38,276

27,860

Total Current Assets

762,303

717,141

Nuclear decommissioning trust

9,038,197

8,524,902

OTHER ASSETS:

Regulatory assets

731,859

751,312

198,796

184,057

252,775

260,015

Total Other Assets

1,183,430

1,195,384

TOTAL ASSETS

11,244,418

10,705,666

CURRENT LIABILITIES:

125,000

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

^[1]

61,833

71,426

Regulatory liabilities

22,547

25,697

Total Current Liabilities

97,100

106,632

917,028

836,935

LONG-TERM LIABILITIES:

Unamortized investment tax credits

3,388,221

3,163,950

Deferred income taxes

1,737,359

1,591,430

207,595

209,763

Regulatory liabilities

243,754

267,114

Accrued employee benefits

445,442

462,304

Asset retirement obligations

283,941

275,285

Total Long-Term Liabilities

85,442

88,825

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:

260,488

268,239

CURRENT LIABILITIES:

26,842

28,309

^[1]

2,457

LONG-TERM LIABILITIES:

Summary Of Significant Accounting Policies

$ 111,218

$ 138,097

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

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

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Consolidated Statements Of Income - USD ($) $ in Thousands	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

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)

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

Description Of Business	9 Months Ended
Description Of Business	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.

Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

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 ended September 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 ended September 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.

Rate Matters And Regulation	9 Months Ended
Rate Matters And Regulation	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.

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.

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 ended September 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 ended September 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 ended September 30, 2016, and a loss of $1.5 million during the nine months ended September 30, 2016. We realized a loss of $0.5 million for the three months ended September 30, 2015, and a loss of $1.0 million for the nine months ended September 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 of 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	)

Pending Merger Pending Merger (Notes)	9 Months Ended
Pending Merger Pending Merger (Notes)	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.

Compensation and Retirement Disclosure [Abstract]

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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+ Details

Debt Financing	9 Months Ended
Debt Financing	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.

Taxes	9 Months Ended
Taxes	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 ended September 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 ended September 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.

Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 30, 2016

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

_______________


(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 ended September 30, 2016 and 2015, we contributed $15.7 million and $29.7 million, respectively, to the Westar Energy pension trust.

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 ended September 30, 2016 and 2015, we funded $14.6 million and $4.5 million of Wolf Creek’s pension plan contributions, respectively.

Commitments And Contingencies	9 Months Ended
Commitments And Contingencies	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.

Legal Proceedings	9 Months Ended
Legal Proceedings	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.

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

_______________

(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.

Summary Of Significant Accounting Policies (Policy)	9 Months Ended
Summary Of Significant Accounting Policies (Policy)	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 ended September 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.

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 ended September 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

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)


(b)	There is a holdback on final redemptions.

Cost And Fair Value Of Investments

This item represents the disclosure regarding the investments in certain entities that calculate net asset value per share that enables users to understand the nature and risks of the investments and whether the investments are probable of being sold at amounts different from net asset value per share. Such disclosure may include (1) the fair value of the investments in the major category, and a description of the significant investment strategies of the investee(s) in the major category; (2) for each major category of investment that includes investments that can never be redeemed with the investees, but the reporting entity receives distributions through the liquidation of the underlying assets of the investees, the reporting entity's estimate of the period of time over which the underlying assets are expected to be liquidated by the investees; (3) the amount of the entity's unfunded commitments related to investments in the major category; (4) a general description of the terms and conditions upon which the investor may redeem investments in the major category; (5) the circumstances in which an otherwise redeemable investment in the major category might not be redeemable; (6) for those otherwise redeemable investments that are restricted from redemption as of the reporting entity's measurement date, the entity's best estimate of when the restriction from redemption might lapse; if an estimate cannot be made, the entity shall disclose that fact and how long the restriction has been in effect; (7) any other significant restriction on the ability to sell investments in the major category at the measurement date; (8) total fair value of held for sale investments and any remaining actions required to complete the sale when the reporting entity determines that it is probable that it will sell the investments for an amount different from net asset value per share; and (9) disclosure of an entity's plans to sell and any remaining actions required to complete the sale when the entity intends to sell a group of investments, but the individual investments to be sold have not been identified.

+ References + Details

Financial Investments (Tables)

9 Months Ended

Sep. 30, 2016

Investments [Abstract]

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	)

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.

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.

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.

