30,638

29,701

Total Current Assets

740,226

768,382

Nuclear decommissioning trust

9,406,054

9,248,359

OTHER ASSETS:

Regulatory assets

750,888

762,479

220,031

200,122

226,214

249,828

Total Other Assets

1,197,133

1,212,429

TOTAL ASSETS

11,596,150

11,487,074

CURRENT LIABILITIES:

125,000

Short-term debt

329,200

366,700

Accounts payable

139,628

220,522

Accrued dividends

53,743

52,885

Accrued taxes

89,742

85,729

^[1]

45,124

72,519

Regulatory liabilities

11,903

15,760

Total Current Liabilities

76,294

81,236

774,172

1,047,193

LONG-TERM LIABILITIES:

Unamortized investment tax credits

3,686,180

3,388,670

Deferred income taxes

1,794,177

1,752,776

209,283

210,654

Regulatory liabilities

230,355

223,693

Accrued employee benefits

511,073

512,412

Asset Retirement Obligations, Noncurrent

368,233

323,951

Total Long-Term Liabilities

85,145

83,326

6,967,099

6,606,691

COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)

Westar Energy, Inc. Shareholders' Equity:

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

710,467

708,956

Paid-in capital

2,019,815

2,018,317

Retained earnings

1,095,247

1,078,602

Total Westar Energy, Inc. Shareholders' Equity

3,825,529

3,805,875

Noncontrolling Interests

29,350

27,315

Total Equity

3,854,879

3,833,190

TOTAL LIABILITIES AND EQUITY

11,596,150

11,487,074

Variable Interest Entity [Member]

CURRENT ASSETS:

252,737

257,904

CURRENT LIABILITIES:

28,538

26,842

^[1]

706

867

LONG-TERM LIABILITIES:

Summary Of Significant Accounting Policies

$ 82,653

$ 111,209

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

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
CURRENT ASSETS:
Allowance for doubtful accounts	$ 5,697	$ 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	142,093,387	141,791,153
Common stock, shares outstanding	142,093,387	141,791,153

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
Consolidated Statements Of Income - USD ($) $ in Thousands	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
REVENUES	$ 609,321	$ 621,448	$ 1,181,895	$ 1,190,898
OPERATING EXPENSES:
Fuel and purchased power	111,790	118,630	225,645	218,688
Network Transmission Cost	61,763	55,227	122,437	115,987
Operating and maintenance	87,158	85,619	168,356	163,377
Depreciation and amortization	94,029	84,226	182,655	167,866
Selling, general and administrative	57,579	75,724	116,735	132,179
Taxes, Miscellaneous	41,890	48,407	84,606	97,375
Total Operating Expenses	454,209	467,833	900,434	895,472
INCOME FROM OPERATIONS	155,112	153,615	281,461	295,426
OTHER INCOME (EXPENSE):
Investment earnings (losses)	2,636	2,280	5,790	4,296
Other income	523	3,382	1,823	12,860
Other expense	(2,647)	(2,908)	(7,963)	(8,451)
Total Other Income	512	2,754	(350)	8,705
Interest expense	43,679	39,683	84,774	80,114
INCOME BEFORE INCOME TAXES	111,945	116,686	196,337	224,017
Income tax expense	35,906	40,542	56,816	79,165
NET INCOME	76,039	76,144	139,521	144,852
Less: Net income attributable to noncontrolling interests	3,974	3,804	7,795	6,927
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 72,065	$ 72,340	$ 131,726	$ 137,925
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 0.50	$ 0.51	$ 0.92	$ 0.97
Earnings Per Share, Diluted	$ 0.50	$ 0.51	$ 0.92	$ 0.97
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,465,749	142,033,842	142,451,266	142,013,344
Weighted Average Number of Shares Outstanding, Diluted	142,596,356	142,497,335	142,579,255	142,361,347
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.40	$ 0.38	$ 0.80	$ 0.76

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 139,521	$ 144,852
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	182,655	167,866
Amortization of nuclear fuel	15,948	16,831
Amortization of deferred regulatory gain from sale leaseback	(2,748)	(2,748)
Amortization of corporate-owned life insurance	8,920	8,819
Non-cash compensation	4,613	4,778
Net deferred income taxes and credits	53,852	75,334
Allowance for equity funds used during construction	(773)	(5,247)
Changes in working capital items:
Accounts receivable	14,154	(40,555)
Fuel inventory and supplies	(2,262)	2,140
Prepaid expenses and other	39,167	7,126
Accounts payable	(20,012)	(21,364)
Accrued taxes	11,019	16,272
Other current liabilities	(103,316)	(62,434)
Changes in other assets	14,891	1,848
Changes in other liabilities	7,695	15,163
Cash Flows from Operating Activities	363,324	328,681
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(383,627)	(503,631)
Purchase of securities - trusts	(12,140)	(39,603)
Sale of securities - trusts	13,538	41,201
Investment in corporate-owned life insurance	13,875	14,648
Proceeds from investment in corporate-owned life insurance	185	24,171
Investment in affiliated company	0	(655)
Other investing activities	(3,199)	(2,798)
Cash Flows used in Investing Activities	(399,118)	(495,963)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(37,632)	(73,300)
Proceeds from long-term debt	(296,296)	(396,577)
Retirements of long-term debt	(125,000)	(50,000)
Repayment of capital leases	(1,663)	(401)
Borrowings against cash surrender value of corporate-owned life insurance	52,302	54,910
Repayment of borrowings against cash surrender value of corporate-owned life insurance	0	(22,921)
Issuance of common stock	659	1,354
Distributions to shareholders of noncontrolling interests	(5,760)	(2,551)
Cash dividends paid	(109,418)	(101,137)
Other financing activities	(7,006)	(4,960)
Cash Flows from Financing Activities	35,938	169,264
NET CHANGE IN CASH AND CASH EQUIVALENTS	144	1,982
CASH AND CASH EQUIVALENTS:
Beginning of period	3,066	3,231
End of period	3,210	5,213
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)

