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 September 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	141,786,012 shares
(Class)	(Outstanding at October 26, 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	42
PART II. Other Information
Item 1.	Legal Proceedings	42
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	44
Signature		45

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
2016 2Q Form 10-Q	Quarterly Report on Form 10-Q for the quarter ended June 30, 2016
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
HSR Act	Hart-Scott-Rodino Antitrust Improvements Act
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
OPC	Office of Public Counsel
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:

- 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, 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,” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (2016 2Q Form 10-Q), including in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Item 1A. Risk Factors,” 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 and the other reports we file from time to time with the SEC. 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 or the other reports we file from time to time with the SEC. 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
	September 30, 2016		December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,937	$	3,231
Accounts receivable, net of allowance for doubtful accounts of $4,175 and $5,294, respectively	322,386		258,286
Fuel inventory and supplies	290,080		301,294
Prepaid expenses	15,625		16,864
Regulatory assets	91,999		109,606
Other	38,276		27,860
Total Current Assets	762,303		717,141
PROPERTY, PLANT AND EQUIPMENT, NET	9,038,197		8,524,902
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	260,488		268,239
OTHER ASSETS:
Regulatory assets	731,859		751,312
Nuclear decommissioning trust	198,796		184,057
Other	252,775		260,015
Total Other Assets	1,183,430		1,195,384
TOTAL ASSETS	$	11,244,418	$	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	182,900		250,300
Accounts payable	228,046		220,969
Accrued dividends	52,822		49,829
Accrued taxes	119,938		83,773
Accrued interest	61,833		71,426
Regulatory liabilities	22,547		25,697
Other	97,100		106,632
Total Current Liabilities	917,028		836,935
LONG-TERM LIABILITIES:
Long-term debt, net	3,388,221		3,163,950
Long-term debt of variable interest entities, net	111,218		138,097
Deferred income taxes	1,737,359		1,591,430
Unamortized investment tax credits	207,595		209,763
Regulatory liabilities	243,754		267,114
Accrued employee benefits	445,442		462,304
Asset retirement obligations	283,941		275,285
Other	85,442		88,825
Total Long-Term Liabilities	6,502,972		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 141,743,883 shares and 141,353,426 shares, respective to each date	708,719		706,767
Paid-in capital	2,013,449		2,004,124
Retained earnings	1,078,799		945,830
Total Westar Energy, Inc. Shareholders’ Equity	3,800,967		3,656,721
Noncontrolling Interests	23,451		15,242
Total Equity	3,824,418		3,671,963
TOTAL LIABILITIES AND EQUITY	$	11,244,418	$	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 September 30,
	2016			2015
REVENUES	$	764,654		$	732,829
OPERATING EXPENSES:
Fuel and purchased power	155,673			163,943
SPP network transmission costs	57,939			57,487
Operating and maintenance	86,758			80,444
Depreciation and amortization	84,972			77,184
Selling, general and administrative	60,582			60,485
Taxes other than income tax	48,154			37,682
Total Operating Expenses	494,078			477,225
INCOME FROM OPERATIONS	270,576			255,604
OTHER INCOME (EXPENSE):
Investment earnings	2,619			314
Other income	13,353			637
Other expense	(5,887		)	(5,392		)
Total Other Income (Expense)	10,085			(4,441		)
Interest expense	40,897			44,306
INCOME BEFORE INCOME TAXES	239,764			206,857
Income tax expense	81,211			66,293
NET INCOME	158,553			140,564
Less: Net income attributable to noncontrolling interests	3,833			2,561
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	154,720		$	138,003
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.09		$	0.97
Diluted earnings per common share	$	1.08		$	0.97
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,090,706			141,622,697
Diluted	142,577,945			141,838,178
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)

	Nine Months Ended September 30,
	2016			2015
REVENUES	$	1,955,552		$	1,913,199
OPERATING EXPENSES:
Fuel and purchased power	374,361			459,504
SPP network transmission costs	173,925			171,651
Operating and maintenance	250,135			248,263
Depreciation and amortization	252,838			228,529
Selling, general and administrative	192,762			179,567
Taxes other than income tax	145,529			113,047
Total Operating Expenses	1,389,550			1,400,561
INCOME FROM OPERATIONS	566,002			512,638
OTHER INCOME (EXPENSE):
Investment earnings	6,916			4,427
Other income	26,212			18,572
Other expense	(14,338		)	(13,737		)
Total Other Income	18,790			9,262
Interest expense	121,011			134,120
INCOME BEFORE INCOME TAXES	463,781			387,780
Income tax expense	160,376			127,810
NET INCOME	303,405			259,970
Less: Net income attributable to noncontrolling interests	10,760			7,277
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	292,645		$	252,693
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	2.06		$	1.84
Diluted earnings per common share	$	2.05		$	1.82
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,039,320			136,686,263
Diluted	142,413,189			138,181,585
DIVIDENDS DECLARED PER COMMON SHARE	$	1.14		$	1.08

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)

	Nine Months Ended September 30,
	2016			2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	303,405		$	259,970
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	252,838			228,529
Amortization of nuclear fuel	22,518			18,528
Amortization of deferred regulatory gain from sale leaseback	(4,121		)	(4,121		)
Amortization of corporate-owned life insurance	13,779			15,309
Non-cash compensation	7,025			6,280
Net deferred income taxes and credits	160,429			126,602
Allowance for equity funds used during construction	(7,894		)	(2,034		)
Changes in working capital items:
Accounts receivable	(64,100		)	(21,437		)
Fuel inventory and supplies	11,680			(28,814		)
Prepaid expenses and other	(385		)	(22,742		)
Accounts payable	9,736			(4,979		)
Accrued taxes	40,711			51,867
Other current liabilities	(61,879		)	(66,000		)
Changes in other assets	(4,377		)	1,394
Changes in other liabilities	13,208			26,512
Cash Flows from Operating Activities	692,573			584,864
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(821,936		)	(486,515		)
Purchase of securities - trusts	(43,252		)	(20,752		)
Sale of securities - trusts	44,326			20,957
Investment in corporate-owned life insurance	(14,648		)	(14,845		)
Proceeds from investment in corporate-owned life insurance	24,242			65,962
Investment in affiliated company	(655		)	—
Other investing activities	(3,095		)	(781		)
Cash Flows used in Investing Activities	(815,018		)	(435,974		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(67,402		)	46,000
Proceeds from long-term debt	396,472			—
Proceeds from long-term debt of variable interest entities	162,048			—
Retirements of long-term debt	(50,000		)	(275,000		)
Retirements of long-term debt of variable interest entities	(190,357		)	(27,933		)
Repayment of capital leases	(2,327		)	(1,759		)
Borrowings against cash surrender value of corporate-owned life insurance	55,952			57,726
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(22,921		)	(63,894		)
Issuance of common stock	2,003			257,169
Distributions to shareholders of noncontrolling interests	(2,551		)	(1,076		)
Cash dividends paid	(152,787		)	(137,616		)
Other financing activities	(4,979		)	(3,234		)
Cash Flows from (used in) Financing Activities	123,151			(149,617		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	706			(727		)
CASH AND CASH EQUIVALENTS:
Beginning of period	3,231			4,556
End of period	$	3,937		$	3,829

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	—	—		—			252,693			7,277			259,970
Issuance of stock	9,229,357	46,147		211,022			—			—			257,169
Issuance of stock for compensation and reinvested dividends	352,078	1,760		6,248			—			—			8,008
Tax withholding related to stock compensation	—	—		(3,234		)	—			—			(3,234		)
Dividends declared on common stock ($1.08 per share)	—	—		—			(150,271		)	—			(150,271		)
Stock compensation expense	—	—		6,212			—			—			6,212
Tax benefit on stock compensation	—	—		1,231			—			—			1,231
Distributions to shareholders of noncontrolling interests	—	—		—			—			(1,076		)	(1,076		)
Other	—	—		(3,395		)	—			—			(3,395		)
Balance as of September 30, 2015	141,268,889	$	706,344	$	1,999,204		$	957,721		$	12,652		$	3,675,921
Balance as of December 31, 2015	141,353,426	$	706,767	$	2,004,124		$	945,830		$	15,242		$	3,671,963
Net income	—	—		—			292,645			10,760			303,405
Issuance of stock	40,441	202		1,801			—			—			2,003
Issuance of stock for compensation and reinvested dividends	350,016	1,750		5,565			—			—			7,315
Tax withholding related to stock compensation	—	—		(4,979		)	—			—			(4,979		)
Dividends declared on common stock ($1.14 per share)	—	—		—			(163,002		)	—			(163,002		)
Stock compensation expense	—	—		6,938			—			—			6,938
Distribution to shareholders of noncontrolling interests	—	—		—			—			(2,551		)	(2,551		)
Cumulative effect of accounting change - stock compensation	—	—		—			3,326			—			3,326
Balance as of September 30, 2016	141,743,883	$	708,719	$	2,013,449		$	1,078,799		$	23,451		$	3,824,418

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 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 nine months endedSeptember 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
	September 30, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	95,936	$	113,438
Supplies	194,144		187,856
Fuel inventory and supplies	$	290,080	$	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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,537		$	466		$	6,884		$	3,047
Equity funds	2,647			—			7,894			2,034
Total	$	5,184		$	466		$	14,778		$	5,081
Average AFUDC Rates	3.6		%	1.0		%	4.2		%	2.8		%

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	158,553	$	140,564	$	303,405	$	259,970
Less: Net income attributable to noncontrolling interests	3,833		2,561		10,760		7,277
Net income attributable to Westar Energy, Inc.	154,720		138,003		292,645		252,693
Less: Net income allocated to RSUs	325		304		605		563
Net income allocated to common stock	$	154,395	$	137,699	$	292,040	$	252,130
Weighted average equivalent common shares outstanding – basic	142,090,706		141,622,697		142,039,320		136,686,263
Effect of dilutive securities:
RSUs	487,239		215,481		373,869		197,373
Forward sale agreements	—		—		—		1,297,949
Weighted average equivalent common shares outstanding – diluted (a)	142,577,945		141,838,178		142,413,189		138,181,585
Earnings per common share, basic	$	1.09	$	0.97	$	2.06	$	1.84
Earnings per common share, diluted	$	1.08	$	0.97	$	2.05	$	1.82

_______________

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

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2016		2015
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	100,828	$	119,173
Interest on financing activities of VIEs	5,846		10,430
Income taxes, net of refunds	13,004		126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	94,007		60,155
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	7,315		8,008
Assets acquired through capital leases	1,310		2,246

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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.

