seek to enjoin the merger and rescind the merger agreement, in addition to certain unspecified damages and reimbursement of costs. While we and Great Plains Energy believe these lawsuits are without merit and intend to vigorously defend against such claims, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation. See Note 12 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings,” for additional information.

The exchange of our common stock for Great Plains Energy common stock and cash will be a taxable transaction for U.S. Federal income tax purposes.

The exchange of our common stock for shares of Great Plains Energy common stock and cash will be a taxable transaction for U.S. federal income tax purposes. In general, domestic shareholders will be required to include in taxable income the excess of the sum of the fair market value of the Great Plains Energy common stock and the cash received in the exchange over such shareholder’s adjusted tax basis in our common stock exchanged therefor.

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. In accordance with SEC guidance, 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.

44

ITEM 6. EXHIBITS

2.1+	Agreement and Plan of Merger, dated as of May 29, 2016, by and among Westar Energy, Inc., Great Plains Energy Incorporated and Merger Sub (incorporated by reference to Exhibit 2.1 to the Form 8-K filed on May 31, 2016)
4.1	Form of Forty-Sixth Supplemental Indenture, dated as of June 20, 2016, by and between Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor to Harris Trust and Savings Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed on June 17, 2016)
10.1++	Amended and Restated Long-Term Incentive and Share Award Plan, effective January 1, 2016 (incorporated by reference to Appendix B to the Proxy Statement filed on April 1, 2016)
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, 2016
31(b)	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended June 30, 2016
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2016 (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
+	The disclosure letters and related schedules to the agreement are not being filed herewith. The registrant agrees to furnish supplementally a copy of any such schedules to the Securities and Exchange Commission upon request.
++	Management contract or compensatory plan or arrangement.

45

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 2, 2016	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

46

EX-31.A

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2016, of Westar Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2016	By:	/s/    Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer
			Westar Energy, Inc.
			(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2016, of Westar Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2016	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer
			Westar Energy, Inc.
			(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Westar Energy, Inc. (the Company) on Form 10-Q for the quarter ended June 30, 2016 (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	August 2, 2016	By:	/s/    Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer

Date:	August 2, 2016	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

XML

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2016	Jul. 27, 2016
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Trading Symbol	WR
Entity Registrant Name	WESTAR ENERGY INC /KS
Entity Central Index Key	0000054507
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		141,734,848

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents		$ 5,213	$ 3,231
Accounts receivable, net of allowance for doubtful accounts of $4,503 and $4,596, respectively		298,841	258,286
Fuel inventory and supplies		299,465	301,294
Prepaid expenses		17,994	16,864
Regulatory assets		87,256	109,606
Other		33,099	27,860
Total Current Assets		741,868	717,141
Property, plant and equipment, net		8,800,698	8,524,902
OTHER ASSETS:
Regulatory assets		734,844	751,312
Nuclear decommissioning trust		189,179	184,057
Other		241,081	260,015
Total Other Assets		1,165,104	1,195,384
TOTAL ASSETS		10,970,742	10,705,666
CURRENT LIABILITIES:
Current maturities of long-term debt		125,000	0
Short-term debt		177,000	250,300
Accounts payable		178,374	220,969
Accrued dividends		52,767	49,829
Accrued taxes		95,084	83,773
Accrued interest	[1]	41,969	71,426
Regulatory liabilities		33,634	25,697
Other		90,841	106,632
Total Current Liabilities		821,511	836,935
LONG-TERM LIABILITIES:
Long-term debt, net		3,387,696	3,163,950
Deferred income taxes		1,655,825	1,591,430
Unamortized investment tax credits		208,318	209,763
Regulatory liabilities		247,916	267,114
Accrued employee benefits		455,923	462,304
Asset retirement obligations		280,507	275,285
Other		87,065	88,825
Total Long-Term Liabilities		6,434,480	6,196,768
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
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		708,455	706,767
Paid-in capital		2,008,491	2,004,124
Retained earnings		978,187	945,830
Total Westar Energy, Inc. Shareholders' Equity		3,695,133	3,656,721
Noncontrolling Interests		19,618	15,242
Total Equity		3,714,751	3,671,963
TOTAL LIABILITIES AND EQUITY		10,970,742	10,705,666
Variable Interest Entity [Member]
CURRENT ASSETS:
Property, plant and equipment, net		263,072	268,239
CURRENT LIABILITIES:
Current maturities of long-term debt		26,842	28,309
Accrued interest	[1]	867	2,457
LONG-TERM LIABILITIES:
Long-term debt, net		$ 111,230	$ 138,097

[1] Included in accrued interest on our consolidated balance sheets.

XML

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Allowance for doubtful accounts	$ 5,093	$ 5,294
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	141,691,017	141,353,426
Common stock, shares outstanding	141,691,017	141,353,426

XML

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES	$ 621,448	$ 589,563	$ 1,190,898	$ 1,180,370
OPERATING EXPENSES:
Fuel and purchased power	118,630	140,080	218,688	295,561
Network Transmission Cost	55,227	57,352	115,987	114,164
Operating and maintenance	85,619	82,739	163,377	167,819
Depreciation and amortization	84,226	76,759	167,866	151,345
Selling, general and administrative	75,724	63,663	132,179	119,082
Taxes, Miscellaneous	48,407	37,494	97,375	75,365
Total Operating Expenses	467,833	458,087	895,472	923,336
INCOME FROM OPERATIONS	153,615	131,476	295,426	257,034
OTHER INCOME (EXPENSE):
Investment earnings (losses)	2,280	1,634	4,296	4,113
Other income	3,382	15,121	12,860	17,935
Other expense	(2,908)	(2,633)	(8,451)	(8,345)
Total Other Income	2,754	14,122	8,705	13,703
Interest expense	39,683	45,516	80,114	89,814
INCOME BEFORE INCOME TAXES	116,686	100,082	224,017	180,923
Income tax expense	40,542	33,839	79,165	61,517
NET INCOME	76,144	66,243	144,852	119,406
Less: Net income attributable to noncontrolling interests	3,804	2,533	6,927	4,716
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 72,340	$ 63,710	$ 137,925	$ 114,690
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 0.51	$ 0.47	$ 0.97	$ 0.85
Earnings Per Share, Diluted	$ 0.51	$ 0.46	$ 0.97	$ 0.84
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,033,842	135,939,197	142,013,344	134,177,136
Weighted Average Number of Shares Outstanding, Diluted	142,497,335	137,412,152	142,361,347	136,329,603
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.38	$ 0.36	$ 0.76	$ 0.72

