33,099

27,860

Total Current Assets

741,868

717,141

Nuclear decommissioning trust

8,800,698

8,524,902

OTHER ASSETS:

Regulatory assets

734,844

751,312

189,179

184,057

241,081

260,015

Total Other Assets

1,165,104

1,195,384

TOTAL ASSETS

10,970,742

10,705,666

CURRENT LIABILITIES:

125,000

Short-term debt

177,000

250,300

Accounts payable

178,374

220,969

Accrued dividends

52,767

49,829

Accrued taxes

95,084

83,773

^[1]

41,969

71,426

Regulatory liabilities

33,634

25,697

Total Current Liabilities

90,841

106,632

821,511

836,935

LONG-TERM LIABILITIES:

Unamortized investment tax credits

3,387,696

3,163,950

Deferred income taxes

1,655,825

1,591,430

208,318

209,763

Regulatory liabilities

247,916

267,114

Accrued employee benefits

455,923

462,304

Asset retirement obligations

280,507

275,285

Total Long-Term Liabilities

87,065

88,825

6,434,480

6,196,768

COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)

Westar Energy, Inc. Shareholders' Equity:

Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 129,272,835 shares and 128,254,229 shares, respective to each date

708,455

706,767

Paid-in capital

2,008,491

2,004,124

Retained earnings

978,187

945,830

Total Westar Energy, Inc. Shareholders' Equity

3,695,133

3,656,721

Noncontrolling Interests

19,618

15,242

Total Equity

3,714,751

3,671,963

TOTAL LIABILITIES AND EQUITY

10,970,742

10,705,666

Variable Interest Entity [Member]

CURRENT ASSETS:

263,072

268,239

CURRENT LIABILITIES:

26,842

28,309

^[1]

867

2,457

LONG-TERM LIABILITIES:

Summary Of Significant Accounting Policies

$ 111,230

$ 138,097

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

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

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

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

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

Description Of Business	6 Months Ended
Description Of Business	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description Of Business	DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 704,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Summary Of Significant Accounting Policies

6 Months Ended

Jun. 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 only of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2015 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.



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

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,338		$	552		$	4,347		$	2,581
Equity funds	2,783			90			5,247			2,041
Total	$	5,121		$	642		$	9,594		$	4,622
Average AFUDC Rates	4.2		%	1.2		%	4.6		%	3.2		%

Earnings Per Share

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

To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,144	$	66,243	$	144,852	$	119,406
Less: Net income attributable to noncontrolling interests	3,804		2,533		6,927		4,716
Net income attributable to Westar Energy, Inc.	72,340		63,710		137,925		114,690
Less: Net income allocated to RSUs	156		141		290		257
Net income allocated to common stock	$	72,184	$	63,569	$	137,635	$	114,433

Weighted average equivalent common shares outstanding – basic	142,033,842		135,939,197		142,013,344		134,177,136
Effect of dilutive securities:
RSUs	463,493		121,234		348,003		127,999
Forward sale agreements	—		1,351,721		—		2,024,468
Weighted average equivalent common shares outstanding – diluted (a)	142,497,335		137,412,152		142,361,347		136,329,603

Earnings per common share, basic	$	0.51	$	0.47	$	0.97	$	0.85
Earnings per common share, diluted	$	0.51	$	0.46	$	0.97	$	0.84

_______________

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

Supplemental Cash Flow Information



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

New Accounting Pronouncements

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accounting and/or disclosure.

Leases

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

Stock-based Compensation

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

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

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

Financial Instruments

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

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We are continuing to analyze the new standard and have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

Rate Matters And Regulation	6 Months Ended
Rate Matters And Regulation	Jun. 30, 2016
Regulated Operations [Abstract]
Rate Matters And Regulation	RATE MATTERS AND REGULATION KCC Proceedings In December 2015, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million. In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR), along with the reduced return on equity (ROE) as described below. The updated prices were retroactively effective April 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $7.0 million. As of June 30, 2016, we have recorded a regulatory liability of $4.0 million for our estimated refund obligation from the refund effective date of April 2016 through June 2016. FERC Proceedings In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. The updated prices were retroactively effective January 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million. This increase also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation during the three months ended June 30, 2016. As of June 30, 2016, we have a remaining refund obligation of $8.1 million which is included in current regulatory liabilities on our balance sheet.