Statement of Cash Flows

In August 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-15, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Among other clarifications, the guidance requires that cash proceeds received from the settlement of corporate-owned life insurance (COLI) policies be classified as cash inflows from investing activities and that cash payments for premiums on COLI policies may be classified as cash outflows for investing activities, operating activities or a combination of both. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Retrospective application is required. We are evaluating the guidance and do not expect it to have a material impact 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 nine months ended September 30, 2015, as $1.2 million higher than as previously reported, and cash flows used in financing activities as $1.2 million higher than as previously reported.

Leases

In February 2016, the FASB issued ASU No. 2016-02, which requires a lessee 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.

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Financial Instruments - Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, which requires financial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.

Financial Instruments - Net Asset Value

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, 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. Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC’s review of the joint application.  On September 27, 2016, the KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017.  On October 18, 2016, the KCC issued an order stating that, if the KCC staff or other interested parties believe that the joint application does not adequately address the standards by which public utility mergers should be evaluated in Kansas, KCC staff or other interested parties should file for relief, including the potential dismissal of the joint application.

In addition, the Public Service Commission of the State of Missouri (Missouri Commission) opened an investigation to determine whether it has jurisdiction over the merger and on August 3, 2016, issued its order closing the investigation. On October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the Missouri Commission seeking to have the Missouri Commission assert jurisdiction over the merger, and various parties have intervened in these complaints. On October 12, 2016, and on October 26, 2016, the Missouri Commission staff and the Office of the Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that Missouri Commission staff and the OPC would not file a complaint, or support another complaint, to assert that the Missouri Commission has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the Missouri Commission, and the Missouri Commission has not ruled on the related consumer complaints. If the Missouri Commission rejects the Stipulation and Agreement, or rules in favor of the consumer complaints, and determines that the Missouri Commission has jurisdiction over the merger, approval of the Missouri Commission also will be required in order to consummate 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 22, 2016, Wolf Creek filed a request with the NRC to approve an indirect transfer of control of Wolf Creek’s operating license.

On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSR Act on October 21, 2016.

Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete 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. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million.

The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of $180.0 million. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b)

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within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of $280.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three and nine months ended September 30, 2016, we incurred approximately $1.9 million and $9.8 million, respectively, of merger-related expenses, which are 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 expenses to coincide with the closing of the merger.

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

4. RATE MATTERS AND REGULATION

KCC Proceedings

In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $17.4 million. The KCC is required to issue an order on our request within 240 days of our filing, which is in June 2017.

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. We have begun refunding our previously recorded refund obligation and as of September 30, 2016, we have a remaining refund obligation of $2.7 million, which is included in current regulatory liabilities on our balance sheet.

FERC Proceedings

Our TFR that includes projected 2017 transmission capital expenditures and operating costs will become effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million.

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 and as of September 30, 2016, we have a remaining refund obligation of $4.6 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.

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• 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 September 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,850,563	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,962		150,877		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 September 30, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	53,950	$	—	$	5,171	$	59,121
International equity funds	—		37,357		—		—		37,357
Core bond fund	—		27,985		—		—		27,985
High-yield bond fund	—		17,686		—		—		17,686
Emerging markets bond fund	—		16,007		—		—		16,007
Combination debt/equity/other funds	—		12,816		—		—		12,816
Alternative investments fund	—		—		—		17,886		17,886
Real estate securities fund	—		—		—		9,737		9,737
Cash equivalents	201		—		—		—		201
Total Nuclear Decommissioning Trust	201		165,801		—		32,794		198,796
Trading Securities:
Domestic equity funds	—		18,004		—		—		18,004
International equity fund	—		4,482		—		—		4,482
Core bond fund	—		12,009		—		—		12,009
Total Trading Securities	—		34,495		—		—		34,495
Total Assets Measured at Fair Value	$	201	$	200,296	$	—	$	32,794	$	233,291
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 September 30, 2016				As of December 31, 2015				As of September 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,171	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	17,886		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,737		—		10,823		—		Quarterly	65 days
Total	$	32,794	$	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 September 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.5 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 and nine months endedSeptember 30, 2016, we recorded an unrealized gain of $1.0 million and $2.2 million, respectively, on assets still held. For the three and nine months endedSeptember 30, 2015, we recorded an unrealized loss of $1.5 million and $0.8 million, respectively, 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 September 30, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized no gains or losses during the three months endedSeptember 30, 2016, and a loss of$1.5 million during the nine months endedSeptember 30, 2016. We realized a loss of $0.5 million for the three months endedSeptember 30, 2015, and a loss of $1.0 million for the nine months endedSeptember 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 September 30, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2016:
Domestic equity funds	$	50,397	$	8,861	$	(137	)	$	59,121	30	%
International equity funds	34,199		3,262		(104		)	37,357		19	%
Core bond fund	27,280		705		—			27,985		14	%
High-yield bond fund	17,805		—		(119		)	17,686		9	%
Emerging market bond fund	16,242		—		(235		)	16,007		8	%
Combination debt/equity/other funds	9,088		3,728		—			12,816		6	%
Alternative investment fund	15,000		2,886		—			17,886		9	%
Real estate securities fund	9,500		237		—			9,737		5	%
Cash equivalents	201		—		—			201		<1%
Total	$	179,712	$	19,679	$	(595	)	$	198,796	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 ofSeptember 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 September 30, 2016:
Domestic equity funds	$	1,710	$	(137	)	$	—	$	—		$	1,710	$	(137	)
International equity funds	—		—			7,954		(104		)	7,954		(104		)
High-yield bond fund	—		—			17,686		(119		)	17,686		(119		)
Emerging market bond fund	—		—			16,007		(235		)	16,007		(235		)
Total	$	1,710	$	(137	)	$	41,647	$	(458	)	$	43,357	$	(595	)
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 redeemed and reissued $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 redemption and reissuance 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, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

8. TAXES

We recorded income tax expense of $81.2 million with an effective income tax rate of 34% for the three months endedSeptember 30, 2016, and income tax expense of $66.3 million with an effective income tax rate of 32% for the same period of 2015. We recorded income tax expense of $160.4 million with an effective income tax rate of 35% for the nine months endedSeptember 30, 2016, and income tax expense of $127.8 million with an effective income tax rate of 33% for the same period of 2015. The increase in the effective income tax rate for the three and nine months ended September 30, 2016, was due primarily to an increase in income before income taxes.

As of September 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $2.2 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 September 30, 2016, we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2015. We accrued no penalties at either September 30, 2016, or December 31, 2015.

As of September 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,922			10,753			1,392			1,422
Expected return on plan assets	(10,664		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			113			114
Actuarial loss (gain), net	5,146			8,033			(279		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,205			(211		)	338
Regulatory adjustment (a)	3,306			1,548			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,753		$	(697	)	$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	13,930		$	16,044		$	813		$	1,082
Interest cost	32,802			32,261			4,178			4,268
Expected return on plan assets	(31,990		)	(31,177		)	(5,125		)	(4,961		)
Amortization of unrecognized:
Prior service costs	594			390			341			342
Actuarial loss (gain), net	15,680			23,746			(839		)	284
Net periodic cost (benefit) before regulatory adjustment	31,016			41,264			(632		)	1,015
Regulatory adjustment (a)	9,919			4,880			(1,458		)	3,038
Net periodic cost (benefit)	$	40,935		$	46,144		$	(2,090	)	$	4,053

 _______________

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

During the nine months endedSeptember 30, 2016 and 2015, we contributed $15.7 million and $29.7 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	31		$	34
Interest cost	2,413			2,254			81			79
Expected return on plan assets	(2,431		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,090			1,482			(3		)	1
Net periodic cost before regulatory adjustment	2,773			3,388			109			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,256		$	3,084		$	109		$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,061		$	5,696		$	95		$	103
Interest cost	7,241			6,761			244			236
Expected return on plan assets	(7,292		)	(6,783		)	—			—
Amortization of unrecognized:
Prior service costs	42			43			—			—
Actuarial loss (gain), net	3,268			4,448			(11		)	2
Net periodic cost before regulatory adjustment	8,320			10,165			328			341
Regulatory adjustment (a)	1,449			(912		)	—			—
Net periodic cost	$	9,769		$	9,253		$	328		$	341

 _______________

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

During the nine months endedSeptember 30, 2016 and 2015, we funded $14.6 million and $4.5 million of Wolf Creek’s pension plan contributions, respectively.

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11. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Update Rule

In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxides (NOx) emissions in 22 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 final 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 final rule on our operations, however, based on our initial analysis we do not believe this rule will 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. In September 2016, the Kansas Department of Health and Environment (KDHE) recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will 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, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. 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, 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 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. Also in October 2015, the EPA 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. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en banc. Despite the stay, 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 cost to comply with the CPP 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 has determined sponsors are entitled to revenue credits for previously completed upgrades, and members will be obligated to pay for revenue credits attributable to these historical upgrades.

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As a result, we expect to pay the SPP in November 2016 approximately $7.0 million related to revenue credits attributable to historical upgrades. As of September 30, 2016, we have recorded a corresponding liability for our obligation to the SPP for the period of March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.

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.

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 cooperated with the DOJ in its investigation, and on October 21, 2016, we were notified that the DOJ closed the investigation.

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.

Pending Merger

Following the announcement of the merger agreement, two putative class action complaints (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas.

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The consolidated putative class action complaint, filed on July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, 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. It also asserts that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that (i) the merger consideration deprives our shareholders of fair consideration for their shares, (ii) the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, (iii) the disclosures are misleading and/or omit material information necessary for Westar Energy shareholders to make an informed decision whether to vote in favor of the proposed transaction and (iv) if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the merger, (ii) rescission of the merger agreement or rescissory damages, (iii) a directive to 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 (iv) an award for costs and disbursements, including attorneys’ fees and experts’ fees.