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 144,852	$ 119,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	167,866	151,345
Amortization of nuclear fuel	16,831	10,085
Amortization of deferred regulatory gain from sale leaseback	(2,748)	(2,748)
Amortization of corporate-owned life insurance	8,819	9,042
Non-cash compensation	4,778	4,241
Net deferred income taxes and credits	75,334	54,740
Allowance for equity funds used during construction	(5,247)	(2,041)
Changes in working capital items:
Accounts receivable	(40,555)	998
Fuel inventory and supplies	2,140	(31,307)
Prepaid expenses and other	7,126	(40,195)
Accounts payable	(21,364)	(2,873)
Accrued taxes	16,272	16,893
Other current liabilities	(62,434)	(65,908)
Changes in other assets	1,848	(9,712)
Changes in other liabilities	15,163	21,046
Cash Flows from Operating Activities	328,681	233,012
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(503,631)	(334,905)
Purchase of securities - trusts	(39,603)	(9,980)
Sale of securities - trusts	41,201	10,263
Investment in corporate-owned life insurance	14,648	14,845
Proceeds from investment in corporate-owned life insurance	24,171	1,192
Investment in affiliated company	(655)	0
Other investing activities	(2,798)	(653)
Cash Flows used in Investing Activities	(495,963)	(348,928)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(73,300)	49,500
Proceeds from long-term debt	(396,577)	0
Retirements of long-term debt	(50,000)	(125,000)
Repayment of capital leases	(401)	(1,721)
Borrowings against cash surrender value of corporate-owned life insurance	54,910	56,622
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(22,921)	(899)
Stock-based compensation excess tax benefits		1,178
Issuance of common stock	1,354	256,394
Distributions to shareholders of noncontrolling interests	(2,551)	(1,076)
Cash dividends paid	(101,137)	(89,035)
Other financing activities	(4,960)	(3,234)
Cash Flows from Financing Activities	169,264	113,626
NET CHANGE IN CASH AND CASH EQUIVALENTS	1,982	(2,290)
CASH AND CASH EQUIVALENTS:
Beginning of period	3,231
End of period	5,213	2,266
Variable Interest Entity [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from long-term debt	(162,048)	0
Retirements of long-term debt	$ (190,355)	$ (27,925)

XML

Consolidated Statements Of Changes In Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2014	$ 3,301,307	$ 658,437	$ 1,781,120	$ 855,299	$ 6,451
Beginning Balance (Shares) at Dec. 31, 2014		131,687,454
Net income	119,406	$ 0	0	114,690	4,716
Issuance of stock	256,394	$ 46,041	210,353	0	0
Issuance of stock (shares)		9,208,267
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		282,897
Issuance Of Stock For Compensation And Reinvested Dividends	5,532	$ 1,415	4,117
Tax withholding related to stock compensation	(3,234)		(3,234)
Dividends on common stock	(99,169)	0	0	(99,169)	0
Stock compensation expense	4,196		4,196
Tax Benefit on stock compensation	1,178	0	1,178	0	0
Distributions to shareholders of noncontrolling interests	(1,076)				(1,076)
Ending Balance at Jun. 30, 2015	3,584,464	$ 705,893	1,997,661	870,820	10,090
Ending Balance (Shares) at Jun. 30, 2015		141,178,618
Stockholders' Equity, Other	(70)		(69)		(1)
Beginning Balance at Dec. 31, 2015	3,671,963	$ 706,767	2,004,124	945,830	15,242
Beginning Balance (Shares) at Dec. 31, 2015		141,353,426
Net income	144,852	$ 0	0	137,925	6,927
Issuance of stock	1,354	$ 143	1,211	0	0
Issuance of stock (shares)		28,674
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		308,917
Issuance Of Stock For Compensation And Reinvested Dividends	4,941	$ 1,545	3,396
Tax withholding related to stock compensation	(4,960)		(4,960)
Dividends on common stock	(108,894)	0	0	(108,894)	0
Stock compensation expense	4,720		4,720
Deconsolidation of variable interest entity	(2,551)				(2,551)
Distributions to shareholders of noncontrolling interests	(2,551)
Ending Balance at Jun. 30, 2016	3,714,751	$ 708,455	$ 2,008,491	978,187	$ 19,618
Ending Balance (Shares) at Jun. 30, 2016		141,691,017
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	$ (3,326)			$ (3,326)

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Consolidated Statements Of Changes in Equity Parenthetical (Parentheticals) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.38	$ 0.36	$ 0.76	$ 0.72

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Description Of Business

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description Of Business

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 704,000 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.

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Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

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) for the United States of America 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 condensed 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 2015 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 ongoing 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 endedJune 30, 2016, are not necessarily indicative of the results to be expected for the full year.

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, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	107,397	$	113,438
Supplies	192,068		187,856
Fuel inventory and supplies	$	299,465	$	301,294

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,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,338		$	552		$	4,347		$	2,581
Equity funds	2,783			90			5,247			2,041
Total	$	5,121		$	642		$	9,594		$	4,622
Average AFUDC Rates	4.2		%	1.2		%	4.6		%	3.2		%

Earnings Per Share

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

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 issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,144	$	66,243	$	144,852	$	119,406
Less: Net income attributable to noncontrolling interests	3,804		2,533		6,927		4,716
Net income attributable to Westar Energy, Inc.	72,340		63,710		137,925		114,690
Less: Net income allocated to RSUs	156		141		290		257
Net income allocated to common stock	$	72,184	$	63,569	$	137,635	$	114,433
Weighted average equivalent common shares outstanding – basic	142,033,842		135,939,197		142,013,344		134,177,136
Effect of dilutive securities:
RSUs	463,493		121,234		348,003		127,999
Forward sale agreements	—		1,351,721		—		2,024,468
Weighted average equivalent common shares outstanding – diluted (a)	142,497,335		137,412,152		142,361,347		136,329,603
Earnings per common share, basic	$	0.51	$	0.47	$	0.97	$	0.85
Earnings per common share, diluted	$	0.51	$	0.46	$	0.97	$	0.84

_______________

(a) We had no antidilutive securities for the three and six months endedJune 30, 2016 and 2015.

Supplemental Cash Flow Information

	Six Months Ended June 30,
	2016			2015
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	70,697		$	82,297
Interest on financing activities of VIEs	4,150			5,651
Income taxes, net of refunds	(77		)	126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	71,830			66,861
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,941			5,532
Assets acquired through capital leases	392			1,102

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, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accounting and/or disclosure.