Financial Instruments and Risk Management

6 Months Ended

Jun. 30, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Financial And Derivative Instruments And Trading Securities

FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. In addition, we measure certain investments that do not have a readily determinable fair value at NAV, which are not included in the fair value hierarchy. Further explanation of these levels and NAV is summarized below.


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

•

Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically liquid investments in funds which have a readily determinable fair value calculated using daily NAVs, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments priced with models using highly observable inputs.


•	Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation.

•

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

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

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



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

Recurring Fair Value Measurements

The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value.



As of June 30, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	—		$	50,856	$	—	$	5,944	$	56,800
International equity funds	—		34,560		—		—		34,560
Core bond fund	—		27,509		—		—		27,509
High-yield bond fund	—		16,557		—		—		16,557
Emerging markets bond fund	—		15,342		—		—		15,342
Combination debt/equity/other funds	—		12,277		—		—		12,277
Alternative investments fund	—		—		—		16,386		16,386
Real estate securities fund	—		—		—		9,500		9,500
Cash equivalents	248		—		—		—		248
Total Nuclear Decommissioning Trust	248		157,101		—		31,830		189,179
Trading Securities:
Domestic equity funds	—		17,782		—		—		17,782
International equity fund	—		4,220		—		—		4,220
Core bond fund	—		11,935		—		—		11,935
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		33,937		—		—		34,093
Total Assets Measured at Fair Value	$	404	$	191,038	$	—	$	31,830	$	223,272

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	—	$	6,050	$	56,922
International equity funds	—		33,595		—		—		33,595
Core bond fund	—		25,976		—		—		25,976
High-yield bond fund	—		15,288		—		—		15,288
Emerging markets bond fund	—		13,584		—		—		13,584
Combination debt/equity/other funds	—		11,343		—		—		11,343
Alternative investments fund	—		—		—		16,439		16,439
Real estate securities fund	—		—		—		10,823		10,823
Cash equivalents	87		—		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		—		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		—		17,876
International equity fund	—		4,430		—		—		4,430
Core bond fund	—		11,423		—		—		11,423
Cash equivalents	159		—		—		—		159
Total Trading Securities	159		33,729		—		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	—	$	33,312	$	217,945

Some of our investments in the Nuclear Decommissioning Trust (NDT) are measured at NAV and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations, these investments may have redemption restrictions. The following table provides additional information on these investments.



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

_______________

(a)

This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.


(b)	There is a holdback on final redemptions.

Price Risk

We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

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

Financial Investments

6 Months Ended

Jun. 30, 2016

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

We report our investments in equity and debt securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

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

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a gain of $0.1 million during the three months ended June 30, 2016, and a loss of $1.4 million during the six months ended June 30, 2016. We realized a loss of $0.6 million for the three months ended June 30, 2015, and a loss of $0.5 million for the six months ended June 30, 2015. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds	$	49,844	$	6,965	$	(9	)	$	56,800	30	%
International equity funds	33,935		1,201		(576		)	34,560		18	%
Core bond fund	26,882		627		—			27,509		15	%
High-yield bond fund	17,405		—		(848		)	16,557		9	%
Emerging market bond fund	16,145		—		(803		)	15,342		8	%
Combination debt/equity/other funds	9,003		3,274		—			12,277		6	%
Alternative investment fund	15,000		1,386		—			16,386		9	%
Real estate securities fund	9,500		—		—			9,500		5	%
Cash equivalents	248		—		—			248		<1%
Total	$	177,962	$	13,453	$	(2,236	)	$	189,179	100	%

As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	100	%

The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2016, and December 31, 2015.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of June 30, 2016:
Domestic equity funds	$	861	$	(9	)	$	—	$	—		$	861	$	(9	)
International equity funds	—		—			7,426		(576		)	7,426		(576		)
High-yield bond fund	—		—			16,557		(848		)	16,557		(848		)
Emerging market bond fund	—		—			15,342		(803		)	15,342		(803		)
Total	$	861	$	(9	)	$	39,325	$	(2,227	)	$	40,186	$	(2,236	)

As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

Pending Merger Pending Merger (Notes)	6 Months Ended
Pending Merger Pending Merger (Notes)	Jun. 30, 2016
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	PENDING MERGER On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock. The closing of the merger is subject to customary conditions including, among others, approval by our shareholders and the shareholders of Great Plains Energy and receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. On July 14, 2016, Great Plains Energy filed a registration statement on Form S-4 with the SEC. The registration statement includes a preliminary proxy statement that, once finalized, will be sent to our shareholders in connection with the special meeting of our shareholders to be held to vote to approve the merger. The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If Great Plains Energy terminates the merger agreement because our board of directors changes its recommendation, if we terminate the merger agreement to enter into an acquisition agreement with a superior proposal, or if our shareholders vote and do not give approval and we enter into an acquisition proposal within 12 months of termination of the merger agreement, we must pay Great Plains Energy a termination fee of $280.0 million. If the merger agreement is terminated under other circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. If we terminate the merger agreement because the Great Plains Energy board of directors changes its recommendation, Great Plains Energy must pay us a termination fee of $180.0 million. If either party terminates the merger agreement because the end date occurred or Great Plains Energy shareholders’ approval was not acquired, and it has either been publicly disclosed that Great Plains Energy has entered into an alternative acquisition proposal, or an acquisition proposal was entered into within 12 months after the termination of the merger agreement, Great Plains Energy must pay us a termination fee of $180.0 million. If Great Plains Energy shareholders’ meeting was held and completed, but approval was not obtained, and the termination fee described above is not payable by Great Plains Energy, Great Plains Energy must pay us a termination fee of $80.0 million. In connection with this transaction, we have incurred merger-related expenses. During the three months ended June 30, 2016, we incurred approximately $7.8 million of merger-related expenses, which is included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to coincide with the closing of the merger. We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies,” and Note 12, “Legal Proceedings,” for more information on legal matters.

- Definition

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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1524-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4922-128472

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4934-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4926-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1383-128463

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-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Debt Financing	6 Months Ended
Debt Financing	Jun. 30, 2016
Long-term Debt, Unclassified [Abstract]
Debt Financing	DEBT FINANCING In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm. Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%. In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of $162.1 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	6 Months Ended
Taxes	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Taxes	TAXES We recorded income tax expense of $40.5 million with an effective income tax rate of 35% for the three months ended June 30, 2016, and income tax expense of $33.8 million with an effective income tax rate of 34% for the same period of 2015. We recorded income tax expense of $79.2 million with an effective income tax rate of 35% for the six months ended June 30, 2016, and income tax expense of $61.5 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three and six months ended June 30, 2016, was due primarily to an increase in income before income taxes. As of June 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $3.0 million and $2.9 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months. As of June 30, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2016, or December 31, 2015. As of June 30, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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



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

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

_______________


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

During the six months ended June 30, 2016 and 2015, we contributed $11.2 million and $19.4 million, respectively, to the Westar Energy pension trust.

Wolf Creek Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2016

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

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	32		$	34
Interest cost	2,414			2,254			82			79
Expected return on plan assets	(2,430		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,089			1,482			(4		)	1
Net periodic cost before regulatory adjustment	2,774			3,388			110			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,257		$	3,084		$	110		$	114

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,374		$	3,797		$	64		$	69
Interest cost	4,828			4,508			163			157
Expected return on plan assets	(4,861		)	(4,522		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,178			2,965			(8		)	1
Net periodic cost before regulatory adjustment	5,547			6,776			219			227
Regulatory adjustment (a)	966			(608		)	—			—
Net periodic cost	$	6,513		$	6,168		$	219		$	227

_______________


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

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

Commitments And Contingencies	6 Months Ended
Commitments And Contingencies	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES Environmental Matters Cross-State Air Pollution Rule In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (NOx) emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results. National Ambient Air Quality Standards Under the federal Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide (CO) and sulfur dioxide (SO₂), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results. In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results. In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, Kansas Department of Health and Environment (KDHE) recommended a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We are working with KDHE to determine the impact of this proposed designation. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results. Greenhouse Gases Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions. In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. In May 2016, the U.S. Court of Appeals for the D.C. Circuit decided to forego the normal three judge panel to review the CPP and to conduct the review en banc. At the same time, the Court scheduled oral arguments for September 2016. In June 2016, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material. Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material. In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material. In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results. Regulation of Coal Combustion Byproducts In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material. SPP Revenue Crediting We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades. We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results, but it could be material. Storage of Spent Nuclear Fuel In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision. Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity. FERC Proceedings See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the Federal Power Act. Department of Justice Proceedings At any time before or after the merger, the Department of Justice (DOJ) or the Federal Trade Commission could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the merger or seeking divestiture of substantial assets of Great Plains Energy, the Company or their respective subsidiaries. Private parties and state attorneys general may also bring an action under the antitrust laws under certain circumstances. On June 23, 2016, the DOJ sent a letter to us and Great Plains Energy informing the parties that it had opened an investigation into the proposed transaction and requested that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

