25,754

29,701

Total Current Assets

733,049

768,382

Nuclear decommissioning trust

9,494,023

9,248,359

OTHER ASSETS:

Regulatory assets

748,934

762,479

229,927

200,122

241,384

249,828

Total Other Assets

1,220,245

1,212,429

TOTAL ASSETS

11,625,375

11,487,074

CURRENT LIABILITIES:

125,000

Short-term debt

189,100

366,700

Accounts payable

147,933

220,522

Accrued dividends

53,770

52,885

Accrued taxes

114,317

85,729

^[1]

64,851

72,519

Regulatory liabilities

14,068

15,760

Total Current Liabilities

74,273

81,236

686,846

1,047,193

LONG-TERM LIABILITIES:

Unamortized investment tax credits

3,686,852

3,388,670

Deferred income taxes

1,866,583

1,752,776

208,597

210,654

Regulatory liabilities

237,065

223,693

Accrued employee benefits

497,298

512,412

Asset Retirement Obligations, Noncurrent

397,505

323,951

Total Long-Term Liabilities

84,296

83,326

7,059,629

6,606,691

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

710,471

708,956

Paid-in capital

2,022,072

2,018,317

Retained earnings

1,196,460

1,078,602

Total Westar Energy, Inc. Shareholders' Equity

3,929,003

3,805,875

Noncontrolling Interests

(50,103)

27,315

Total Equity

3,878,900

3,833,190

TOTAL LIABILITIES AND EQUITY

11,625,375

11,487,074

Variable Interest Entity [Member]

CURRENT ASSETS:

178,058

257,904

CURRENT LIABILITIES:

28,534

26,842

^[1]

867

LONG-TERM LIABILITIES:

Summary Of Significant Accounting Policies

$ 81,433

$ 111,209

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

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS:
Allowance for doubtful accounts	$ 4,658	$ 6,667
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	142,094,176	141,791,153
Common stock, shares outstanding	142,094,176	141,791,153

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Consolidated Statements Of Income - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES	$ 794,327	$ 764,654	$ 1,976,222	$ 1,955,552
OPERATING EXPENSES:
Fuel and purchased power	189,804	155,673	415,449	374,361
Network Transmission Cost	62,578	57,939	185,015	173,925
Operating and maintenance	79,856	86,758	248,211	250,135
Depreciation and amortization	94,668	84,972	277,322	252,838
Selling, general and administrative	65,630	60,582	182,367	192,762
Taxes, Miscellaneous	41,815	48,154	126,421	145,529
Total Operating Expenses	534,351	494,078	1,434,785	1,389,550
INCOME FROM OPERATIONS	259,976	270,576	541,437	566,002
OTHER INCOME (EXPENSE):
Investment earnings (losses)	2,593	2,619	8,384	6,916
Other income	3,849	13,353	5,672	26,212
Other expense	(6,493)	(5,887)	(14,457)	(14,338)
Total Other Income	(51)	10,085	(401)	18,790
Interest expense	43,458	40,897	128,232	121,011
INCOME BEFORE INCOME TAXES	216,467	239,764	412,804	463,781
Income tax expense	55,743	81,211	112,559	160,376
NET INCOME	160,724	158,553	300,245	303,405
Less: Net income attributable to noncontrolling interests	2,418	3,833	10,213	10,760
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 158,306	$ 154,720	$ 290,032	$ 292,645
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 1.11	$ 1.09	$ 2.03	$ 2.06
Earnings Per Share, Diluted	$ 1.11	$ 1.08	$ 2.03	$ 2.05
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,472,987	142,090,706	142,458,586	142,039,320
Weighted Average Number of Shares Outstanding, Diluted	142,516,049	142,577,945	142,495,896	142,413,189
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.40	$ 0.38	$ 1.20	$ 1.14

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 300,245	$ 303,405
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	277,322	252,838
Amortization of nuclear fuel	24,150	22,518
Amortization of deferred regulatory gain from sale leaseback	(4,121)	(4,121)
Gain on lease modification	(3,500)	0
Amortization of corporate-owned life insurance	15,744	13,779
Non-cash compensation	6,777	7,025
Net deferred income taxes and credits	126,986	160,429
Allowance for equity funds used during construction	(1,094)	(7,894)
Changes in working capital items:
Accounts receivable	(19,696)	(64,100)
Fuel inventory and supplies	15,515	11,680
Prepaid expenses and other	61,287	(385)
Accounts payable	(10,044)	9,736
Accrued taxes	35,631	40,711
Other current liabilities	(108,503)	(61,879)
Changes in other assets	20,085	(4,377)
Changes in other liabilities	5,538	13,208
Cash Flows from Operating Activities	742,322	692,573
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(564,622)	(821,936)
Purchase of securities - trusts	(15,262)	(43,252)
Sale of securities - trusts	15,896	44,326
Investment in corporate-owned life insurance	13,875	14,648
Proceeds from investment in corporate-owned life insurance	265	24,242
Investment in affiliated company	0	(655)
Other investing activities	(3,411)	(3,095)
Cash Flows used in Investing Activities	(581,009)	(815,018)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(177,732)	(67,402)
Proceeds from long-term debt	(296,215)	(396,472)
Retirements of long-term debt	(125,000)	(50,000)
Repayment of capital leases	(2,592)	(2,327)
Borrowings against cash surrender value of corporate-owned life insurance	53,422	55,952
Repayment of borrowings against cash surrender value of corporate-owned life insurance	0	(22,921)
Issuance of common stock	659	2,003
Distributions to shareholders of noncontrolling interests	(5,760)	(2,551)
Cash dividends paid	(166,340)	(152,787)
Other financing activities	(7,023)	(4,979)
Cash Flows from Financing Activities	(160,991)	123,151
NET CHANGE IN CASH AND CASH EQUIVALENTS	322	706
CASH AND CASH EQUIVALENTS:
Beginning of period	3,066	3,231
End of period	3,388	3,937
Variable Interest Entity [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from long-term debt	0	(162,048)
Retirements of long-term debt	$ (26,840)	$ (190,357)

Consolidated Statements Of Changes In Equity - USD ($)	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2015	$ 3,671,963,000	$ 706,767,000	$ 2,004,124,000	$ 945,830,000	$ 15,242,000
Beginning Balance (Shares) at Dec. 31, 2015		141,353,426
Net income	303,405,000	$ 0	0	292,645,000	10,760,000
Issuance of stock	2,003,000	$ 202,000	1,801,000	0	0
Issuance of stock (shares)		40,441
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		350,016
Issuance Of Stock For Compensation And Reinvested Dividends	7,315,000	$ 1,750,000	5,565,000
Tax withholding related to stock compensation	(4,979,000)		(4,979,000)
Dividends on common stock	(163,002,000)	0	0	(163,002,000)	0
Stock compensation expense	6,938,000		6,938,000
Distributions to shareholders of noncontrolling interests	(2,551,000)				(2,551,000)
Ending Balance at Sep. 30, 2016	3,824,418,000	$ 708,719,000	2,013,449,000	1,078,799,000	23,451,000
Ending Balance (Shares) at Sep. 30, 2016		141,743,883
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				3,326,000.000
Beginning Balance at Dec. 31, 2016	3,833,190,000	$ 708,956,000	2,018,317,000	1,078,602,000	27,315,000
Beginning Balance (Shares) at Dec. 31, 2016		141,791,153
Net income	300,245,000	$ 0	0	290,032,000	10,213,000
Issuance of stock	659,000	$ 61,000	598,000	0	0
Issuance of stock (shares)		12,131
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		290,892
Issuance Of Stock For Compensation And Reinvested Dividends	4,944,000	$ 1,454,000	3,490,000
Tax withholding related to stock compensation	(7,023,000)		(7,023,000)
Dividends on common stock	(172,174,000)	0	0	(172,174,000)	0
Stock compensation expense	6,690,000		6,690,000
Deconsolidation of variable interest entity	(81,871,000)				(81,871,000)
Distributions to shareholders of noncontrolling interests	(5,760,000)				(5,760,000)
Ending Balance at Sep. 30, 2017	$ 3,878,900,000	$ 710,471,000	$ 2,022,072,000	$ 1,196,460,000	$ (50,103,000)
Ending Balance (Shares) at Sep. 30, 2017		142,094,176

Description Of Business	9 Months Ended
Description Of Business	Sep. 30, 2017
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 707,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2016 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 (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and nine months ended September 30, 2017, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory and Supplies

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



	As of		As of
	September 30, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	87,429	$	107,086
Supplies	197,645		193,039
Fuel inventory and supplies	$	285,074	$	300,125

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 condensed consolidated statements of income as follows.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Dollars In Thousands)
Borrowed funds	$	1,210		$	2,537		$	3,958		$	6,884
Equity funds	321			2,647			1,094			7,894
Total	$	1,531		$	5,184		$	5,052		$	14,778
Average AFUDC Rates	2.2		%	3.6		%	2.0		%	4.2		%

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 RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	160,724	$	158,553	$	300,245	$	303,405
Less: Net income attributable to noncontrolling interests	2,418		3,833		10,213		10,760
Net income attributable to Westar Energy, Inc.	158,306		154,720		290,032		292,645
Less: Net income allocated to RSUs	289		325		515		605
Net income allocated to common stock	$	158,017	$	154,395	$	289,517	$	292,040

Weighted average equivalent common shares outstanding – basic	142,472,987		142,090,706		142,458,586		142,039,320
Effect of dilutive securities:
RSUs	43,062		487,239		37,310		373,869
Weighted average equivalent common shares outstanding – diluted (a)	142,516,049		142,577,945		142,495,896		142,413,189

Earnings per common share, basic	$	1.11	$	1.09	$	2.03	$	2.06
Earnings per common share, diluted	$	1.11	$	1.08	$	2.03	$	2.05

_______________

(a) We had no antidilutive securities for the three and nine months ended September 30, 2017 and 2016.

Supplemental Cash Flow Information



	Nine Months Ended September 30,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	108,965		$	100,828
Interest on financing activities of VIEs	3,061			5,846
Income taxes, net of refunds	(12,645		)	13,004
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	112,493			94,007
Deconsolidation of property, plant and equipment of VIE	(72,901		)	—
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,944			7,315
Deconsolidation of VIE	(83,096		)	—
Assets acquired through capital leases	4,611			1,310

New Accounting Pronouncements

We prepare our condensed 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 that may affect our accounting and/or disclosure.

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our condensed consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. 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. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. 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 modified retrospective method. We will use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. We have analyzed and documented the impact of the new revenue standard and related ASU’s for our significant revenue streams including retail, transmission and wholesale, as well as other less significant revenue streams. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. We are finalizing our analysis of revenue-related controls and development of revenue-related disclosure with an overarching emphasis on effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material.

Pending Merger Pending Merger (Notes)	9 Months Ended
Pending Merger Pending Merger (Notes)	Sep. 30, 2017
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 that provided for the acquisition of us by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) denied our and Great Plains Energy’s merger application. On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into one share of common stock of a new holding company with a final name still to be determined. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately 47.5% of the new holding company. The closing of the merger is subject to conditions including, among others, approval of our shareholders representing a majority of the outstanding shares of our common stock; approval of Great Plains Energy’s shareholders representing two-thirds of the outstanding shares of Great Plains Energy common stock; clearance under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act); receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar Energy and its subsidiaries, taken as a whole); effectiveness of the registration statement for the shares of the new holding company’s common stock to be issued to our shareholders and Great Plains Energy’s shareholders upon consummation of the merger and approval of the listing of such shares on the New York Stock Exchange; the receipt of tax opinions by us and Great Plains Energy that the merger will be treated as a non-taxable event for U.S. federal income tax purposes; there being no shares of Great Plains Energy preference stock outstanding; and Great Plains Energy having not less than $1.25 billion in cash or cash equivalents on its balance sheet. The closing of the merger is also subject to other standard conditions, such as accuracy of representations and warranties, compliance with covenants and the absence of a material adverse effect on either company. Either party may terminate the amended and restated merger agreement if the merger is not consummated by July 10, 2018, subject to an extension of up to six months. Either party may also terminate the agreement if our shareholders or Great Plains Energy’s shareholders do not approve the merger or an order that prohibits the merger becomes final and non-appealable. There are also termination rights for both parties in certain cases if the other party’s board of directors changes its recommendation to its shareholders regarding approval of the merger, or the other party accepts an alternative, superior offer. On August 25, 2017, we and Great Plains Energy filed a joint application with the KCC requesting approval of the merger. On August 31, 2017, we and Great Plains Energy applied for approval of the merger from the MPSC. On September 1, 2017, we and Great Plains Energy filed a joint application for approval of the merger with FERC. On September 5, 2017, Wolf Creek filed a request with the NRC to approve an indirect transfer of control of Wolf Creek’s operating license. We and Great Plains Energy each scheduled special meetings for our respective shareholders on November 21, 2017 to vote on the proposed merger. The amended and restated merger agreement provides that Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated due to (i) failure to receive regulatory approval prior to July 10, 2018, subject to an extension of up to six months, (ii) a non-appealable regulatory order enjoining the merger or (iii) Great Plains Energy’s failure to close after all conditions precedent to closing have been satisfied. In addition, we may be required to pay Great Plains Energy a termination fee of $190.0 million if the agreement is terminated by us under certain circumstances, such as entering into a definitive acquisition agreement with respect to a superior proposal or by Great Plains Energy as a result of our board of directors changing its recommendation of the merger prior to our shareholder approval having been obtained. Similarly, Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated by Great Plains Energy under certain circumstances, such as entering into a definitive acquisition agreement with respect to a superior proposal or by us as a result of Great Plains Energy’s board of directors changing its recommendation of the merger prior to its shareholder approval having been obtained. Additionally, if the agreement is terminated by either Great Plains Energy or us as a result of Great Plains Energy’s shareholders not approving the agreement, Great Plains Energy may be required to pay us a termination fee of $80.0 million. In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our selling, general, and administrative expenses. During 2016, we incurred approximately $10.2 million of merger-related expenses. During the three and nine months ended September 30, 2017, we incurred approximately $7.8 million and $8.6 million, respectively, of merger-related expenses. In the event that the merger is consummated, we expect total merger-related expenses will be approximately $45.0 million. See also Note 13, “Legal Proceedings,” for more information on litigation related to the merger.

Rate Matters And Regulation	9 Months Ended
Rate Matters And Regulation	Sep. 30, 2017
Regulated Operations [Abstract]
Rate Matters And Regulation	RATE MATTERS AND REGULATION KCC Proceedings In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. In May 2017, we entered into a settlement agreement with the major parties to the rate review. In June 2017, the agreement was approved by the KCC. The new prices were effective June 2017 and are expected to increase our annual retail revenues by approximately $16.4 million. In March 2017, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2017 and are expected to increase our annual retail revenues by approximately $12.7 million. In December 2016, 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 2017 and are expected to decrease our annual retail revenues by approximately $26.8 million. FERC Proceedings Our TFR that includes projected 2018 transmission capital expenditures and operating costs will become effective in January 2018 and is expected to increase our annual transmission revenues by approximately $26.1 million. Our TFR that includes projected 2017 transmission capital expenditures and operating costs was effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above.

Financial Instruments and Risk Management

9 Months Ended

Sep. 30, 2017

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 net asset value (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 that 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 that do not have a readily determinable fair value. 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 condensed consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed-rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.

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



	As of September 30, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,857,763	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	109,967		110,586		137,962		139,733

Recurring Fair Value Measurements

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



As of September 30, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	64,855	$	—	$	5,139	$	69,994
International equity funds	—		46,020		—		—		46,020
Core bond fund	—		32,914		—		—		32,914
High-yield bond fund	—		17,866		—		—		17,866
Emerging markets bond fund	—		17,617		—		—		17,617
Combination debt/equity/other fund	—		13,688		—		—		13,688
Alternative investments fund	—		—		—		21,063		21,063
Real estate securities fund	—		—		—		10,594		10,594
Cash equivalents	171		—		—		—		171
Total Nuclear Decommissioning Trust	171		192,960		—		36,796		229,927
Trading Securities:
Domestic equity funds	—		17,883		—		—		17,883
International equity fund	—		4,491		—		—		4,491
Core bond fund	—		11,789		—		—		11,789
Total Trading Securities	—		34,163		—		—		34,163
Total Assets Measured at Fair Value	$	171	$	227,123	$	—	$	36,796	$	264,090

As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	56,312	$	—	$	5,056	$	61,368
International equity funds	—		35,944		—		—		35,944
Core bond fund	—		27,423		—		—		27,423
High-yield bond fund	—		18,188		—		—		18,188
Emerging markets bond fund	—		14,738		—		—		14,738
Combination debt/equity/other fund	—		13,484		—		—		13,484
Alternative investments fund	—		—		—		18,958		18,958
Real estate securities fund	—		—		—		9,946		9,946
Cash equivalents	73		—		—		—		73
Total Nuclear Decommissioning Trust	73		166,089		—		33,960		200,122
Trading Securities:
Domestic equity funds	—		18,364		—		—		18,364
International equity fund	—		4,467		—		—		4,467
Core bond fund	—		11,504		—		—		11,504
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		34,335		—		—		34,491
Total Assets Measured at Fair Value	$	229	$	200,424	$	—	$	33,960	$	234,613

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



	As of September 30, 2017				As of December 31, 2016				As of September 30, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,139	$	2,929	$	5,056	$	3,529	(a)	(a)
Alternative investments fund (b)	21,063		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,594		—		9,946		—		Quarterly	65 days
Total	$	36,796	$	2,929	$	33,960	$	3,529

_______________

(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 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 condensed consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

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

Financial Investments

9 Months Ended

Sep. 30, 2017

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of September 30, 2017, and December 31, 2016, we measured the fair value of trust assets at $34.2 million and $34.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our condensed consolidated statements of income. For the three and nine months ended September 30, 2017, we recorded an unrealized gain of $1.0 million and $3.5 million, respectively, on assets still held in the trust. For the three and nine months ended September 30, 2016, we recorded an unrealized gain of $1.0 million and $2.2 million, respectively, on assets still held in the trust.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of September 30, 2017, and December 31, 2016.

Using the specific identification method to determine cost, we realized no gains or losses during the three months ended September 30, 2017, and a gain of $0.1 million during the nine months ended September 30, 2017. We realized no gains or losses during the three months ended September 30, 2016, and a loss of $1.5 million for the nine months ended September 30, 2016. We record net realized and unrealized gains and losses in regulatory liabilities on our condensed consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of September 30, 2017, and December 31, 2016.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2017:
Domestic equity funds	$	55,387	$	15,227	$	(620	)	$	69,994	30	%
International equity funds	35,937		10,083		—			46,020		20	%
Core bond fund	32,980		—		(66		)	32,914		14	%
High-yield bond fund	17,450		416		—			17,866		8	%
Emerging markets bond fund	17,186		431		—			17,617		8	%
Combination debt/equity/other fund	8,068		5,620		—			13,688		6	%
Alternative investments fund	15,000		6,063		—			21,063		9	%
Real estate securities fund	9,500		1,094		—			10,594		5	%
Cash equivalents	171		—		—			171		<1%
Total	$	191,679	$	38,934	$	(686	)	$	229,927	100	%

As of December 31, 2016:
Domestic equity funds	$	53,192	$	8,295	$	(119	)	$	61,368	31	%
International equity funds	34,502		2,075		(633		)	35,944		18	%
Core bond fund	27,952		—		(529		)	27,423		14	%
High-yield bond fund	18,358		—		(170		)	18,188		9	%
Emerging markets bond fund	16,397		—		(1,659		)	14,738		7	%
Combination debt/equity/other fund	9,171		4,313		—			13,484		7	%
Alternative investments fund	15,000		3,958		—			18,958		9	%
Real estate securities fund	9,500		446		—			9,946		5	%
Cash equivalents	73		—		—			73		<1%
Total	$	184,145	$	19,087	$	(3,110	)	$	200,122	100	%

The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of September 30, 2017, and December 31, 2016.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2017:
Domestic equity funds	$	1,809	$	(337	)	$	1,904	$	(283	)	$	3,713	$	(620	)
Core bond fund	32,914		(66		)	—		—			32,914		(66		)
Total	$	34,723	$	(403	)	$	1,904	$	(283	)	$	36,627	$	(686	)

As of December 31, 2016:
Domestic equity funds	$	1,788	$	(119	)	$	—	$	—		$	1,788	$	(119	)
International equity funds	—		—			7,489		(633		)	7,489		(633		)
Core bond fund	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging markets bond fund	—		—			14,738		(1,659		)	14,738		(1,659		)
Total	$	29,211	$	(648	)	$	40,415	$	(2,462	)	$	69,626	$	(3,110	)

Debt Financing	9 Months Ended
Debt Financing	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
Debt Financing	DEBT FINANCING In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds (FMBs) bearing a stated interest at 5.15% maturing January 2017. In March 2017, Westar Energy issued $300.0 million in principal amount of FMBs bearing a stated interest at 3.10% and maturing April 2027.

Taxes	9 Months Ended
Taxes	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Taxes	TAXES We recorded income tax expense of $55.7 million with an effective income tax rate of 26% for the three months ended September 30, 2017, and income tax expense of $81.2 million with an effective income tax rate of 34% for the same period of 2016. We recorded income tax expense of $112.6 million with an effective income tax rate of 27% for the nine months ended September 30, 2017, and income tax expense of $160.4 million with an effective income tax rate of 35% for the same period of 2016. The decrease in the effective income tax rate for the three and nine months ended September 30, 2017, was due primarily to lower income before income taxes, an increase in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service, and a favorable deferred tax true-up related to plant differences. As of September 30, 2017, and December 31, 2016, our unrecognized income tax benefits totaled $1.6 million and $2.8 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months. As of September 30, 2017, we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2016. We accrued no penalties at either September 30, 2017, or December 31, 2016. As of September 30, 2017, and December 31, 2016, we had recorded $0.2 million and $1.5 million, respectively, for probable assessments of taxes other than income taxes.

Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,922			1,314			1,392
Expected return on plan assets	(10,760		)	(10,664		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			113
Actuarial loss (gain), net	5,489			5,146			(195		)	(279		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(697	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	15,655		$	13,930		$	813		$	813
Interest cost	31,862			32,802			3,941			4,178
Expected return on plan assets	(32,280		)	(31,990		)	(5,154		)	(5,125		)
Amortization of unrecognized:
Prior service costs	512			594			341			341
Actuarial loss (gain), net	16,467			15,680			(585		)	(839		)
Net periodic cost (benefit) before regulatory adjustment	32,216			31,016			(644		)	(632		)
Regulatory adjustment (a)	9,864			9,919			(1,434		)	(1,458		)
Net periodic cost (benefit)	$	42,080		$	40,935		$	(2,078	)	$	(2,090	)

_______________


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

During the nine months ended September 30, 2017 and 2016, we contributed $20.6 million and $15.7 million, respectively, to the Westar Energy pension trust.

Wolf Creek Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 30, 2017

Defined Benefit Plan [Abstract]

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,950		$	1,687		$	37		$	31
Interest cost	2,475			2,413			70			81
Expected return on plan assets	(2,643		)	(2,431		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,245			1,090			(13		)	(3		)
Net periodic cost before regulatory adjustment	3,041			2,773			94			109
Regulatory adjustment (a)	247			483			—			—
Net periodic cost	$	3,288		$	3,256		$	94		$	109

_______________


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



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,850		$	5,061		$	110		$	95
Interest cost	7,425			7,241			210			244
Expected return on plan assets	(7,928		)	(7,292		)	—			—
Amortization of unrecognized:
Prior service costs	41			42			—			—
Actuarial loss (gain), net	3,734			3,268			(38		)	(11		)
Net periodic cost before regulatory adjustment	9,122			8,320			282			328
Regulatory adjustment (a)	740			1,449			—			—
Net periodic cost	$	9,862		$	9,769		$	282		$	328

_______________


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

During the nine months ended September 30, 2017 and 2016, we funded $12.0 million and $14.6 million, respectively, of Wolf Creek’s pension plan contributions.

Commitments And Contingencies	9 Months Ended
Commitments And Contingencies	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES Environmental Matters Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below. Cross-State Air Pollution Update Rule In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxide (NOx) emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and established an ozone season budget for Kansas. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit. We do not believe this rule will have a material impact on our operations and condensed 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 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 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment (KDHE) recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as attainment/unclassifiable. The EPA was required to make attainment/nonattainment designations for the revised standards by October 2017, with an option to extend this deadline by one year. However, the EPA failed to issue these designations by the October 2017 deadline. If the EPA agrees with the recommended designations for the state of Kansas, we do not believe this will have a material impact on our condensed consolidated financial results. Various states and others are challenging the revised 2015 ozone NAAQS in the D.C. Circuit. In April 2017, at the request of the EPA, the court issued an order holding the case in abeyance because the new administration is planning to review the 2015 ozone NAAQS and will determine whether to reconsider all or a portion of the rule. In October 2017, environmental groups sent a notice to the EPA of their intent to sue for failure to make the required area designations by the October 2017 deadline. 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 attainment/unclassifiable with the standard. We do not believe this will have a material impact on our operations or condensed consolidated financial results. In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable. In addition, in January 2017, KDHE formally recommended to the EPA 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 that governs the next round of the designations. Also in January 2017, KDHE recommended the EPA change the designation of the area surrounding the facility from unclassifiable to attainment/unclassifiable. In August 2017, the EPA indicated they would address this area redesignation request in a separate action. By agreeing to the 2,000 ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and condensed 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 condensed 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 (NSPS) for GHGs that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per MWh depending on various characteristics of the units. Legal challenges to the GHG NSPS have been filed in the D.C. Circuit by various states and industry members. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including us, in the D.C. Circuit. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before an en banc panel of D.C. Circuit judges and a decision on the legal challenges is pending. In March 2017, President Trump signed an Executive Order instructing the EPA to immediately review the CPP and GHG NSPS, and “if appropriate . . . as soon as practicable . . . publish for notice and comment proposed rules suspending, revising or rescinding those rules.” On the same day the Executive Order was signed, the EPA filed motions with the D.C. Circuit asking the court to hold the challenges to the CPP and the GHG NSPS in abeyance while the EPA completes its administrative review of the rules and issues any forthcoming rulemakings. In April 2017, the court issued orders to hold the cases in abeyance for 60 days and requested briefing on whether the cases should be remanded to the EPA or continue to be held in abeyance. In May 2017, all parties in the case filed supplemental briefs stating their positions regarding remanding the rule back to the EPA or continuing to hold the case in abeyance. Also in April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details, in light of the Executive Order and the agency’s review of the CPP. Also in April 2017, the EPA published a notice in the Federal Register that it is initiating administrative reviews of the CPP and the GHG NSPS in light of the Executive Order. In October 2017, the EPA issued a proposed rule to repeal the CPP. The proposed rule indicates the CPP exceeds EPA’s authority and the EPA has not determined whether or not they will issue a replacement rule. The EPA is soliciting comments on the legal interpretations contained in this rulemaking. Comments on the proposed rule are due in December 2017. On the same day the EPA issued its proposal to repeal the CPP, the EPA filed a motion in the D.C. Circuit to extend the abeyance period for the rulemaking challenges until the conclusion of the new rulemaking. Certain states and environmental groups have opposed the EPA’s motion and asked the court to issue its ruling on the CPP. Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, 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 effluent limitations guidelines (ELGs) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2018 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending the EPA’s review. In September 2017, the EPA finalized a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for bottom ash transport water and flue gas desulfurization wastewater. These compliance dates have been postponed for two years while the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form. 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 or cooling lakes that can be classified as closed cycle cooling. We do not expect the impact from this rule 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 (WOTUS) 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 and others have filed lawsuits challenging the WOTUS rule in district courts and courts of appeals across the country. The appellate court challenges have been consolidated in the U.S. Court of Appeals for the Sixth Circuit and, in October 2015, the Sixth Circuit issued an order that temporarily stays implementation of the WOTUS rule nationwide pending the outcome of the various legal challenges. In July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results. Regulation of Coal Combustion Residuals In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), 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 CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017 and 2018. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. Electric generation industry participants requested and the EPA has granted a request to reconsider portions of the final CCR regulation. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or condensed 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. In 2016, the SPP completed a process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are generation interconnection or transmission service projects that benefit SPP members and that are paid for directly by a sponsor without customer support. The SPP determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, in November 2016 we paid the SPP $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. In October 2017, the SPP issued revised allocations and we believe we will receive a small refund. 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. Wolf Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE began accepting spent nuclear fuel. As a co-owner of Wolf Creek, we received $0.8 million of the settlement representing reimbursement of costs incurred through 2015 for project planning. Wolf Creek submitted a settlement claim to the DOE in August 2017 for costs incurred between January 2016 and June 2017, with our share of the claim being approximately $0.5 million. 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.

Asset Retirement Obligations (Notes)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

In 2017, Wolf Creek filed a nuclear decommissioning cost study with the KCC. As a result of the study, we recorded a $19.4 million increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek. In addition, we revised other AROs by $40.8 million relating to asbestos removal, CCR and windfarms other than Western Plains Wind Farm. We recorded a new ARO liability of approximately $13.5 million corresponding to placing Western Plains Wind Farm in service. See Note 11, “Commitments and Contingencies - Regulation of Coal Combustion Residuals,” for additional information related to the CCR rule.

The change in the balance of our ARO liability from December 31, 2016, through September 30, 2017, is summarized in the following table.



	(In Thousands)
Balance as of December 31, 2016	$	323,951
Increase in ARO liabilities	13,471
Liabilities settled	(1,928		)
Accretion expense	12,353
Revision to nuclear decommissioning ARO liability	19,377
Revisions in estimated cash flows	40,829
Balance as of September 30, 2017	408,053
Balance included in other current liabilities	(10,548		)
Long-term AROs	$	397,505

Legal Proceedings	9 Months Ended
Legal Proceedings	Sep. 30, 2017
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 condensed 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 original merger agreement in May 2016, two putative class action petitions (which were consolidated and superseded by a consolidated class action petition) and one putative derivative petition challenging the original merger were filed in the District Court of Shawnee County, Kansas. In September 2016, the plaintiffs in both actions agreed in principle to dismiss the actions in exchange for our agreement to make supplemental disclosures to shareholders in connection with the original merger agreement and grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in a sale process that was conducted as part of the original merger agreement. As described below, since the announcement of the revised merger agreement, the plaintiffs in the consolidated putative class action has moved to amend their petition, and the plaintiff in the putative derivative case has refiled his petition. The consolidated putative class action petition, originally filed July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This petition named as defendants Westar Energy, the members of our board of directors and Great Plains Energy. On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an amended petition. The proposed petition now includes an additional plaintiff. The petition challenges the revised proposed merger and alleges a claim of breach of fiduciary duty against our board of directors and a claim of aiding and abetting that alleged breach against us and Great Plains Energy. The lawsuit seeks injunctive relief declaring the action maintainable as a class action and certifying that the plaintiffs are the class representatives; preliminarily and permanently enjoining the defendants from closing the merger unless we implement a procedure to obtain a merger agreement providing fair and reasonable terms and consideration to the plaintiffs and the class; rescinding the merger agreement or granting the plaintiffs and the class rescissory damages; directing our board of directors to account to the plaintiffs and the class for damages suffered as a result of the alleged breach of fiduciary duty; awarding the plaintiffs reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The proposed amended petition alleges inadequacies in our joint proxy statement concerning the revised proposed transaction and the degree to which our board of directors solicited or considered offers from prior bidders after the proposed original merger was denied by the KCC, and claims that the consideration our stockholders stand to receive in connection with the revised proposed transaction is unfair. Plaintiffs have added two new defendants, Monarch Energy Holding, Inc. and King Energy, Inc., whom they allege aided and abetted our board of directors in breaching their fiduciary duties. On October 18, 2017, the putative derivative petition, captioned Braunstein v. Chandler et al., Case No. 2017-CV-000692, was re-filed in the District Court of Shawnee County, Kansas. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy, and subsidiaries of Great Plains Energy, with Westar Energy named as a nominal defendant. The petition asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with actions taken after the KCC rejected the proposed original merger. It also asserts that Great Plains Energy and subsidiaries of Great Plains Energy aided and abetted such breaches of fiduciary duties. The petition alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that members of our board of directors committed waste by not collecting termination fees that may have been payable following the KCC’s rejection of the original merger agreement. The petition seeks, among other remedies, an order enjoining the merger on the terms proposed and directing 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 merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement if consummated, the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and an award for costs, including attorneys’ fees and experts’ fees. In addition, on September 21, 2017, a putative class action lawsuit was filed in the United States District Court for the District of Kansas. The federal class action complaint challenges the merger and alleges violations of sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended (Exchange Act). The complaint seeks an order declaring that the action is maintainable as a class action and certifying that the plaintiff is the class representative; preliminarily and permanently enjoining defendants from consummating the mergers or, if consummated, setting them aside and awarding rescissory damages; directing the defendants to file a registration statement on Form S-4 that corrects alleged misstatements; directing our board of directors to account to plaintiff and the class for their damages; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other further relief as the court deems proper. The case is captioned David Pill v. Westar Energy, Inc. et al, Civil Action No. 17-4086. On October 6, 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas. This federal class action complaint challenges the proposed merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act. The complaint seeks an order enjoining the board and other parties from proceeding with, consummating, or closing the merger or, if consummated, setting it aside and awarding rescissory damages; directing the board to disseminate a registration statement that corrects alleged misstatements and includes all material facts the plaintiff asserts are missing; declaring that the defendants violated sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The case is captioned Robert L. Reese v. Westar Energy, Inc. et al, Civil Action No. 2:17-cv-02584.

Variable Interest Entities

9 Months Ended

Sep. 30, 2017

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 trust holding our 50% interest in La Cygne unit 2 is a VIE. The trust holding our 8% interest in Jeffrey Energy Center (JEC) was a VIE until the expiration of a purchase option in July 2017. We remain the primary beneficiary of the trust holding our 50% interest in La Cygne unit 2.

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 VIE 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 met the requirements to be considered the primary beneficiary of the trust until July 2017, when a contractual option to purchase the 8% interest in the plant covered by the lease expired. Accordingly, we deconsolidated the trust in the third quarter of 2017.

In determining the primary beneficiary of the trust, we concluded at the inception of the lease that the activities of the trust that most significantly impacted its economic performance and that we had the power to direct included (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise an option that expired in July 2017 to purchase the plant 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 had 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 was greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also created 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.

Financial Statement Impact

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



	As of		As of
	September 30, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	178,058	$	257,904
Regulatory assets (a)	—		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,534	$	26,842
Accrued interest (b)	—		867
Long-term debt of variable interest entities, net	81,433		111,209

_______________

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

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

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

Summary Of Significant Accounting Policies (Policy)	9 Months Ended
Summary Of Significant Accounting Policies (Policy)	Sep. 30, 2017
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements We prepare our condensed 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 that may affect our accounting and/or disclosure. Compensation - Retirement Benefits In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our condensed consolidated financial statements. Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. 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. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. 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 modified retrospective method. We will use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. We have analyzed and documented the impact of the new revenue standard and related ASU’s for our significant revenue streams including retail, transmission and wholesale, as well as other less significant revenue streams. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. We are finalizing our analysis of revenue-related controls and development of revenue-related disclosure with an overarching emphasis on effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material.
Principles Of Consolidation	Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.
Use Of Management's Estimates	Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and nine months ended September 30, 2017, are not necessarily indicative of the results to be expected for the full year.
Fuel Inventory And Supplies	Fuel Inventory and Supplies We state fuel inventory and supplies at average cost.
Allowance For Funds Used During Construction	Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost
Earnings Per Share	Earnings Per Share We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

Summary Of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Schedule of Utility Inventory

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



	As of		As of
	September 30, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	87,429	$	107,086
Supplies	197,645		193,039
Fuel inventory and supplies	$	285,074	$	300,125

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 condensed consolidated statements of income as follows.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Dollars In Thousands)
Borrowed funds	$	1,210		$	2,537		$	3,958		$	6,884
Equity funds	321			2,647			1,094			7,894
Total	$	1,531		$	5,184		$	5,052		$	14,778
Average AFUDC Rates	2.2		%	3.6		%	2.0		%	4.2		%

Reconciliation Of Basic And Diluted EPS

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	160,724	$	158,553	$	300,245	$	303,405
Less: Net income attributable to noncontrolling interests	2,418		3,833		10,213		10,760
Net income attributable to Westar Energy, Inc.	158,306		154,720		290,032		292,645
Less: Net income allocated to RSUs	289		325		515		605
Net income allocated to common stock	$	158,017	$	154,395	$	289,517	$	292,040

Weighted average equivalent common shares outstanding – basic	142,472,987		142,090,706		142,458,586		142,039,320
Effect of dilutive securities:
RSUs	43,062		487,239		37,310		373,869
Weighted average equivalent common shares outstanding – diluted (a)	142,516,049		142,577,945		142,495,896		142,413,189

Earnings per common share, basic	$	1.11	$	1.09	$	2.03	$	2.06
Earnings per common share, diluted	$	1.11	$	1.08	$	2.03	$	2.05

_______________

(a) We had no antidilutive securities for the three and nine months ended September 30, 2017 and 2016.