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

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

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%

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

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

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

Financial and Derivative Instruments and Trading Securities [Line Items]

Amount of cumulative effect of the change in accounting principle or new accounting pronouncement on retained earnings or other components of equity or net assets in the statement of financial position as of the beginning of the earliest period presented.

+ References + Details

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%

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

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]

$ 198,796

$ 184,057

Trading securities

34,495

33,888

Total

233,291

217,945

Fair Value [Member]

Decommissioning Trust Assets [Member] | Fair Value [Member]

32,794

33,312

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

3,689

1,948

Domestic Equity [Member]

Domestic Equity [Member] | Fair Value [Member]

59,121

56,922

Trading securities

18,004

17,876

Financial and Derivative Instruments and Trading Securities [Line Items]

^[1]

5,171

6,050

Alternative Funds [Member]

3,689

1,948

Financial and Derivative Instruments and Trading Securities [Line Items]

Alternative Funds [Member] | Fair Value [Member]

17,886

16,439

Financial and Derivative Instruments and Trading Securities [Line Items]

17,886

16,439

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

^[2]

65 days

Real Estate Securities [Member]

Financial and Derivative Instruments and Trading Securities [Line Items]

Real Estate Securities [Member] | Fair Value [Member]

$ 9,737

10,823

Financial and Derivative Instruments and Trading Securities [Line Items]

9,737

10,823

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

^[2]

65 days

[1]

[2]

There is a holdback on final redemptions.

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

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

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)

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

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%

Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	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

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

Pension Benefits [Member]

Pension Contributions

$ 15,700

$ 29,700

$ 4,633

$ 5,348

13,930

16,044

10,922

10,753

32,802

32,261

(10,664)

(10,059)

(31,990)

(31,177)

174

130

594

390

5,146

8,033

15,680

23,746

10,211

14,205

31,016

41,264

3,306

^[1]

1,548

^[1]

9,919

^[2]

4,880

^[2]

Post-Retirement Benefits [Member]

13,517

15,753

40,935

46,144

271

361

813

1,082

1,392

1,422

4,178

4,268

(1,708)

(1,654)

(5,125)

(4,961)

113

114

341

342

(279)

(839)

284

(211)

338

(632)

1,015

(486)

^[1]

1,013

^[1]

(1,458)

^[2]

3,038

^[2]

$ (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.

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

Pension Contributions

$ 15,700

$ 29,700

Wolf Creek [Member]

Subsidiary Interest in Defined Benefit Plans

Pension Contributions

$ 14,600

4,500

KGE Member

47.00%

Pension Benefits [Member]

$ 4,633

$ 5,348

$ 13,930

16,044

10,922

10,753

32,802

32,261

(10,664)

(10,059)

(31,990)

(31,177)

174

130

594

390

5,146

8,033

15,680

23,746

10,211

14,205

31,016

41,264

3,306

^[1]

1,548

^[1]

9,919

^[2]

4,880

^[2]

Pension Benefits [Member] | Wolf Creek [Member]

13,517

15,753

40,935

46,144

1,687

1,899

5,061

5,696

2,413

2,254

7,241

6,761

(2,431)

(2,261)

(7,292)

(6,783)

1,090

1,482

3,268

4,448

2,773

3,388

8,320

10,165

483

^[3]

(304)

^[3]

1,449

^[4]

(912)

^[4]

Post-Retirement Benefits [Member]

3,256

3,084

9,769

9,253

271

361

813

1,082

1,392

1,422

4,178

4,268

(1,708)

(1,654)

(5,125)

(4,961)

113

114

341

342

(279)

(839)

284

(211)

338

(632)

1,015

(486)

^[1]

1,013

^[1]

(1,458)

^[2]

3,038

^[2]

Post-Retirement Benefits [Member] | Wolf Creek [Member]

(697)

1,351

(2,090)

4,053

103

244

236

(3)

(11)

109

114

328

341

^[3]

^[4]

Variable Interest Entity [Line Items]

$ 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.

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

Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($)
$ in Thousands

Sep. 30, 2016

Dec. 31, 2015

$ 9,038,197

$ 8,524,902

125,000

^[1]

61,833

71,426

Variable Interest Entity, Primary Beneficiary [Member]

3,388,221

3,163,950

Variable Interest Entity [Line Items]

260,488

268,239

Regulatory assets

^[2]

10,053

9,088

26,842

28,309

^[1]

2,457