The putative derivative complaint, filed on July 5, 2016 and as amended on August 25, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action 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 a 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. It also asserts 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, and that the disclosures are false or misleading due to the omission of certain information. The complaint seeks, among other remedies, (i) a direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, (ii) a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the merger agreement, (iv) the imposition of 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, (v) award for costs, including attorneys’ fees and experts’ fees, and (vi) the imposition of an injunction against the defendants and others from consummating the merger on the terms proposed. The defendants have moved for dismissal of this complaint.

On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases. In exchange, the parties in the putative derivative complaint agreed that Westar would make supplemental disclosures to the shareholders, which disclosures were made in a Form 8-K filed on September 21, 2016, and the parties in the consolidated putative class action agreed that Westar Energy would (i) make the disclosures in the Form 8-K filed on September 21, 2016, and (ii) grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in the Westar Energy sale process. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety.

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.

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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 redemption and reissuance 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
	September 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	260,488	$	268,239
Regulatory assets (a)	10,053		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	19		2,457
Long-term debt of variable interest entities, net	111,218		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 nine months endedSeptember 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 Notes 3, 11 and 12 of the Notes to Condensed Consolidated Financial Statements, “Pending Merger,” “Commitments and Contingencies” and “Legal Proceedings,” respectively, and Item “1A. Risk Factors.”

Earnings Per Share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016		2015		Change		2016		2015		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	154,720	$	138,003	$	16,717	$	292,645	$	252,693	$	39,952
Earnings per common share, basic	1.09		0.97		0.12		2.06		1.84		0.22

Net income and basic EPS increased for the three and nine months ended September 30, 2016, compared to the same periods in 2015, due primarily to higher retail prices and to our having recorded more COLI proceeds. For the three and nine months ended September 30, 2016, we recorded $10.4 million and $3.1 million, respectively, more in COLI proceeds. Offsetting these increases were merger-related expenses and our having recorded a $7.0 million liability related to SPP revenue crediting. See the discussion under “—Operating Results” below and Note 11 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies - SPP Revenue Crediting,” 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);

• 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 September 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 Nine Months EndedSeptember 30, 2016, Compared to Three and Nine Months EndedSeptember 30, 2015

Below we discuss our operating results for the three and nine months endedSeptember 30, 2016, compared to the results for the three and nine months endedSeptember 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 September 30,											Nine Months Ended September 30,
	2016			2015			Change			% Change		2016			2015			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	282,272		$	255,804		$	26,468		10.3		$	664,400		$	610,775		$	53,625		8.8
Commercial	218,377			213,461			4,916			2.3		572,247			550,761			21,486			3.9
Industrial	106,021			105,307			714			0.7		314,723			304,937			9,786			3.2
Other retail	7,883			1,620			6,263			386.6		(23,002		)	(5,503		)	(17,499		)	(318.0	)
Total Retail Revenues	614,553			576,192			38,361			6.7		1,528,368			1,460,970			67,398			4.6
Wholesale	86,421			87,918			(1,497		)	(1.7	)	220,520			249,502			(28,982		)	(11.6	)
Transmission	58,462			61,190			(2,728		)	(4.5	)	188,996			181,070			7,926			4.4
Other	5,218			7,529			(2,311		)	(30.7	)	17,668			21,657			(3,989		)	(18.4	)
Total Revenues	764,654			732,829			31,825			4.3		1,955,552			1,913,199			42,353			2.2
OPERATING EXPENSES:
Fuel and purchased power	155,673			163,943			(8,270		)	(5.0	)	374,361			459,504			(85,143		)	(18.5	)
SPP network transmission costs	57,939			57,487			452			0.8		173,925			171,651			2,274			1.3
Operating and maintenance	86,758			80,444			6,314			7.8		250,135			248,263			1,872			0.8
Depreciation and amortization	84,972			77,184			7,788			10.1		252,838			228,529			24,309			10.6
Selling, general and administrative	60,582			60,485			97			0.2		192,762			179,567			13,195			7.3
Taxes other than income tax	48,154			37,682			10,472			27.8		145,529			113,047			32,482			28.7
Total Operating Expenses	494,078			477,225			16,853			3.5		1,389,550			1,400,561			(11,011		)	(0.8	)
INCOME FROM OPERATIONS	270,576			255,604			14,972			5.9		566,002			512,638			53,364			10.4
OTHER INCOME (EXPENSE):
Investment earnings	2,619			314			2,305			734.1		6,916			4,427			2,489			56.2
Other income	13,353			637			12,716			(a)		26,212			18,572			7,640			41.1
Other expense	(5,887		)	(5,392		)	(495		)	(9.2	)	(14,338		)	(13,737		)	(601		)	(4.4	)
Total Other Income (Expense)	10,085			(4,441		)	14,526			327.1		18,790			9,262			9,528			102.9
Interest expense	40,897			44,306			(3,409		)	(7.7	)	121,011			134,120			(13,109		)	(9.8	)
INCOME BEFORE INCOME TAXES	239,764			206,857			32,907			15.9		463,781			387,780			76,001			19.6
Income tax expense	81,211			66,293			14,918			22.5		160,376			127,810			32,566			25.5
NET INCOME	158,553			140,564			17,989			12.8		303,405			259,970			43,435			16.7
Less: Net income attributable to noncontrolling interests	3,833			2,561			1,272			49.7		10,760			7,277			3,483			47.9
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	154,720		$	138,003		$	16,717		12.1		$	292,645		$	252,693		$	39,952		15.8
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.09		$	0.97		$	0.12		12.4		$	2.06		$	1.84		$	0.22		12.0
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.08		$	0.97		$	0.11		11.3		$	2.05		$	1.82		$	0.23		12.6

_______________

(a) Change greater than 1,000%

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Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP 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 nine months endedSeptember 30, 2016 and 2015.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2016		2015		Change			% Change		2016		2015		Change			% Change
	(Dollars In Thousands)
Revenues	$	764,654	$	732,829	$	31,825		4.3		$	1,955,552	$	1,913,199	$	42,353		2.2
Less: Fuel and purchased power expense	155,673		163,943		(8,270		)	(5.0	)	374,361		459,504		(85,143		)	(18.5	)
SPP network transmission costs	57,939		57,487		452			0.8		173,925		171,651		2,274			1.3
Gross Margin	$	551,042	$	511,399	$	39,643		7.8		$	1,407,266	$	1,282,044	$	125,222		9.8

The following table reflects changes in electricity sales for the three and nine months endedSeptember 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 September 30,						Nine Months Ended September 30,
	2016	2015	Change		% Change		2016	2015	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	2,209	2,168	41		1.9		5,097	5,108	(11	)	(0.2	)
Commercial	2,230	2,221	9		0.4		5,763	5,787	(24	)	(0.4	)
Industrial	1,444	1,463	(19	)	(1.3	)	4,137	4,195	(58	)	(1.4	)
Other retail	19	21	(2	)	(9.5	)	60	63	(3	)	(4.8	)
Total Retail	5,902	5,873	29		0.5		15,057	15,153	(96	)	(0.6	)
Wholesale	2,389	2,200	189		8.6		5,960	6,817	(857	)	(12.6	)
Total	8,291	8,073	218		2.7		21,017	21,970	(953	)	(4.3	)

Gross margin increased for the three and nine months ended September 30, 2016, compared to the same period in 2015, due primarily to higher retail prices, which increased approximately 6% and 5%, respectively. Partially offsetting this increase for both periods was our having recorded a $7.0 million liability to the SPP. See Note 11 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies - SPP Revenue Crediting,” for additional information on this liability. Also, during the nine months ended September 30, 2016, industrial sales were lower due to a few of our larger chemical and oil pipeline customers who experienced weaker global demand for their products. During the three and nine months ended September 30, 2016, compared to the same period in 2015, there were approximately 7% and 8%, respectively, more cooling degree days. The increase in cooling degree days during the nine months ended September 30, 2016, was offset by milder winter weather during the beginning of the year, which resulted in approximately 12% fewer heating degree days.

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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 nine months endedSeptember 30, 2016 and 2015.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars In Thousands)
Gross margin	$	551,042	$	511,399	$	39,643	7.8	$	1,407,266	$	1,282,044	$	125,222	9.8
Less: Operating and maintenance expense	86,758		80,444		6,314		7.8	250,135		248,263		1,872		0.8
Depreciation and amortization expense	84,972		77,184		7,788		10.1	252,838		228,529		24,309		10.6
Selling, general and administrative expense	60,582		60,485		97		0.2	192,762		179,567		13,195		7.3
Taxes other than income tax	48,154		37,682		10,472		27.8	145,529		113,047		32,482		28.7
Income from operations	$	270,576	$	255,604	$	14,972	5.9	$	566,002	$	512,638	$	53,364	10.4

Operating Expenses and Other Income and Expense Items

	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	86,758	$	80,444	$	6,314	7.8	$	250,135	$	248,263	$	1,872	0.8

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

• higher distribution operating and maintenance costs of $3.9 million due partially to improving long-term reliability in 2016; and

• higher operating and maintenance costs at our coal fired plants of $2.4 million, due primarily to scheduled outages; however,

• partially offsetting these increases was a $4.2 million decrease in operating and maintenance costs related to retiring three generating units in late 2015.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	84,972	$	77,184	$	7,788	10.1	$	252,838	$	228,529	$	24,309	10.6

Depreciation and amortization expense increased during the three and nine months endedSeptember 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 September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	60,582	$	60,485	$	97	0.2	$	192,762	$	179,567	$	13,195	7.3

Selling, general and administrative expense increased during nine months ended September 30, 2016, compared to the same period in 2015, due primarily to:

• incurring $9.8 million of merger-related expenses in 2016; and

• an increase of $4.2 million in outside services related principally to technology services; however,

• partially offsetting these increases was lower employee benefit costs of $4.5 million.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	48,154	$	37,682	$	10,472	27.8	$	145,529	$	113,047	$	32,482	28.7

Taxes other than income tax increased for the three and nine months endedSeptember 30, 2016, compared to the same periods in 2015, due primarily to increases of $10.6 million and $33.4 million, respectively, in property tax expense. These increases are mostly offset in retail revenues.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Other income	$	13,353	$	637	$	12,716	(a)	$	26,212	$	18,572	$	7,640	41.1
(a) Change greater than 1,000%

Other income increased for the three and nine months endedSeptember 30, 2016, compared to the same periods in 2015, due principally to increases in equity AFUDC of $2.7 million and $5.9 million, respectively, and to our having recorded more in COLI benefits of $10.4 million and $3.1 million, respectively.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2016		2015		Change			% Change		2016		2015		Change			% Change
	(Dollars in Thousands)
Interest expense	$	40,897	$	44,306	$	(3,409	)	(7.7	)	$	121,011	$	134,120	$	(13,109	)	(9.8	)

Interest expense decreased for the three months endedSeptember 30, 2016, compared to the same period in 2015, due primarily to a $2.1 million increase in debt AFUDC and a $1.5 million decrease in interest expense on long-term debt of VIEs due to refinancing long-term debt of the La Cygne VIE.