Supplemental Cash Flow Information



	Nine Months Ended September 30,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	108,965		$	100,828
Interest on financing activities of VIEs	3,061			5,846
Income taxes, net of refunds	(12,645		)	13,004
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	112,493			94,007
Deconsolidation of property, plant and equipment of VIE	(72,901		)	—
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,944			7,315
Deconsolidation of VIE	(83,096		)	—
Assets acquired through capital leases	4,611			1,310

Financial Instruments and Risk Management (Tables)

9 Months Ended

Sep. 30, 2017

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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



	As of September 30, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,857,763	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	109,967		110,586		137,962		139,733

Fair Value Of Assets And Liabilities

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



As of September 30, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	64,855	$	—	$	5,139	$	69,994
International equity funds	—		46,020		—		—		46,020
Core bond fund	—		32,914		—		—		32,914
High-yield bond fund	—		17,866		—		—		17,866
Emerging markets bond fund	—		17,617		—		—		17,617
Combination debt/equity/other fund	—		13,688		—		—		13,688
Alternative investments fund	—		—		—		21,063		21,063
Real estate securities fund	—		—		—		10,594		10,594
Cash equivalents	171		—		—		—		171
Total Nuclear Decommissioning Trust	171		192,960		—		36,796		229,927
Trading Securities:
Domestic equity funds	—		17,883		—		—		17,883
International equity fund	—		4,491		—		—		4,491
Core bond fund	—		11,789		—		—		11,789
Total Trading Securities	—		34,163		—		—		34,163
Total Assets Measured at Fair Value	$	171	$	227,123	$	—	$	36,796	$	264,090

As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	56,312	$	—	$	5,056	$	61,368
International equity funds	—		35,944		—		—		35,944
Core bond fund	—		27,423		—		—		27,423
High-yield bond fund	—		18,188		—		—		18,188
Emerging markets bond fund	—		14,738		—		—		14,738
Combination debt/equity/other fund	—		13,484		—		—		13,484
Alternative investments fund	—		—		—		18,958		18,958
Real estate securities fund	—		—		—		9,946		9,946
Cash equivalents	73		—		—		—		73
Total Nuclear Decommissioning Trust	73		166,089		—		33,960		200,122
Trading Securities:
Domestic equity funds	—		18,364		—		—		18,364
International equity fund	—		4,467		—		—		4,467
Core bond fund	—		11,504		—		—		11,504
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		34,335		—		—		34,491
Total Assets Measured at Fair Value	$	229	$	200,424	$	—	$	33,960	$	234,613

Unrealized Gains And Losses On Fair Value Assets And Liabilities

Investments In Financial Instruments

The following table provides additional information on these investments.



	As of September 30, 2017				As of December 31, 2016				As of September 30, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,139	$	2,929	$	5,056	$	3,529	(a)	(a)
Alternative investments fund (b)	21,063		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,594		—		9,946		—		Quarterly	65 days
Total	$	36,796	$	2,929	$	33,960	$	3,529

_______________

(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)

9 Months Ended

Sep. 30, 2017

Investments [Abstract]

Cost And Fair Value Of Investments

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of September 30, 2017, and December 31, 2016.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2017:
Domestic equity funds	$	55,387	$	15,227	$	(620	)	$	69,994	30	%
International equity funds	35,937		10,083		—			46,020		20	%
Core bond fund	32,980		—		(66		)	32,914		14	%
High-yield bond fund	17,450		416		—			17,866		8	%
Emerging markets bond fund	17,186		431		—			17,617		8	%
Combination debt/equity/other fund	8,068		5,620		—			13,688		6	%
Alternative investments fund	15,000		6,063		—			21,063		9	%
Real estate securities fund	9,500		1,094		—			10,594		5	%
Cash equivalents	171		—		—			171		<1%
Total	$	191,679	$	38,934	$	(686	)	$	229,927	100	%

As of December 31, 2016:
Domestic equity funds	$	53,192	$	8,295	$	(119	)	$	61,368	31	%
International equity funds	34,502		2,075		(633		)	35,944		18	%
Core bond fund	27,952		—		(529		)	27,423		14	%
High-yield bond fund	18,358		—		(170		)	18,188		9	%
Emerging markets bond fund	16,397		—		(1,659		)	14,738		7	%
Combination debt/equity/other fund	9,171		4,313		—			13,484		7	%
Alternative investments fund	15,000		3,958		—			18,958		9	%
Real estate securities fund	9,500		446		—			9,946		5	%
Cash equivalents	73		—		—			73		<1%
Total	$	184,145	$	19,087	$	(3,110	)	$	200,122	100	%

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

September 30, 2017, and December 31, 2016.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2017:
Domestic equity funds	$	1,809	$	(337	)	$	1,904	$	(283	)	$	3,713	$	(620	)
Core bond fund	32,914		(66		)	—		—			32,914		(66		)
Total	$	34,723	$	(403	)	$	1,904	$	(283	)	$	36,627	$	(686	)

As of December 31, 2016:
Domestic equity funds	$	1,788	$	(119	)	$	—	$	—		$	1,788	$	(119	)
International equity funds	—		—			7,489		(633		)	7,489		(633		)
Core bond fund	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging markets bond fund	—		—			14,738		(1,659		)	14,738		(1,659		)
Total	$	29,211	$	(648	)	$	40,415	$	(2,462	)	$	69,626	$	(3,110	)

Pension and Post-Retirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,922			1,314			1,392
Expected return on plan assets	(10,760		)	(10,664		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			113
Actuarial loss (gain), net	5,489			5,146			(195		)	(279		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(697	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	15,655		$	13,930		$	813		$	813
Interest cost	31,862			32,802			3,941			4,178
Expected return on plan assets	(32,280		)	(31,990		)	(5,154		)	(5,125		)
Amortization of unrecognized:
Prior service costs	512			594			341			341
Actuarial loss (gain), net	16,467			15,680			(585		)	(839		)
Net periodic cost (benefit) before regulatory adjustment	32,216			31,016			(644		)	(632		)
Regulatory adjustment (a)	9,864			9,919			(1,434		)	(1,458		)
Net periodic cost (benefit)	$	42,080		$	40,935		$	(2,078	)	$	(2,090	)

_______________


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

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

9 Months Ended

Sep. 30, 2017

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,922			1,314			1,392
Expected return on plan assets	(10,760		)	(10,664		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			113
Actuarial loss (gain), net	5,489			5,146			(195		)	(279		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(697	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	15,655		$	13,930		$	813		$	813
Interest cost	31,862			32,802			3,941			4,178
Expected return on plan assets	(32,280		)	(31,990		)	(5,154		)	(5,125		)
Amortization of unrecognized:
Prior service costs	512			594			341			341
Actuarial loss (gain), net	16,467			15,680			(585		)	(839		)
Net periodic cost (benefit) before regulatory adjustment	32,216			31,016			(644		)	(632		)
Regulatory adjustment (a)	9,864			9,919			(1,434		)	(1,458		)
Net periodic cost (benefit)	$	42,080		$	40,935		$	(2,078	)	$	(2,090	)

_______________


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

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,950		$	1,687		$	37		$	31
Interest cost	2,475			2,413			70			81
Expected return on plan assets	(2,643		)	(2,431		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,245			1,090			(13		)	(3		)
Net periodic cost before regulatory adjustment	3,041			2,773			94			109
Regulatory adjustment (a)	247			483			—			—
Net periodic cost	$	3,288		$	3,256		$	94		$	109

_______________


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



	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,850		$	5,061		$	110		$	95
Interest cost	7,425			7,241			210			244
Expected return on plan assets	(7,928		)	(7,292		)	—			—
Amortization of unrecognized:
Prior service costs	41			42			—			—
Actuarial loss (gain), net	3,734			3,268			(38		)	(11		)
Net periodic cost before regulatory adjustment	9,122			8,320			282			328
Regulatory adjustment (a)	740			1,449			—			—
Net periodic cost	$	9,862		$	9,769		$	282		$	328

_______________


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

Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2017

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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



	As of		As of
	September 30, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	178,058	$	257,904
Regulatory assets (a)	—		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,534	$	26,842
Accrued interest (b)	—		867
Long-term debt of variable interest entities, net	81,433		111,209

_______________

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

(b) Included in accrued interest on our condensed 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	Sep. 30, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Total	$ 285,074	$ 300,125
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	87,429	107,086
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 197,645	$ 193,039

Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Borrowed funds	$ (1,210)	$ (2,537)	$ (3,958)	$ (6,884)
Equity funds	321	2,647	1,094	7,894
Total	$ 1,531	$ 5,184	$ 5,052	$ 14,778
Average AFUDC rates	2.20%	3.60%	2.00%	4.20%

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	$ 289	$ 325	$ 515	$ 605
Net income allocated to common stock	$ 158,017	$ 154,395	$ 289,517	$ 292,040
Weighted Average Number of Shares Outstanding , Basic	142,472,987	142,090,706	142,458,586	142,039,320
RSUs	43,062	487,239	37,310	373,869
Weighted average equivalent common shares outstanding - diluted	142,516,049	142,577,945	142,495,896	142,413,189
Earnings Per Share, Basic	$ 1.11	$ 1.09	$ 2.03	$ 2.06
Earnings Per Share, Diluted	$ 1.11	$ 1.08	$ 2.03	$ 2.05
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities			0

Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash Paid For (Received From)
Interest on financing activities	$ 108,965	$ 100,828
Income taxes, net of refunds	(12,645)	13,004
Noncash Investing and Financing Transactions
Property, plant and equipment	112,493	94,007
Issuance of common stock for reinvested dividends and compensation plans	4,944	7,315
Deconsolidation of VIE	(83,096)
Assets acquired through capital leases	4,611	1,310
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	3,061	$ 5,846
Noncash Investing and Financing Transactions
Deconsolidation of property, plant and equipment of VIE	$ (72,901)

Summary Of Significant Accounting Policies New Accounting Pronouncements (Details)	3 Months Ended
	Sep. 30, 2016
Item Effected [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	3326

- Definition

Disclosure related to a new accounting pronouncement or a change in accounting principle, including the nature and reason for the change and the effect of the change on prior periods and the current period.

+ References + Details

Pending Merger Pending Merger (Narrative) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2016	Jul. 09, 2017
Westar Energy [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio				1
Business Acquisition, Percentage of Voting Interests Acquired				52.50%
Westar Energy [Member] \| Westar Energy breaches agreement and enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				$ 190.0
Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio				0.5981
Business Acquisition, Percentage of Voting Interests Acquired				47.50%
Cash				$ 1,250.0
Business Combination, Acquisition Related Costs	$ 7.8	$ 8.6	$ 10.2
Business Combination, Expected Acquisition Related Costs		$ 45.0
Great Plains Energy, Inc. Merger [Member] \| End date occurred and Great Plains Energy enters into acquisition proposal within 12 months of termination, paid to Westar Energy [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				190.0
Great Plains Energy, Inc. Merger [Member] \| Great Plains Energy breaches merger agreement and enters into acquisition proposal within 12 months of termination [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				190.0
Great Plains Energy, Inc. Merger [Member] \| Great Plains shareholder no vote, paid to Westar Energy [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				$ 80.0

Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Oct. 31, 2017	Jun. 30, 2017	Apr. 30, 2017	Jan. 31, 2017	Dec. 31, 2016
Kansas Corporation Commission [Member] \| Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 16.4
Kansas Corporation Commission [Member] \| Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 12.7
Kansas Corporation Commission [Member] \| Ad Valorem Tax [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 26.8
Federal Energy Regulatory Commission [Member] \| Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 29.6
Subsequent Event [Member] \| Federal Energy Regulatory Commission [Member] \| Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 26.1

Financial Instruments and Risk Management (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,605,000	$ 3,430,000
Fair Value	3,857,763	3,597,441
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	109,967	137,962
Fair Value	$ 110,586	$ 139,733

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

9 Months Ended

Sep. 30, 2017

Dec. 31, 2016

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

$ 229,927

$ 200,122

Trading securities

34,163

34,491

Total

264,090

234,613

Fair Value [Member]

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

36,796

33,960

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

2,929

3,529

Domestic Equity [Member]

Domestic Equity [Member] | Fair Value [Member]

69,994

61,368

Trading securities

17,883

18,364

Financial and Derivative Instruments and Trading Securities [Line Items]

^[1]

5,139

5,056

Alternative Funds [Member]

2,929

3,529

Financial and Derivative Instruments and Trading Securities [Line Items]

Alternative Funds [Member] | Fair Value [Member]

21,063

18,958

Financial and Derivative Instruments and Trading Securities [Line Items]

21,063

18,958

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]

$ 10,594

9,946

Financial and Derivative Instruments and Trading Securities [Line Items]

10,594

9,946

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

^[2]

65 days

[1]

[2]

There is a holdback on final redemptions.

Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 34,163		$ 34,163		$ 34,491
Unrealized gains losses	1,000	$ 1,000	3,500	$ 2,200
Realized gains on available-for-sale-securities	$ 0	$ 0	$ 100	$ 1,500

Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,000	$ 1,000	$ 3,500	$ 2,200
Trading securities	34,163		34,163		$ 34,491
Cost	191,679		191,679		184,145
Available-for-sale Securities, Gross Unrealized Gain	38,934		38,934		19,087
Available-for-sale Securities, Gross Unrealized Loss	(686)		(686)		(3,110)
Available-for-sale Securities	$ 229,927		$ 229,927		$ 200,122
Allocation	100.00%		100.00%		100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 17,883		$ 17,883		$ 18,364
Cost	55,387		55,387		53,192
Available-for-sale Securities, Gross Unrealized Gain	15,227		15,227		8,295
Available-for-sale Securities, Gross Unrealized Loss	(620)		(620)		(119)
Available-for-sale Securities	$ 69,994		$ 69,994		$ 61,368
Allocation	30.00%		30.00%		31.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 4,491		$ 4,491		$ 4,467
Cost	35,937		35,937		34,502
Available-for-sale Securities, Gross Unrealized Gain	10,083		10,083		2,075
Available-for-sale Securities, Gross Unrealized Loss	0		0		(633)
Available-for-sale Securities	$ 46,020		$ 46,020		$ 35,944
Allocation	20.00%		20.00%		18.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 11,789		$ 11,789		$ 11,504
Cost	32,980		32,980		27,952
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(66)		(66)		(529)
Available-for-sale Securities	$ 32,914		$ 32,914		$ 27,423
Allocation	14.00%		14.00%		14.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,450		$ 17,450		$ 18,358
Available-for-sale Securities, Gross Unrealized Gain	416		416		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(170)
Available-for-sale Securities	$ 17,866		$ 17,866		$ 18,188
Allocation	8.00%		8.00%		9.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,186		$ 17,186		$ 16,397
Available-for-sale Securities, Gross Unrealized Gain	431		431		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(1,659)
Available-for-sale Securities	$ 17,617		$ 17,617		$ 14,738
Allocation	8.00%		8.00%		7.00%
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 8,068		$ 8,068
Available-for-sale Securities, Gross Unrealized Gain	5,620		5,620
Available-for-sale Securities, Gross Unrealized Loss	0		0
Available-for-sale Securities	$ 13,688		$ 13,688
Allocation	6.00%		6.00%
Combination Debt and Equity Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost					$ 9,171
Available-for-sale Securities, Gross Unrealized Gain					4,313
Available-for-sale Securities, Gross Unrealized Loss					0
Available-for-sale Securities					$ 13,484
Allocation					7.00%
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	6,063		6,063		3,958
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 21,063		$ 21,063		$ 18,958
Allocation	9.00%		9.00%		9.00%
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,500		$ 9,500		$ 9,500
Available-for-sale Securities, Gross Unrealized Gain	1,094		1,094		446
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 10,594		$ 10,594		$ 9,946
Allocation	5.00%		5.00%		5.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities					$ 156
Cost	$ 171		$ 171		73
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 171		$ 171		$ 73

Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,000	$ 1,000	$ 3,500	$ 2,200
Fair Value, Less than 12 Months	34,723		34,723		$ 29,211
Gross Unrealized Losses, Less than 12 Months	(403)		(403)		(648)
Fair Value, 12 Months or Greater	1,904		1,904		40,415
Gross Unrealized Losses, 12 Months or Greater	(283)		(283)		(2,462)
Fair Value, Total	36,627		36,627		69,626
Gross Unrealized Losses, Total	(686)		(686)		(3,110)
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	1,809		1,809		1,788
Gross Unrealized Losses, Less than 12 Months	(337)		(337)		(119)
Fair Value, 12 Months or Greater	1,904		1,904		0
Gross Unrealized Losses, 12 Months or Greater	(283)		(283)		0
Fair Value, Total	3,713		3,713		1,788
Gross Unrealized Losses, Total	(620)		(620)		(119)
International Equity [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					7,489
Gross Unrealized Losses, 12 Months or Greater					(633)
Fair Value, Total					7,489
Gross Unrealized Losses, Total					(633)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	32,914		32,914		27,423
Gross Unrealized Losses, Less than 12 Months	(66)		(66)		(529)
Fair Value, 12 Months or Greater	0		0		0
Gross Unrealized Losses, 12 Months or Greater	0		0		0
Fair Value, Total	32,914		32,914		27,423
Gross Unrealized Losses, Total	$ (66)		$ (66)		(529)
High-Yield Bonds [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					18,188
Gross Unrealized Losses, 12 Months or Greater					(170)
Fair Value, Total					18,188
Gross Unrealized Losses, Total					(170)
Emerging Market Bonds [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					14,738
Gross Unrealized Losses, 12 Months or Greater					(1,659)
Fair Value, Total					14,738
Gross Unrealized Losses, Total					$ (1,659)

Debt Financing (Narrative) (Details) - Westar Energy [Member] - Secured Debt [Member] - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2017	Mar. 06, 2017
Debt Instrument Two [Member]
Debt Instrument [Line Items]
Repayments of Debt	$ 125.0
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument 8930 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 300.0
Debt Instrument, Interest Rate, Stated Percentage		3.10%

Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Income Tax Contingency [Line Items]
Income tax expense	$ 55,743	$ 81,211	$ 112,559	$ 160,376
Effective income tax rate	26.00%	34.00%	27.00%	35.00%
Liability for unrecognized income tax benefits	$ 1,600		$ 1,600		$ 2,800
Interest on liability related to unrecognized income tax benefits	100		100		0
Penalties accrued for unrecognized income tax benefits	0		0		0
Accrual for taxes other than income taxes	$ 200		$ 200		$ 1,500

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Payment for Pension Benefits

$ 20,600

$ 15,700

Pension Benefits [Member]

$ 5,218

$ 4,633

15,655

13,930

10,621

10,922

31,862

32,802

(10,760)

(10,664)

(32,280)

(31,990)

171

174

512

594

5,489

5,146

16,467

15,680

10,739

10,211

32,216

31,016

3,288

^[1]

3,306

^[1]

9,864

^[2]

9,919

^[2]

Post-Retirement Benefits [Member]

14,027

13,517

42,080

40,935

271

813

1,314

1,392

3,941

4,178

(1,718)

(1,708)

(5,154)

(5,125)

114

113

341

(195)

(279)

(585)

(839)

(214)

(211)

(644)

(632)

(478)

^[1]

(486)

^[1]

(1,434)

^[2]

(1,458)

^[2]

$ (692)

$ (697)

$ (2,078)

$ (2,090)

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

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Payment for Pension Benefits

$ 20,600

$ 15,700

Wolf Creek [Member]

Payment for Pension Benefits

$ 12,000

14,600

KGE Member

Subsidiary Interest in Defined Benefit Plans

47.00%

Pension Benefits [Member]

$ 5,218

$ 4,633

$ 15,655

13,930

10,621

10,922

31,862

32,802

(10,760)

(10,664)

(32,280)

(31,990)

171

174

512

594

5,489

5,146

16,467

15,680

10,739

10,211

32,216

31,016

3,288

^[1]

3,306

^[1]

9,864

^[2]

9,919

^[2]

Pension Benefits [Member] | Wolf Creek [Member]

14,027

13,517

42,080

40,935

1,950

1,687

5,850

5,061

2,475

2,413

7,425

7,241

(2,643)

(2,431)

(7,928)

(7,292)

1,245

1,090

3,734

3,268

3,041

2,773

9,122

8,320

247

^[3]

483

^[3]

740

^[4]

1,449

^[4]

Post-Retirement Benefits [Member]

3,288

3,256

9,862

9,769

271

813

1,314

1,392

3,941

4,178

(1,718)

(1,708)

(5,154)

(5,125)

114

113

341

(195)

(279)

(585)

(839)

(214)

(211)

(644)

(632)

(478)

^[1]

(486)

^[1]

(1,434)

^[2]

(1,458)

^[2]

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

(692)

(697)

(2,078)

(2,090)

110

210

244

(13)

(3)

(38)

(11)

109

282

328

^[3]

^[4]

Variable Interest Entity [Line Items]

$ 94

$ 109

$ 282

$ 328

[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.

Commitments And Contingencies Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Nov. 30, 2016	Aug. 30, 2017	Jun. 02, 2017
Loss Contingencies [Line Items]
Loss Contingency Accrual, Payments	$ 7.6
Settlement Assets, Current		$ 0.5	$ 0.8

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Liabilities Incurred	$ 13,471
Asset Retirement Obligation, Liabilities Settled	1,928
Asset Retirement Obligation, Accretion Expense	12,353
Asset Retirement Obligation, Revision of Estimate	40,829
Asset Retirement Obligation	408,053	$ 323,951
Asset Retirement Obligation, Current	(10,548)
Asset Retirement Obligations, Noncurrent	397,505	$ 323,951
Wolf Creek [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate	$ 19,377

Variable Interest Entities (Narrative) (Details)	9 Months Ended
Variable Interest Entities (Narrative) (Details)	Sep. 30, 2017 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Consolidated, Liabilities, Noncurrent, Recourse	$ 0
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

Sep. 30, 2017

Dec. 31, 2016

$ 9,494,023

$ 9,248,359

125,000

^[1]

64,851

72,519

Variable Interest Entity, Primary Beneficiary [Member]

3,686,852

3,388,670

Variable Interest Entity [Line Items]

178,058

257,904

Regulatory assets

^[2]

10,396

28,534

26,842

^[1]

867