Consolidated Statements Of Changes In Equity - USD ($)	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2015	$ 3,671,963,000	$ 706,767,000	$ 2,004,124,000	$ 945,830,000	$ 15,242,000
Beginning Balance (Shares) at Dec. 31, 2015		141,353,426
Net income	144,852,000	$ 0	0	137,925,000	6,927,000
Issuance of stock	1,354,000	$ 143,000	1,211,000	0	0
Issuance of stock (shares)		28,674
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		308,917
Issuance Of Stock For Compensation And Reinvested Dividends	4,941,000	$ 1,545,000	3,396,000
Tax withholding related to stock compensation	(4,960,000)		(4,960,000)
Dividends on common stock	(108,894,000)	0	0	(108,894,000)	0
Stock compensation expense	4,720,000		4,720,000
Distributions to shareholders of noncontrolling interests	(2,551,000)				(2,551,000)
Ending Balance at Jun. 30, 2016	3,714,751,000	$ 708,455,000	2,008,491,000	978,187,000	19,618,000
Ending Balance (Shares) at Jun. 30, 2016		141,691,017
Beginning Balance at Dec. 31, 2016	3,833,190,000	$ 708,956,000	2,018,317,000	1,078,602,000	27,315,000
Beginning Balance (Shares) at Dec. 31, 2016		141,791,153
Net income	139,521,000	$ 0	0	131,726,000	7,795,000
Issuance of stock	659,000	$ 60,000	599,000	0	0
Issuance of stock (shares)		12,131
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		290,103
Issuance Of Stock For Compensation And Reinvested Dividends	4,801,000	$ 1,451,000	3,350,000
Tax withholding related to stock compensation	(7,006,000)		(7,006,000)
Dividends on common stock	(115,081,000)	0	0	(115,081,000)	0
Stock compensation expense	4,555,000		4,555,000
Deconsolidation of variable interest entity	(5,760,000)				(5,760,000)
Distributions to shareholders of noncontrolling interests	(5,760,000)
Ending Balance at Jun. 30, 2017	$ 3,854,879,000	$ 710,467,000	$ 2,019,815,000	1,095,247,000	$ 29,350,000
Ending Balance (Shares) at Jun. 30, 2017		142,093,387
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				$ 3,326,000.000

Description Of Business	6 Months Ended
Description Of Business	Jun. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description Of Business	DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 708,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2016 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2017, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory and Supplies

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



	As of		As of
	June 30, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	106,764	$	107,086
Supplies	195,932		193,039
Fuel inventory and supplies	$	302,696	$	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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(Dollars In Thousands)
Borrowed funds	$	895		$	2,338		$	2,748		$	4,347
Equity funds	—			2,783			773			5,247
Total	$	895		$	5,121		$	3,521		$	9,594
Average AFUDC Rates	1.5		%	4.2		%	2.0		%	4.6		%

Earnings Per Share

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

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,039	$	76,144	$	139,521	$	144,852
Less: Net income attributable to noncontrolling interests	3,974		3,804		7,795		6,927
Net income attributable to Westar Energy, Inc.	72,065		72,340		131,726		137,925
Less: Net income allocated to RSUs	130		156		237		290
Net income allocated to common stock	$	71,935	$	72,184	$	131,489	$	137,635

Weighted average equivalent common shares outstanding – basic	142,465,749		142,033,842		142,451,266		142,013,344
Effect of dilutive securities:
RSUs	130,607		463,493		127,989		348,003
Weighted average equivalent common shares outstanding – diluted (a)	142,596,356		142,497,335		142,579,255		142,361,347

Earnings per common share, basic	$	0.50	$	0.51	$	0.92	$	0.97
Earnings per common share, diluted	$	0.50	$	0.51	$	0.92	$	0.97

_______________

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

Supplemental Cash Flow Information



	Six Months Ended June 30,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	76,024		$	70,697
Interest on financing activities of VIEs	1,696			4,150
Income taxes, net of refunds	(12,685		)	(77		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	89,899			71,830
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,801			4,941
Assets acquired through capital leases	3,054			392

New Accounting Pronouncements

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

Compensation - Retirement Benefits

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

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or modified retrospective method. We will use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. We continue to analyze the impact of the new revenue standard and related ASUs. We completed initial revenue contract assessments. 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. We are finalizing our changes to revenue-related disclosure and ensuring we have effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material.

Pending Merger Pending Merger (Notes)	6 Months Ended
Pending Merger Pending Merger (Notes)	Jun. 30, 2017
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	PENDING MERGER On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy that provided for the acquisition of Westar by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) denied our and Great Plains Energy’s merger application. On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into one share of common stock of a new holding company with a final name still to be determined. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately 47.5% of the new holding company. The closing of the merger is subject to conditions including, among others, approval of our shareholders representing a majority of the outstanding shares of our common stock; approval of Great Plains Energy’s shareholders representing two-thirds of the outstanding shares of Great Plains Energy common stock; clearance under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act); receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar and its subsidiaries, taken as a whole); effectiveness of the registration statement for the shares of the new holding company’s common stock to be issued to our shareholders and Great Plains Energy’s shareholders upon consummation of the merger and approval of the listing of such shares on the New York Stock Exchange; the receipt of tax opinions by us and Great Plains Energy that the merger will be treated as a non-taxable event for U.S. federal income tax purposes; there being no shares of Great Plains Energy preference stock outstanding; and Great Plains Energy having not less than $1.25 billion in cash or cash equivalents on its balance sheet. The closing of the merger is also subject to other standard conditions, such as accuracy of representations and warranties, compliance with covenants and the absence of a material adverse effect on either company. Either party may terminate the amended and restated merger agreement if the merger is not consummated by July 10, 2018, subject to an extension of up to six months. Either party may also terminate the agreement if our shareholders or Great Plains Energy’s shareholders do not approve the merger or an order that prohibits the merger becomes final and non-appealable. There are also termination rights for both parties in certain cases if the other party’s board of directors changes its recommendation to its shareholders regarding approval of the merger, or the other party accepts an alternative, superior offer. The amended and restated merger agreement provides that Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated due to (i) failure to receive regulatory approval prior to July 10, 2018, subject to an extension of up to six months, (ii) a non-appealable regulatory order enjoining the merger or (iii) Great Plains Energy’s failure to close after all conditions precedent to closing have been satisfied. In addition, we may be required to pay Great Plains Energy a termination fee of $190.0 million if the agreement is terminated by us under certain circumstances, such as entering into a definitive acquisition agreement with respect to a superior proposal or by Great Plains Energy as a result of our board of directors changing its recommendation of the merger prior to our shareholder approval having been obtained. Similarly, Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated by Great Plains Energy under certain circumstances, such as entering into a definitive acquisition agreement with respect to a superior proposal or by us as a result of Great Plains Energy’s board of directors changing its recommendation of the merger prior to its shareholder approval having been obtained. Additionally, if the agreement is terminated by either Great Plains Energy or us as a result of Great Plains Energy’s shareholders not approving the agreement, Great Plains Energy may be required to pay us a termination fee of $80.0 million. In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our selling, general, and administrative expenses. During 2016, we incurred approximately $10.2 million of merger-related expenses. During the three and six months ended June 30, 2017, we incurred approximately $0.3 million and $0.7 million, respectively, of merger-related expenses. We incurred approximately $7.5 million in additional merger-related expenses in July 2017, with the balance of expenses to be incurred through the closing of the merger. In the event that the merger is consummated, we expect total merger-related expenses will be approximately $45.0 million. See also Note 13, “Legal Proceedings,” for more information on litigation related to the merger.