Leases

In February 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-02 which requires lessees to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. We are evaluating the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated financial statements.

Stock-based Compensation

In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.

Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits and expense. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying condensed consolidated statements of cash flows for the six months ended June 30, 2015, as $1.2 million higher than as previously reported, and cash flows from financing activities as $1.2 million lower than as previously reported.

Financial Instruments

In May 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 5, “Financial Instruments and Trading Securities.”

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which 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 was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We are continuing to analyze the new standard and 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.

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Rate Matters And Regulation

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

Rate Matters And Regulation

RATE MATTERS AND REGULATION

KCC Proceedings

In December 2015, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million.

In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR), along with the reduced return on equity (ROE) as described below. The updated prices were retroactively effective April 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $7.0 million. As of June 30, 2016, we have recorded a regulatory liability of $4.0 million for our estimated refund obligation from the refund effective date of April 2016 through June 2016.

FERC Proceedings

In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO.

The updated prices were retroactively effective January 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million. This increase also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation during the three months ended June 30, 2016. As of June 30, 2016, we have a remaining refund obligation of $8.1 million which is included in current regulatory liabilities on our balance sheet.

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Financial Instruments and Risk Management

6 Months Ended

Jun. 30, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Financial And Derivative Instruments And Trading Securities

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. In addition, we measure certain investments that do not have a readily determinable fair value at NAV, which are not included in the fair value hierarchy. Further explanation of these levels and NAV is summarized below.

• 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 liquid investments in funds which have a readily determinable fair value calculated using daily NAVs, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments 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.

• Net Asset Value - Investments that do not have a readily determinable fair value are measured at NAV. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments.

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.

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, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,865,914	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,963		154,097		166,271		179,030

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, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	—		$	50,856	$	—	$	5,944	$	56,800
International equity funds	—		34,560		—		—		34,560
Core bond fund	—		27,509		—		—		27,509
High-yield bond fund	—		16,557		—		—		16,557
Emerging markets bond fund	—		15,342		—		—		15,342
Combination debt/equity/other funds	—		12,277		—		—		12,277
Alternative investments fund	—		—		—		16,386		16,386
Real estate securities fund	—		—		—		9,500		9,500
Cash equivalents	248		—		—		—		248
Total Nuclear Decommissioning Trust	248		157,101		—		31,830		189,179
Trading Securities:
Domestic equity funds	—		17,782		—		—		17,782
International equity fund	—		4,220		—		—		4,220
Core bond fund	—		11,935		—		—		11,935
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		33,937		—		—		34,093
Total Assets Measured at Fair Value	$	404	$	191,038	$	—	$	31,830	$	223,272
As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	—	$	6,050	$	56,922
International equity funds	—		33,595		—		—		33,595
Core bond fund	—		25,976		—		—		25,976
High-yield bond fund	—		15,288		—		—		15,288
Emerging markets bond fund	—		13,584		—		—		13,584
Combination debt/equity/other funds	—		11,343		—		—		11,343
Alternative investments fund	—		—		—		16,439		16,439
Real estate securities fund	—		—		—		10,823		10,823
Cash equivalents	87		—		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		—		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		—		17,876
International equity fund	—		4,430		—		—		4,430
Core bond fund	—		11,423		—		—		11,423
Cash equivalents	159		—		—		—		159
Total Trading Securities	159		33,729		—		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	—	$	33,312	$	217,945

Some of our investments in the Nuclear Decommissioning Trust (NDT) are measured at NAV 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, 2016				As of December 31, 2015				As of June 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,944	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	16,386		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,500		—		10,823		—		Quarterly	65 days
Total	$	31,830	$	3,689	$	33,312	$	1,948

_______________

(a) This investment is in four 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. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b) 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 from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

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

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Financial Investments

6 Months Ended

Jun. 30, 2016

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

We report 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 that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.1 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months endedJune 30, 2016, we recorded an unrealized gain of $0.6 million on assets still held. For the six months endedJune 30, 2016, we recorded an unrealized gain of $1.1 million on assets still held. For the three months ended June 30, 2015, we recorded no unrealized gain or loss on assets still held. For the six months ended June 30, 2015, we recorded an unrealized gain of $0.7 million on 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, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a gain of$0.1 million during the three months endedJune 30, 2016, and a loss of$1.4 million during the six months endedJune 30, 2016. We realized a loss of $0.6 million for the three months endedJune 30, 2015, and a loss of $0.5 million for the six months endedJune 30, 2015. 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, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds	$	49,844	$	6,965	$	(9	)	$	56,800	30	%
International equity funds	33,935		1,201		(576		)	34,560		18	%
Core bond fund	26,882		627		—			27,509		15	%
High-yield bond fund	17,405		—		(848		)	16,557		9	%
Emerging market bond fund	16,145		—		(803		)	15,342		8	%
Combination debt/equity/other funds	9,003		3,274		—			12,277		6	%
Alternative investment fund	15,000		1,386		—			16,386		9	%
Real estate securities fund	9,500		—		—			9,500		5	%
Cash equivalents	248		—		—			248		<1%
Total	$	177,962	$	13,453	$	(2,236	)	$	189,179	100	%
As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	100	%

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 ofJune 30, 2016, and December 31, 2015.

	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, 2016:
Domestic equity funds	$	861	$	(9	)	$	—	$	—		$	861	$	(9	)
International equity funds	—		—			7,426		(576		)	7,426		(576		)
High-yield bond fund	—		—			16,557		(848		)	16,557		(848		)
Emerging market bond fund	—		—			15,342		(803		)	15,342		(803		)
Total	$	861	$	(9	)	$	39,325	$	(2,227	)	$	40,186	$	(2,236	)
As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

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Pending Merger Pending Merger (Notes)

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock.

The closing of the merger is subject to customary conditions including, among others, approval by our shareholders and the shareholders of Great Plains Energy and receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger.

On July 14, 2016, Great Plains Energy filed a registration statement on Form S-4 with the SEC. The registration statement includes a preliminary proxy statement that, once finalized, will be sent to our shareholders in connection with the special meeting of our shareholders to be held to vote to approve the merger.

The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If Great Plains Energy terminates the merger agreement because our board of directors changes its recommendation, if we terminate the merger agreement to enter into an acquisition agreement with a superior proposal, or if our shareholders vote and do not give approval and we enter into an acquisition proposal within 12 months of termination of the merger agreement, we must pay Great Plains Energy a termination fee of $280.0 million.

If the merger agreement is terminated under other circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. If we terminate the merger agreement because the Great Plains Energy board of directors changes its recommendation, Great Plains Energy must pay us a termination fee of $180.0 million. If either party terminates the merger agreement because the end date occurred or Great Plains Energy shareholders’ approval was not acquired, and it has either been publicly disclosed that Great Plains Energy has entered into an alternative acquisition proposal, or an acquisition proposal was entered into within 12 months after the termination of the merger agreement, Great Plains Energy must pay us a termination fee of $180.0 million. If Great Plains Energy shareholders’ meeting was held and completed, but approval was not obtained, and the termination fee described above is not payable by Great Plains Energy, Great Plains Energy must pay us a termination fee of $80.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three months ended June 30, 2016, we incurred approximately $7.8 million of merger-related expenses, which is included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to coincide with the closing of the merger.

We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies,” andNote 12, “Legal Proceedings,” for more information on legal matters.

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Debt Financing

6 Months Ended

Jun. 30, 2016

Long-term Debt, Unclassified [Abstract]

Debt Financing

DEBT FINANCING

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of$162.1 millionin outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from5.647% to 2.398%. See Note 13, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

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Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Taxes

TAXES

We recorded income tax expense of $40.5 million with an effective income tax rate of 35% for the three months endedJune 30, 2016, and income tax expense of $33.8 million with an effective income tax rate of 34% for the same period of 2015. We recorded income tax expense of $79.2 million with an effective income tax rate of 35% for the six months endedJune 30, 2016, and income tax expense of $61.5 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three and six months ended June 30, 2016, was due primarily to an increase in income before income taxes.

As of June 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $3.0 million and $2.9 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of June 30, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2016, or December 31, 2015.

As of June 30, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

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Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,921			10,753			1,393			1,422
Expected return on plan assets	(10,663		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			114			114
Actuarial loss (gain), net	5,146			8,053			(280		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,225			(210		)	338
Regulatory adjustment (a)	3,306			1,534			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,759		$	(696	)	$	1,351

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

 _______________

(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 endedJune 30, 2016 and 2015, we contributed $11.2 million and $19.4 million, respectively, to the Westar Energy pension trust.

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Wolf Creek Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Wolf Creek Pension And Post-Retirement Benefit Plans

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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	32		$	34
Interest cost	2,414			2,254			82			79
Expected return on plan assets	(2,430		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,089			1,482			(4		)	1
Net periodic cost before regulatory adjustment	2,774			3,388			110			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,257		$	3,084		$	110		$	114

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,374		$	3,797		$	64		$	69
Interest cost	4,828			4,508			163			157
Expected return on plan assets	(4,861		)	(4,522		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,178			2,965			(8		)	1
Net periodic cost before regulatory adjustment	5,547			6,776			219			227
Regulatory adjustment (a)	966			(608		)	—			—
Net periodic cost	$	6,513		$	6,168		$	219		$	227

 _______________

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

During the six months endedJune 30, 2016 and 2015, we funded $3.2 million and $2.5 million of Wolf Creek’s pension plan contributions, respectively.

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Rule

In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (NOx) emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

Under the federal Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide (CO) and sulfur dioxide (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.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, Kansas Department of Health and Environment (KDHE) recommended a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We are working with KDHE to determine the impact of this proposed designation. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review.  Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay.  In February 2016, the U.S. Supreme Court granted the stay request. In May 2016, the U.S. Court of Appeals for the D.C. Circuit decided to forego the normal three judge panel to review the CPP and to conduct the review en banc. At the same time, the Court scheduled oral arguments for September 2016. In June 2016, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

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 were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology 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 La Cygne and Wolf Creek. 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 we do not expect it to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results.

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. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results, but it could be material.

Storage of Spent Nuclear Fuel

In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.

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.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the Federal Power Act.

Department of Justice Proceedings

At any time before or after the merger, the Department of Justice (DOJ) or the Federal Trade Commission could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the merger or seeking divestiture of substantial assets of Great Plains Energy, the Company or their respective subsidiaries. Private parties and state attorneys general may also bring an action under the antitrust laws under certain circumstances. On June 23, 2016, the DOJ sent a letter to us and Great Plains Energy informing the parties that it had opened an investigation into the proposed transaction and requested that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

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Legal Proceedings

6 Months Ended

Jun. 30, 2016

Legal Proceedings [Abstract]

Legal Proceedings

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 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information.

Pending Merger

Following the announcement of the merger agreement, two putative class action complaints and one putative derivative action complaint challenging the merger were filed on behalf of purported Westar Energy shareholders in the District Court of Shawnee County, Kansas.

The first complaint, filed on June 13, 2016, is captioned Smith v. Westar Energy, Inc., et al., Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that we and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration undervalues Westar Energy, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourages third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, our CEO will reap significant personal financial gain. The complaint seeks, among other remedies, a declaration that the action may be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement (to the extent already implemented), a directive to the members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

The second complaint, filed on June 14, 2016, is captioned Miller v. Westar Energy, Inc., et al., Case No. 2016-CV-000458. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration deprives our shareholders of fair consideration for their shares, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, an order to permit the action to be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement, a directive to defendants to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

Counsel for plaintiffs in the Smith matter and the Miller matter have filed an unopposed motion for consolidation and appointment of lead counsel. The defendants believe that the claims asserted against them in both class action lawsuits are without merit and intend to vigorously defend against such claims.

The third complaint, filed on July 5, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action is brought on behalf of our shareholders and names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as the nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals. The complaint seeks, among other remedies, an order to permit the action to be maintained as a derivative action, enjoining direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement (to the extent already implemented), imposing a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The defendants intend to seek dismissal of this complaint at the appropriate time.

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Variable Interest Entities

6 Months Ended

Jun. 30, 2016

Variable Interest Entities [Abstract]

Variable Interest Entities

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 Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 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 and (2) 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 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 7, “Debt Financing,” for additional information.

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, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	263,072	$	268,239
Regulatory assets (a)	9,758		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,230		138,097

_______________

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

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

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

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Summary Of Significant Accounting Policies (Policy)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Principles Of Consolidation

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) for the United States of America 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 condensed consolidated financial statements, have been included.

Use Of Management's Estimates

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 ongoing 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.

Fuel Inventory And Supplies

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost.

Allowance For Funds Used During Construction

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

Earnings Per Share

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).

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 issuable common shares resulting from our forward sale agreements, if any, 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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Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Schedule of Utility Inventory

Following are the balances for fuel inventory and supplies stated separately.

