Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our 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.

Use of Management’s Estimates

When we prepare our 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 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 billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 4, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

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 December 31,
	2016		2015
	(In Thousands)
Fuel inventory	$	107,086	$	113,438
Supplies	193,039		187,856
Fuel inventory and supplies	$	300,125	$	301,294

Property, Plant and Equipment

We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:



	Year Ended December 31,
	2016			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	9,964		$	3,505		$	12,044
Equity funds	11,630			2,075			17,029
Total	$	21,594		$	5,580		$	29,073
Average AFUDC Rates	4.2		%	2.7		%	6.7		%

We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.

Depreciation

We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.4% in 2016, 2.5% in 2015 and 2.4% in 2014.

Depreciable lives of property, plant and equipment are as follows.



	Years
Fossil fuel generating facilities	6	to	78
Nuclear fuel generating facility	55	to	71
Wind generating facilities	19	to	20
Transmission facilities	15	to	75
Distribution facilities	22	to	68
Other	5	to	30

Nuclear Fuel

We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units. The accumulated amortization of nuclear fuel in the reactor was $40.0 million as of December 31, 2016, and $59.1 million as of December 31, 2015. The cost of nuclear fuel charged to fuel and purchased power expense was $26.8 million in 2016, $27.3 million in 2015 and $27.3 million in 2014.

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.



	As of December 31,
	2016			2015
	(In Thousands)
Cash surrender value of policies	$	1,267,349		$	1,299,408
Borrowings against policies	(1,137,360		)	(1,168,794		)
Corporate-owned life insurance, net	$	129,989		$	130,614

We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.

Revenue Recognition

We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $74.4 million as of December 31, 2016, and $66.0 million as of December 31, 2015.

Allowance for Doubtful Accounts

We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management’s judgment.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.

We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.

The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 11, “Taxes,” for additional detail on our accounting for income taxes.

Sales Tax

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.

Earnings Per Share

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

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

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



	Year Ended December 31,
	2016		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	361,200	$	301,796	$	322,325
Less: Net income attributable to noncontrolling interests	14,623		9,867		9,066
Net income attributable to Westar Energy, Inc.	346,577		291,929		313,259
Less: Net income allocated to RSUs	714		646		790
Net income allocated to common stock	$	345,863	$	291,283	$	312,469

Weighted average equivalent common shares outstanding – basic	142,067,558		137,957,515		130,014,941
Effect of dilutive securities:
RSUs	407,123		299,198		181,397
Forward sale agreements	—		1,021,510		2,628,187
Weighted average equivalent common shares outstanding – diluted (a)	142,474,681		139,278,223		132,824,525

Earnings per common share, basic	$	2.43	$	2.11	$	2.40
Earnings per common share, diluted	$	2.43	$	2.09	$	2.35

_______________


(a)	For the years ended December 31, 2016, 2015 and 2014, we had no antidilutive securities.

Supplemental Cash Flow Information



	Year Ended December 31,
	2016		2015			2014
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	139,029	$	161,484		$	160,292
Interest on financing activities of VIEs	5,846		10,430			12,183
Income taxes, net of refunds	13,103		(410		)	458
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	151,474		105,169			143,192
Property, plant and equipment of VIEs	—		—			(7,342		)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	9,685		10,453			9,155
Deconsolidation of VIEs	—		—			(7,342		)
Assets acquired through capital leases	2,744		3,130			8,717

New Accounting Pronouncements

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

Statement of Cash Flows

In August 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-15, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Among other clarifications, the guidance requires that cash proceeds received from the settlement of COLI policies be classified as cash inflows from investing activities and that cash payments for premiums on COLI policies may be classified as cash outflows for investing activities, operating activities or a combination of both. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Retrospective application is required. We are evaluating the guidance and do not expect it to have a material impact on our consolidated financial statements.

Stock-based Compensation

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

Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits or expense, respectively. Prior to the adoption of the ASU, additional paid-in-capital was not recognized to the extent that an excess tax benefit had not be realized (e.g., due to a carryforward of a net operating loss). Under the ASU, all excess tax benefits previously unrecognized because the related tax deduction had not reduced taxes payable are recognized on a modified retrospective basis as a cumulative-effect adjustment to retained earnings as of the date of adoption. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized as well as a $3.3 million increase in deferred tax assets.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying consolidated statements of cash flows for the years ended December 31, 2015 and 2014, as $1.3 million and $0.9 million higher than as previously reported, respectively. We have retrospectively presented cash flows used in financing activities as $1.3 million higher for the year ended December 31, 2015, than as previously reported and cash flows from financing activities as $0.9 million lower for the year ended December 31, 2014, than as previously reported.

Leases

In February 2016, the FASB issued ASU No. 2016-02, which requires a lessee to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The criteria used to determine lease classification will remain substantially the same, but will be more subjective under the new guidance. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. In 2016, we started evaluating our current leases to assess the initial impact on our consolidated financial results. We continue to evaluate the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated balance sheet, with minimal impact to our consolidated statement of income. We also continue to monitor unresolved industry issues, including renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts.

Financial Instruments - Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, which requires financial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.

Financial Instruments - Net Asset Value

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

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method. We continue to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. In summary, material revenue streams were identified and representative contract/transaction types were sampled. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. Based upon our completed assessments, we do not expect the impact on our consolidated financial statements to be material.

Pending Merger Pending Merger (Notes)	12 Months Ended
Pending Merger Pending Merger (Notes)	Dec. 31, 2016
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	On May 29, 2016, we entered into an agreement and plan of merger (merger) with Great Plains Energy Incorporated (Great Plains Energy), a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock. The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement, without prior approval of Great Plains Energy, limits our quarterly dividends declared in 2017 to $0.40 per share, which represents an annualized increase of $0.08 per share, consistent with last year’s dividend increase. The closing of the merger is subject to customary conditions including, among others, receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC’s review of the joint application. On September 27, 2016, the KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017. On December 16, 2016, KCC staff and its representatives filed testimony that, among other things, objected to the proposed merger, stated that no changes could be made to the joint application filed by us and Great Plains Energy that would satisfy the KCC staff and recommended that the KCC reject the merger. A number of intervening parties also filed testimony against approval of the merger. On January 9, 2017, we and Great Plains Energy filed rebuttal testimony in response to the KCC staff and the other intervenors explaining why we and Great Plains Energy believe the joint application meets the KCC’s merger standards and why the merger is in the public interest. An evidentiary hearing was held at the KCC from January 30, 2017 to February 7, 2017. In addition, there are two open dockets in Missouri related to the merger. In the first docket, Great Plains Energy sought approval from the Public Service Commission of the State of Missouri (MPSC) to waive certain affiliate transaction rules following the closing of the merger. In this docket, on October 12, 2016, and on October 26, 2016, the MPSC staff and the Office of Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that MPSC staff and the OPC would not file a complaint, or support another complaint, to assert that the MPSC has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the MPSC. Regarding the second docket, on October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the MPSC seeking to have the MPSC assert jurisdiction over the merger, and various parties have intervened in these complaints. The MPSC dismissed the complaint against us on December 6, 2016, but the complaint against Great Plains Energy remains open. On February 16, 2017, the MPSC indicated at a public meeting that it would assert jurisdiction over the merger, and it requested that an order be prepared to assert jurisdiction. Accordingly, we believe Great Plains Energy will also need approval of the MPSC in order to consummate the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. Approval of the merger application requires action by the FERC commissioners because it is a contested application. The Federal Power Act requires a quorum of three or more commissioners to act on a contested application. Following the resignation of the FERC Chairman effective February 3, 2017, the FERC commission is comprised only of two commissioners and is therefore unable to act on the application. A new commissioner must be appointed by the President of the United States, with the advice and consent of the United States Senate, before FERC will be able to act on the application. If the FERC commissioners do not issue an order on the application within 180 days after the application was deemed complete because of the lack of a quorum, approval of the application may be deemed granted by operation of law, unless an order is issued extending the time for review. The FERC staff has authority to issue an order extending the period for review of the application. Under these circumstances, we do not believe it is likely that the FERC staff will allow approval of our application to be deemed granted. We are unable to predict when FERC will regain a quorum or how the change in commissioners will impact the review of the application. On July 22, 2016, Wolf Creek filed a request with the Nuclear Regulatory Commission (NRC) to approve an indirect transfer of control of Wolf Creek’s operating license. On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSR Act on October 21, 2016. Under the HSR Act, a new statutory waiting period will start one year from the date on which an existing waiting period expires, or October 21, 2017. Accordingly, if the merger has not closed prior to October 21, 2017, we and Great Plains Energy will need to re-file the necessary HSR Act notifications. Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete the merger. The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of $180.0 million. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b) within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of $280.0 million. In connection with this transaction, we have incurred merger-related expenses. During 2016, we incurred approximately $10.2 million of merger-related expenses, which are included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expenses to coincide with the closing of the merger. See also Note 16, “Legal Proceedings,” for more information on litigation related to the merger.

Rate Matters And Regulation

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

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+ Details

Rate Matters And Regulation

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

RATE MATTERS AND REGULATION

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.



	As of December 31,
	2016		2015
	(In Thousands)
Regulatory Assets:
Deferred employee benefit costs	$	381,129	$	353,785
Amounts due from customers for future income taxes, net	124,020		144,120
Debt reacquisition costs	115,502		121,631
Depreciation	63,171		65,797
Asset retirement obligations	35,487		31,996
Retail energy cost adjustment	32,451		—
Treasury yield hedges	25,927		25,634
Wolf Creek outage	20,316		16,561
Ad valorem tax	17,637		44,455
Disallowed plant costs	15,453		15,639
La Cygne environmental costs	14,370		15,446
Analog meter unrecovered investment	8,500		1,454
Energy efficiency program costs	7,097		7,922
Other regulatory assets	18,802		16,478
Total regulatory assets	$	879,862	$	860,918

Regulatory Liabilities:
Deferred regulatory gain from sale leaseback	$	70,065	$	75,560
Pension and other post-retirement benefits costs	37,172		32,181
Nuclear decommissioning	34,094		30,659
Jurisdictional allowance for funds used during construction	33,119		32,673
La Cygne leasehold dismantling costs	27,742		25,330
Kansas tax credits	13,142		12,857
Purchase power agreement	9,265		9,972
Removal costs	5,663		53,834
Retail energy cost adjustment	—		12,686
Other regulatory liabilities	9,191		7,059
Total regulatory liabilities	$	239,453	$	292,811

Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

•

Deferred employee benefit costs: Includes $354.6 million for pension and post-retirement benefit obligations and $26.5 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. The increase from 2015 to 2016 is attributable primarily to a decrease in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations. During 2017, we will amortize to expense approximately $27.9 million of the benefit obligations and approximately $6.8 million of the excess pension expense. We are amortizing the excess pension expense over a five-year period. We do not earn a return on this asset.

•

Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices. We do not earn a return on this net asset.


•	Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.


•	Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.


•	Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 15, “Asset Retirement Obligations.” We recover these amounts over the life of the related plant. We do not earn a return on this asset.


•	Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the

cost of fuel and purchased power needed to serve our customers. This item represents the actual cost

of fuel consumed in producing electricity and the cost of purchased power in excess of the amounts we

have collected from customers. We expect to recover in our prices this shortfall over a one-year

period. We do not earn a return on this asset.


•	Treasury yield hedges: Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.


•	Wolf Creek outage: We defer the expenses associated with Wolf Creek’s scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.


•	Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.

•

Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the KCC revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.

•

La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.


•	Analog meter unrecovered investment: Represents the deferral of unrecovered investment of analog meters retired between October 2015 and the next general rate case. Once these amounts are included in base rates established in our next general rate case, we will amortize these amounts over a five-year period. No return on this regulatory asset is allowed.


•	Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.


•	Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.

Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.


•	Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne unit 2. We amortize the gain over the lease term.

•

Pension and other post-retirement benefits costs: Includes $7.4 million for pension and post-retirement benefit obligations and $29.8 million for pension and post-retirement expense recognized in setting our prices in excess of actual pension and post-retirement expense. During 2017, we will amortize to expense approximately $0.6 million of the benefit obligations and approximately $3.4 million of the excess pension and post-retirement expense recognized in setting our prices. We will amortize the excess pension and post-retirement expense over a five-year period.

•

Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 5, 6 and 15, “Financial Instruments and Trading Securities,” “Financial Investments” and “Asset Retirement Obligations,” respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.


•	Jurisdictional allowance for funds used during construction: This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our rates and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.


•	La Cygne leasehold dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.


•	Kansas tax credits: This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.


•	Purchase power agreement: This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a three-year period.


•	Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.

•

Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.


•	Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.

KCC Proceedings

General and Abbreviated Rate Reviews

In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $17.4 million. The KCC is required to issue an order on our request within 240 days of our filing, which is in June 2017.

In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million.

Environmental Costs

In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:


•	$10.8 million effective in June 2015; and


•	$11.0 million effective in June 2014.

Transmission Costs

We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:


•	$7.0 million effective in April 2016;


•	$7.2 million effective in April 2015; and


•	$41.0 million effective in April 2014.

In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the TFR, along with the reduced return on equity (ROE) as described below. The updated prices were retroactively effective April 2016. We have begun refunding our previously-recorded refund obligation and as of December 31, 2016, we have a remaining refund obligation of $1.3 million, which is included in current regulatory liabilities on our balance sheet.

Property Tax Surcharge

We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to adjust our annual retail revenues by approximately:


•	$26.8 million decrease effective in January 2017;


•	$5.0 million increase effective in January 2016;


•	$4.9 million increase effective in January 2015; and


•	$12.7 million increase effective in January 2014.

FERC Proceedings

In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years, we posted our TFR, which was expected to adjust our annual transmission revenues by approximately:


•	$29.6 million increase effective in January 2017;


•	$24.0 million increase effective in January 2016;


•	$4.6 million decrease effective in January 2015; and


•	$44.3 million increase effective in January 2014.

In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in a regional transmission organization (RTO). The updated prices were retroactively effective January 2016. This adjustment also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation and as of December 31, 2016, we have a remaining refund obligation of $1.2 million, which is included in current regulatory liabilities on our balance sheet.

Financial Instruments and Trading Securities

12 Months Ended

Dec. 31, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management

FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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


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

•

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


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

•

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

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

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



	As of December 31, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,597,441	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,962		139,733		166,271		179,030

Recurring Fair Value Measurements

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



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

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

Some of our investments in the 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 December 31, 2016				As of December 31, 2015				As of December 31, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,056	$	3,529	$	6,050	$	1,948	(a)	(a)
Alternative investment fund (b)	18,958		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,946		—		10,823		—		Quarterly	65 days
Total Nuclear Decommissioning Trust	$	33,960	$	3,529	$	33,312	$	1,948

_______________

(a)

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

Derivative Instruments

Price Risk

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

Interest Rate Risk

We have entered into numerous fixed and variable rate debt obligations. For details, see Note 10, “Long-Term Debt.” 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

12 Months Ended

Dec. 31, 2016

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. These obligations totaled $26.8 million and $27.4 million as of December 31, 2016 and 2015, respectively. For additional information on our benefit obligations, see Note 12, “Employee Benefit Plans.”

As of December 31, 2016 and 2015, we measured the fair value of trust assets at $34.5 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the years ended December 31, 2016, 2015 and 2014, we recorded unrealized gains of $2.5 million, $0.4 million and $2.6 million, respectively, on assets still held.

Available-for-Sale Securities

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

Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of $1.5 million and $0.9 million in 2016 and 2015, respectively. In 2014, we realized a gain on our available-for-sale securities of $0.1 million. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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



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

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

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



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of December 31, 2016:
Domestic equity funds	$	1,788	$	(119	)	$	—	$	—		$	1,788	$	(119	)
International equity funds	—		—			7,489		(633		)	7,489		(633		)
Core bond funds	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging market bond fund	—		—			14,738		(1,659		)	14,738		(1,659		)
Total	$	29,211	$	(648	)	$	40,415	$	(2,462	)	$	69,626	$	(3,110	)

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

Property, Plant And Equipment

12 Months Ended

Dec. 31, 2016

Public Utilities, Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

The following is a summary of our property, plant and equipment balance.



	As of December 31,
	2016			2015
	(In Thousands)
Electric plant in service	$	11,986,046		$	11,449,933
Electric plant acquisition adjustment	802,318			802,318
Accumulated depreciation	(4,404,977		)	(4,178,885		)
	8,383,387			8,073,366
Construction work in progress	773,095			349,402
Nuclear fuel, net	61,952			68,349
Plant to be retired, net (a)	29,925			33,785
Net property, plant and equipment	$	9,248,359		$	8,524,902

_______________

(a) Represents the planned retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.

The following is a summary of property, plant and equipment of VIEs.



	As of December 31,
	2016			2015
	(In Thousands)
Electric plant of VIEs	$	497,999		$	497,999
Accumulated depreciation of VIEs	(240,095		)	(229,760		)
Net property, plant and equipment of VIEs	$	257,904		$	268,239

We recorded depreciation expense on property, plant and equipment of $316.7 million in 2016, $287.9 million in 2015 and $263.8 million in 2014. Approximately $9.5 million, $9.6 million and $9.7 million of depreciation expense in 2016, 2015 and 2014, respectively, was attributable to property, plant and equipment of VIEs.

Joint Ownership of Utility Plants

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

Joint Ownership of Utility Plants

JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of December 31, 2016, is shown in the table below.



Plant	In-Service Dates	Investment		Accumulated Depreciation		Construction Work in Progress		Net MW	Ownership Percentage
		(Dollars in Thousands)
La Cygne unit 1 (a)	June 1973	$	613,348	$	163,234	$	39,096	368	50
JEC unit 1 (a)	July 1978	817,402		203,410		7,131		670	92
JEC unit 2 (a)	May 1980	567,298		200,296		4,198		675	92
JEC unit 3 (a)	May 1983	740,170		325,701		4,108		659	92
Wolf Creek (b)	Sept. 1985	1,922,877		842,595		82,756		551	47
State Line (c)	June 2001	111,444		62,332		861		196	40
Total		$	4,772,539	$	1,797,568	$	138,150	3,119

_______________


(a)	Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.


(b)	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 324 MW of net capacity. The VIE’s investment in the 50% interest was $392.1 million and accumulated depreciation was $208.7 million as of December 31, 2016. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 18, “Variable Interest Entities,” for additional information about VIEs.

Short-Term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Short-Term Debt

SHORT-TERM DEBT

In December 2016, Westar Energy extended the term of the $270.0 million revolving credit facility to terminate in February 2018. So long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $400.0 million, subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2016 and 2015, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20.7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2016, no amounts had been borrowed and $12.3 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility.

Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy’s revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. Westar Energy had $366.7 million and $250.3 million of commercial paper issued and outstanding as of December 31, 2016 and 2015, respectively.

In addition, total combined borrowings under Westar Energy’s commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as of December 31, 2016 and 2015, was 0.96% and 0.77%, respectively. Additional information regarding our short-term debt is as follows.



	Year Ended December 31,
	2016			2015
	(Dollars in Thousands)
Weighted average short-term debt outstanding	$	284,700		$	350,380
Weighted daily average interest rates, excluding fees	0.78		%	0.48		%

Our interest expense on short-term debt was $3.6 million in 2016, $3.0 million in 2015 and $2.0 million in 2014.

Long-Term Debt

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

Outstanding Debt

The following table summarizes our long-term debt outstanding.



	As of December 31,
	2016			2015
	(In Thousands)
Westar Energy
First mortgage bond series:
5.15% due 2017	$	125,000		$	125,000
5.10% due 2020	250,000			250,000
3.25% due 2025	250,000			250,000
2.55% due 2026	350,000			—
4.125% due 2042	550,000			550,000
4.10% due 2043	430,000			430,000
4.625% due 2043	250,000			250,000
4.25% due 2045	300,000			300,000
	2,505,000			2,155,000
Pollution control bond series:
Variable due 2032, 1.14% as of December 31, 2016; 0.02% as of December 31, 2015	45,000			45,000
Variable due 2032, 1.32% as of December 31, 2016; 0.02% as of December 31, 2015	30,500			30,500
	75,500			75,500

KGE
First mortgage bond series:
6.70% due 2019	300,000			300,000
6.15% due 2023	50,000			50,000
6.53% due 2037	175,000			175,000
6.64% due 2038	100,000			100,000
4.30% due 2044	250,000			250,000
	875,000			875,000
Pollution control bond series:
Variable due 2027, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	21,940			21,940
4.85% due 2031	—			50,000
2.50% due 2031	50,000			—
Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	14,500			14,500
Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	10,000			10,000
	96,440			96,440

Total long-term debt	3,551,940			3,201,940
Unamortized debt discount (a)	(10,358		)	(10,374		)
Unamortized debt issuance expense (a)	(27,912		)	(27,616		)
Long-term debt due within one year	(125,000		)	—
Long-term debt, net	$	3,388,670		$	3,163,950

Variable Interest Entities
5.92% due 2019 (b)	$	1,157		$	4,223
5.647% due 2021 (b)	—			162,048
2.398% due 2021 (b)	136,805			—
Total long-term debt of variable interest entities	137,962			166,271
Unamortized debt premium (a)	89			135
Long-term debt of variable interest entities due within one year	(26,842		)	(28,309		)
Long-term debt of variable interest entities, net	$	111,209		$	138,097

_______________

(a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.

(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGE first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended, is limited to a maximum of $3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2016, approximately $931.6 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. As of December 31, 2016, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in KGE’s mortgage.

As of December 31, 2016, we had $121.9 million of variable rate, tax-exempt bonds outstanding. While the interest rates for these bonds have been low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.

In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds bearing a stated interest at 5.15% maturing January 2017.

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used in renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE redeemed and reissued $50.0 million in principal amount pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a redemption and reissuance of $162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 18, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

In November 2015, Westar Energy issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 3.25% and maturing December 2025. Concurrently, Westar Energy issued $300.0 million in principal amount of first mortgage bonds bearing stated interest at 4.25% and maturing December 2045.

Also in November 2015, Westar Energy redeemed $300.0 million in principal amount of first mortgage bonds bearing stated interest at 8.625% maturing in December 2018 for $360.9 million which included a call premium. The call premium was recorded as a regulatory asset and is being amortized over the term of the new bonds.

In August 2015, Westar Energy redeemed $150.0 million in principal amount of first mortgage bonds bearing stated interest at 5.875% and maturing July 2036.

In January 2015, Westar Energy redeemed $125.0 million in principal amount of first mortgage bonds bearing stated interest at 5.95% and maturing January 2035.

With the exception of Green Bonds, proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.

Maturities

The principal amounts of our long-term debt maturities as of December 31, 2016, are as follows.



Year	Long-term debt		Long-term debt of VIEs
	(In Thousands)
2017	$	125,000	$	26,842
2018	—		28,538
2019	300,000		31,485
2020	250,000		32,254
2021	—		18,843
Thereafter	2,876,940		—
Total maturities	$	3,551,940	$	137,962

Interest expense on long-term debt, net of debt AFUDC, was $141.4 million in 2016, $152.7 million in 2015 and $158.8 million in 2014. Interest expense on long-term debt of VIEs was $4.2 million in 2016, $9.8 million in 2015 and $11.4 million in 2014.

Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Taxes

TAXES

Income tax expense is comprised of the following components.



	Year Ended December 31,
	2016			2015			2014
	(In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal	$	(1,007	)	$	327		$	416
State	318			341			(597		)
Deferred income taxes:
Federal	155,230			124,891			124,923
State	32,892			29,484			29,657
Investment tax credit amortization	(2,893		)	(3,043		)	(3,129		)
Income tax expense	$	184,540		$	152,000		$	151,270

The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.



	As of December 31,
	2016		2015
	(In Thousands)
Deferred tax assets:
Tax credit carryforward (a)	$	265,750	$	266,963
Deferred employee benefit costs	137,337		122,757
Net operating loss carryforward (b)	86,693		129,232
Deferred state income taxes	73,294		67,307
Deferred compensation	31,981		27,266
Deferred regulatory gain on sale-leaseback	30,868		33,287
Alternative minimum tax carryforward (c)	29,412		26,725
Accrued liabilities	21,757		21,115
LaCygne dismantling cost	10,972		10,018
Disallowed costs	9,600		10,211
Capital loss carryforward	—		1,668
Other	47,200		41,319
Total gross deferred tax assets	744,864		757,868
Less: Valuation allowance	—		1,668
Deferred tax assets	$	744,864	$	756,200

Deferred tax liabilities:
Accelerated depreciation	$	1,925,270	$	1,787,457
Acquisition premium	147,868		155,881
Deferred employee benefit costs	137,337		122,757
Amounts due from customers for future income taxes, net	124,020		144,120
Deferred state income taxes	61,110		59,787
Debt reacquisition costs	41,753		42,314
Pension expense tracker	5,560		12,051
Other	54,722		23,263
Total deferred tax liabilities	$	2,497,640	$	2,347,630

Net deferred income tax liabilities	$	1,752,776	$	1,591,430

_______________

(a)

Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2016), we had available federal general business tax credits of $88.4 million and state investment tax credits of $177.3 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2036. The state investment tax credits expire beginning in 2021 and ending in 2032.


(b)	As of December 31, 2016, we had a federal net operating loss carryforward of $198.1 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2032 and ending in 2035.


(c)	As of December 31, 2016, we had available an alternative minimum tax credit carryforward of $29.4 million, which has an unlimited carryforward period.

In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.

Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.



	Year Ended December 31,
	2016		2015		2014
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
Effect of:
COLI policies	(4.2	)	(4.4	)	(4.0	)
State income taxes	4.0		4.3		4.0
Flow through depreciation for plant-related differences	3.1		2.6		2.0
Production tax credits	(1.8	)	(2.1	)	(2.1	)
Non-controlling interest	(0.9	)	(0.8	)	(0.7	)
AFUDC equity	(0.8	)	(0.2	)	(1.3	)
Amortization of federal investment tax credits	(0.5	)	(0.7	)	(0.7	)
Share based payments	(0.5	)	(0.1	)	—
Capital loss utilization carryforward	0.4		(0.1	)	(0.3	)
Liability for unrecognized income tax benefits	—		—		(0.2	)
Other	—		—		0.2
Effective income tax rate	33.8	%	33.5	%	31.9	%

We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2013 and forward.

The unrecognized income tax benefits decreased from $2.9 million at December 31, 2015, to $2.8 million at December 31, 2016. The decrease for unrecognized income tax benefits was primarily attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement in a tax period for which the statute of limitations has closed. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:



	2016			2015			2014
	(In Thousands)
Unrecognized income tax benefits as of January 1	$	2,901		$	3,188		$	1,703
Additions based on tax positions related to the current year	434			410			872
Additions for tax positions of prior years	—			—			813
Reductions for tax positions of prior years	(1		)	(86		)	(200		)
Lapse of statute of limitations	(568		)	(611		)	—
Settlements	—			—			—
Unrecognized income tax benefits as of December 31	$	2,766		$	2,901		$	3,188

The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $2.7 million, $2.9 million and $3.2 million (net of tax) as of December 31, 2016, 2015 and 2014, respectively.

Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2016 and 2015, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2016 or 2015.

As of December 31, 2016 and 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Pension and Post-Retirement Benefit Plans

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, and union employees hired after December 31, 2011, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.

The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee’s years of service. In 2014 and prior years, our retirees were covered under a health insurance policy. In January 2015, we began giving our retirees a fixed annual allowance, which provides them the flexibility to obtain health coverage in the marketplace that is tailored to their needs.

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. See Note 13, “Wolf Creek Employee Benefit Plans,” for information about Wolf Creek’s benefit plans.

The following tables summarize the status of our pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	965,193		$	1,030,645		$	126,284		$	141,516
Service cost	18,563			21,392			1,084			1,443
Interest cost	43,723			43,014			5,571			5,691
Plan participants’ contributions	—			—			395			582
Benefits paid	(63,540		)	(44,945		)	(7,697		)	(6,549		)
Actuarial losses (gains)	51,482			(90,644		)	3,926			(16,399		)
Amendments	(3,397		)	5,731			—			—
Benefit obligation, end of year (a)	$	1,012,024		$	965,193		$	129,563		$	126,284

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	653,945		$	661,141		$	115,416		$	121,349
Actual return on plan assets	45,181			(6,948		)	7,274			(208		)
Employer contributions	20,200			41,000			—			—
Plan participants’ contributions	—			—			356			534
Benefits paid	(60,852		)	(41,248		)	(7,427		)	(6,259		)
Fair value of plan assets, end of year	$	658,474		$	653,945		$	115,619		$	115,416

Funded status, end of year	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,260	)	$	(2,745	)	$	(284	)	$	(344	)
Noncurrent liability	(351,290		)	(308,503		)	(13,660		)	(10,524		)
Net amount recognized	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	282,462		$	254,085		$	(7,603	)	$	(12,208	)
Prior service cost	3,913			8,078			2,674			3,130
Net amount recognized	$	286,375		$	262,163		$	(4,929	)	$	(9,078	)

_______________

(a) As of December 31, 2016 and 2015, pension benefits include non-qualified benefit obligations of $26.8 million and $27.4 million, respectively, which are funded by a trust containing assets of $34.5 million and $33.9 million, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 5 and 6, “Financial Instruments and Trading Securities” and “Financial Investments,” respectively, for additional information regarding these amounts.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	1,012,024		$	965,193		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	905,661		$	864,263		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	129,563		$	126,284
Fair value of plan assets	—			—			115,619			115,416

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.25		%	4.60		%	4.15		%	4.51		%
Compensation rate increase	4.00		%	4.00		%	—			—

We use a measurement date of December 31 for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2016, increased the pension and post-retirement benefit obligations by approximately $50.2 million and $5.0 million, respectively.

We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2016			2015			2014			2016			2015			2014
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	18,563		$	21,392		$	16,218		$	1,084		$	1,443		$	1,381
Interest cost	43,723			43,014			41,600			5,571			5,691			6,351
Expected return on plan assets	(42,653		)	(40,236		)	(36,438		)	(6,835		)	(6,614		)	(6,576		)
Amortization of unrecognized:
Prior service costs	768			520			526			455			455			2,524
Actuarial loss (gain), net	20,577			32,131			19,362			(1,118		)	379			(742		)
Net periodic cost (benefit) before regulatory adjustment	40,978			56,821			41,268			(843		)	1,354			2,938
Regulatory adjustment (a)	14,528			6,886			15,479			(1,922		)	4,096			4,499
Net periodic cost (benefit)	$	55,506		$	63,707		$	56,747		$	(2,765	)	$	5,450		$	7,437

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain)	$	48,954		$	(43,459	)	$	162,569		$	3,486		$	(9,576	)	$	15,896
Amortization of actuarial (loss) gain	(20,577		)	(32,379		)	(19,362		)	1,118			(379		)	742
Current year prior service cost	(3,397		)	5,730			—			—			—			(7,834		)
Amortization of prior service costs	(768		)	(520		)	(526		)	(455		)	(455		)	(2,524		)
Other adjustments	—			352			—			—			—			—
Total recognized in regulatory assets	$	24,212		$	(70,276	)	$	142,681		$	4,149		$	(10,410	)	$	6,280

Total recognized in net periodic cost and regulatory assets	$	79,718		$	(6,569	)	$	199,428		$	1,384		$	(4,960	)	$	13,717

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate	4.60		%	4.17		%	5.07		%	4.51		%	4.10		%	4.88		%
Expected long-term return on plan assets	6.50		%	6.50		%	6.50		%	6.00		%	6.00		%	6.00		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%

_______________


(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.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	21,956	$	(780	)
Prior service cost	683		455
Total	$	22,639	$	(325	)

We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

Plan Assets

We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company’s debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.

Target allocations for our pension plan assets are approximately 39% to debt securities, 39% to equity securities, 12% to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining 10% to a fund which provides tactical portfolio overlay by investing in futures related to debt, equity and foreign currency. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.

Target allocations for our post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities. Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy. See Note 5, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	168,407	$	—	$	23,580	$	191,987
International equity fund	—		83,738		—		—		83,738
Emerging market equity fund	—		21,055		—		—		21,055
Domestic bond fund	—		101,200		—		—		101,200
Core bond funds	—		86,109		—		—		86,109
High-yield bond fund	—		30,729		—		—		30,729
Emerging market bond fund	—		23,584		—		—		23,584
Combination debt/equity/other fund	—		37,851		—		—		37,851
Alternative investment funds	—		—		—		43,686		43,686
Real estate securities fund	—		—		—		32,390		32,390
Cash equivalents	—		6,145		—		—		6,145
Total Assets Measured at Fair Value	$	—	$	558,818	$	—	$	99,656	$	658,474

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
Assets:	(In Thousands)
Domestic equity funds	$	—	$	165,506	$	—	$	25,277	$	190,783
International equity fund	—		75,453		—		—		75,453
Emerging market equity fund	—		20,798		—		—		20,798
Domestic bond fund	—		105,279		—		—		105,279
Core bond funds	—		99,726		—		—		99,726
High-yield bond fund	—		28,288		—		—		28,288
Emerging market bond fund	—		23,019		—		—		23,019
Combination debt/equity/other fund	—		36,151		—		—		36,151
Alternative investment funds	—		—		—		39,557		39,557
Real estate securities fund	—		—		—		30,173		30,173
Cash equivalents	—		4,718		—		—		4,718
Total Assets Measured at Fair Value	$	—	$	558,938	$	—	$	95,007	$	653,945

The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	61,055	$	—	$	—	$	61,055
International equity fund	—		15,034		—		—		15,034
Core bond funds	—		38,952		—		—		38,952
Cash equivalents	—		578		—		—		578
Total Assets Measured at Fair Value	$	—	$	115,619	$	—	$	—	$	115,619

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	59,946	$	—	$	—	$	59,946
International equity fund	—		14,419		—		—		14,419
Core bond funds	—		40,475		—		—		40,475
Cash equivalents	—		576		—		—		576
Total Assets Measured at Fair Value	$	—	$	115,416	$	—	$	—	$	115,416

Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.



	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2017	$	25.2					$	—

Expected benefit payments:
2017	$	(55.7	)	$	(2.3	)	$	(7.8	)	$	(0.3	)
2018	(58.1		)	(2.3		)	(7.9		)	(0.3		)
2019	(60.2		)	(2.3		)	(8.1		)	(0.3		)
2020	(62.7		)	(2.2		)	(8.2		)	(0.2		)
2021	(64.4		)	(2.2		)	(8.3		)	(0.2		)
2022-2026	(325.1		)	(10.8		)	(40.2		)	(0.9		)

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $8.0 million in 2016, $7.7 million in 2015 and $7.0 million in 2014.

Stock-Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to 8.3 million shares of common stock may be granted under the LTISA Plan. As of December 31, 2016, awards of approximately 5.2 million shares of common stock had been made under the plan.

All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to four years. However, upon consummation of the merger, all unrecognized compensation costs for outstanding RSU awards will be expensed on our income statement. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.



	Year Ended December 31,
	2016		2015		2014
	(In Thousands)
Compensation expense	$	9,237	$	8,250	$	7,193
Income tax benefits related to stock-based compensation arrangements	3,653		3,263		2,845

We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.

RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy’s common stock, are paid on these RSUs during the vesting period.

RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2016 valuation, inputs for expected volatility ranged from 16.9% to 22.4% and the risk-free interest rate was approximately 0.9%. For the 2015 valuation, inputs for expected volatility ranged from 14.6% to 19.1% and the risk-free interest rate was approximately 1.0%. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.

During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with only service requirements was as follows.



	As of December 31,
	2016				2015				2014
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	309.9		$	35.21	342.2		$	31.38	352.5		$	28.38
Granted	99.3		46.35		115.7		39.50		131.5		34.53
Vested	(115.9	)	32.33		(115.4	)	28.77		(118.2	)	26.19
Forfeited	(3.9	)	40.95		(32.6	)	33.07		(23.6	)	30.00
Nonvested balance, end of year	289.4		40.11		309.9		35.21		342.2		31.38

Total unrecognized compensation cost related to RSU awards with only service requirements was $5.0 million and $4.5 million as of December 31, 2016 and 2015, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of 1.8 years. The total fair value of RSUs with only service requirements that vested during the years ended December 31, 2016, 2015 and 2014, was $5.2 million, $4.7 million and $3.9 million, respectively.

During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with performance measures was as follows.



	As of December 31,
	2016				2015				2014
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	299.1		$	36.00	345.1		$	32.31	350.1		$	30.35
Granted	100.9		46.03		94.8		40.26		126.1		35.97
Vested	(98.5	)	31.59		(109.0	)	28.99		(108.2	)	30.56
Forfeited	(3.8	)	41.57		(31.8	)	34.03		(22.9	)	30.70
Nonvested balance, end of year	297.7		40.79		299.1		36.00		345.1		32.31

As of December 31, 2016 and 2015, total unrecognized compensation cost related to RSU awards with performance measures was $4.5 million and $4.0 million, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with performance measures that vested during the years ended December 31, 2016, 2015 and 2014, was $7.5 million, $3.1 million and $0.5 million, respectively.

Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 170 shares of common stock for dividends in 2016, 296 shares in 2015 and 403 shares in 2014. Participants received common stock distributions of 2,110 shares in 2016, 2,024 shares in 2015 and 1,944 shares in 2014.

Wolf Creek Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

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

Wolf Creek Employee Benefit Plans

WOLF CREEK EMPLOYEE BENEFIT PLANS

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. KGE accrues its 47% share of Wolf Creek’s cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status of KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	206,418		$	210,320		$	7,793		$	8,240
Service cost	6,748			7,595			127			138
Interest cost	9,655			9,016			325			314
Plan participants’ contributions	—			—			989			934
Benefits paid	(6,974		)	(6,217		)	(1,531		)	(1,622		)
Actuarial losses (gains)	13,178			(14,296		)	(488		)	(211		)
Benefit obligation, end of year	$	229,025		$	206,418		$	7,215		$	7,793

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	121,622		$	124,660		$	105		$	6
Actual return on plan assets	8,967			(2,879		)	(4		)	—
Employer contributions	14,820			5,805			458			787
Plan participants’ contributions	—			—			989			934
Benefits paid	(6,721		)	(5,964		)	(1,531		)	(1,622		)
Fair value of plan assets, end of year	$	138,688		$	121,622		$	17		$	105

Funded status, end of year	$	(90,337	)	$	(84,796	)	$	(7,198	)	$	(7,688	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(248	)	$	(247	)	$	(538	)	$	(597	)
Noncurrent liability	(90,089		)	(84,549		)	(6,660		)	(7,091		)
Net amount recognized	$	(90,337	)	$	(84,796	)	$	(7,198	)	$	(7,688	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	66,324		$	56,747		$	(654	)	$	(184	)
Prior service cost	446			501			—			—
Net amount recognized	$	66,770		$	57,248		$	(654	)	$	(184	)



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	229,025		$	206,418		$	—		$	—
Fair value of plan assets	138,688			121,622			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	201,963		$	180,718		$	—		$	—
Fair value of plan assets	138,688			121,622			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	7,215		$	7,793
Fair value of plan assets	—			—			17			105

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.26		%	4.61		%	3.95		%	4.27		%
Compensation rate increase	4.00		%	4.00		%	—		%	—		%

Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2016, increased Wolf Creek’s pension and post-retirement benefit obligations by approximately $11.2 million and $0.2 million, respectively.

The prior service cost is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2016			2015			2014			2016			2015			2014
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	6,748		$	7,595		$	5,695		$	127		$	138		$	173
Interest cost	9,655			9,016			8,469			325			314			464
Expected return on plan assets	(9,722		)	(9,044		)	(8,084		)	—			—			—
Amortization of unrecognized:
Prior service costs	55			57			58			—			—			—
Actuarial loss (gain), net	4,357			5,930			2,987			(14		)	3			165
Net periodic cost before regulatory adjustment	11,093			13,554			9,125			438			455			802
Regulatory adjustment (a)	1,886			(1,485		)	2,328			—			—			—
Net periodic cost	$	12,979		$	12,069		$	11,453		$	438		$	455		$	802

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain)	$	13,934		$	(2,373	)	$	38,833		$	(484	)	$	(211	)	$	(1,881	)
Amortization of actuarial (gain) loss	(4,357		)	(5,930		)	(2,987		)	14			(3		)	(165		)
Amortization of prior service cost	(55		)	(57		)	(58		)	—			—			—
Total recognized in regulatory assets	$	9,522		$	(8,360	)	$	35,788		$	(470	)	$	(214	)	$	(2,046	)

Total recognized in net periodic cost and regulatory assets	$	22,501		$	3,709		$	47,241		$	(32	)	$	241		$	(1,244	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate	4.61		%	4.20		%	5.11		%	4.27		%	3.89		%	4.70		%
Expected long-term return on plan assets	7.50		%	7.50		%	7.50		%	—		%	—		%	—		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	—		%	—		%	—		%

_______________


(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.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	4,979	$	(50	)
Prior service cost	55		—
Total	$	5,034	$	(50	)

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

For measurement purposes, the assumed annual health care cost growth rates were as follows.



	As of December 31,
	2016		2015
Health care cost trend rate assumed for next year	6.5	%	7.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%

Year that the rate reaches the ultimate trend rate	2020		2020

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.



	One-Percentage- Point Increase			One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	(7	)	$	7
Effect on post-retirement benefit obligation	(126		)	133

Plan Assets

Wolf Creek’s pension and post-retirement plan investment strategy is to manage assets in a prudent manner with regard to preserving principal while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

The target allocations for Wolf Creek’s pension plan assets are 31% to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. See Note 5, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

The following table provides the fair value of KGE’s 47% share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	34,586	$	—	$	—	$	34,586
International equity funds	—		43,269		—		—		43,269
Core bond funds	—		35,048		—		—		35,048
Real estate securities fund	—		—		—		6,948		6,948
Alternative investment fund	—		14,073		—		4,164		18,237
Cash equivalents	—		600		—		—		600
Total Assets Measured at Fair Value	$	—	$	127,576	$	—	$	11,112	$	138,688

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	30,503	$	—	$	—	$	30,503
International equity funds	—		37,682		—		—		37,682
Core bond funds	—		30,287		—		—		30,287
Real estate securities fund	—		6,123		—		6,434		12,557
Commodities fund	—		5,811		—		—		5,811
Alternative investment fund	—		—		—		4,258		4,258
Cash equivalents	—		524		—		—		524
Total Assets Measured at Fair Value	$	—	$	110,930	$	—	$	10,692	$	121,622

Cash Flows

The following table shows our expected cash flows for KGE’s 47% share of Wolf Creek’s pension and post-retirement benefit plans for future years.



Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2017	$	10.8					$	0.6

Expected benefit payments:
2017	$	(7.2	)	$	(0.3	)	$	(2.0	)	$	—
2018	(8.1		)	(0.3		)	(2.3		)	—
2019	(9.0		)	(0.3		)	(2.6		)	—
2020	(9.8		)	(0.3		)	(2.9		)	—
2021	(10.7		)	(0.3		)	(3.2		)	—
2022 - 2026	(66.0		)	(1.3		)	(20.2		)	—

Savings Plan

Wolf Creek maintains a qualified 401(k) savings plan in which most of its employees participate. Wolf Creek matches employees’ contributions in cash up to specified maximum limits. Wolf Creek’s contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. KGE’s portion of the expense associated with Wolf Creek’s matching contributions was $1.6 million in 2016, $1.6 million in 2015 and $1.4 million in 2014.

Commitments And Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel and Purchased Power Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2016, was as follows.



	Committed Amount
	(In Thousands)
2017	$	310,711
2018	73,149
2019	25,411
Thereafter	8,100
Total amount committed	$	417,371

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. Since his inauguration in January 2017, reports and other information that have been released suggest that President Trump may alter federal environmental policy, including through executive orders and influencing changes to statutes, regulations and agency priorities. Due in part to the preliminary nature of information that is available to us, as well as the complex nature of environmental regulation, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.

Federal Clean Air Act

We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.

Sulfur Dioxide and Nitrogen Oxide

Through the combustion of fossil fuels at our generating facilities, we emit SO₂ and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet SO₂ and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.

We are subject to the SO₂ allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO