27,070

29,701

Total Current Assets

721,100

768,382

Nuclear decommissioning trust

9,321,669

9,248,359

OTHER ASSETS:

Regulatory assets

751,437

762,479

212,820

200,122

253,243

249,828

Total Other Assets

1,217,500

1,212,429

TOTAL ASSETS

11,515,590

11,487,074

CURRENT LIABILITIES:

125,000

Short-term debt

226,300

366,700

Accounts payable

162,231

220,522

Accrued dividends

55,771

52,885

Accrued taxes

126,497

85,729

^[1]

85,612

72,519

Regulatory liabilities

11,973

15,760

Total Current Liabilities

69,816

81,236

766,738

1,047,193

LONG-TERM LIABILITIES:

Unamortized investment tax credits

3,685,752

3,388,670

Deferred income taxes

1,767,299

1,752,776

209,968

210,654

Regulatory liabilities

226,943

223,693

Accrued employee benefits

511,368

512,412

Asset retirement obligations

349,933

323,951

Total Long-Term Liabilities

83,757

83,326

6,917,683

6,606,691

COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)

Westar Energy, Inc. Shareholders' Equity:

Common stock, par value $5 per share

710,238

708,956

Paid-in capital

2,015,287

2,018,317

Retained earnings

1,080,268

1,078,602

Total Westar Energy, Inc. Shareholders' Equity

3,805,793

3,805,875

Noncontrolling Interests

25,376

27,315

Total Equity

3,831,169

3,833,190

TOTAL LIABILITIES AND EQUITY

11,515,590

11,487,074

Variable Interest Entity [Member]

CURRENT ASSETS:

255,321

257,904

CURRENT LIABILITIES:

28,538

26,842

^[1]

867

LONG-TERM LIABILITIES:

Summary Of Significant Accounting Policies

$ 82,663

$ 111,209

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

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Allowance for doubtful accounts	$ 8,420	$ 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	142,047,633	141,791,153
Common stock, shares outstanding	142,047,633	141,791,153

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended
Consolidated Statements Of Income - USD ($) $ in Thousands	Mar. 31, 2017	Mar. 31, 2016
REVENUES	$ 572,574	$ 569,450
OPERATING EXPENSES:
Fuel and purchased power	113,855	100,058
Network Transmission Cost	60,674	60,760
Operating and maintenance	81,198	77,757
Depreciation and amortization	88,625	83,640
Selling, general and administrative	59,157	56,456
Taxes, Miscellaneous	42,716	48,968
Total Operating Expenses	446,225	427,639
INCOME FROM OPERATIONS	126,349	141,811
OTHER INCOME (EXPENSE):
Investment earnings (losses)	3,155	2,016
Other income	1,300	9,477
Other expense	(5,316)	(5,543)
Total Other Income	(861)	5,950
Interest expense	41,095	40,431
INCOME BEFORE INCOME TAXES	84,393	107,330
Income tax expense	20,911	38,622
NET INCOME	63,482	68,708
Less: Net income attributable to noncontrolling interests	3,821	3,123
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 59,661	$ 65,585
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 0.42	$ 0.46
Earnings Per Share, Diluted	$ 0.42	$ 0.46
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,436,622	141,992,846
Weighted Average Number of Shares Outstanding, Diluted	142,695,606	142,311,228
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.40	$ 0.38

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 63,482	$ 68,708
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	88,625	83,640
Amortization of nuclear fuel	8,069	8,329
Amortization of deferred regulatory gain from sale leaseback	(1,374)	(1,374)
Amortization of corporate-owned life insurance	5,901	5,261
Non-cash compensation	2,468	2,491
Net deferred income taxes and credits	19,011	33,984
Allowance for equity funds used during construction	(775)	(2,464)
Changes in working capital items:
Accounts receivable	51,547	33,196
Fuel inventory and supplies	(10,581)	109
Prepaid expenses and other	27,399	7,712
Accounts payable	(23,135)	(31,158)
Accrued taxes	47,775	49,339
Other current liabilities	(54,223)	(28,984)
Changes in other assets	2,328	21,933
Changes in other liabilities	10,606	(11,846)
Cash Flows from Operating Activities	237,123	238,876
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(175,400)	(220,849)
Purchase of securities - trusts	(4,191)	(13,712)
Sale of securities - trusts	5,720	16,332
Proceeds from investment in corporate-owned life insurance	103	23,963
Investment in affiliated company	0	(655)
Other investing activities	(2,354)	(2,840)
Cash Flows used in Investing Activities	(176,122)	(197,761)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(140,407)	66,500
Proceeds from long-term debt	296,475	0
Retirements of long-term debt	(125,000)	0
Repayment of capital leases	(800)	(675)
Borrowings against cash surrender value of corporate-owned life insurance	910	963
Repayment of borrowings against cash surrender value of corporate-owned life insurance	0	(22,837)
Issuance of common stock	470	657
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(5,760)	(2,550)
Cash dividends paid	(52,750)	(49,665)
Other financing activities	(7,006)	(4,961)
Cash Flows from Financing Activities	(60,708)	(40,875)
NET CHANGE IN CASH AND CASH EQUIVALENTS	293	240
CASH AND CASH EQUIVALENTS:
Beginning of period	3,066	3,231
End of period	3,359	3,471
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)	(190,355)
Noncontrolling Interest [Member]
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	3,821	3,123
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	$ (5,760)	$ (2,550)

Consolidated Statements Of Changes In Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Beginning Balance at Dec. 31, 2015	$ 3,671,963	$ 706,767	$ 2,004,124	$ 945,830	$ 15,242
Beginning Balance (Shares) at Dec. 31, 2015		141,353,426
Net income	68,708	$ 0	0	65,585	3,123
Issuance of stock	657	$ 75	582	0	0
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		260,229
Issuance of stock (shares)		14,907
Issuance Of Stock For Compensation And Reinvested Dividends	2,405	$ 1,301	1,104
Tax withholding related to stock compensation	(4,961)		4,961
Dividends on common stock	(54,805)	0	0	(54,805)	0
Stock compensation expense	2,462		2,462
Distributions to shareholders of noncontrolling interests	(2,550)				(2,550)
Ending Balance at Mar. 31, 2016	3,687,205	$ 708,143	2,003,311	959,936	15,815
Ending Balance (Shares) at Mar. 31, 2016		141,628,562
Stockholders' Equity, Other	3,326		0
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				3,326
Beginning Balance at Dec. 31, 2016	3,833,190	$ 708,956	2,018,317	1,078,602	27,315
Beginning Balance (Shares) at Dec. 31, 2016		141,791,153
Net income	63,482	$ 0	0	59,661	3,821
Issuance of stock	470	$ 43	427	0	0
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		247,834
Issuance of stock (shares)		8,646
Issuance Of Stock For Compensation And Reinvested Dividends	2,349	$ 1,239	1,110
Tax withholding related to stock compensation	(7,006)		7,006
Dividends on common stock	(57,995)	0	0	(57,995)	0
Stock compensation expense	2,439		2,439
Distributions to shareholders of noncontrolling interests	(5,760)				(5,760)
Ending Balance at Mar. 31, 2017	$ 3,831,169	$ 710,238	$ 2,015,287	$ 1,080,268	$ 25,376
Ending Balance (Shares) at Mar. 31, 2017		142,047,633

Description Of Business	3 Months Ended
Description Of Business	Mar. 31, 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 701,000 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

3 Months Ended

Mar. 31, 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 GAAP for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 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 months ended March 31, 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
	March 31, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	115,921	$	107,086
Supplies	194,940		193,039
Fuel inventory and supplies	$	310,861	$	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 March 31,
	2017			2016
	(Dollars In Thousands)
Borrowed funds	$	1,853		$	2,008
Equity funds	775			2,464
Total	$	2,628		$	4,472
Average AFUDC Rates	2.2		%	5.2		%

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 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 March 31,
	2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	63,482	$	68,708
Less: Net income attributable to noncontrolling interests	3,821		3,123
Net income attributable to Westar Energy, Inc.	59,661		65,585
Less: Net income allocated to RSUs	108		135
Net income allocated to common stock	$	59,553	$	65,450

Weighted average equivalent common shares outstanding – basic	142,436,622		141,992,846
Effect of dilutive securities:
RSUs	258,984		318,382
Weighted average equivalent common shares outstanding – diluted (a)	142,695,606		142,311,228

Earnings per common share, basic	$	0.42	$	0.46
Earnings per common share, diluted	$	0.42	$	0.46

_______________

(a)We had no antidilutive securities for the three months ended March 31, 2017 and 2016.

Supplemental Cash Flow Information



	Three Months Ended March 31,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	35,644		$	30,415
Interest on financing activities of VIEs	1,696			4,150
Income taxes, net of refunds	(13,000		)	(383		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	97,196			130,532
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	2,349			2,405
Assets acquired through capital leases	293			180

New Accounting Pronouncements

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

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update 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 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 cumulative effect transition method. We have not yet selected a transition method. We continue to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. In summary, material revenue streams were identified and representative contract/transaction types were sampled. 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. Based upon our completed assessments, we do not expect the impact on our consolidated financial statements to be material.

Pending Merger Pending Merger (Notes)	3 Months Ended
Pending Merger Pending Merger (Notes)	Mar. 31, 2017
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	On May 29, 2016, we entered into an agreement and plan of merger (merger) with Great Plains Energy, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock. The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement, without prior approval of Great Plains Energy, limits our quarterly dividends declared in 2017 to $0.40 per share, which represents an annualized increase of $0.08 per share, consistent with last year’s dividend increase. The closing of the merger is subject to customary conditions including, among others, receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On April 19, 2017, the KCC rejected the merger application citing, among other concerns, an excessive purchase price, Great Plains Energy’s capital structure, quantifiable and demonstrable customer benefits and staffing levels in our service territory. On May 4, 2017, we and Great Plains Energy filed with the KCC a petition for reconsideration of the KCC’s order and to set the matter for further proceedings so that we and Great Plains Energy may work together to determine whether it is feasible to develop a revised transaction that addresses the KCC’s concerns. Under applicable Kansas regulations, the KCC has 30 days following the filing of the petition for reconsideration to either deny or grant the petition. If we and Great Plains Energy agree on a revised transaction, then we and Great Plains Energy would expect to file the revised proposal and a supplemental application with the KCC. In addition, there are two open dockets in Missouri related to the merger. In the first docket, Great Plains Energy sought approval from the Public Service Commission of the State of Missouri (MPSC) to waive certain affiliate transaction rules following the closing of the merger. In this docket, on October 12, 2016, and on October 26, 2016, the MPSC staff and the Office of Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that MPSC staff and the OPC would not file a complaint, or support another complaint, to assert that the MPSC has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the MPSC. Regarding the second docket, on October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the MPSC seeking to have the MPSC assert jurisdiction over the merger, and various parties have intervened in these complaints. The MPSC dismissed the complaint against us on December 6, 2016, but on February 22, 2017, the MPSC ordered that Great Plains Energy was required to obtain MPSC approval prior to consummation of the merger. On February 23, 2017, Great Plains Energy filed an application with the MPSC seeking approval of the merger. The merger application docket was consolidated with the affiliate transaction waiver docket. Several parties filed testimony and the evidentiary hearing was held in April 2017. On April 20, 2017, after the KCC’s order rejecting the merger was issued, Great Plains Energy filed a motion to suspend the briefing schedule in the MPSC merger docket, effectively suspending that proceeding indefinitely until Great Plains Energy takes further action in the docket. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. Approval of the merger application requires action by the FERC commissioners because it is a contested application. The Federal Power Act (FPA) requires a quorum of three or more commissioners to act on a contested application. Following the resignation of the FERC Chairman effective February 3, 2017, the FERC commission is comprised only of two commissioners and is therefore unable to act on the application. A new commissioner must be appointed by the President of the United States, with the advice and consent of the United States Senate, before FERC will be able to act on the application. If the FERC commissioners do not issue an order on the application within 180 days after the application was deemed complete because of the lack of a quorum, approval of the application may be deemed granted by operation of law, unless an order is issued extending the time for review. On May 3, 2017, the FERC staff extended the time period for a review of the application until November 1, 2017. We are unable to predict when FERC will regain a quorum or how the change in commissioners will impact the review of the application. On April 7, 2017, the NRC approved Wolf Creek’s request of an indirect transfer of control of Wolf Creek’s operating license. The transfer will not be completed until receipt of all required regulatory approvals and written notification is made to the NRC. On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSR Act on October 21, 2016. Under the HSR Act, a new statutory waiting period will start one year from the date on which an existing waiting period expires, or October 21, 2017. Accordingly, if the merger has not closed prior to October 21, 2017, we and Great Plains Energy will need to re-file the necessary HSR Act notifications. Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete the merger. The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of $180.0 million. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b) within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of $280.0 million. In connection with this transaction, we have incurred merger-related expenses. During the three months ended March 31, 2017, we incurred approximately $0.4 million of merger-related expenses, which are included in our selling, general, and administrative expenses. In the event the merger is consummated, we expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to be paid upon closing. See also Note 12, “Legal Proceedings,” for more information on litigation related to the merger.

Financial And Derivative Instruments and Trading Securities [Abstract]

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1524-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4922-128472

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4934-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4926-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Rate Matters And Regulation	3 Months Ended
Rate Matters And Regulation	Mar. 31, 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 reached an agreement with the major parties to the rate review. If the agreement is approved by the KCC, we estimate that the new prices will increase our annual retail revenues by approximately $16.4 million. We expect the KCC to issue an order on our request in June 2017. In March 2017, the KCC issued an order allowing us to adjust our retail prices, subject to refund, 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 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 Trading Securities

3 Months Ended

Mar. 31, 2017

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 which have a readily determinable fair value calculated using daily NAVs, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments priced with models using highly observable inputs.


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

•

Net Asset Value - Investments that do not have a readily determinable fair value are measured at NAV. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds 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 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 March 31, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,756,244	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	111,122		111,513		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 March 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	59,559	$	—	$	4,894	$	64,453
International equity funds	—		40,287		—		—		40,287
Core bond fund	—		27,912		—		—		27,912
High-yield bond fund	—		18,836		—		—		18,836
Emerging market bond fund	—		16,275		—		—		16,275
Combination debt/equity/other fund	—		14,608		—		—		14,608
Alternative investment fund	—		—		—		20,107		20,107
Real estate securities fund	—		—		—		10,170		10,170
Cash equivalents	172		—		—		—		172
Total Nuclear Decommissioning Trust	172		177,477		—		35,171		212,820
Trading Securities:
Domestic equity funds	—		17,165		—		—		17,165
International equity fund	—		4,287		—		—		4,287
Core bond fund	—		11,584		—		—		11,584
Total Trading Securities	—		33,036		—		—		33,036
Total Assets Measured at Fair Value	$	172	$	210,513	$	—	$	35,171	$	245,856