	As of		As of
	June 30, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	107,397	$	113,438
Supplies	192,068		187,856
Fuel inventory and supplies	$	299,465	$	301,294

Allowance For Funds Used During Construction

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,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,338		$	552		$	4,347		$	2,581
Equity funds	2,783			90			5,247			2,041
Total	$	5,121		$	642		$	9,594		$	4,622
Average AFUDC Rates	4.2		%	1.2		%	4.6		%	3.2		%

Reconciliation Of Basic And Diluted EPS

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,144	$	66,243	$	144,852	$	119,406
Less: Net income attributable to noncontrolling interests	3,804		2,533		6,927		4,716
Net income attributable to Westar Energy, Inc.	72,340		63,710		137,925		114,690
Less: Net income allocated to RSUs	156		141		290		257
Net income allocated to common stock	$	72,184	$	63,569	$	137,635	$	114,433
Weighted average equivalent common shares outstanding – basic	142,033,842		135,939,197		142,013,344		134,177,136
Effect of dilutive securities:
RSUs	463,493		121,234		348,003		127,999
Forward sale agreements	—		1,351,721		—		2,024,468
Weighted average equivalent common shares outstanding – diluted (a)	142,497,335		137,412,152		142,361,347		136,329,603
Earnings per common share, basic	$	0.51	$	0.47	$	0.97	$	0.85
Earnings per common share, diluted	$	0.51	$	0.46	$	0.97	$	0.84

_______________

(a) We had no antidilutive securities for the three and six months endedJune 30, 2016 and 2015.

Supplemental Cash Flow Information

	Six Months Ended June 30,
	2016			2015
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	70,697		$	82,297
Interest on financing activities of VIEs	4,150			5,651
Income taxes, net of refunds	(77		)	126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	71,830			66,861
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,941			5,532
Assets acquired through capital leases	392			1,102

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Financial Instruments and Risk Management (Tables)

6 Months Ended

Jun. 30, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

The following table provides the carrying values and measured fair values of our fixed-rate debt.

	As of June 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,865,914	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,963		154,097		166,271		179,030

Fair Value Of Assets And Liabilities

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, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	—		$	50,856	$	—	$	5,944	$	56,800
International equity funds	—		34,560		—		—		34,560
Core bond fund	—		27,509		—		—		27,509
High-yield bond fund	—		16,557		—		—		16,557
Emerging markets bond fund	—		15,342		—		—		15,342
Combination debt/equity/other funds	—		12,277		—		—		12,277
Alternative investments fund	—		—		—		16,386		16,386
Real estate securities fund	—		—		—		9,500		9,500
Cash equivalents	248		—		—		—		248
Total Nuclear Decommissioning Trust	248		157,101		—		31,830		189,179
Trading Securities:
Domestic equity funds	—		17,782		—		—		17,782
International equity fund	—		4,220		—		—		4,220
Core bond fund	—		11,935		—		—		11,935
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		33,937		—		—		34,093
Total Assets Measured at Fair Value	$	404	$	191,038	$	—	$	31,830	$	223,272
As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	—	$	6,050	$	56,922
International equity funds	—		33,595		—		—		33,595
Core bond fund	—		25,976		—		—		25,976
High-yield bond fund	—		15,288		—		—		15,288
Emerging markets bond fund	—		13,584		—		—		13,584
Combination debt/equity/other funds	—		11,343		—		—		11,343
Alternative investments fund	—		—		—		16,439		16,439
Real estate securities fund	—		—		—		10,823		10,823
Cash equivalents	87		—		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		—		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		—		17,876
International equity fund	—		4,430		—		—		4,430
Core bond fund	—		11,423		—		—		11,423
Cash equivalents	159		—		—		—		159
Total Trading Securities	159		33,729		—		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	—	$	33,312	$	217,945

Unrealized Gains And Losses On Fair Value Assets And Liabilities

Investments In Financial Instruments

The following table provides additional information on these investments.

	As of June 30, 2016				As of December 31, 2015				As of June 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,944	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	16,386		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,500		—		10,823		—		Quarterly	65 days
Total	$	31,830	$	3,689	$	33,312	$	1,948

_______________

(a) This investment is in four 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. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b) There is a holdback on final redemptions.

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Financial Investments (Tables)

6 Months Ended

Jun. 30, 2016

Investments [Abstract]

Cost And Fair Value Of Investments

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, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds	$	49,844	$	6,965	$	(9	)	$	56,800	30	%
International equity funds	33,935		1,201		(576		)	34,560		18	%
Core bond fund	26,882		627		—			27,509		15	%
High-yield bond fund	17,405		—		(848		)	16,557		9	%
Emerging market bond fund	16,145		—		(803		)	15,342		8	%
Combination debt/equity/other funds	9,003		3,274		—			12,277		6	%
Alternative investment fund	15,000		1,386		—			16,386		9	%
Real estate securities fund	9,500		—		—			9,500		5	%
Cash equivalents	248		—		—			248		<1%
Total	$	177,962	$	13,453	$	(2,236	)	$	189,179	100	%
As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	100	%

Fair Value And Gross Unrealized Losses Of Available-For-Sale Securities

June 30, 2016, and December 31, 2015.

	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, 2016:
Domestic equity funds	$	861	$	(9	)	$	—	$	—		$	861	$	(9	)
International equity funds	—		—			7,426		(576		)	7,426		(576		)
High-yield bond fund	—		—			16,557		(848		)	16,557		(848		)
Emerging market bond fund	—		—			15,342		(803		)	15,342		(803		)
Total	$	861	$	(9	)	$	39,325	$	(2,227	)	$	40,186	$	(2,236	)
As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

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Pension and Post-Retirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,921			10,753			1,393			1,422
Expected return on plan assets	(10,663		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			114			114
Actuarial loss (gain), net	5,146			8,053			(280		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,225			(210		)	338
Regulatory adjustment (a)	3,306			1,534			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,759		$	(696	)	$	1,351

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

 _______________

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

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Wolf Creek Pension and Post-Retirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Wolf Creek Pension And Post-Retirement Benefit Plans [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,921			10,753			1,393			1,422
Expected return on plan assets	(10,663		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			114			114
Actuarial loss (gain), net	5,146			8,053			(280		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,225			(210		)	338
Regulatory adjustment (a)	3,306			1,534			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,759		$	(696	)	$	1,351

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

 _______________

(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.