Interest expense decreased for the nine months endedSeptember 30, 2016, compared to the same period in 2015, due primarily to a $6.5 million decrease in interest expense on long-term debt due to refinancing long-term debt, a $4.1 million decrease in interest on long-term debt of VIEs due to refinancing long-term debt of the La Cygne VIE and a $3.8 million increase in debt AFUDC.

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	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change		% Change	2016		2015		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	81,211	$	66,293	$	14,918	22.5	$	160,376	$	127,810	$	32,566	25.5

Income tax expense increased for the three and nine months endedSeptember 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 September 30, 2016, compared to December 31, 2015.

	As of		As of
	September 30, 2016		December 31, 2015		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	823,858	$	860,918	$	(37,060	)	(4.3	)
Regulatory liabilities	266,301		292,811		(26,510		)	(9.1	)
Net regulatory assets	$	557,557	$	568,107	$	(10,550	)	(1.9	)

Total regulatory assets decreased due primarily to the following items:

• a $26.4 million decrease in deferred employee benefit costs;

• a $16.5 million decrease in amounts deferred for property taxes;

• a $13.4 million decrease in amounts due from customers for future income taxes; and

• a $4.8 million decrease in amounts deferred for Wolf Creek refueling and maintenance outages; however,

• partially offsetting these decreases was a $17.6 million increase in amounts to be collected from our customers for the deferred cost of fuel and purchased power; and

• a $5.6 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 primarily to the following items:

• spending $31.9 million more than collected for the cost to remove retired plant assets; and

• a $12.7 million decrease in our refund obligations related to amounts we have collected from our customers in excess of our actual cost of fuel and purchased power; however,

• partially offsetting these decreases was a $5.7 million increase in amounts recognized in setting our prices in excess of actual pension and post-retirement expense; and

• a $4.6 million increase for the FERC settlement refund obligation and a $2.7 million increase for the KCC approved refund obligation related to the reduced ROE in our TFR. See Note 4 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” for a discussion of these refund obligations.

	As of		As of
	September 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	9,038,197	$	8,524,902	$	513,295	6.0

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 to improve long-term reliability.

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	As of		As of
	September 30, 2016		December 31, 2015		Change			% Change
	(Dollars in Thousands)
Short-term debt	$	182,900	$	250,300	$	(67,400	)	(26.9	)

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.”

	As of		As of
	September 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Current maturities of long-term debt	$	125,000	$	—	$	125,000	—
Long-term debt, net	3,388,221		3,163,950		224,271		7.1
Total long-term debt	$	3,513,221	$	3,163,950	$	349,271	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
	September 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	111,218		138,097		(26,879		)	(19.5	)
Total long-term debt of variable interest entities	$	138,060	$	166,406	$	(28,346	)	(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
	September 30, 2016		December 31, 2015		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,737,359	$	1,591,430	$	145,929	9.2

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

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Short-Term Borrowings

Westar Energy 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 October 26, 2016, Westar Energy had $185.9 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 October 26, 2016, no amounts were borrowed and $12.6 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 redeemed and reissued $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 redemption and reissuance 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 September 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.

39

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.

As of October 26, 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

	Nine Months Ended September 30,
	2016			2015			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	692,573		$	584,864		$	107,709		18.4
Investing activities	(815,018		)	(435,974		)	(379,044		)	(86.9	)
Financing activities	123,151			(149,617		)	272,768			182.3
Net change in cash and cash equivalents	$	706		$	(727	)	$	1,433		(197.1	)

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having paid $98.5 million less for coal and natural gas, receiving $74.3 million more from retail customers, paying $26.7 million in 2015 for the Wolf Creek refueling outage and paying $22.9 million less for interest. Partially offsetting these increases was our having received $36.2 million less for wholesale power salesand transmission services, paying $12.9 million more in income tax payments and receiving $7.3 million less in COLI proceeds.

Cash Flows used in Investing Activities

Cash flows used in investing activities increased due primarily to our having invested $335.4 million more in additions to property, plant and equipment primarily related to the construction of Western Plains Wind Farm and our having received $41.7 million less from our investment in COLI.

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Cash Flows from Financing Activities

Cash flows from financing activities increased due principally to our having issued $396.5 million more in long-term debt, redeeming $225.0 million less in long-term debt, issuing $162.0 million more in long-term debt of VIEs and repaying $41.0 million less for borrowings against the cash surrender value of COLI. Partially offsetting these increases was our having issued $255.2 million less in common stock, redeeming $162.4 million more in long-term debt of VIEs, issuing $113.4 million less in commercial paper, and paying $15.2 million more in dividends

Pension Contribution

During the nine months endedSeptember 30, 2016, we contributed $15.7 million to the Westar Energy pension trust. We funded $14.6 million of Wolf Creek’s pension plan contributions during the same period.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2015, through September 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 September 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

Corporate-Owned Life Insurance

In October 2016, we recorded an additional $4.7 million in COLI benefits, resulting in a total of $21.4 million year-to-date ended October 26, 2016.

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 September 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.

41

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 endedSeptember 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.

ITEM 1A. RISK FACTORS

     Our 2015 Form 10-K, as supplemented by our 2016 2Q Form 10-Q, contains descriptions of risk factors relating to us, as required by Item 503(c) of Regulation S-K. The first, second and eighth risk factors included in the 2016 2Q Form 10-Q are replaced with the respective risk factors described below. Except as indicated below, or as otherwise described in filings we make from time to time with the SEC, there were no material changes in our risk factors from December 31, 2015, through September 30, 2016.

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) 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), (ii) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the merger, (iii) the effectiveness of the Great Plains Energy registration statement on Form S-4 that was filed with the SEC, (iv) the approval of the listing of the Great Plains Energy common stock to be issued in the merger, (v) the absence of any material adverse effect with respect to us and our subsidiaries and (vi) 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.

42

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 HSR 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).

On June 28, 2016, we and Great Plains Energy filed a joint application with the KCC requesting approval of the merger.  Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC’s review of the joint application.  On September 27, 2016, KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017.  On October 18, 2016, the KCC issued an order stating that, if the KCC staff or other interested parties believe that the joint application does not adequately address the standards by which public utility mergers should be evaluated in Kansas, KCC staff or other interested parties should file for relief, including potential dismissal of the joint application.  We cannot predict if the KCC staff or another interested party will file for relief, or if so how the KCC will rule.  If the joint application is dismissed, we and Great Plains Energy would need to re-file the joint application and the timeframe for a decision by the KCC would restart.

In addition, the Missouri Commission opened an investigation to determine whether it has jurisdiction over the merger and on August 3, 2016, issued its order closing the investigation. On October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the Missouri Commission seeking to have the Missouri Commission assert jurisdiction over the merger, and various parties have intervened in these complaints. On October 12, 2016, and on October 26, 2016, the Missouri Commission staff and the OPC, respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that Missouri Commission staff and the OPC would not file a complaint, or support another complaint, to assert that the Missouri Commission has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the Missouri Commission, and the Missouri Commission has not ruled on the related consumer complaints. If the Missouri Commission rejects the Stipulation and Agreement, or rules in favor of the consumer complaints, and determines that 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.

For additional information on the status of various approvals in connection with the pending merger, see Notes 3 and 11 of the Notes to Consolidated Financial Statements, “Pending Merger” and “Commitments and Contingencies,” respectively.

Pending litigation against us and Great Plains Energy 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 putative class action 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 putative derivative 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 sought to enjoin the merger and rescind the merger agreement, in addition to certain unspecified damages and reimbursement of costs. On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety. The outcome of 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.

43

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.

ITEM 6. EXHIBITS

31(a)	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 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 September 30, 2016
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 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

44

SIGNATURE

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

		WESTAR ENERGY, INC.
Date:	November 1, 2016	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

45

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 September 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:	November 1, 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 September 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:	November 1, 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 September 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:	November 1, 2016	By:	/s/    Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer

Date:	November 1, 2016	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2016	Oct. 26, 2016
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
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		141,786,012

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents		$ 3,937	$ 3,231
Accounts receivable, net of allowance for doubtful accounts of $4,503 and $4,596, respectively		322,386	258,286
Fuel inventory and supplies		290,080	301,294
Prepaid expenses		15,625	16,864
Regulatory assets		91,999	109,606
Other		38,276	27,860
Total Current Assets		762,303	717,141
Property, plant and equipment, net		9,038,197	8,524,902
OTHER ASSETS:
Regulatory assets		731,859	751,312
Nuclear decommissioning trust		198,796	184,057
Other		252,775	260,015
Total Other Assets		1,183,430	1,195,384
TOTAL ASSETS		11,244,418	10,705,666
CURRENT LIABILITIES:
Current maturities of long-term debt		125,000	0
Short-term debt		182,900	250,300
Accounts payable		228,046	220,969
Accrued dividends		52,822	49,829
Accrued taxes		119,938	83,773
Accrued interest	[1]	61,833	71,426
Regulatory liabilities		22,547	25,697
Other		97,100	106,632
Total Current Liabilities		917,028	836,935
LONG-TERM LIABILITIES:
Long-term debt, net		3,388,221	3,163,950
Deferred income taxes		1,737,359	1,591,430
Unamortized investment tax credits		207,595	209,763
Regulatory liabilities		243,754	267,114
Accrued employee benefits		445,442	462,304
Asset retirement obligations		283,941	275,285
Other		85,442	88,825
Total Long-Term Liabilities		6,502,972	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		708,719	706,767
Paid-in capital		2,013,449	2,004,124
Retained earnings		1,078,799	945,830
Total Westar Energy, Inc. Shareholders' Equity		3,800,967	3,656,721
Noncontrolling Interests		23,451	15,242
Total Equity		3,824,418	3,671,963
TOTAL LIABILITIES AND EQUITY		11,244,418	10,705,666
Variable Interest Entity [Member]
CURRENT ASSETS:
Property, plant and equipment, net		260,488	268,239
CURRENT LIABILITIES:
Current maturities of long-term debt		26,842	28,309
Accrued interest	[1]	19	2,457
LONG-TERM LIABILITIES:
Long-term debt, net		$ 111,218	$ 138,097

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

XML

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Allowance for doubtful accounts	$ 4,175	$ 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	141,743,883	141,353,426
Common stock, shares outstanding	141,743,883	141,353,426

XML

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES	$ 764,654	$ 732,829	$ 1,955,552	$ 1,913,199
OPERATING EXPENSES:
Fuel and purchased power	155,673	163,943	374,361	459,504
Network Transmission Cost	57,939	57,487	173,925	171,651
Operating and maintenance	86,758	80,444	250,135	248,263
Depreciation and amortization	84,972	77,184	252,838	228,529
Selling, general and administrative	60,582	60,485	192,762	179,567
Taxes, Miscellaneous	48,154	37,682	145,529	113,047
Total Operating Expenses	494,078	477,225	1,389,550	1,400,561
INCOME FROM OPERATIONS	270,576	255,604	566,002	512,638
OTHER INCOME (EXPENSE):
Investment earnings (losses)	2,619	314	6,916	4,427
Other income	13,353	637	26,212	18,572
Other expense	(5,887)	(5,392)	(14,338)	(13,737)
Total Other Income	10,085	(4,441)	18,790	9,262
Interest expense	40,897	44,306	121,011	134,120
INCOME BEFORE INCOME TAXES	239,764	206,857	463,781	387,780
Income tax expense	81,211	66,293	160,376	127,810
NET INCOME	158,553	140,564	303,405	259,970
Less: Net income attributable to noncontrolling interests	3,833	2,561	10,760	7,277
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 154,720	$ 138,003	$ 292,645	$ 252,693
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 1.09	$ 0.97	$ 2.06	$ 1.84
Earnings Per Share, Diluted	$ 1.08	$ 0.97	$ 2.05	$ 1.82
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,090,706	141,622,697	142,039,320	136,686,263
Weighted Average Number of Shares Outstanding, Diluted	142,577,945	141,838,178	142,413,189	138,181,585
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.38	$ 0.36	$ 1.14	$ 1.08

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 303,405	$ 259,970
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	252,838	228,529
Amortization of nuclear fuel	22,518	18,528
Amortization of deferred regulatory gain from sale leaseback	(4,121)	(4,121)
Amortization of corporate-owned life insurance	13,779	15,309
Non-cash compensation	7,025	6,280
Net deferred income taxes and credits	160,429	126,602
Allowance for equity funds used during construction	(7,894)	(2,034)
Changes in working capital items:
Accounts receivable	(64,100)	(21,437)
Fuel inventory and supplies	11,680	(28,814)
Prepaid expenses and other	(385)	(22,742)
Accounts payable	9,736	(4,979)
Accrued taxes	40,711	51,867
Other current liabilities	(61,879)	(66,000)
Changes in other assets	(4,377)	1,394
Changes in other liabilities	13,208	26,512
Cash Flows from Operating Activities	692,573	584,864
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(821,936)	(486,515)
Purchase of securities - trusts	(43,252)	(20,752)
Sale of securities - trusts	44,326	20,957
Investment in corporate-owned life insurance	14,648	14,845
Proceeds from investment in corporate-owned life insurance	24,242	65,962
Investment in affiliated company	(655)	0
Other investing activities	(3,095)	(781)
Cash Flows used in Investing Activities	(815,018)	(435,974)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(67,402)	46,000
Proceeds from long-term debt	(396,472)	0
Retirements of long-term debt	(50,000)	(275,000)
Repayment of capital leases	(2,327)	(1,759)
Borrowings against cash surrender value of corporate-owned life insurance	55,952	57,726
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(22,921)	(63,894)
Stock-based compensation excess tax benefits	1,200	1,231
Issuance of common stock	2,003	257,169
Distributions to shareholders of noncontrolling interests	(2,551)	(1,076)
Cash dividends paid	(152,787)	(137,616)
Other financing activities	(4,979)	(3,234)
Cash Flows from Financing Activities	123,151	(149,617)
NET CHANGE IN CASH AND CASH EQUIVALENTS	706	(727)
CASH AND CASH EQUIVALENTS:
Beginning of period	3,231	4,556
End of period	3,937	3,829
Variable Interest Entity [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from long-term debt	(162,048)	0
Retirements of long-term debt	$ (190,357)	$ (27,933)

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	259,970	$ 0	0	252,693	7,277
Issuance of stock	257,169	$ 46,147	211,022	0	0
Issuance of stock (shares)		9,229,357
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		352,078
Issuance Of Stock For Compensation And Reinvested Dividends	8,008	$ 1,760	6,248
Tax withholding related to stock compensation	(3,234)		(3,234)
Dividends on common stock	(150,271)	0	0	(150,271)	0
Stock compensation expense	6,212		6,212
Tax Benefit on stock compensation	1,231	0	1,231	0	0
Distributions to shareholders of noncontrolling interests	(1,076)				(1,076)
Ending Balance at Sep. 30, 2015	3,675,921	$ 706,344	1,999,204	957,721	12,652
Ending Balance (Shares) at Sep. 30, 2015		141,268,889
Stockholders' Equity, Other	(3,395)		(3,395)		0
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	303,405	$ 0	0	292,645	10,760
Issuance of stock	2,003	$ 202	1,801	0	0
Issuance of stock (shares)		40,441
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		350,016
Issuance Of Stock For Compensation And Reinvested Dividends	7,315	$ 1,750	5,565
Tax withholding related to stock compensation	(4,979)		(4,979)
Dividends on common stock	(163,002)	0	0	(163,002)	0
Stock compensation expense	6,938		6,938
Tax Benefit on stock compensation	1,200
Deconsolidation of variable interest entity	(2,551)				(2,551)
Distributions to shareholders of noncontrolling interests	(2,551)
Ending Balance at Sep. 30, 2016	3,824,418	$ 708,719	$ 2,013,449	1,078,799	$ 23,451
Ending Balance (Shares) at Sep. 30, 2016		141,743,883
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.38	$ 0.36	$ 1.14	$ 1.08

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Description Of Business

9 Months Ended

Sep. 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

9 Months Ended

Sep. 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 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 nine months endedSeptember 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
	September 30, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	95,936	$	113,438
Supplies	194,144		187,856
Fuel inventory and supplies	$	290,080	$	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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,537		$	466		$	6,884		$	3,047
Equity funds	2,647			—			7,894			2,034
Total	$	5,184		$	466		$	14,778		$	5,081
Average AFUDC Rates	3.6		%	1.0		%	4.2		%	2.8		%

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	158,553	$	140,564	$	303,405	$	259,970
Less: Net income attributable to noncontrolling interests	3,833		2,561		10,760		7,277
Net income attributable to Westar Energy, Inc.	154,720		138,003		292,645		252,693
Less: Net income allocated to RSUs	325		304		605		563
Net income allocated to common stock	$	154,395	$	137,699	$	292,040	$	252,130
Weighted average equivalent common shares outstanding – basic	142,090,706		141,622,697		142,039,320		136,686,263
Effect of dilutive securities:
RSUs	487,239		215,481		373,869		197,373
Forward sale agreements	—		—		—		1,297,949
Weighted average equivalent common shares outstanding – diluted (a)	142,577,945		141,838,178		142,413,189		138,181,585
Earnings per common share, basic	$	1.09	$	0.97	$	2.06	$	1.84
Earnings per common share, diluted	$	1.08	$	0.97	$	2.05	$	1.82

_______________

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

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2016		2015
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	100,828	$	119,173
Interest on financing activities of VIEs	5,846		10,430
Income taxes, net of refunds	13,004		126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	94,007		60,155
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	7,315		8,008
Assets acquired through capital leases	1,310		2,246

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.

Statement of Cash Flows

In August 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-15, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Among other clarifications, the guidance requires that cash proceeds received from the settlement of corporate-owned life insurance (COLI) policies be classified as cash inflows from investing activities and that cash payments for premiums on COLI policies may be classified as cash outflows for investing activities, operating activities or a combination of both. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Retrospective application is required. We are evaluating the guidance and do not expect it to have a material impact 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 nine months ended September 30, 2015, as $1.2 million higher than as previously reported, and cash flows used in financing activities as $1.2 million higher than as previously reported.

Leases

In February 2016, the FASB issued ASU No. 2016-02, which requires a lessee 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.

Financial Instruments - Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, which requires financial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.

Financial Instruments - Net Asset Value

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

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Rate Matters And Regulation

RATE MATTERS AND REGULATION

KCC Proceedings

In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $17.4 million. The KCC is required to issue an order on our request within 240 days of our filing, which is in June 2017.

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. We have begun refunding our previously recorded refund obligation and as of September 30, 2016, we have a remaining refund obligation of $2.7 million, which is included in current regulatory liabilities on our balance sheet.

FERC Proceedings

Our TFR that includes projected 2017 transmission capital expenditures and operating costs will become effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million.

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 and as of September 30, 2016, we have a remaining refund obligation of $4.6 million, which is included in current regulatory liabilities on our balance sheet.