Rate Matters And Regulation	6 Months Ended
Rate Matters And Regulation	Jun. 30, 2017
Regulated Operations [Abstract]
Rate Matters And Regulation	RATE MATTERS AND REGULATION KCC Proceedings In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. In May 2017, we entered into a settlement agreement with the major parties to the rate review. In June 2017, the agreement was approved by the KCC. The new prices were effective June 2017 and are expected to increase our annual retail revenues by approximately $16.4 million. In March 2017, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2017 and are expected to increase our annual retail revenues by approximately $12.7 million. In December 2016, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2017 and are expected to decrease our annual retail revenues by approximately $26.8 million. FERC Proceedings Our TFR that includes projected 2017 transmission capital expenditures and operating costs was effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above.

Financial Instruments and Risk Management

6 Months Ended

Jun. 30, 2017

Financial And Derivative Instruments and Trading Securities [Abstract]

Financial And Derivative Instruments And Trading Securities

FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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


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

•

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


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

•

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

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

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



	As of June 30, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,846,301	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	111,122		111,850		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 June 30, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	61,322	$	—	$	5,048	$	66,370
International equity funds	—		42,888		—		—		42,888
Core bond fund	—		32,378		—		—		32,378
High-yield bond fund	—		17,377		—		—		17,377
Emerging markets bond fund	—		16,873		—		—		16,873
Combination debt/equity/other fund	—		13,048		—		—		13,048
Alternative investments fund	—		—		—		20,584		20,584
Real estate securities fund	—		—		—		10,380		10,380
Cash equivalents	133		—		—		—		133
Total Nuclear Decommissioning Trust	133		183,886		—		36,012		220,031
Trading Securities:
Domestic equity funds	—		17,523		—		—		17,523
International equity fund	—		4,361		—		—		4,361
Core bond fund	—		11,739		—		—		11,739
Total Trading Securities	—		33,623		—		—		33,623
Total Assets Measured at Fair Value	$	133	$	217,509	$	—	$	36,012	$	253,654

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

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



	As of June 30, 2017				As of December 31, 2016				As of June 30, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,048	$	3,129	$	5,056	$	3,529	(a)	(a)
Alternative investments fund (b)	20,584		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,380		—		9,946		—		Quarterly	65 days
Total	$	36,012	$	3,129	$	33,960	$	3,529

_______________

(a)

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


(b)	There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

Financial Investments

6 Months Ended

Jun. 30, 2017

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2017, and December 31, 2016, we measured the fair value of trust assets at $33.6 million and $34.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our condensed consolidated statements of income. For the three and six months ended June 30, 2017, we recorded an unrealized gain of $1.1 million and $2.5 million, respectively, on assets still held in the trust. For the three and six months ended June 30, 2016, we recorded an unrealized gain of $0.6 million and $1.1 million, respectively, on assets still held in the trust.

Available-for-Sale Securities

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

Using the specific identification method to determine cost, we realized a $0.2 million gain during the three months ended June 30, 2017, and a gain of $0.1 million during the six months ended June 30, 2017. We realized a gain of $0.1 million for the three months ended June 30, 2016, and a loss of $1.4 million for the six months ended June 30, 2016. We record net realized and unrealized gains and losses in regulatory liabilities on our condensed consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2017:
Domestic equity funds	$	54,563	$	12,260	$	(453	)	$	66,370	30	%
International equity funds	35,664		7,224		—			42,888		19	%
Core bond fund	32,542		—		(164		)	32,378		15	%
High-yield bond fund	17,060		317		—			17,377		8	%
Emerging markets bond fund	17,047		—		(174		)	16,873		8	%
Combination debt/equity/other fund	7,980		5,068		—			13,048		6	%
Alternative investments fund	15,000		5,584		—			20,584		9	%
Real estate securities fund	9,500		880		—			10,380		5	%
Cash equivalents	133		—		—			133		<1%
Total	$	189,489	$	31,333	$	(791	)	$	220,031	100	%

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

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



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of June 30, 2017:
Domestic equity funds	$	3,780	$	(453	)	$	—	$	—		$	3,780	$	(453	)
Core bond fund	32,378		(164		)	—		—			32,378		(164		)
Emerging markets bond fund	—		—			16,873		(174		)	16,873		(174		)
Total	$	36,158	$	(617	)	$	16,873	$	(174	)	$	53,031	$	(791	)

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

Debt Financing	6 Months Ended
Debt Financing	Jun. 30, 2017
Long-term Debt, Unclassified [Abstract]
Debt Financing	DEBT FINANCING In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds (FMBs) bearing a stated interest at 5.15% maturing January 2017. In March 2017, Westar Energy issued $300.0 million in principal amount of FMBs bearing a stated interest at 3.10% and maturing April 2027.

Taxes	6 Months Ended
Taxes	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Taxes	TAXES We recorded income tax expense of $35.9 million with an effective income tax rate of 32% for the three months ended June 30, 2017, and income tax expense of $40.5 million with an effective income tax rate of 35% for the same period of 2016. The decrease in the effective income tax rate for the three months ended June 30, 2017, was due primarily to increases in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service. We recorded income tax expense of $56.8 million with an effective income tax rate of 29% for the six months ended June 30, 2017, and income tax expense of $79.2 million with an effective income tax rate of 35% for the same period of 2016. The decrease in the effective income tax rate for the six months ended June 30, 2017, was due primarily to a decrease in income before income taxes and increases in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service. As of June 30, 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 June 30, 2017, we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2016. We accrued no penalties at either June 30, 2017, or December 31, 2016. As of June 30, 2017, and December 31, 2016, we had recorded $0.1 million and $1.5 million, respectively, for probable assessments of taxes other than income taxes.

Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2017

Retirement Benefits [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,921			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			114
Actuarial loss (gain), net	5,489			5,146			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(210		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(696	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	10,437		$	9,297		$	542		$	542
Interest cost	21,242			21,880			2,627			2,786
Expected return on plan assets	(21,520		)	(21,326		)	(3,436		)	(3,417		)
Amortization of unrecognized:
Prior service costs	341			420			228			228
Actuarial loss (gain), net	10,978			10,534			(390		)	(560		)
Net periodic cost (benefit) before regulatory adjustment	21,478			20,805			(429		)	(421		)
Regulatory adjustment (a)	6,576			6,613			(956		)	(972		)
Net periodic cost (benefit)	$	28,054		$	27,418		$	(1,385	)	$	(1,393	)

_______________


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

During the six months ended June 30, 2017 and 2016, we contributed $13.1 million and $11.2 million, respectively, to the Westar Energy pension trust.

Wolf Creek Pension and Post-Retirement Benefit Plans

6 Months Ended

Jun. 30, 2017

Defined Benefit Plan [Abstract]

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	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			82
Expected return on plan assets	(2,643		)	(2,430		)	—			—
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			2,774			94			110
Regulatory adjustment (a)	247			483			—			—
Net periodic cost	$	3,288		$	3,257		$	94		$	110

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,900		$	3,374		$	73		$	64
Interest cost	4,950			4,828			140			163
Expected return on plan assets	(5,286		)	(4,861		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,490			2,178			(25		)	(8		)
Net periodic cost before regulatory adjustment	6,082			5,547			188			219
Regulatory adjustment (a)	494			966			—			—
Net periodic cost	$	6,576		$	6,513		$	188		$	219

_______________


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

During the six months ended June 30, 2017, we did not fund Wolf Creek’s pension plan. During the six months ended June 30, 2016, we funded $3.2 million of Wolf Creek’s pension plan contributions.

Commitments And Contingencies	6 Months Ended
Commitments And Contingencies	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES Environmental Matters Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below. Cross-State Air Pollution Update Rule In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxide (NOx) emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and 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 condensed consolidated financial results. National Ambient Air Quality Standards Under the federal Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide and sulfur dioxide (SO₂), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment (KDHE) recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as in attainment/unclassifiable. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017, with an option to extend this deadline by one year. If the EPA agrees with the recommended designations for the state of Kansas, we do not believe this will have a material impact on our condensed consolidated financial results. Various states and others are challenging the revised 2015 ozone NAAQS in the D.C. Circuit. In April 2017, at the request of the EPA, the court issued an order holding the case in abeyance because the new administration is planning to review the 2015 ozone NAAQS and will determine whether to reconsider all or a portion of the rule. In 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 condensed consolidated financial results. In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, 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 that 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 condensed consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and condensed consolidated financial results. Greenhouse Gases Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions. In October 2015, the EPA published a rule establishing new source performance standards (NSPS) for GHGs that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per MWh depending on various characteristics of the units. Legal challenges to the GHG NSPS have been filed in the D.C. Circuit by various states and industry members. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including us, in the D.C. Circuit. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before an en banc panel of D.C. Circuit judges and a decision on the legal challenges is pending. In March 2017, President Trump signed an Executive Order instructing the EPA to immediately review the CPP and GHG NSPS, and “if appropriate . . . as soon as practicable . . . publish for notice and comment proposed rules suspending, revising or rescinding those rules.” On the same day the Executive Order was signed, the EPA filed motions with the D.C. Circuit asking the court to hold the challenges to the CPP and the GHG NSPS in abeyance while the EPA completes its administrative review of the rules and issues any forthcoming rulemakings. In April 2017, the court issued orders to hold the cases in abeyance for 60 days and requested briefing on whether the cases should be remanded to the EPA or continue to be held in abeyance. In May 2017, all parties in the case filed supplemental briefs stating their positions regarding remanding the rule back to the EPA or continuing to hold the case in abeyance. Also in April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details, in light of the Executive Order and the agency’s review of the CPP. Also in April 2017, the EPA published a notice in the Federal Register that it is initiating administrative reviews of the CPP and the GHG NSPS in light of the Executive Order. Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes effluent limitations guidelines (ELGs) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending the EPA’s review. In June 2017, the EPA proposed a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. These compliance dates would be postponed until the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form. In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or condensed 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 July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results. Regulation of Coal Combustion Residuals In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or condensed consolidated financial results could be material. SPP Revenue Crediting We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. In 2016, the SPP completed a process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are generation interconnection or transmission service projects that benefit SPP members and that are paid for directly by a sponsor without customer support. The SPP determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, in November 2016 we paid the SPP $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. In 2017, the SPP notified us that it would be issuing revised allocations. Due to the complexity of the allocation process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and the complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate whether the amount we previously paid will change. If the SPP’s revised calculation allocates additional charges to us, we believe that most of the additional charges will be recovered from our customers in future prices. Storage of Spent Nuclear Fuel In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision. Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Wolf Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE began accepting spent nuclear fuel. As a co-owner of Wolf Creek, we received $0.8 million of the settlement representing reimbursement of costs incurred through 2015 for project planning. We plan to apply for reimbursement of additional costs incurred after 2015. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Asset Retirement Obligations (Notes)

6 Months Ended

Jun. 30, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

In 2017, we recorded a new ARO liability of approximately $13.5 million corresponding to placing Western Plains Wind Farm in service. In addition, we revised our AROs by $34.7 million relating to asbestos removal, CCR and other owned windfarms. See Note 11, “Commitments and Contingencies - Regulation of Coal Combustion Residuals,” for additional information related to the CCR rule.