Wolf Creek [Member]

Wolf Creek Pension And Post-Retirement Benefit Plans [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	32		$	34
Interest cost	2,414			2,254			82			79
Expected return on plan assets	(2,430		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,089			1,482			(4		)	1
Net periodic cost before regulatory adjustment	2,774			3,388			110			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,257		$	3,084		$	110		$	114

 _______________

(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,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,374		$	3,797		$	64		$	69
Interest cost	4,828			4,508			163			157
Expected return on plan assets	(4,861		)	(4,522		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,178			2,965			(8		)	1
Net periodic cost before regulatory adjustment	5,547			6,776			219			227
Regulatory adjustment (a)	966			(608		)	—			—
Net periodic cost	$	6,513		$	6,168		$	219		$	227

 _______________

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

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2016

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	263,072	$	268,239
Regulatory assets (a)	9,758		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,230		138,097

_______________

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

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

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Description Of Business (Details)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of customers in Kansas	704,000

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Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Total	$ 299,465	$ 301,294
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	107,397	113,438
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 192,068	$ 187,856

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Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accounting Policies [Abstract]
Borrowed funds	$ (2,338)	$ (552)	$ (4,347)	$ (2,581)
Equity funds	2,783	90	5,247	2,041
Total	$ 5,121	$ 642	$ 9,594	$ 4,622
Average AFUDC rates	4.20%	1.20%	4.60%	3.20%

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Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accounting Policies [Abstract]
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	$ 156	$ 141	$ 290	$ 257
Net income allocated to common stock	$ 72,184	$ 63,569	$ 137,635	$ 114,433
Weighted Average Number of Shares Outstanding , Basic	142,033,842	135,939,197	142,013,344	134,177,136
RSUs	463,493	121,234	348,003	127,999
Forward sale agreements	0	1,351,721	0	2,024,468
Weighted average equivalent common shares outstanding - diluted	142,497,335	137,412,152	142,361,347	136,329,603
Earnings Per Share, Basic	$ 0.51	$ 0.47	$ 0.97	$ 0.85
Earnings Per Share, Diluted	$ 0.51	$ 0.46	$ 0.97	$ 0.84
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities		0	0	0

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Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Paid For (Received From)
Interest on financing activities	$ 70,697	$ 82,297
Income taxes, net of refunds	(77)	126
Noncash Investing and Financing Transactions
Property, plant and equipment	71,830	66,861
Issuance of common stock for reinvested dividends and compensation plans	4,941	5,532
Deconsolidation of VIE	(2,551)
Assets acquired through capital leases	392	1,102
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 4,150	$ 5,651

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Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 24.0
Kansas Corporation Commission [Member] | Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 7.0
Kansas Corporation Commission [Member] | Ad Valorem Tax [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 5.0
Kansas Corporation Commission [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Loss Contingency Accrual	4.0
Federal Energy Regulatory Commission [Member] | Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Loss Contingency Accrual	$ 8.1
Total Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Return on Equity, Percentage		10.30%
Base Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Return on Equity, Percentage		9.80%
Incentive Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Return on Equity, Percentage		0.50%

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Financial Instruments and Risk Management (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,430,000	$ 3,080,000
Fair Value	3,865,914	3,259,533
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	137,963	166,271
Fair Value	$ 154,097	$ 179,030

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Financial Instruments and Risk Management (Fair Value Of Assets And Liabilities) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Financial and Derivative Instruments and Trading Securities [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period	15 years
Nuclear decommissioning trust assets	$ 189,179	$ 184,057
Trading securities	34,093	33,888
Total assets measured at fair value	223,272	217,945
Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	248	87
Trading securities	156	159
Total assets measured at fair value	404	246
Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	157,101	150,658
Trading securities	33,937	33,729
Total assets measured at fair value	191,038	184,387
Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Total assets measured at fair value	0	0
Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	56,800	56,922
Trading securities	17,782	17,876
Domestic Equity [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Domestic Equity [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	50,856	50,872
Trading securities	17,782	17,876
Domestic Equity [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	34,560	33,595
Trading securities	4,220	4,430
International Equity [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
International Equity [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	34,560	33,595
Trading securities	4,220	4,430
International Equity [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	27,509	25,976
Trading securities	11,935	11,423
Core Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Core Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	27,509	25,976
Trading securities	11,935	11,423
Core Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
High-Yield Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	16,557	15,288
High-Yield Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
High-Yield Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	16,557	15,288
High-Yield Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Emerging Market Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	15,342	13,584
Emerging Market Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Emerging Market Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	15,342	13,584
Emerging Market Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	12,277
Combination Debt Equity And Other Fund [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0
Combination Debt Equity And Other Fund [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	12,277
Combination Debt Equity And Other Fund [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0
Combination Debt and Equity Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		11,343
Combination Debt and Equity Fund [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0
Combination Debt and Equity Fund [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		11,343
Combination Debt and Equity Fund [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0
Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	16,386	16,439
Alternative Funds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Alternative Funds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Alternative Funds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	9,500	10,823
Real Estate Securities [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Real Estate Securities [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Real Estate Securities [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Cash Equivalents [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	248	87
Trading securities	156	159
Cash Equivalents [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	248	87
Trading securities	156	159
Cash Equivalents [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Cash Equivalents [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Portion at Other than Fair Value Measurement [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	31,830	33,312
Trading securities	0	0
Total assets measured at fair value	31,830	33,312
Portion at Other than Fair Value Measurement [Member] | Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	5,944	6,050
Trading securities	0	0
Portion at Other than Fair Value Measurement [Member] | International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Portion at Other than Fair Value Measurement [Member] | Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Portion at Other than Fair Value Measurement [Member] | High-Yield Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Portion at Other than Fair Value Measurement [Member] | Emerging Market Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Portion at Other than Fair Value Measurement [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0
Portion at Other than Fair Value Measurement [Member] | Combination Debt and Equity Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0
Portion at Other than Fair Value Measurement [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	16,386	16,439
Portion at Other than Fair Value Measurement [Member] | Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	9,500	10,823
Portion at Other than Fair Value Measurement [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	$ 0	$ 0

XML

Financial Instruments and Risk Management (Investments In Financial Instruments) (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		$ 189,179	$ 184,057
Trading securities		34,093	33,888
Total		223,272	217,945
Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		31,830	33,312
Decommissioning Trust Assets [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		3,689	1,948
Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		56,800	56,922
Trading securities		17,782	17,876
Domestic Equity [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	[1]	5,944	6,050
Unfunded commitments		3,689	1,948
Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		16,386	16,439
Alternative Funds [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		16,386	16,439
Unfunded commitments		$ 0	0
Investment redemption frequency		Quarterly
Investment redemption length of settlement	[2]	65 days
Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		$ 9,500	10,823
Real Estate Securities [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		9,500	10,823
Unfunded commitments		$ 0	$ 0
Investment redemption frequency		Quarterly
Investment redemption length of settlement		65 days

[1] This investment is in four 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.