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Financial Instruments and Risk Management

9 Months Ended

Sep. 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 September 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,850,563	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,962		150,877		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 September 30, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	53,950	$	—	$	5,171	$	59,121
International equity funds	—		37,357		—		—		37,357
Core bond fund	—		27,985		—		—		27,985
High-yield bond fund	—		17,686		—		—		17,686
Emerging markets bond fund	—		16,007		—		—		16,007
Combination debt/equity/other funds	—		12,816		—		—		12,816
Alternative investments fund	—		—		—		17,886		17,886
Real estate securities fund	—		—		—		9,737		9,737
Cash equivalents	201		—		—		—		201
Total Nuclear Decommissioning Trust	201		165,801		—		32,794		198,796
Trading Securities:
Domestic equity funds	—		18,004		—		—		18,004
International equity fund	—		4,482		—		—		4,482
Core bond fund	—		12,009		—		—		12,009
Total Trading Securities	—		34,495		—		—		34,495
Total Assets Measured at Fair Value	$	201	$	200,296	$	—	$	32,794	$	233,291
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 September 30, 2016				As of December 31, 2015				As of September 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,171	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	17,886		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,737		—		10,823		—		Quarterly	65 days
Total	$	32,794	$	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

9 Months Ended

Sep. 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 September 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.5 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 and nine months endedSeptember 30, 2016, we recorded an unrealized gain of $1.0 million and $2.2 million, respectively, on assets still held. For the three and nine months endedSeptember 30, 2015, we recorded an unrealized loss of $1.5 million and $0.8 million, respectively, 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 September 30, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized no gains or losses during the three months endedSeptember 30, 2016, and a loss of$1.5 million during the nine months endedSeptember 30, 2016. We realized a loss of $0.5 million for the three months endedSeptember 30, 2015, and a loss of $1.0 million for the nine months endedSeptember 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 September 30, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2016:
Domestic equity funds	$	50,397	$	8,861	$	(137	)	$	59,121	30	%
International equity funds	34,199		3,262		(104		)	37,357		19	%
Core bond fund	27,280		705		—			27,985		14	%
High-yield bond fund	17,805		—		(119		)	17,686		9	%
Emerging market bond fund	16,242		—		(235		)	16,007		8	%
Combination debt/equity/other funds	9,088		3,728		—			12,816		6	%
Alternative investment fund	15,000		2,886		—			17,886		9	%
Real estate securities fund	9,500		237		—			9,737		5	%
Cash equivalents	201		—		—			201		<1%
Total	$	179,712	$	19,679	$	(595	)	$	198,796	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 ofSeptember 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 September 30, 2016:
Domestic equity funds	$	1,710	$	(137	)	$	—	$	—		$	1,710	$	(137	)
International equity funds	—		—			7,954		(104		)	7,954		(104		)
High-yield bond fund	—		—			17,686		(119		)	17,686		(119		)
Emerging market bond fund	—		—			16,007		(235		)	16,007		(235		)
Total	$	1,710	$	(137	)	$	41,647	$	(458	)	$	43,357	$	(595	)
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)

9 Months Ended

Sep. 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, 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. Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC’s review of the joint application.  On September 27, 2016, the KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017.  On October 18, 2016, the KCC issued an order stating that, if the KCC staff or other interested parties believe that the joint application does not adequately address the standards by which public utility mergers should be evaluated in Kansas, KCC staff or other interested parties should file for relief, including the potential dismissal of the joint application.

In addition, the Public Service Commission of the State of Missouri (Missouri Commission) opened an investigation to determine whether it has jurisdiction over the merger and on August 3, 2016, issued its order closing the investigation. On October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the Missouri Commission seeking to have the Missouri Commission assert jurisdiction over the merger, and various parties have intervened in these complaints. On October 12, 2016, and on October 26, 2016, the Missouri Commission staff and the Office of the Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that Missouri Commission staff and the OPC would not file a complaint, or support another complaint, to assert that the Missouri Commission has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the Missouri Commission, and the Missouri Commission has not ruled on the related consumer complaints. If the Missouri Commission rejects the Stipulation and Agreement, or rules in favor of the consumer complaints, and determines that the Missouri Commission has jurisdiction over the merger, approval of the Missouri Commission also will be required in order to consummate 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 22, 2016, Wolf Creek filed a request with the NRC to approve an indirect transfer of control of Wolf Creek’s operating license.

On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSR Act on October 21, 2016.

Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete 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. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million.

The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of $180.0 million. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b) within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of $280.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three and nine months ended September 30, 2016, we incurred approximately $1.9 million and $9.8 million, respectively, of merger-related expenses, which are 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 expenses to coincide with the closing of the merger.

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

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Debt Financing

9 Months Ended

Sep. 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 redeemed and reissued $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 redemption and reissuance 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, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

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Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Taxes

TAXES

We recorded income tax expense of $81.2 million with an effective income tax rate of 34% for the three months endedSeptember 30, 2016, and income tax expense of $66.3 million with an effective income tax rate of 32% for the same period of 2015. We recorded income tax expense of $160.4 million with an effective income tax rate of 35% for the nine months endedSeptember 30, 2016, and income tax expense of $127.8 million with an effective income tax rate of 33% for the same period of 2015. The increase in the effective income tax rate for the three and nine months ended September 30, 2016, was due primarily to an increase in income before income taxes.

As of September 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $2.2 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 September 30, 2016, we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2015. We accrued no penalties at either September 30, 2016, or December 31, 2015.

As of September 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

9 Months Ended

Sep. 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,922			10,753			1,392			1,422
Expected return on plan assets	(10,664		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			113			114
Actuarial loss (gain), net	5,146			8,033			(279		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,205			(211		)	338
Regulatory adjustment (a)	3,306			1,548			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,753		$	(697	)	$	1,351

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

	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	13,930		$	16,044		$	813		$	1,082
Interest cost	32,802			32,261			4,178			4,268
Expected return on plan assets	(31,990		)	(31,177		)	(5,125		)	(4,961		)
Amortization of unrecognized:
Prior service costs	594			390			341			342
Actuarial loss (gain), net	15,680			23,746			(839		)	284
Net periodic cost (benefit) before regulatory adjustment	31,016			41,264			(632		)	1,015
Regulatory adjustment (a)	9,919			4,880			(1,458		)	3,038
Net periodic cost (benefit)	$	40,935		$	46,144		$	(2,090	)	$	4,053

 _______________

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

During the nine months endedSeptember 30, 2016 and 2015, we contributed $15.7 million and $29.7 million, respectively, to the Westar Energy pension trust.

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Wolf Creek Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	31		$	34
Interest cost	2,413			2,254			81			79
Expected return on plan assets	(2,431		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,090			1,482			(3		)	1
Net periodic cost before regulatory adjustment	2,773			3,388			109			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,256		$	3,084		$	109		$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,061		$	5,696		$	95		$	103
Interest cost	7,241			6,761			244			236
Expected return on plan assets	(7,292		)	(6,783		)	—			—
Amortization of unrecognized:
Prior service costs	42			43			—			—
Actuarial loss (gain), net	3,268			4,448			(11		)	2
Net periodic cost before regulatory adjustment	8,320			10,165			328			341
Regulatory adjustment (a)	1,449			(912		)	—			—
Net periodic cost	$	9,769		$	9,253		$	328		$	341

 _______________

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

During the nine months endedSeptember 30, 2016 and 2015, we funded $14.6 million and $4.5 million of Wolf Creek’s pension plan contributions, respectively.

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Update Rule

In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxides (NOx) emissions in 22 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 final 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 final rule on our operations, however, based on our initial analysis we do not believe this rule will 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. In September 2016, the Kansas Department of Health and Environment (KDHE) recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will 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, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. 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, 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 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. Also in October 2015, the EPA 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. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en banc. Despite the stay, 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 cost to comply with the CPP 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 has determined sponsors are entitled to revenue credits for previously completed upgrades, and members will be obligated to pay for revenue credits attributable to these historical upgrades.

As a result, we expect to pay the SPP in November 2016 approximately $7.0 million related to revenue credits attributable to historical upgrades. As of September 30, 2016, we have recorded a corresponding liability for our obligation to the SPP for the period of March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.

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.

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 cooperated with the DOJ in its investigation, and on October 21, 2016, we were notified that the DOJ closed the investigation.

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Legal Proceedings

9 Months Ended

Sep. 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 (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas.

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Variable Interest Entities

9 Months Ended

Sep. 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 redemption and reissuance 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
	September 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	260,488	$	268,239
Regulatory assets (a)	10,053		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	19		2,457
Long-term debt of variable interest entities, net	111,218		138,097

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

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

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

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Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 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 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. The results of operations for the three and nine months endedSeptember 30, 2016, are not necessarily indicative of the results to be expected for the full year.

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)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Schedule of Utility Inventory

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

	As of		As of
	September 30, 2016		December 31, 2015
	(In Thousands)
Fuel inventory	$	95,936	$	113,438
Supplies	194,144		187,856
Fuel inventory and supplies	$	290,080	$	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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,537		$	466		$	6,884		$	3,047
Equity funds	2,647			—			7,894			2,034
Total	$	5,184		$	466		$	14,778		$	5,081
Average AFUDC Rates	3.6		%	1.0		%	4.2		%	2.8		%

Reconciliation Of Basic And Diluted EPS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	158,553	$	140,564	$	303,405	$	259,970
Less: Net income attributable to noncontrolling interests	3,833		2,561		10,760		7,277
Net income attributable to Westar Energy, Inc.	154,720		138,003		292,645		252,693
Less: Net income allocated to RSUs	325		304		605		563
Net income allocated to common stock	$	154,395	$	137,699	$	292,040	$	252,130
Weighted average equivalent common shares outstanding – basic	142,090,706		141,622,697		142,039,320		136,686,263
Effect of dilutive securities:
RSUs	487,239		215,481		373,869		197,373
Forward sale agreements	—		—		—		1,297,949
Weighted average equivalent common shares outstanding – diluted (a)	142,577,945		141,838,178		142,413,189		138,181,585
Earnings per common share, basic	$	1.09	$	0.97	$	2.06	$	1.84
Earnings per common share, diluted	$	1.08	$	0.97	$	2.05	$	1.82

_______________

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

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2016		2015
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	100,828	$	119,173
Interest on financing activities of VIEs	5,846		10,430
Income taxes, net of refunds	13,004		126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	94,007		60,155
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	7,315		8,008
Assets acquired through capital leases	1,310		2,246

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Financial Instruments and Risk Management (Tables)

9 Months Ended

Sep. 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 September 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,850,563	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,962		150,877		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 September 30, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	53,950	$	—	$	5,171	$	59,121
International equity funds	—		37,357		—		—		37,357
Core bond fund	—		27,985		—		—		27,985
High-yield bond fund	—		17,686		—		—		17,686
Emerging markets bond fund	—		16,007		—		—		16,007
Combination debt/equity/other funds	—		12,816		—		—		12,816
Alternative investments fund	—		—		—		17,886		17,886
Real estate securities fund	—		—		—		9,737		9,737
Cash equivalents	201		—		—		—		201
Total Nuclear Decommissioning Trust	201		165,801		—		32,794		198,796
Trading Securities:
Domestic equity funds	—		18,004		—		—		18,004
International equity fund	—		4,482		—		—		4,482
Core bond fund	—		12,009		—		—		12,009
Total Trading Securities	—		34,495		—		—		34,495
Total Assets Measured at Fair Value	$	201	$	200,296	$	—	$	32,794	$	233,291
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 September 30, 2016				As of December 31, 2015				As of September 30, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,171	$	3,689	$	6,050	$	1,948	(a)	(a)
Alternative investments fund (b)	17,886		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,737		—		10,823		—		Quarterly	65 days
Total	$	32,794	$	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)

9 Months Ended

Sep. 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 September 30, 2016, and December 31, 2015.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2016:
Domestic equity funds	$	50,397	$	8,861	$	(137	)	$	59,121	30	%
International equity funds	34,199		3,262		(104		)	37,357		19	%
Core bond fund	27,280		705		—			27,985		14	%
High-yield bond fund	17,805		—		(119		)	17,686		9	%
Emerging market bond fund	16,242		—		(235		)	16,007		8	%
Combination debt/equity/other funds	9,088		3,728		—			12,816		6	%
Alternative investment fund	15,000		2,886		—			17,886		9	%
Real estate securities fund	9,500		237		—			9,737		5	%
Cash equivalents	201		—		—			201		<1%
Total	$	179,712	$	19,679	$	(595	)	$	198,796	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

September 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 September 30, 2016:
Domestic equity funds	$	1,710	$	(137	)	$	—	$	—		$	1,710	$	(137	)
International equity funds	—		—			7,954		(104		)	7,954		(104		)
High-yield bond fund	—		—			17,686		(119		)	17,686		(119		)
Emerging market bond fund	—		—			16,007		(235		)	16,007		(235		)
Total	$	1,710	$	(137	)	$	41,647	$	(458	)	$	43,357	$	(595	)
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)

9 Months Ended

Sep. 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,922			10,753			1,392			1,422
Expected return on plan assets	(10,664		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			113			114
Actuarial loss (gain), net	5,146			8,033			(279		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,205			(211		)	338
Regulatory adjustment (a)	3,306			1,548			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,753		$	(697	)	$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	13,930		$	16,044		$	813		$	1,082
Interest cost	32,802			32,261			4,178			4,268
Expected return on plan assets	(31,990		)	(31,177		)	(5,125		)	(4,961		)
Amortization of unrecognized:
Prior service costs	594			390			341			342
Actuarial loss (gain), net	15,680			23,746			(839		)	284
Net periodic cost (benefit) before regulatory adjustment	31,016			41,264			(632		)	1,015
Regulatory adjustment (a)	9,919			4,880			(1,458		)	3,038
Net periodic cost (benefit)	$	40,935		$	46,144		$	(2,090	)	$	4,053

 _______________

(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)

9 Months Ended

Sep. 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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,633		$	5,348		$	271		$	361
Interest cost	10,922			10,753			1,392			1,422
Expected return on plan assets	(10,664		)	(10,059		)	(1,708		)	(1,654		)
Amortization of unrecognized:
Prior service costs	174			130			113			114
Actuarial loss (gain), net	5,146			8,033			(279		)	95
Net periodic cost (benefit) before regulatory adjustment	10,211			14,205			(211		)	338
Regulatory adjustment (a)	3,306			1,548			(486		)	1,013
Net periodic cost (benefit)	$	13,517		$	15,753		$	(697	)	$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	13,930		$	16,044		$	813		$	1,082
Interest cost	32,802			32,261			4,178			4,268
Expected return on plan assets	(31,990		)	(31,177		)	(5,125		)	(4,961		)
Amortization of unrecognized:
Prior service costs	594			390			341			342
Actuarial loss (gain), net	15,680			23,746			(839		)	284
Net periodic cost (benefit) before regulatory adjustment	31,016			41,264			(632		)	1,015
Regulatory adjustment (a)	9,919			4,880			(1,458		)	3,038
Net periodic cost (benefit)	$	40,935		$	46,144		$	(2,090	)	$	4,053

 _______________

(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 September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	31		$	34
Interest cost	2,413			2,254			81			79
Expected return on plan assets	(2,431		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,090			1,482			(3		)	1
Net periodic cost before regulatory adjustment	2,773			3,388			109			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,256		$	3,084		$	109		$	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
Nine Months Ended September 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,061		$	5,696		$	95		$	103
Interest cost	7,241			6,761			244			236
Expected return on plan assets	(7,292		)	(6,783		)	—			—
Amortization of unrecognized:
Prior service costs	42			43			—			—
Actuarial loss (gain), net	3,268			4,448			(11		)	2
Net periodic cost before regulatory adjustment	8,320			10,165			328			341
Regulatory adjustment (a)	1,449			(912		)	—			—
Net periodic cost	$	9,769		$	9,253		$	328		$	341

 _______________

(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)

9 Months Ended

Sep. 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
	September 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	260,488	$	268,239
Regulatory assets (a)	10,053		9,088
Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	19		2,457
Long-term debt of variable interest entities, net	111,218		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)	9 Months Ended
	Sep. 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	Sep. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Total	$ 290,080	$ 301,294
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	95,936	113,438
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 194,144	$ 187,856

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Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Borrowed funds	$ (2,537)	$ (466)	$ (6,884)	$ (3,047)
Equity funds	2,647	0	7,894	2,034
Total	$ 5,184	$ 466	$ 14,778	$ 5,081
Average AFUDC rates	3.60%	1.00%	4.20%	2.80%

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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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	$ 325	$ 304	$ 605	$ 563
Net income allocated to common stock	$ 154,395	$ 137,699	$ 292,040	$ 252,130
Weighted Average Number of Shares Outstanding , Basic	142,090,706	141,622,697	142,039,320	136,686,263
RSUs	487,239	215,481	373,869	197,373
Forward sale agreements	0	0	0	1,297,949
Weighted average equivalent common shares outstanding - diluted	142,577,945	141,838,178	142,413,189	138,181,585
Earnings Per Share, Basic	$ 1.09	$ 0.97	$ 2.06	$ 1.84
Earnings Per Share, Diluted	$ 1.08	$ 0.97	$ 2.05	$ 1.82
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	0	0	0	0

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Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash Paid For (Received From)
Interest on financing activities	$ 100,828	$ 119,173
Income taxes, net of refunds	13,004	126
Noncash Investing and Financing Transactions
Property, plant and equipment	94,007	60,155
Issuance of common stock for reinvested dividends and compensation plans	7,315	8,008
Deconsolidation of VIE	(2,551)
Assets acquired through capital leases	1,310	2,246
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 5,846	$ 10,430

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Summary Of Significant Accounting Policies New Accounting Pronouncements (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Item Effected [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	$ 3,326
Excess Tax Benefit from Share-based Compensation, Operating Activities	1,200
Stock-based compensation excess tax benefits	$ 1,200	$ 1,231

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Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions		1 Months Ended
	Oct. 26, 2016	Oct. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2016
Regulatory Proceedings [Line Items]
Loss Contingency Accrual						$ 7.0
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						2.7
Federal Energy Regulatory Commission [Member] | Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Loss Contingency Accrual						$ 4.6
Subsequent Event [Member] | Kansas Corporation Commission [Member] | Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 17.4
Subsequent Event [Member] | Federal Energy Regulatory Commission [Member] | Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 29.6
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	Sep. 30, 2016	Dec. 31, 2015
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,430,000	$ 3,080,000
Fair Value	3,850,563	3,259,533
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	137,962	166,271
Fair Value	$ 150,877	$ 179,030

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Financial Instruments and Risk Management (Fair Value Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 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	[1]	15 years
Nuclear decommissioning trust assets		$ 198,796	$ 184,057
Trading securities		34,495	33,888
Total assets measured at fair value		233,291	217,945
Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		201	87
Trading securities		0	159
Total assets measured at fair value		201	246
Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		165,801	150,658
Trading securities		34,495	33,729
Total assets measured at fair value		200,296	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		59,121	56,922
Trading securities		18,004	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		53,950	50,872
Trading securities		18,004	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		37,357	33,595
Trading securities		4,482	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		37,357	33,595
Trading securities		4,482	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		27,985	25,976
Trading securities		12,009	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		27,985	25,976
Trading securities		12,009	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		17,686	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		17,686	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		16,007	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		16,007	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		12,816
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		12,816
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		17,886	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		9,737	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		201	87
Trading securities			159
Cash Equivalents [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		201	87
Trading securities			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
Cash Equivalents [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0	0
Trading securities			0
Portion at Other than Fair Value Measurement [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		32,794	33,312
Trading securities		0	0
Total assets measured at fair value		32,794	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		5,171	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		17,886	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		9,737	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

[1] subject to the general partner’s right to extend the term for up to three additional one-year periods.

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Financial Instruments and Risk Management (Investments In Financial Instruments) (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		$ 198,796	$ 184,057
Trading securities		34,495	33,888
Total		233,291	217,945
Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		32,794	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		59,121	56,922
Trading securities		18,004	17,876
Domestic Equity [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	[1]	5,171	6,050
Unfunded commitments		3,689	1,948
Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		17,886	16,439
Alternative Funds [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		17,886	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		$ 9,737	10,823
Real Estate Securities [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		9,737	10,823
Unfunded commitments		$ 0	$ 0
Investment redemption frequency		Quarterly
Investment redemption length of settlement	[2]	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. Our initial investment in the fourth fund occurred in the second quarter of 2016.

[2] There is a holdback on final redemptions.

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Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 34,495		$ 34,495		$ 33,888
Unrealized gains losses	1,000	$ 1,500	2,200	$ 800
Realized gains on available-for-sale-securities	$ 0	$ 500	$ 1,500	$ 1,000

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Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,000	$ 1,500	$ 2,200	$ 800
Trading securities	34,495		34,495		$ 33,888
Cost	179,712		179,712		177,048
Available-for-sale Securities, Gross Unrealized Gain	19,679		19,679		13,351
Available-for-sale Securities, Gross Unrealized Loss	(595)		(595)		(6,342)
Available-for-sale Securities	$ 198,796		$ 198,796		$ 184,057
Allocation	100.00%		100.00%		100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 18,004		$ 18,004		$ 17,876
Cost	50,397		50,397		49,488
Available-for-sale Securities, Gross Unrealized Gain	8,861		8,861		7,436
Available-for-sale Securities, Gross Unrealized Loss	(137)		(137)		(2)
Available-for-sale Securities	$ 59,121		$ 59,121		$ 56,922
Allocation	30.00%		30.00%		32.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 4,482		$ 4,482		$ 4,430
Cost	34,199		34,199		33,458
Available-for-sale Securities, Gross Unrealized Gain	3,262		3,262		1,372
Available-for-sale Securities, Gross Unrealized Loss	(104)		(104)		(1,235)
Available-for-sale Securities	$ 37,357		$ 37,357		$ 33,595
Allocation	19.00%		19.00%		18.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 12,009		$ 12,009		$ 11,423
Cost	27,280		27,280		26,397
Available-for-sale Securities, Gross Unrealized Gain	705		705		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(421)
Available-for-sale Securities	$ 27,985		$ 27,985		$ 25,976
Allocation	14.00%		14.00%		14.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,805		$ 17,805		$ 17,047
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(119)		(119)		(1,759)
Available-for-sale Securities	$ 17,686		$ 17,686		$ 15,288
Allocation	9.00%		9.00%		8.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 16,242		$ 16,242		$ 16,306
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(235)		(235)		(2,722)
Available-for-sale Securities	$ 16,007		$ 16,007		$ 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	$ 9,088		$ 9,088
Available-for-sale Securities, Gross Unrealized Gain	3,728		3,728
Available-for-sale Securities, Gross Unrealized Loss	0		0
Available-for-sale Securities	$ 12,816		$ 12,816
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	2,886		2,886		1,439
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 17,886		$ 17,886		$ 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	237		237		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(203)
Available-for-sale Securities	$ 9,737		$ 9,737		$ 10,823
Allocation	5.00%		5.00%		6.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities					$ 159
Cost	$ 201		$ 201		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	$ 201		$ 201		$ 87

XML

Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,000	$ 1,500	$ 2,200	$ 800
Fair Value, Less than 12 Months	1,710		1,710		$ 41,264
Gross Unrealized Losses, Less than 12 Months	(137)		(137)		(2,180)
Fair Value, 12 Months or Greater	41,647		41,647		31,792
Gross Unrealized Losses, 12 Months or Greater	(458)		(458)		(4,162)
Fair Value, Total	43,357		43,357		73,056
Gross Unrealized Losses, Total	(595)		(595)		(6,342)
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	1,710		1,710		0
Gross Unrealized Losses, Less than 12 Months	(137)		(137)		0
Fair Value, 12 Months or Greater	0		0		668
Gross Unrealized Losses, 12 Months or Greater	0		0		(2)
Fair Value, Total	1,710		1,710		668
Gross Unrealized Losses, Total	(137)		(137)		(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	7,954		7,954		6,717
Gross Unrealized Losses, 12 Months or Greater	(104)		(104)		(1,235)
Fair Value, Total	7,954		7,954		6,717
Gross Unrealized Losses, Total	(104)		(104)		(1,235)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months					25,976
Gross Unrealized Losses, Less than 12 Months					(421)
Fair Value, 12 Months or Greater					0
Gross Unrealized Losses, 12 Months or Greater					0
Fair Value, Total					25,976
Gross Unrealized Losses, Total					(421)
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		15,288
Gross Unrealized Losses, Less than 12 Months	0		0		(1,759)
Fair Value, 12 Months or Greater	17,686		17,686		0
Gross Unrealized Losses, 12 Months or Greater	(119)		(119)		0
Fair Value, Total	17,686		17,686		15,288
Gross Unrealized Losses, Total	(119)		(119)		(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	16,007		16,007		13,584
Gross Unrealized Losses, 12 Months or Greater	(235)		(235)		(2,722)
Fair Value, Total	16,007		16,007		13,584
Gross Unrealized Losses, Total	$ (235)		$ (235)		(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)

XML

Pending Merger Pending Merger (Narrative) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended	9 Months Ended
	Jun. 28, 2016	May 29, 2016	Sep. 30, 2016	Sep. 30, 2016
Business Combination [Line Items]
Public Utilities, Kansas time limit for KCC review	300 days
Great Plains Energy, Inc. Merger [Member]
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			$ 1.9	$ 9.8
Business Combination, Expected Acquisition Related Costs				$ 30.0
Cash Consideration per Share [Member] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Common stock right to convert to cash, price per share		$ 51.00
Total Consideration per Share [Member] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Common stock right to convert to cash, price per share		$ 60.00
Westar Energy breaches agreement and enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Member] [Domain] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		$ 280.0
Failure to obtain regulatory approvals, paid to Westar Energy [Member] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		380.0
Great Plains Energy breaches merger agreement and enters into acquisition proposal within 12 months of termination [Member] [Domain] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		180.0
End date occurred and Great Plains Energy enters into acquisition proposal within 12 months of termination, paid to Westar Energy [Member] [Domain] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		180.0
end date occurred and Westar Energy enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Domain] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		$ 280.0

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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
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
Debt Instrument, Interest Rate, Stated Percentage	2.55%
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Income tax expense	$ 81,211	$ 66,293	$ 160,376	$ 127,810
Effective income tax rate	34.00%	32.00%	35.00%	33.00%
Liability for unrecognized income tax benefits	$ 2,200		$ 2,200		$ 2,900
Interest on liability related to unrecognized income tax benefits	100		100		0
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				9 Months Ended
	Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Components of Net Periodic Cost (Benefit):
Pension Contributions					$ 15,700		$ 29,700
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	$ 4,633		$ 5,348		13,930		16,044
Interest cost	10,922		10,753		32,802		32,261
Expected return on plan assets	(10,664)		(10,059)		(31,990)		(31,177)
Prior service costs	174		130		594		390
Actuarial loss, net	5,146		8,033		15,680		23,746
Net periodic cost before regulatory adjustment	10,211		14,205		31,016		41,264
Regulatory adjustment	3,306	[1]	1,548	[1]	9,919	[2]	4,880	[2]
Net periodic cost	13,517		15,753		40,935		46,144
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	271		361		813		1,082
Interest cost	1,392		1,422		4,178		4,268
Expected return on plan assets	(1,708)		(1,654)		(5,125)		(4,961)
Prior service costs	113		114		341		342
Actuarial loss, net	(279)		95		(839)		284
Net periodic cost before regulatory adjustment	(211)		338		(632)		1,015
Regulatory adjustment	(486)	[1]	1,013	[1]	(1,458)	[2]	3,038	[2]
Net periodic cost	$ (697)		$ 1,351		$ (2,090)		$ 4,053

[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				9 Months Ended
	Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Components of Net Periodic Cost (Benefit):
Pension Contributions					$ 15,700		$ 29,700
Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Pension Contributions					$ 14,600		4,500
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		$ 13,930		16,044
Interest cost	10,922		10,753		32,802		32,261
Expected return on plan assets	(10,664)		(10,059)		(31,990)		(31,177)
Prior service costs	174		130		594		390
Actuarial loss, net	5,146		8,033		15,680		23,746
Net periodic cost before regulatory adjustment	10,211		14,205		31,016		41,264
Regulatory adjustment	3,306	[1]	1,548	[1]	9,919	[2]	4,880	[2]
Net periodic cost	13,517		15,753		40,935		46,144
Pension Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	1,687		1,899		5,061		5,696
Interest cost	2,413		2,254		7,241		6,761
Expected return on plan assets	(2,431)		(2,261)		(7,292)		(6,783)
Prior service costs	14		14		42		43
Actuarial loss, net	1,090		1,482		3,268		4,448
Net periodic cost before regulatory adjustment	2,773		3,388		8,320		10,165
Regulatory adjustment	483	[3]	(304)	[3]	1,449	[4]	(912)	[4]
Net periodic cost	3,256		3,084		9,769		9,253
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	271		361		813		1,082
Interest cost	1,392		1,422		4,178		4,268
Expected return on plan assets	(1,708)		(1,654)		(5,125)		(4,961)
Prior service costs	113		114		341		342
Actuarial loss, net	(279)		95		(839)		284
Net periodic cost before regulatory adjustment	(211)		338		(632)		1,015
Regulatory adjustment	(486)	[1]	1,013	[1]	(1,458)	[2]	3,038	[2]
Net periodic cost	(697)		1,351		(2,090)		4,053
Post-Retirement Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	31		34		95		103
Interest cost	81		79		244		236
Expected return on plan assets	0		0		0		0
Prior service costs	0		0		0		0
Actuarial loss, net	(3)		1		(11)		2
Net periodic cost before regulatory adjustment	109		114		328		341
Regulatory adjustment	0	[3]	0	[3]	0	[4]	0	[4]
Net periodic cost	$ 109		$ 114		$ 328		$ 341

[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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Commitments And Contingencies Commitments And Contingencies (Narrative) (Details) $ in Millions	Sep. 30, 2016 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency Accrual	$ 7.0

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Variable Interest Entities (Narrative) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2016	Feb. 16, 2016
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
KGE Member | Debt Instrument La Cygne [Member] | La Cygne Generating Station [Member]
Variable Interest Entity [Line Items]
Long-term Debt, Gross		$ 162,100,000

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Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Property, plant and equipment, net		$ 9,038,197	$ 8,524,902
Current maturities of long-term debt		125,000	0
Accrued interest	[1]	61,833	71,426
Long-term debt, net		3,388,221	3,163,950
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Property, plant and equipment, net		260,488	268,239
Regulatory assets	[2]	10,053	9,088
Current maturities of long-term debt		26,842	28,309
Accrued interest	[1]	19	2,457
Long-term debt, net		$ 111,218	$ 138,097

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

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