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



	(In Thousands)
Balance as of December 31, 2016	$	323,951
Increase in ARO liabilities	13,471
Liabilities settled	(1,431		)
Accretion expense	8,077
Revisions in estimated cash flows	34,713
Balance as of June 30, 2017	378,781
Balance included in other current liabilities	(10,548		)
Long-term AROs	$	368,233

Legal Proceedings	6 Months Ended
Legal Proceedings	Jun. 30, 2017
Legal Proceedings [Abstract]
Legal Proceedings	LEGAL PROCEEDINGS We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our condensed consolidated financial results. See Note 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information. Pending Merger Following the announcement of the original merger agreement, 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 original 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 original merger consideration deprived our shareholders of fair consideration for their shares, (ii) the original merger agreement contained deal protection provisions that unfairly favored Great Plains Energy and discouraged third parties from submitting potentially superior proposals, (iii) the disclosures were misleading and/or omitted material information necessary for our shareholders to make an informed decision whether to vote in favor of the original merger and (iv) if the original merger were to have been consummated, certain of our directors and officers may have received significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the original merger, (ii) rescission of the original 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 original 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 in the original merger 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 original merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the original 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 original 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. The September 2016 agreement in principle may be null and void as a result of entering into the amended and restated merger agreement in July 2017. The outcome of litigation is inherently uncertain, and we cannot predict how existing litigation will progress, or whether additional claims may result from the amended and restated merger agreement. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation.

Variable Interest Entities

6 Months Ended

Jun. 30, 2017

Variable Interest Entities [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 are VIEs. Upon the expiration of a purchase option in July 2017, we are no longer the primary beneficiary of the trust holding our 8% interest in JEC. We remain the primary beneficiary of the trust holding our 50% interest in La Cygne unit 2.

We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of the entities. We also continuously assess whether we are the primary beneficiary of the 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 met the requirements to be considered the primary beneficiary of the trust until July 2017, when a contractual option to purchase the 8% interest in the plant covered by the lease expired. Accordingly, we will deconsolidate the trust in the third quarter.

In determining the primary beneficiary of the trust, we had concluded that the activities of the trust that most significantly impacted its economic performance and that we had the power to direct included (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise an option that expired in July 2017 to purchase the plant at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We had the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement was greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also created the potential for us to receive significant benefits.

50% Interest in La Cygne Unit 2

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

Financial Statement Impact

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



	As of		As of
	June 30, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	252,737	$	257,904
Regulatory assets (a)	11,155		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,538	$	26,842
Accrued interest (b)	706		867
Long-term debt of variable interest entities, net	82,653		111,209

_______________

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

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

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

Summary Of Significant Accounting Policies (Policy)	6 Months Ended
Summary Of Significant Accounting Policies (Policy)	Jun. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements We prepare our condensed consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements that may affect our accounting and/or disclosure. Compensation - Retirement Benefits In March 2017, the FASB issued Accounting Standard Update No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our condensed consolidated financial statements. Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or modified retrospective method. We will use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. We continue to analyze the impact of the new revenue standard and related ASUs. We completed initial revenue contract assessments. 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. We are finalizing our changes to revenue-related disclosure and ensuring we have effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material.
Principles Of Consolidation	Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.
Use Of Management's Estimates	Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2017, are not necessarily indicative of the results to be expected for the full year.
Fuel Inventory And Supplies	Fuel Inventory and Supplies We state fuel inventory and supplies at average cost.
Allowance For Funds Used During Construction	Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost
Earnings Per Share	Earnings Per Share We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

Schedule of Utility Inventory

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



	As of		As of
	June 30, 2017		December 31, 2016
	(In Thousands)
Fuel inventory	$	106,764	$	107,086
Supplies	195,932		193,039
Fuel inventory and supplies	$	302,696	$	300,125

Allowance For Funds Used During Construction

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(Dollars In Thousands)
Borrowed funds	$	895		$	2,338		$	2,748		$	4,347
Equity funds	—			2,783			773			5,247
Total	$	895		$	5,121		$	3,521		$	9,594
Average AFUDC Rates	1.5		%	4.2		%	2.0		%	4.6		%

Reconciliation Of Basic And Diluted EPS

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	76,039	$	76,144	$	139,521	$	144,852
Less: Net income attributable to noncontrolling interests	3,974		3,804		7,795		6,927
Net income attributable to Westar Energy, Inc.	72,065		72,340		131,726		137,925
Less: Net income allocated to RSUs	130		156		237		290
Net income allocated to common stock	$	71,935	$	72,184	$	131,489	$	137,635

Weighted average equivalent common shares outstanding – basic	142,465,749		142,033,842		142,451,266		142,013,344
Effect of dilutive securities:
RSUs	130,607		463,493		127,989		348,003
Weighted average equivalent common shares outstanding – diluted (a)	142,596,356		142,497,335		142,579,255		142,361,347

Earnings per common share, basic	$	0.50	$	0.51	$	0.92	$	0.97
Earnings per common share, diluted	$	0.50	$	0.51	$	0.92	$	0.97

_______________

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

Supplemental Cash Flow Information



	Six Months Ended June 30,
	2017			2016
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	76,024		$	70,697
Interest on financing activities of VIEs	1,696			4,150
Income taxes, net of refunds	(12,685		)	(77		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	89,899			71,830
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	4,801			4,941
Assets acquired through capital leases	3,054			392

Financial Instruments and Risk Management (Tables)

6 Months Ended

Jun. 30, 2017

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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



	As of June 30, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,846,301	$	3,430,000	$	3,597,441
Fixed-rate debt of VIEs	111,122		111,850		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 June 30, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	61,322	$	—	$	5,048	$	66,370
International equity funds	—		42,888		—		—		42,888
Core bond fund	—		32,378		—		—		32,378
High-yield bond fund	—		17,377		—		—		17,377
Emerging markets bond fund	—		16,873		—		—		16,873
Combination debt/equity/other fund	—		13,048		—		—		13,048
Alternative investments fund	—		—		—		20,584		20,584
Real estate securities fund	—		—		—		10,380		10,380
Cash equivalents	133		—		—		—		133
Total Nuclear Decommissioning Trust	133		183,886		—		36,012		220,031
Trading Securities:
Domestic equity funds	—		17,523		—		—		17,523
International equity fund	—		4,361		—		—		4,361
Core bond fund	—		11,739		—		—		11,739
Total Trading Securities	—		33,623		—		—		33,623
Total Assets Measured at Fair Value	$	133	$	217,509	$	—	$	36,012	$	253,654

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

Unrealized Gains And Losses On Fair Value Assets And Liabilities

Investments In Financial Instruments

The following table provides additional information on these investments.



	As of June 30, 2017				As of December 31, 2016				As of June 30, 2017
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,048	$	3,129	$	5,056	$	3,529	(a)	(a)
Alternative investments fund (b)	20,584		—		18,958		—		Quarterly	65 days
Real estate securities fund (b)	10,380		—		9,946		—		Quarterly	65 days
Total	$	36,012	$	3,129	$	33,960	$	3,529

_______________

(a)


(b)	There is a holdback on final redemptions.

- Definition

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

+ References + Details

Financial Investments (Tables)

6 Months Ended

Jun. 30, 2017

Investments [Abstract]

Cost And Fair Value Of Investments

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



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2017:
Domestic equity funds	$	54,563	$	12,260	$	(453	)	$	66,370	30	%
International equity funds	35,664		7,224		—			42,888		19	%
Core bond fund	32,542		—		(164		)	32,378		15	%
High-yield bond fund	17,060		317		—			17,377		8	%
Emerging markets bond fund	17,047		—		(174		)	16,873		8	%
Combination debt/equity/other fund	7,980		5,068		—			13,048		6	%
Alternative investments fund	15,000		5,584		—			20,584		9	%
Real estate securities fund	9,500		880		—			10,380		5	%
Cash equivalents	133		—		—			133		<1%
Total	$	189,489	$	31,333	$	(791	)	$	220,031	100	%

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

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

June 30, 2017, and December 31, 2016.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of June 30, 2017:
Domestic equity funds	$	3,780	$	(453	)	$	—	$	—		$	3,780	$	(453	)
Core bond fund	32,378		(164		)	—		—			32,378		(164		)
Emerging markets bond fund	—		—			16,873		(174		)	16,873		(174		)
Total	$	36,158	$	(617	)	$	16,873	$	(174	)	$	53,031	$	(791	)

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

Pension and Post-Retirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2017

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,921			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			114
Actuarial loss (gain), net	5,489			5,146			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(210		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(696	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	10,437		$	9,297		$	542		$	542
Interest cost	21,242			21,880			2,627			2,786
Expected return on plan assets	(21,520		)	(21,326		)	(3,436		)	(3,417		)
Amortization of unrecognized:
Prior service costs	341			420			228			228
Actuarial loss (gain), net	10,978			10,534			(390		)	(560		)
Net periodic cost (benefit) before regulatory adjustment	21,478			20,805			(429		)	(421		)
Regulatory adjustment (a)	6,576			6,613			(956		)	(972		)
Net periodic cost (benefit)	$	28,054		$	27,418		$	(1,385	)	$	(1,393	)

_______________


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

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

6 Months Ended

Jun. 30, 2017

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,218		$	4,633		$	271		$	271
Interest cost	10,621			10,921			1,314			1,393
Expected return on plan assets	(10,760		)	(10,663		)	(1,718		)	(1,708		)
Amortization of unrecognized:
Prior service costs	171			174			114			114
Actuarial loss (gain), net	5,489			5,146			(195		)	(280		)
Net periodic cost (benefit) before regulatory adjustment	10,739			10,211			(214		)	(210		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Net periodic cost (benefit)	$	14,027		$	13,517		$	(692	)	$	(696	)

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	10,437		$	9,297		$	542		$	542
Interest cost	21,242			21,880			2,627			2,786
Expected return on plan assets	(21,520		)	(21,326		)	(3,436		)	(3,417		)
Amortization of unrecognized:
Prior service costs	341			420			228			228
Actuarial loss (gain), net	10,978			10,534			(390		)	(560		)
Net periodic cost (benefit) before regulatory adjustment	21,478			20,805			(429		)	(421		)
Regulatory adjustment (a)	6,576			6,613			(956		)	(972		)
Net periodic cost (benefit)	$	28,054		$	27,418		$	(1,385	)	$	(1,393	)

_______________


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

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	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			82
Expected return on plan assets	(2,643		)	(2,430		)	—			—
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			2,774			94			110
Regulatory adjustment (a)	247			483			—			—
Net periodic cost	$	3,288		$	3,257		$	94		$	110

_______________


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



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,900		$	3,374		$	73		$	64
Interest cost	4,950			4,828			140			163
Expected return on plan assets	(5,286		)	(4,861		)	—			—
Amortization of unrecognized:
Prior service costs	28			28			—			—
Actuarial loss (gain), net	2,490			2,178			(25		)	(8		)
Net periodic cost before regulatory adjustment	6,082			5,547			188			219
Regulatory adjustment (a)	494			966			—			—
Net periodic cost	$	6,576		$	6,513		$	188		$	219

_______________


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

Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2017

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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



	As of		As of
	June 30, 2017		December 31, 2016
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	252,737	$	257,904
Regulatory assets (a)	11,155		10,396

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,538	$	26,842
Accrued interest (b)	706		867
Long-term debt of variable interest entities, net	82,653		111,209

_______________

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

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

- Definition

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

+ References + Details

Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Total	$ 302,696	$ 300,125
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	106,764	107,086
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 195,932	$ 193,039

Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Accounting Policies [Abstract]
Borrowed funds	$ (895)	$ (2,338)	$ (2,748)	$ (4,347)
Equity funds	0	2,783	773	5,247
Total	$ 895	$ 5,121	$ 3,521	$ 9,594
Average AFUDC rates	1.50%	4.20%	2.00%	4.60%

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Accounting Policies [Abstract]
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	$ 130	$ 156	$ 237	$ 290
Net income allocated to common stock	$ 71,935	$ 72,184	$ 131,489	$ 137,635
Weighted Average Number of Shares Outstanding , Basic	142,465,749	142,033,842	142,451,266	142,013,344
RSUs	130,607	463,493	127,989	348,003
Weighted average equivalent common shares outstanding - diluted	142,596,356	142,497,335	142,579,255	142,361,347
Earnings Per Share, Basic	$ 0.50	$ 0.51	$ 0.92	$ 0.97
Earnings Per Share, Diluted	$ 0.50	$ 0.51	$ 0.92	$ 0.97
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	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash Paid For (Received From)
Interest on financing activities	$ 76,024	$ 70,697
Income taxes, net of refunds	(12,685)	(77)
Noncash Investing and Financing Transactions
Property, plant and equipment	89,899	71,830
Issuance of common stock for reinvested dividends and compensation plans	4,801	4,941
Deconsolidation of VIE	(5,760)
Assets acquired through capital leases	3,054	392
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 1,696	$ 4,150

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

- Definition

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

+ References + Details

Pending Merger Pending Merger (Narrative) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2017	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Jul. 09, 2017
Westar Energy [Member] \| Subsequent Event [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio					1
Business Acquisition, Percentage of Voting Interests Acquired					52.50%
Westar Energy [Member] \| Subsequent Event [Member] \| Westar Energy breaches agreement and enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee					$ 190.0
Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Acquisition Related Costs		$ 0.3	$ 0.7	$ 10.2
Business Combination, Expected Acquisition Related Costs			$ 45.0
Great Plains Energy, Inc. Merger [Member] \| Subsequent Event [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio					0.5981
Business Acquisition, Percentage of Voting Interests Acquired					47.50%
Cash					$ 1,250.0
Business Combination, Expected Acquisition Related Costs	$ 7.5
Great Plains Energy, Inc. Merger [Member] \| Subsequent Event [Member] \| End date occurred and Great Plains Energy enters into acquisition proposal within 12 months of termination, paid to Westar Energy [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee					190.0
Great Plains Energy, Inc. Merger [Member] \| Subsequent Event [Member] \| Great Plains Energy breaches merger agreement and enters into acquisition proposal within 12 months of termination [Member] [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee					190.0
Great Plains Energy, Inc. Merger [Member] \| Subsequent Event [Member] \| Great Plains shareholder no vote, paid to Westar Energy [Domain]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee					$ 80.0

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

Financial Instruments and Risk Management (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,605,000	$ 3,430,000
Fair Value	3,846,301	3,597,441
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	111,122	137,962
Fair Value	$ 111,850	$ 139,733

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

6 Months Ended

Jun. 30, 2017

Dec. 31, 2016

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

$ 220,031

$ 200,122

Trading securities

33,623

34,491

Total

253,654

234,613

Fair Value [Member]

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

36,012

33,960

Financial and Derivative Instruments and Trading Securities [Line Items]

Financial and Derivative Instruments and Trading Securities [Line Items]

3,129

3,529

Domestic Equity [Member]

Domestic Equity [Member] | Fair Value [Member]

66,370

61,368

Trading securities

17,523

18,364

Financial and Derivative Instruments and Trading Securities [Line Items]

^[1]

5,048

5,056

Alternative Funds [Member]

3,129

3,529

Financial and Derivative Instruments and Trading Securities [Line Items]

Alternative Funds [Member] | Fair Value [Member]

20,584

18,958

Financial and Derivative Instruments and Trading Securities [Line Items]

20,584

18,958

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

^[2]

65 days

Real Estate Securities [Member]

Financial and Derivative Instruments and Trading Securities [Line Items]

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

$ 10,380

9,946

Financial and Derivative Instruments and Trading Securities [Line Items]

10,380

9,946

Investment redemption frequency

$ 0

Quarterly

Investment redemption length of settlement

65 days

[1]

[2]

There is a holdback on final redemptions.

Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 33,623		$ 33,623		$ 34,491
Unrealized gains losses	1,100	$ 600	2,500	$ 1,100
Realized gains on available-for-sale-securities	$ (200)	$ 100	$ 100	$ 1,400

Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,100	$ 600	$ 2,500	$ 1,100
Trading securities	33,623		33,623		$ 34,491
Cost	189,489		189,489		184,145
Available-for-sale Securities, Gross Unrealized Gain	31,333		31,333		19,087
Available-for-sale Securities, Gross Unrealized Loss	(791)		(791)		(3,110)
Available-for-sale Securities	$ 220,031		$ 220,031		$ 200,122
Allocation	100.00%		100.00%		100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 17,523		$ 17,523		$ 18,364
Cost	54,563		54,563		53,192
Available-for-sale Securities, Gross Unrealized Gain	12,260		12,260		8,295
Available-for-sale Securities, Gross Unrealized Loss	(453)		(453)		(119)
Available-for-sale Securities	$ 66,370		$ 66,370		$ 61,368
Allocation	30.00%		30.00%		31.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 4,361		$ 4,361		$ 4,467
Cost	35,664		35,664		34,502
Available-for-sale Securities, Gross Unrealized Gain	7,224		7,224		2,075
Available-for-sale Securities, Gross Unrealized Loss	0		0		(633)
Available-for-sale Securities	$ 42,888		$ 42,888		$ 35,944
Allocation	19.00%		19.00%		18.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 11,739		$ 11,739		$ 11,504
Cost	32,542		32,542		27,952
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(164)		(164)		(529)
Available-for-sale Securities	$ 32,378		$ 32,378		$ 27,423
Allocation	15.00%		15.00%		14.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,060		$ 17,060		$ 18,358
Available-for-sale Securities, Gross Unrealized Gain	317		317		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		(170)
Available-for-sale Securities	$ 17,377		$ 17,377		$ 18,188
Allocation	8.00%		8.00%		9.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 17,047		$ 17,047		$ 16,397
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(174)		(174)		(1,659)
Available-for-sale Securities	$ 16,873		$ 16,873		$ 14,738
Allocation	8.00%		8.00%		7.00%
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 7,980		$ 7,980
Available-for-sale Securities, Gross Unrealized Gain	5,068		5,068
Available-for-sale Securities, Gross Unrealized Loss	0		0
Available-for-sale Securities	$ 13,048		$ 13,048
Allocation	6.00%		6.00%
Combination Debt and Equity Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost					$ 9,171
Available-for-sale Securities, Gross Unrealized Gain					4,313
Available-for-sale Securities, Gross Unrealized Loss					0
Available-for-sale Securities					$ 13,484
Allocation					7.00%
Alternative Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 15,000		$ 15,000		$ 15,000
Available-for-sale Securities, Gross Unrealized Gain	5,584		5,584		3,958
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 20,584		$ 20,584		$ 18,958
Allocation	9.00%		9.00%		9.00%
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,500		$ 9,500		$ 9,500
Available-for-sale Securities, Gross Unrealized Gain	880		880		446
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 10,380		$ 10,380		$ 9,946
Allocation	5.00%		5.00%		5.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities					$ 156
Cost	$ 133		$ 133		73
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 133		$ 133		$ 73

Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,100	$ 600	$ 2,500	$ 1,100
Fair Value, Less than 12 Months	36,158		36,158		$ 29,211
Gross Unrealized Losses, Less than 12 Months	(617)		(617)		(648)
Fair Value, 12 Months or Greater	16,873		16,873		40,415
Gross Unrealized Losses, 12 Months or Greater	(174)		(174)		(2,462)
Fair Value, Total	53,031		53,031		69,626
Gross Unrealized Losses, Total	(791)		(791)		(3,110)
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	3,780		3,780		1,788
Gross Unrealized Losses, Less than 12 Months	(453)		(453)		(119)
Fair Value, 12 Months or Greater	0		0		0
Gross Unrealized Losses, 12 Months or Greater	0		0		0
Fair Value, Total	3,780		3,780		1,788
Gross Unrealized Losses, Total	(453)		(453)		(119)
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months					0
Gross Unrealized Losses, Less than 12 Months					0
Fair Value, 12 Months or Greater					7,489
Gross Unrealized Losses, 12 Months or Greater					(633)
Fair Value, Total					7,489
Gross Unrealized Losses, Total					(633)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	32,378		32,378		27,423
Gross Unrealized Losses, Less than 12 Months	(164)		(164)		(529)
Fair Value, 12 Months or Greater	0		0		0
Gross Unrealized Losses, 12 Months or Greater	0		0		0
Fair Value, Total	32,378		32,378		27,423
Gross Unrealized Losses, Total	(164)		(164)		(529)
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months					0
Gross Unrealized Losses, Less than 12 Months					0
Fair Value, 12 Months or Greater					18,188
Gross Unrealized Losses, 12 Months or Greater					(170)
Fair Value, Total					18,188
Gross Unrealized Losses, Total					(170)
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	16,873		16,873		14,738
Gross Unrealized Losses, 12 Months or Greater	(174)		(174)		(1,659)
Fair Value, Total	16,873		16,873		14,738
Gross Unrealized Losses, Total	$ (174)		$ (174)		$ (1,659)

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

Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Income Tax Contingency [Line Items]
Income tax expense	$ 35,906	$ 40,542	$ 56,816	$ 79,165
Effective income tax rate	32.00%	35.00%	29.00%	35.00%
Liability for unrecognized income tax benefits					$ 2,800
Interest on liability related to unrecognized income tax benefits	$ 100		$ 100		0
Penalties accrued for unrecognized income tax benefits	0		0		0
Accrual for taxes other than income taxes	$ 100		$ 100		$ 1,500

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

3 Months Ended

6 Months Ended

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Payment for Pension Benefits

$ 13,100

$ 11,200

Pension Benefits [Member]

$ 5,218

$ 4,633

10,437

9,297

10,621

10,921

21,242

21,880

(10,760)

(10,663)

(21,520)

(21,326)

171

174

341

420

5,489

5,146

10,978

10,534

10,739

10,211

21,478

20,805

3,288

^[1]

3,306

^[1]

6,576

^[2]

6,613

^[2]

Post-Retirement Benefits [Member]

14,027

13,517

28,054

27,418

271

542

1,314

1,393

2,627

2,786

(1,718)

(1,708)

(3,436)

(3,417)

114

228

(195)

(280)

(390)

(560)

(214)

(210)

(429)

(421)

(478)

^[1]

(486)

^[1]

(956)

^[2]

(972)

^[2]

$ (692)

$ (696)

$ (1,385)

$ (1,393)

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

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

3 Months Ended

6 Months Ended

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Payment for Pension Benefits

$ 13,100,000

$ 11,200,000

Wolf Creek [Member]

Payment for Pension Benefits

$ 0

3,200,000

KGE Member

Subsidiary Interest in Defined Benefit Plans

47.00%

Pension Benefits [Member]

$ 5,218,000

$ 4,633,000

$ 10,437,000

9,297,000

10,621,000

10,921,000

21,242,000

21,880,000

(10,760,000)

(10,663,000)

(21,520,000)

(21,326,000)

171,000

174,000

341,000

420,000

5,489,000

5,146,000

10,978,000

10,534,000

10,739,000

10,211,000

21,478,000

20,805,000

3,288,000

^[1]

3,306,000

^[1]

6,576,000

^[2]

6,613,000

^[2]

Pension Benefits [Member] | Wolf Creek [Member]

14,027,000

13,517,000

28,054,000

27,418,000

1,950,000

1,687,000

3,900,000

3,374,000

2,475,000

2,414,000

4,950,000

4,828,000

(2,643,000)

(2,430,000)

(5,286,000)

(4,861,000)

14,000

28,000

1,245,000

1,089,000

2,490,000

2,178,000

3,041,000

2,774,000

6,082,000

5,547,000

247,000

^[3]

483,000

^[3]

494,000

^[4]

966,000

^[4]

Post-Retirement Benefits [Member]

3,288,000

3,257,000

6,576,000

6,513,000

271,000

542,000

1,314,000

1,393,000

2,627,000

2,786,000

(1,718,000)

(1,708,000)

(3,436,000)

(3,417,000)

114,000

228,000

(195,000)

(280,000)

(390,000)

(560,000)

(214,000)

(210,000)

(429,000)

(421,000)

(478,000)

^[1]

(486,000)

^[1]

(956,000)

^[2]

(972,000)

^[2]

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

(692,000)

(696,000)

(1,385,000)

(1,393,000)

37,000

32,000

73,000

64,000

70,000

82,000

140,000

163,000

(13,000)

(4,000)

(25,000)

(8,000)

94,000

110,000

188,000

219,000

^[3]

^[4]

Variable Interest Entity [Line Items]

$ 94,000

$ 110,000

$ 188,000

$ 219,000

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

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

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Liabilities Settled	$ (1,431)
Asset Retirement Obligation, Accretion Expense	8,077
Asset Retirement Obligation, Revision of Estimate	34,713
Asset Retirement Obligation, Liabilities Incurred	13,471
Asset Retirement Obligation	378,781	$ 323,951
Asset Retirement Obligation, Current	(10,548)
Asset Retirement Obligations, Noncurrent	$ 368,233	$ 323,951

Variable Interest Entities (Narrative) (Details)	6 Months Ended
Variable Interest Entities (Narrative) (Details)	Jun. 30, 2017 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Initial Consolidation, Gain (Loss)	$ 0
Jeffrey Energy Center [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	8.00%
Agreement expiration date	Jan. 01, 2019
La Cygne Generating Station [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	50.00%
Agreement expiration date	Sep. 01, 2029

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

Jun. 30, 2017

Dec. 31, 2016

$ 9,406,054

$ 9,248,359

125,000

^[1]

45,124

72,519

Variable Interest Entity, Primary Beneficiary [Member]

3,686,180

3,388,670

Variable Interest Entity [Line Items]

252,737

257,904

Regulatory assets

^[2]

11,155

10,396

28,538

26,842

^[1]

706

867