Legal Proceedings	6 Months Ended
Legal Proceedings	Jun. 30, 2016
Legal Proceedings [Abstract]
Legal Proceedings	LEGAL PROCEEDINGS We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Note 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information. Pending Merger Following the announcement of the merger agreement, two putative class action complaints and one putative derivative action complaint challenging the merger were filed on behalf of purported Westar Energy shareholders in the District Court of Shawnee County, Kansas. The first complaint, filed on June 13, 2016, is captioned Smith v. Westar Energy, Inc., et al., Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that we and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration undervalues Westar Energy, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourages third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, our CEO will reap significant personal financial gain. The complaint seeks, among other remedies, a declaration that the action may be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement (to the extent already implemented), a directive to the members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The second complaint, filed on June 14, 2016, is captioned Miller v. Westar Energy, Inc., et al., Case No. 2016-CV-000458. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration deprives our shareholders of fair consideration for their shares, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, an order to permit the action to be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement, a directive to defendants to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. Counsel for plaintiffs in the Smith matter and the Miller matter have filed an unopposed motion for consolidation and appointment of lead counsel. The defendants believe that the claims asserted against them in both class action lawsuits are without merit and intend to vigorously defend against such claims. The third complaint, filed on July 5, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action is brought on behalf of our shareholders and names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as the nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals. The complaint seeks, among other remedies, an order to permit the action to be maintained as a derivative action, enjoining direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement (to the extent already implemented), imposing a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The defendants intend to seek dismissal of this complaint at the appropriate time.

Variable Interest Entities

6 Months Ended

Jun. 30, 2016

Variable Interest Entities [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

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

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 7, “Debt Financing,” for additional information.

Financial Statement Impact

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



	As of		As of
	June 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	263,072	$	268,239
Regulatory assets (a)	9,758		9,088

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,230		138,097

_______________

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

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

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

Summary Of Significant Accounting Policies (Policy)	6 Months Ended
Summary Of Significant Accounting Policies (Policy)	Jun. 30, 2016
Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.
Use Of Management's Estimates	Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.
Fuel Inventory And Supplies	Fuel Inventory and Supplies We state fuel inventory and supplies at average cost.
Allowance For Funds Used During Construction	Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost
Earnings Per Share	Earnings Per Share We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Schedule of Utility Inventory

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



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

Allowance For Funds Used During Construction

We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Dollars In Thousands)
Borrowed funds	$	2,338		$	552		$	4,347		$	2,581
Equity funds	2,783			90			5,247			2,041
Total	$	5,121		$	642		$	9,594		$	4,622
Average AFUDC Rates	4.2		%	1.2		%	4.6		%	3.2		%

Reconciliation Of Basic And Diluted EPS

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,144	$	66,243	$	144,852	$	119,406
Less: Net income attributable to noncontrolling interests	3,804		2,533		6,927		4,716
Net income attributable to Westar Energy, Inc.	72,340		63,710		137,925		114,690
Less: Net income allocated to RSUs	156		141		290		257
Net income allocated to common stock	$	72,184	$	63,569	$	137,635	$	114,433

Weighted average equivalent common shares outstanding – basic	142,033,842		135,939,197		142,013,344		134,177,136
Effect of dilutive securities:
RSUs	463,493		121,234		348,003		127,999
Forward sale agreements	—		1,351,721		—		2,024,468
Weighted average equivalent common shares outstanding – diluted (a)	142,497,335		137,412,152		142,361,347		136,329,603

Earnings per common share, basic	$	0.51	$	0.47	$	0.97	$	0.85
Earnings per common share, diluted	$	0.51	$	0.46	$	0.97	$	0.84

_______________

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

Supplemental Cash Flow Information



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

Financial Instruments and Risk Management (Tables)

6 Months Ended

Jun. 30, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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



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

Fair Value Of Assets And Liabilities

The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value.



As of June 30, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	—		$	50,856	$	—	$	5,944	$	56,800
International equity funds	—		34,560		—		—		34,560
Core bond fund	—		27,509		—		—		27,509
High-yield bond fund	—		16,557		—		—		16,557
Emerging markets bond fund	—		15,342		—		—		15,342
Combination debt/equity/other funds	—		12,277		—		—		12,277
Alternative investments fund	—		—		—		16,386		16,386
Real estate securities fund	—		—		—		9,500		9,500
Cash equivalents	248		—		—		—		248
Total Nuclear Decommissioning Trust	248		157,101		—		31,830		189,179
Trading Securities:
Domestic equity funds	—		17,782		—		—		17,782
International equity fund	—		4,220		—		—		4,220
Core bond fund	—		11,935		—		—		11,935
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		33,937		—		—		34,093
Total Assets Measured at Fair Value	$	404	$	191,038	$	—	$	31,830	$	223,272

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	—	$	6,050	$	56,922
International equity funds	—		33,595		—		—		33,595
Core bond fund	—		25,976		—		—		25,976
High-yield bond fund	—		15,288		—		—		15,288
Emerging markets bond fund	—		13,584		—		—		13,584
Combination debt/equity/other funds	—		11,343		—		—		11,343
Alternative investments fund	—		—		—		16,439		16,439
Real estate securities fund	—		—		—		10,823		10,823
Cash equivalents	87		—		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		—		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		—		17,876
International equity fund	—		4,430		—		—		4,430
Core bond fund	—		11,423		—		—		11,423
Cash equivalents	159		—		—		—		159
Total Trading Securities	159		33,729		—		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	—	$	33,312	$	217,945

Unrealized Gains And Losses On Fair Value Assets And Liabilities

Investments In Financial Instruments

The following table provides additional information on these investments.



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

_______________

(a)


(b)	There is a holdback on final redemptions.

- Definition

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)

6 Months Ended

Jun. 30, 2016

Investments [Abstract]

Cost And Fair Value Of Investments

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds	$	49,844	$	6,965	$	(9	)	$	56,800	30	%
International equity funds	33,935		1,201		(576		)	34,560		18	%
Core bond fund	26,882		627		—			27,509		15	%
High-yield bond fund	17,405		—		(848		)	16,557		9	%
Emerging market bond fund	16,145		—		(803		)	15,342		8	%
Combination debt/equity/other funds	9,003		3,274		—			12,277		6	%
Alternative investment fund	15,000		1,386		—			16,386		9	%
Real estate securities fund	9,500		—		—			9,500		5	%
Cash equivalents	248		—		—			248		<1%
Total	$	177,962	$	13,453	$	(2,236	)	$	189,179	100	%

As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	100	%

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

June 30, 2016, and December 31, 2015.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of June 30, 2016:
Domestic equity funds	$	861	$	(9	)	$	—	$	—		$	861	$	(9	)
International equity funds	—		—			7,426		(576		)	7,426		(576		)
High-yield bond fund	—		—			16,557		(848		)	16,557		(848		)
Emerging market bond fund	—		—			15,342		(803		)	15,342		(803		)
Total	$	861	$	(9	)	$	39,325	$	(2,227	)	$	40,186	$	(2,236	)

As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

Pension and Post-Retirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



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

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

_______________


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

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

6 Months Ended

Jun. 30, 2016

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



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

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,297		$	10,696		$	542		$	722
Interest cost	21,880			21,507			2,786			2,845
Expected return on plan assets	(21,326		)	(20,118		)	(3,417		)	(3,307		)
Amortization of unrecognized:
Prior service costs	420			260			228			227
Actuarial loss (gain), net	10,534			15,714			(560		)	190
Net periodic cost (benefit) before regulatory adjustment	20,805			28,059			(421		)	677
Regulatory adjustment (a)	6,613			3,332			(972		)	2,026
Net periodic cost (benefit)	$	27,418		$	31,391		$	(1,393	)	$	2,703

_______________


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

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

The following tables summarize the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization.



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,687		$	1,899		$	32		$	34
Interest cost	2,414			2,254			82			79
Expected return on plan assets	(2,430		)	(2,261		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,089			1,482			(4		)	1
Net periodic cost before regulatory adjustment	2,774			3,388			110			114
Regulatory adjustment (a)	483			(304		)	—			—
Net periodic cost	$	3,257		$	3,084		$	110		$	114

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2016			2015			2016			2015
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,374		$	3,797		$	64		$	69
Interest cost	4,828			4,508			163			157
Expected return on plan assets	(4,861		)	(4,522		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,178			2,965			(8		)	1
Net periodic cost before regulatory adjustment	5,547			6,776			219			227
Regulatory adjustment (a)	966			(608		)	—			—
Net periodic cost	$	6,513		$	6,168		$	219		$	227

_______________


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

Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2016

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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



	As of		As of
	June 30, 2016		December 31, 2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	263,072	$	268,239
Regulatory assets (a)	9,758		9,088

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,230		138,097

_______________

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

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

- Definition

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	Jun. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Total	$ 299,465	$ 301,294
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	107,397	113,438
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 192,068	$ 187,856

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

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

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

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

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

Financial Instruments and Risk Management (Investments In Financial Instruments) (Details) - USD ($)
$ in Thousands

6 Months Ended

Jun. 30, 2016

Dec. 31, 2015

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

$ 189,179

$ 184,057

Trading securities

34,093

33,888

Total

223,272

217,945

Fair Value [Member]

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

31,830

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]

56,800

56,922

Trading securities

17,782

17,876

Financial and Derivative Instruments and Trading Securities [Line Items]

^[1]

5,944

6,050

Alternative Funds [Member]

3,689

1,948

Financial and Derivative Instruments and Trading Securities [Line Items]

Alternative Funds [Member] | Fair Value [Member]

16,386

16,439

Financial and Derivative Instruments and Trading Securities [Line Items]

16,386

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]

$ 9,500

10,823

Financial and Derivative Instruments and Trading Securities [Line Items]

9,500

10,823

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

65 days

[1]	This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013.
[2]	There is a holdback on final redemptions.

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

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

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

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

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

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

Pension and Post-Retirement Benefit Plans (Net Periodic Costs And Pension Contributions) (Details) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Pension Benefits [Member]

Pension Contributions

$ 11,200

$ 19,400

$ 4,633

$ 5,348

9,297

10,696

10,921

10,753

21,880

21,507

(10,663)

(10,059)

(21,326)

(20,118)

174

130

420

260

5,146

8,053

10,534

15,714

10,211

14,225

20,805

28,059

3,306

^[1]

1,534

^[1]

6,613

^[2]

3,332

^[2]

Post-Retirement Benefits [Member]

13,517

15,759

27,418

31,391

271

361

542

722

1,393

1,422

2,786

2,845

(1,708)

(1,654)

(3,417)

(3,307)

114

228

227

(280)

(560)

190

(210)

338

(421)

677

(486)

^[1]

1,013

^[1]

(972)

^[2]

2,026

^[2]

$ (696)

$ 1,351

$ (1,393)

$ 2,703

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

Wolf Creek Pension and Post-Retirement Benefit Plans Wolf Creek Pension and Post-Retirement Benefit Plans (Net Periodic Costs and Pension Contributions) (Details) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Subsidiary Interest in Defined Benefit Plans

Pension Contributions

$ 11,200

$ 19,400

KGE Member

47.00%

Pension Benefits [Member]

$ 4,633

$ 5,348

$ 9,297

10,696

10,921

10,753

21,880

21,507

(10,663)

(10,059)

(21,326)

(20,118)

174

130

420

260

5,146

8,053

10,534

15,714

10,211

14,225

20,805

28,059

3,306

^[1]

1,534

^[1]

6,613

^[2]

3,332

^[2]

Pension Benefits [Member] | Wolf Creek [Member]

13,517

15,759

27,418

31,391

1,687

1,899

3,374

3,797

2,414

2,254

4,828

4,508

(2,430)

(2,261)

(4,861)

(4,522)

1,089

1,482

2,178

2,965

2,774

3,388

5,547

6,776

483

^[3]

(304)

^[3]

966

^[4]

(608)

^[4]

Post-Retirement Benefits [Member]

3,257

3,084

6,513

6,168

271

361

542

722

1,393

1,422

2,786

2,845

(1,708)

(1,654)

(3,417)

(3,307)

114

228

227

(280)

(560)

190

(210)

338

(421)

677

(486)

^[1]

1,013

^[1]

(972)

^[2]

2,026

^[2]

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

(696)

1,351

(1,393)

2,703

163

157

(4)

(8)

110

114

219

227

^[3]

^[4]

Variable Interest Entity [Line Items]

$ 110

$ 114

$ 219

$ 227

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

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

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

Jun. 30, 2016

Dec. 31, 2015

$ 8,800,698

$ 8,524,902

125,000

^[1]

41,969

71,426

Variable Interest Entity, Primary Beneficiary [Member]

3,387,696

3,163,950

Variable Interest Entity [Line Items]

263,072

268,239

Regulatory assets

^[2]

9,758

9,088

26,842

28,309

^[1]

867

2,457