[2] There is a holdback on final redemptions.

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Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 34,093		$ 34,093		$ 33,888
Unrealized gains losses	600	$ 0	1,100	$ 700
Realized gains on available-for-sale-securities	$ (100)	$ 600	$ (1,400)	$ 500

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Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 600	$ 0	$ 1,100	$ 700
Trading securities	34,093		34,093		$ 33,888
Cost	177,962		177,962		177,048
Available-for-sale Securities, Gross Unrealized Gain	13,453		13,453		13,351
Available-for-sale Securities, Gross Unrealized Loss	(2,236)		(2,236)		(6,342)
Available-for-sale Securities	$ 189,179		$ 189,179		$ 184,057
Allocation	100.00%		100.00%		100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 17,782		$ 17,782		$ 17,876
Cost	49,844		49,844		49,488
Available-for-sale Securities, Gross Unrealized Gain	6,965		6,965		7,436
Available-for-sale Securities, Gross Unrealized Loss	(9)		(9)		(2)
Available-for-sale Securities	$ 56,800		$ 56,800		$ 56,922
Allocation	30.00%		30.00%		32.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 4,220		$ 4,220		$ 4,430
Cost	33,935		33,935		33,458
Available-for-sale Securities, Gross Unrealized Gain	1,201		1,201		1,372
Available-for-sale Securities, Gross Unrealized Loss	(576)		(576)		(1,235)
Available-for-sale Securities	$ 34,560		$ 34,560		$ 33,595
Allocation	18.00%		18.00%		18.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 11,935		$ 11,935		$ 11,423
Cost	26,882		26,882		26,397
Available-for-sale Securities, Gross Unrealized Gain	627		627		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(421)
Available-for-sale Securities	$ 27,509		$ 27,509		$ 25,976
Allocation	15.00%		15.00%		14.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,405		$ 17,405		$ 17,047
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(848)		(848)		(1,759)
Available-for-sale Securities	$ 16,557		$ 16,557		$ 15,288
Allocation	9.00%		9.00%		8.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 16,145		$ 16,145		$ 16,306
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(803)		(803)		(2,722)
Available-for-sale Securities	$ 15,342		$ 15,342		$ 13,584
Allocation	8.00%		8.00%		7.00%
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,003		$ 9,003
Available-for-sale Securities, Gross Unrealized Gain	3,274		3,274
Available-for-sale Securities, Gross Unrealized Loss	0		0
Available-for-sale Securities	$ 12,277		$ 12,277
Allocation	6.00%		6.00%
Combination Debt and Equity Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost					$ 8,239
Available-for-sale Securities, Gross Unrealized Gain					3,104
Available-for-sale Securities, Gross Unrealized Loss					0
Available-for-sale Securities					$ 11,343
Allocation					6.00%
Alternative Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 15,000		$ 15,000		$ 15,000
Available-for-sale Securities, Gross Unrealized Gain	1,386		1,386		1,439
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 16,386		$ 16,386		$ 16,439
Allocation	9.00%		9.00%		9.00%
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,500		$ 9,500		$ 11,026
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(203)
Available-for-sale Securities	$ 9,500		$ 9,500		$ 10,823
Allocation	5.00%		5.00%		6.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 156		$ 156		$ 159
Cost	248		248		87
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 248		$ 248		$ 87

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Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 600	$ 0	$ 1,100	$ 700
Fair Value, Less than 12 Months	861		861		$ 41,264
Gross Unrealized Losses, Less than 12 Months	(9)		(9)		(2,180)
Fair Value, 12 Months or Greater	39,325		39,325		31,792
Gross Unrealized Losses, 12 Months or Greater	(2,227)		(2,227)		(4,162)
Fair Value, Total	40,186		40,186		73,056
Gross Unrealized Losses, Total	(2,236)		(2,236)		(6,342)
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	861		861		0
Gross Unrealized Losses, Less than 12 Months	(9)		(9)		0
Fair Value, 12 Months or Greater	0		0		668
Gross Unrealized Losses, 12 Months or Greater	0		0		(2)
Fair Value, Total	861		861		668
Gross Unrealized Losses, Total	(9)		(9)		(2)
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	7,426		7,426		6,717
Gross Unrealized Losses, 12 Months or Greater	(576)		(576)		(1,235)
Fair Value, Total	7,426		7,426		6,717
Gross Unrealized Losses, Total	(576)		(576)		(1,235)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		25,976
Gross Unrealized Losses, Less than 12 Months	0		0		(421)
Fair Value, 12 Months or Greater	16,557		16,557		0
Gross Unrealized Losses, 12 Months or Greater	(848)		(848)		0
Fair Value, Total	16,557		16,557		25,976
Gross Unrealized Losses, Total	(848)		(848)		(421)
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months					15,288
Gross Unrealized Losses, Less than 12 Months					(1,759)
Fair Value, 12 Months or Greater					0
Gross Unrealized Losses, 12 Months or Greater					0
Fair Value, Total					15,288
Gross Unrealized Losses, Total					(1,759)
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	15,342		15,342		13,584
Gross Unrealized Losses, 12 Months or Greater	(803)		(803)		(2,722)
Fair Value, Total	15,342		15,342		13,584
Gross Unrealized Losses, Total	$ (803)		$ (803)		(2,722)
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months					0
Gross Unrealized Losses, Less than 12 Months					0
Fair Value, 12 Months or Greater					10,823
Gross Unrealized Losses, 12 Months or Greater					(203)
Fair Value, Total					10,823
Gross Unrealized Losses, Total					$ (203)

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Pending Merger Pending Merger (Narrative) - Great Plains Energy, Inc. Merger [Member] - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	May 29, 2016	Jun. 30, 2016
Business Combination [Line Items]
Business Combination, Share Conversion Ratio, Minimum	0.2709
Business Combination, Share Conversion Ratio, Maximum	0.3148
Business Combination, Share Conversion Ratio, Trading Period	20 days
Business Combination, Acquisition Related Costs		$ 7.8
Business Combination, Expected Acquisition Related Costs		$ 30.0
Cash Consideration per Share [Member]
Business Combination [Line Items]
Common stock right to convert to cash, price per share	$ 51.00
Total Consideration per Share [Member]
Business Combination [Line Items]
Common stock right to convert to cash, price per share	$ 60.00
Change in Westar Energy Board Recommendation [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	$ 280.0
Change in Westar Energy Board Recommendation [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	280.0
Westar Energy shareholder approval not obtained and enter into acquisition proposal within 12 months of termination [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	280.0
Failure to obtain regulatory approvals, paid to Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	380.0
Change in Great Plains Energy Board Recommendation, paid to Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	180.0
End date occurred, paid to Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	180.0
End date occurred, paid to Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	180.0
Shareholder meeting held, Great Plains Energy shareholder approval not obtained, paid to Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	$ 80.0

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Debt Financing (Narrative) (Details) - USD ($)	Jun. 20, 2016	Jun. 01, 2016	Feb. 16, 2016
KGE Member | Debt Instrument Five [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 50,000,000.00
Debt Instrument, Interest Rate, Stated Percentage		4.85%
Debt instrument, interest rate, refunded stated percentage		2.50%
Westar Energy [Member] | Debt Instrument Four [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 350,000,000.00
Debt Instrument, Interest Rate, Stated Percentage	3.00%
La Cygne Generating Station [Member] | KGE Member | Debt Instrument La Cygne [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 162,100,000
Debt Instrument, Interest Rate, Stated Percentage			5.647%
Debt instrument, interest rate, refunded stated percentage			2.398%

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Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Income tax expense	$ 40,542	$ 33,839	$ 79,165	$ 61,517
Effective income tax rate	35.00%	34.00%	35.00%	34.00%
Liability for unrecognized income tax benefits	$ 3,000		$ 3,000		$ 2,900
Interest on liability related to unrecognized income tax benefits	0		0		3,000
Penalties accrued for unrecognized income tax benefits	0		0		0
Accrual for taxes other than income taxes	$ 1,500		$ 1,500		$ 1,500

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Pension and Post-Retirement Benefit Plans (Net Periodic Costs And Pension Contributions) (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Components of Net Periodic Cost (Benefit):
Pension Contributions					$ 11,200		$ 19,400
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	$ 4,633		$ 5,348		9,297		10,696
Interest cost	10,921		10,753		21,880		21,507
Expected return on plan assets	(10,663)		(10,059)		(21,326)		(20,118)
Prior service costs	174		130		420		260
Actuarial loss, net	5,146		8,053		10,534		15,714
Net periodic cost before regulatory adjustment	10,211		14,225		20,805		28,059
Regulatory adjustment	3,306	[1]	1,534	[1]	6,613	[2]	3,332	[2]
Net periodic cost	13,517		15,759		27,418		31,391
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	271		361		542		722
Interest cost	1,393		1,422		2,786		2,845
Expected return on plan assets	(1,708)		(1,654)		(3,417)		(3,307)
Prior service costs	114		114		228		227
Actuarial loss, net	(280)		95		(560)		190
Net periodic cost before regulatory adjustment	(210)		338		(421)		677
Regulatory adjustment	(486)	[1]	1,013	[1]	(972)	[2]	2,026	[2]
Net periodic cost	$ (696)		$ 1,351		$ (1,393)		$ 2,703

[1] 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.

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

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Wolf Creek Pension and Post-Retirement Benefit Plans Wolf Creek Pension and Post-Retirement Benefit Plans (Net Periodic Costs and Pension Contributions) (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Components of Net Periodic Cost (Benefit):
Pension Contributions					$ 11,200		$ 19,400
KGE Member
Subsidiary Interest in Defined Benefit Plans					47.00%
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	$ 4,633		$ 5,348		$ 9,297		10,696
Interest cost	10,921		10,753		21,880		21,507
Expected return on plan assets	(10,663)		(10,059)		(21,326)		(20,118)
Prior service costs	174		130		420		260
Actuarial loss, net	5,146		8,053		10,534		15,714
Net periodic cost before regulatory adjustment	10,211		14,225		20,805		28,059
Regulatory adjustment	3,306	[1]	1,534	[1]	6,613	[2]	3,332	[2]
Net periodic cost	13,517		15,759		27,418		31,391
Pension Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	1,687		1,899		3,374		3,797
Interest cost	2,414		2,254		4,828		4,508
Expected return on plan assets	(2,430)		(2,261)		(4,861)		(4,522)
Prior service costs	14		14		28		28
Actuarial loss, net	1,089		1,482		2,178		2,965
Net periodic cost before regulatory adjustment	2,774		3,388		5,547		6,776
Regulatory adjustment	483	[3]	(304)	[3]	966	[4]	(608)	[4]
Net periodic cost	3,257		3,084		6,513		6,168
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	271		361		542		722
Interest cost	1,393		1,422		2,786		2,845
Expected return on plan assets	(1,708)		(1,654)		(3,417)		(3,307)
Prior service costs	114		114		228		227
Actuarial loss, net	(280)		95		(560)		190
Net periodic cost before regulatory adjustment	(210)		338		(421)		677
Regulatory adjustment	(486)	[1]	1,013	[1]	(972)	[2]	2,026	[2]
Net periodic cost	(696)		1,351		(1,393)		2,703
Post-Retirement Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	32		34		64		69
Interest cost	82		79		163		157
Expected return on plan assets	0		0		0		0
Prior service costs	0		0		0		0
Actuarial loss, net	(4)		1		(8)		1
Net periodic cost before regulatory adjustment	110		114		219		227
Regulatory adjustment	0	[3]	0	[3]	0	[4]	0	[4]
Net periodic cost	$ 110		$ 114		$ 219		$ 227

[1] 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.

[2] (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.

[3] (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.

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

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Variable Interest Entities (Narrative) (Details)	6 Months Ended
	Jun. 30, 2016 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Initial Consolidation, Gain (Loss)	$ 0
Jeffrey Energy Center [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	8.00%
Agreement expiration date	Jan. 01, 2019
La Cygne Generating Station [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	50.00%
Agreement expiration date	Sep. 01, 2029

XML

Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Property, plant and equipment, net		$ 8,800,698	$ 8,524,902
Current maturities of long-term debt		125,000	0
Accrued interest	[1]	41,969	71,426
Long-term debt, net		3,387,696	3,163,950
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Property, plant and equipment, net		263,072	268,239
Regulatory assets	[2]	9,758	9,088
Current maturities of long-term debt		26,842	28,309
Accrued interest	[1]	867	2,457
Long-term debt, net		$ 111,230	$ 138,097

[1] Included in accrued interest on our consolidated balance sheets.

[2] Included in long-term regulatory assets on our consolidated balance sheets.