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 market bond fund	—		14,738		—		—		14,738
Combination debt/equity/other fund	—		13,484		—		—		13,484
Alternative investment 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 March 31, 2017				As of December 31, 2016				As of March 31, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	4,894	$	3,349	$	5,056	$	3,529	(a)	(a)
Alternative investment fund (b)	20,107		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,170		—		9,946		—		Quarterly	65 days
Total Nuclear Decommissioning Trust	$	35,171	$	3,349	$	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 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

3 Months Ended

Mar. 31, 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 March 31, 2017, and December 31, 2016, we measured the fair value of trust assets at $33.0 million and $34.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months ended March 31, 2017 and 2016, we recorded unrealized gains of $1.4 million and $0.5 million, respectively, on the assets still held.

Available-for-Sale Securities

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

Using the specific identification method to determine cost, we realized no gains or losses on our available-for-sale securities during the three months ended March 31, 2017, and a loss of $1.6 million during the three months ended March 31, 2016. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of March 31, 2017:
Domestic equity funds	$	54,038	$	10,725	$	(310	)	$	64,453	30	%
International equity funds	35,520		4,767		—			40,287		19	%
Core bond fund	28,360		—		(448		)	27,912		13	%
High-yield bond fund	18,782		54		—			18,836		9	%
Emerging market bond fund	16,997		—		(722		)	16,275		8	%
Combination debt/equity/other fund	9,476		5,132		—			14,608		7	%
Alternative investment fund	15,000		5,107		—			20,107		9	%
Real estate securities fund	9,500		670		—			10,170		5	%
Cash equivalents	172		—		—			172		<1%
Total	$	187,845	$	26,455	$	(1,480	)	$	212,820	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 market bond fund	16,397		—		(1,659		)	14,738		7	%
Combination debt/equity/other fund	9,171		4,313		—			13,484		7	%
Alternative investment 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 March 31, 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 March 31, 2017:
Domestic equity funds	$	4,894	$	(310	)	$	—	$	—		$	4,894	$	(310	)
Core bonds	27,912		(448		)	—		—			27,912		(448		)
Emerging market bond fund	—		—			16,275		(722		)	16,275		(722		)
Total	$	32,806	$	(758	)	$	16,275	$	(722	)	$	49,081	$	(1,480	)

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 funds	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging market bond fund	—		—			14,738		(1,659		)	14,738		(1,659		)
Total	$	29,211	$	(648	)	$	40,415	$	(2,462	)	$	69,626	$	(3,110	)

Debt Financing	3 Months Ended
Debt Financing	Mar. 31, 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	3 Months Ended
Taxes	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Taxes	TAXES We recorded income tax expense of $20.9 million with an effective income tax rate of 25% for the three months ended March 31, 2017, and income tax expense of $38.6 million with an effective income tax rate of 36% for the same period of 2016. The decrease in the effective income tax rate for the three months ended March 31, 2017, was due primarily to a decrease in income before income taxes and increases in tax benefits from production tax credits and stock-based compensation. As of March 31, 2017, and December 31, 2016, our unrecognized income tax benefits totaled $2.8 million. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months. As of March 31, 2017, and December 31, 2016, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either March 31, 2017, or December 31, 2016. As of March 31, 2017, and December 31, 2016, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Pension and Post-Retirement Benefit Plans

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

The following table summarizes 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 March 31,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,664		$	271		$	271
Interest cost	10,621			10,959			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,709		)
Amortization of unrecognized:
Prior service costs	171			246			114			114
Actuarial loss (gain), net	5,489			5,388			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,594			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,900		$	(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.

During the three months ended March 31, 2017 and 2016, we contributed $7.0 million and $6.8 million, respectively, to the Westar Energy pension trust.

Wolf Creek Pension and Post-Retirement Benefit Plans

3 Months Ended

Mar. 31, 2017

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

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. The following table summarizes 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 March 31,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,950		$	1,687		$	37		$	32
Interest cost	2,475			2,414			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			1,089			(13		)	(4		)
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.

During the three months ended March 31, 2017, we did not fund Wolf Creek’s pension plan. During the three months ended March 31, 2016, we funded $1.6 million of Wolf Creek’s pension plan contributions.

Commitments And Contingencies	3 Months Ended
Commitments And Contingencies	Mar. 31, 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 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 NOx emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. 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 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 in attainment/unclassifiable. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. 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 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 determine whether to reconsider all or a portion of the rule. In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results. In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in 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 which governs the next round of the designations. 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 consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results. Greenhouse Gases Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions. In October 2015, the EPA published a rule establishing new source performance standards (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 our Company, 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. 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. Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or 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 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending EPA’s review. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or 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. Biological monitoring may be required for La Cygne Generating Station (La Cygne) and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material. In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States (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 March 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a notice of intent to review and rescind or revise the WOTUS rule, as required by an Executive Order signed in February 2017. 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 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. 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 consolidated financial results could be material. Storage of Spent Nuclear Fuel In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision. Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Wolf Creek is in discussions with the DOE to determine which of its incremental costs may be reimbursable. 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.

Legal Proceedings	3 Months Ended
Legal Proceedings	Mar. 31, 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 consolidated financial results. See Notes 4 and 11, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information. Pending Merger Following the announcement of the merger agreement, two putative class action complaints (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas. The consolidated putative class action complaint, filed on July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that (i) the merger consideration deprives our shareholders of fair consideration for their shares, (ii) the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, (iii) the disclosures are misleading and/or omit material information necessary for our shareholders to make an informed decision whether to vote in favor of the proposed transaction and (iv) if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the merger, (ii) rescission of the merger agreement or rescissory damages, (iii) a directive to members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties and (iv) an award for costs and disbursements, including attorneys’ fees and experts’ fees. The putative derivative complaint, filed on July 5, 2016, and as amended on August 25, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as a nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that the disclosures are false or misleading due to the omission of certain information. The complaint seeks, among other remedies, (i) a direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, (ii) a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the merger agreement, (iv) the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, (v) award for costs, including attorneys’ fees and experts’ fees, and (vi) the imposition of an injunction against the defendants and others from consummating the merger on the terms proposed. On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases. In exchange, the parties in the putative derivative complaint agreed that we would make supplemental disclosures to the shareholders, which disclosures were made in a Form 8-K filed on September 21, 2016, and the parties in the consolidated putative class action agreed that we would (i) make the disclosures in the Form 8-K filed on September 21, 2016, and (ii) grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in the our sale process. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety.

Variable Interest Entities

3 Months Ended

Mar. 31, 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 trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

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

8% Interest in Jeffrey Energy Center

Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We are currently evaluating if we will exercise the purchase option, which expires July 2017. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive

benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of

the agreement is greater than the fixed amount.

Financial Statement Impact

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



	As of		As of
	March 31, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	255,321	$	257,904
Regulatory assets (a)	10,791		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,538	$	26,842
Accrued interest (b)	19		867
Long-term debt of variable interest entities, net	82,663		111,209

_______________

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

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

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

Summary Of Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

Compensation - Retirement Benefits

Revenue Recognition

Principles Of Consolidation

Principles of Consolidation

Use Of Management's Estimates

Use of Management’s Estimates

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

Earnings Per Share

Supplemental Cash Flow Information



	Three Months Ended March 31,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	35,644		$	30,415
Interest on financing activities of VIEs	1,696			4,150
Income taxes, net of refunds	(13,000		)	(383		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	97,196			130,532
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	2,349			2,405
Assets acquired through capital leases	293			180

Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Schedule of Utility Inventory

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



	As of		As of
	March 31, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	115,921	$	107,086
Supplies	194,940		193,039
Fuel inventory and supplies	$	310,861	$	300,125

Allowance For Funds Used During Construction

on the accompanying condensed consolidated statements of income as follows:



	Three Months Ended March 31,
	2017			2016
	(Dollars In Thousands)
Borrowed funds	$	1,853		$	2,008
Equity funds	775			2,464
Total	$	2,628		$	4,472
Average AFUDC Rates	2.2		%	5.2		%

Reconciliation Of Basic And Diluted EPS

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



	Three Months Ended March 31,
	2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	63,482	$	68,708
Less: Net income attributable to noncontrolling interests	3,821		3,123
Net income attributable to Westar Energy, Inc.	59,661		65,585
Less: Net income allocated to RSUs	108		135
Net income allocated to common stock	$	59,553	$	65,450

Weighted average equivalent common shares outstanding – basic	142,436,622		141,992,846
Effect of dilutive securities:
RSUs	258,984		318,382
Weighted average equivalent common shares outstanding – diluted (a)	142,695,606		142,311,228

Earnings per common share, basic	$	0.42	$	0.46
Earnings per common share, diluted	$	0.42	$	0.46

_______________

(a)We had no antidilutive securities for the three months ended March 31, 2017 and 2016.

Supplemental Cash Flow Information



	Three Months Ended March 31,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	35,644		$	30,415
Interest on financing activities of VIEs	1,696			4,150
Income taxes, net of refunds	(13,000		)	(383		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	97,196			130,532
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	2,349			2,405
Assets acquired through capital leases	293			180

Financial Instruments and Trading Securities (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,756,244	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	111,122		111,513		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 March 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	59,559	$	—	$	4,894	$	64,453
International equity funds	—		40,287		—		—		40,287
Core bond fund	—		27,912		—		—		27,912
High-yield bond fund	—		18,836		—		—		18,836
Emerging market bond fund	—		16,275		—		—		16,275
Combination debt/equity/other fund	—		14,608		—		—		14,608
Alternative investment fund	—		—		—		20,107		20,107
Real estate securities fund	—		—		—		10,170		10,170
Cash equivalents	172		—		—		—		172
Total Nuclear Decommissioning Trust	172		177,477		—		35,171		212,820
Trading Securities:
Domestic equity funds	—		17,165		—		—		17,165
International equity fund	—		4,287		—		—		4,287
Core bond fund	—		11,584		—		—		11,584
Total Trading Securities	—		33,036		—		—		33,036
Total Assets Measured at Fair Value	$	172	$	210,513	$	—	$	35,171	$	245,856

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 market bond fund	—		14,738		—		—		14,738
Combination debt/equity/other fund	—		13,484		—		—		13,484
Alternative investment 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

Reconciliations Of Assets And Liabilities At Fair Value

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 March 31, 2017				As of December 31, 2016				As of March 31, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	4,894	$	3,349	$	5,056	$	3,529	(a)	(a)
Alternative investment fund (b)	20,107		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,170		—		9,946		—		Quarterly	65 days
Total Nuclear Decommissioning Trust	$	35,171	$	3,349	$	33,960	$	3,529

_______________

(a)


(b)	There is a holdback on final redemptions.

Cost And Fair Value Of Investments

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

+ References + Details

Financial Investments (Tables)

3 Months Ended

Mar. 31, 2017

Investments [Abstract]

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of March 31, 2017:
Domestic equity funds	$	54,038	$	10,725	$	(310	)	$	64,453	30	%
International equity funds	35,520		4,767		—			40,287		19	%
Core bond fund	28,360		—		(448		)	27,912		13	%
High-yield bond fund	18,782		54		—			18,836		9	%
Emerging market bond fund	16,997		—		(722		)	16,275		8	%
Combination debt/equity/other fund	9,476		5,132		—			14,608		7	%
Alternative investment fund	15,000		5,107		—			20,107		9	%
Real estate securities fund	9,500		670		—			10,170		5	%
Cash equivalents	172		—		—			172		<1%
Total	$	187,845	$	26,455	$	(1,480	)	$	212,820	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 market bond fund	16,397		—		(1,659		)	14,738		7	%
Combination debt/equity/other fund	9,171		4,313		—			13,484		7	%
Alternative investment 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



	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 March 31, 2017:
Domestic equity funds	$	4,894	$	(310	)	$	—	$	—		$	4,894	$	(310	)
Core bonds	27,912		(448		)	—		—			27,912		(448		)
Emerging market bond fund	—		—			16,275		(722		)	16,275		(722		)
Total	$	32,806	$	(758	)	$	16,275	$	(722	)	$	49,081	$	(1,480	)

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 funds	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging market 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)

3 Months Ended

Mar. 31, 2017

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

The following table summarizes 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 March 31,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,664		$	271		$	271
Interest cost	10,621			10,959			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,709		)
Amortization of unrecognized:
Prior service costs	171			246			114			114
Actuarial loss (gain), net	5,489			5,388			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,594			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,900		$	(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.

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

3 Months Ended

Mar. 31, 2017

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

The following table summarizes 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 March 31,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,664		$	271		$	271
Interest cost	10,621			10,959			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,709		)
Amortization of unrecognized:
Prior service costs	171			246			114			114
Actuarial loss (gain), net	5,489			5,388			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,594			(214		)	(211		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,900		$	(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.

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

The following table summarizes 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 March 31,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,950		$	1,687		$	37		$	32
Interest cost	2,475			2,414			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			1,089			(13		)	(4		)
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.

Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2017

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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



	As of		As of
	March 31, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	255,321	$	257,904
Regulatory assets (a)	10,791		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,538	$	26,842
Accrued interest (b)	19		867
Long-term debt of variable interest entities, net	82,663		111,209

_______________

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

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

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

+ References + Details

Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Total	$ 310,861	$ 300,125
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utilities Inventory	115,921	107,086
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utilities Inventory	$ 194,940	$ 193,039

Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accounting Policies [Abstract]
Borrowed funds	$ (1,853)	$ (2,008)
Equity funds	775	2,464
Total	$ 2,628	$ 4,472
Average AFUDC rates	2.20%	5.20%

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accounting Policies [Abstract]
Net Income Allocated to RSUs	$ 108	$ 135
Net income allocated to common stock	$ 59,553	$ 65,450
Weighted Average Number of Shares Outstanding , Basic	142,436,622	141,992,846
RSUs	258,984	318,382
Weighted average equivalent common shares outstanding - diluted	142,695,606	142,311,228
Earnings Per Share, Basic	$ 0.42	$ 0.46
Earnings Per Share, Diluted	$ 0.42	$ 0.46
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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Paid For (Received From)
Interest on financing activities	$ 35,644	$ 30,415
Income Taxes Paid, Net	(13,000)	(383)
Noncash Investing and Financing Transactions
Property, plant and equipment	97,196	130,532
Issuance of common stock for reinvested dividends and compensation plans	2,349	2,405
Assets acquired through capital leases	293	180
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 1,696	$ 4,150

Summary Of Significant Accounting Policies Summary Of Significant Accounting Policies (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	$ 3,326

Financial and Derivative Instruments and Trading Securities [Line Items]

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

+ References + Details

Pending Merger Pending Merger (Narrative) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended	12 Months Ended
	May 29, 2016	Mar. 31, 2017	Dec. 31, 2016
Business Combination [Line Items]
Public Utilities, time limit for FERC action			180 days
Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio, Minimum	0.2709
Business Combination, Share Conversion Ratio, Maximum	0.3148
Business Combination, Share Conversion Ratio, Trading Period	20 days
Business Combination, Acquisition Related Costs		$ 0.4
Business Combination, Expected Acquisition Related Costs		$ 30.0
Cash Consideration per Share [Member] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Acquisition, Dividend Increase Restriction	$ 0.08
Business Acquisition, Share Price	51.00
Business Acquisition, Dividend Restriction	0.40
Total Consideration per Share [Member] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Acquisition, Share Price	$ 60.00
Failure to obtain regulatory approvals, paid to Westar Energy [Member] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	$ 380.0
End date occurred and Great Plains Energy enters into acquisition proposal within 12 months of termination, paid to Westar Energy [Member] [Domain] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	180.0
end date occurred and Westar Energy enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Domain] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee	$ 280.0

Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions		1 Months Ended
	May 03, 2017	Jan. 31, 2017	Apr. 01, 2017
Federal Energy Regulatory Commission [Member] \| Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 29.6
Kansas Corporation Commission [Member] \| Subsequent Event [Member]
Regulatory Proceedings [Line Items]
Estimated Increase In Annual Retail Revenues For Transmission Costs			$ 12.7
Kansas Corporation Commission [Member] \| Abbreviated Rate Case [Member] [Member] \| Subsequent Event [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 16.4
Kansas Corporation Commission [Member] \| Ad Valorem Tax [Member]
Regulatory Proceedings [Line Items]
Estimated Increase In Annual Revenues For Property Tax		$ 26.8

Financial Instruments and Trading Securities (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,605,000	$ 3,430,000
Fair Value	3,756,244	3,597,441
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	111,122	137,962
Fair Value	$ 111,513	$ 139,733

Financial Instruments and Trading Securities (Investments In Financial Instruments) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2017

Dec. 31, 2016

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period

15 years

Financial and Derivative Instruments and Trading Securities [Line Items]

$ 212,820

$ 200,122

Trading securities

33,036

34,491

Total

245,856

234,613

Fair Value [Member]

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

35,171

33,960

Financial and Derivative Instruments and Trading Securities [Line Items]

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments

3,349

3,529

Domestic Equity Funds [Member]

Financial and Derivative Instruments and Trading Securities [Line Items]

Domestic Equity Funds [Member] | Fair Value [Member]

64,453

61,368

Trading securities

17,165

18,364

Financial and Derivative Instruments and Trading Securities [Line Items]

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments

^[1]

4,894

5,056

^[1]

3,349

3,529

Alternative Funds [Member]

Financial and Derivative Instruments and Trading Securities [Line Items]

Alternative Funds [Member] | Fair Value [Member]

20,107

18,958

Financial and Derivative Instruments and Trading Securities [Line Items]

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments

^[2]

20,107

18,958

^[2]

$ 0

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period

65 days

Real Estate Securities Fund [Member]

Financial and Derivative Instruments and Trading Securities [Line Items]

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

$ 10,170

9,946

Financial and Derivative Instruments and Trading Securities [Line Items]

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments

^[2]

10,170

9,946

^[2]

$ 0

Investment redemption frequency

Quarterly

Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period

65 days

[1]

[2]

There is a holdback on final redemptions.

Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities	$ 33,036		$ 34,491
Unrealized gains losses	1,400	$ 500
Realized gains on available-for-sale-securities	$ 0	$ 1,600

Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 187,845	$ 184,145
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	26,455	19,087
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	1,480	3,110
Available-for-sale Securities	$ 212,820	$ 200,122
Allocation	100.00%	100.00%
Domestic Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 54,038	$ 53,192
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	10,725	8,295
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	310	119
Available-for-sale Securities	$ 64,453	$ 61,368
Allocation	30.00%	31.00%
International Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 35,520	$ 34,502
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	4,767	2,075
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	633
Available-for-sale Securities	$ 40,287	$ 35,944
Allocation	19.00%	18.00%
Core Bonds Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 28,360	$ 27,952
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	0	0
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	448	529
Available-for-sale Securities	$ 27,912	$ 27,423
Allocation	13.00%	14.00%
High-Yield Bonds Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 18,782	$ 18,358
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	54	0
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	170
Available-for-sale Securities	$ 18,836	$ 18,188
Allocation	9.00%	9.00%
Emerging Market Bonds Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 16,997	$ 16,397
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	0	0
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	722	1,659
Available-for-sale Securities	$ 16,275	$ 14,738
Allocation	8.00%	7.00%
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 9,476	$ 9,171
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	5,132	4,313
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	0
Available-for-sale Securities	$ 14,608	$ 13,484
Allocation	7.00%	7.00%
Alternative Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 15,000	$ 15,000
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	5,107	3,958
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	0
Available-for-sale Securities	$ 20,107	$ 18,958
Allocation	9.00%	9.00%
Real Estate Securities Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 9,500	$ 9,500
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	670	446
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	0
Available-for-sale Securities	$ 10,170	$ 9,946
Allocation	5.00%	5.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Amortized Cost Basis	$ 172	$ 73
Available-for-sale Securities, Accumulated Gross Unrealized Gain, before Tax	0	0
Available-for-sale Securities, Accumulated Gross Unrealized Loss, before Tax	0	0
Available-for-sale Securities	$ 172	$ 73

Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,400	$ 500
Fair Value, Less than 12 Months	32,806		$ 29,211
Gross Unrealized Losses, Less than 12 Months	(758)		(648)
Fair Value, 12 Months or Greater	16,275		40,415
Gross Unrealized Losses, 12 Months or Greater	(722)		(2,462)
Fair Value, Total	49,081		69,626
Gross Unrealized Losses, Total	(1,480)		(3,110)
Domestic Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	4,894		1,788
Gross Unrealized Losses, Less than 12 Months	(310)		(119)
Fair Value, 12 Months or Greater	0		0
Gross Unrealized Losses, 12 Months or Greater	0		0
Fair Value, Total	4,894		1,788
Gross Unrealized Losses, Total	(310)		(119)
International Equity Funds [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 Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	27,912		27,423
Gross Unrealized Losses, Less than 12 Months	(448)		(529)
Fair Value, 12 Months or Greater	0		0
Gross Unrealized Losses, 12 Months or Greater	0		0
Fair Value, Total	27,912		27,423
Gross Unrealized Losses, Total	(448)		(529)
Emerging Market Bonds Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0
Gross Unrealized Losses, Less than 12 Months	0		0
Fair Value, 12 Months or Greater	16,275		14,738
Gross Unrealized Losses, 12 Months or Greater	(722)		(1,659)
Fair Value, Total	16,275		14,738
Gross Unrealized Losses, Total	$ (722)		(1,659)
High-Yield Bonds Fund [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)

Debt Financing (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2017	Mar. 31, 2017	Mar. 31, 2016	Mar. 06, 2017
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 125,000	$ 0
Secured Debt [Member] \| Debt Instrument Two [Member] \| Westar Energy [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 125,000
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Secured Debt [Member] \| Debt Instrument 8930 [Member] \| Westar Energy [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross				$ 300,000
Debt Instrument, Interest Rate, Stated Percentage				3.10%

Taxes Taxes (Narrative) (Details) - USD ($)	3 Months Ended
Taxes Taxes (Narrative) (Details) - USD ($)	Mar. 31, 2017	Mar. 31, 2016
Income Tax Contingency [Line Items]
Income tax expense	$ 20,911,000	$ 38,622,000
Effective income tax rate	25.00%	36.00%
Liability for unrecognized income tax benefits	$ 2,800,000
Interest on liability related to unrecognized income tax benefits	0
Penalties accrued for unrecognized income tax benefits	0
Accrual for taxes other than income taxes	$ 1,500,000

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

3 Months Ended

Mar. 31, 2017

Mar. 31, 2016

Pension Benefits [Member]

Pension Contributions

$ 7,000

$ 6,800

5,218

4,664

10,621

10,959

(10,760)

(10,663)

171

246

5,489

5,388

10,739

10,594

^[1]

(3,288)

(3,306)

Post-Retirement Benefits [Member]

14,027

13,900

271

1,314

1,393

(1,718)

(1,709)

114

(195)

(280)

(214)

(211)

^[1]

(478)

486

$ (692)

$ (697)

[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.

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

Mar. 31, 2017

Mar. 31, 2016

Pension Contributions

$ 7,000

$ 6,800

Wolf Creek [Member]

Subsidiary Interest in Defined Benefit Plans

Pension Contributions

1,600

KGE [Member]

47.00%

Pension Benefits [Member]

$ 5,218

4,664

10,621

10,959

(10,760)

(10,663)

171

246

5,489

5,388

10,739

10,594

^[1]

(3,288)

(3,306)

Pension Benefits [Member] | Wolf Creek [Member]

14,027

13,900

1,950

1,687

2,475

2,414

(2,643)

(2,431)

1,245

1,089

3,041

2,773

^[2]

(247)

483

Post-Retirement Benefits [Member]

3,288

3,256

271

1,314

1,393

(1,718)

(1,709)

114

(195)

(280)

(214)

(211)

^[1]

(478)

486

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

(692)

(697)

(13)

(4)

109

^[2]

Variable Interest Entity [Line Items]

$ 94

$ 109

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

Variable Interest Entities (Narrative) (Details)	3 Months Ended
Variable Interest Entities (Narrative) (Details)	Mar. 31, 2017
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

Mar. 31, 2017

Dec. 31, 2016

$ 9,321,669

$ 9,248,359

125,000

^[1]

85,612

72,519

Variable Interest Entity, Primary Beneficiary [Member]

3,685,752

3,388,670

Variable Interest Entity [Line Items]

255,321

257,904

Regulatory assets

^[2]

10,791

10,396

28,538

26,842

^[1]

867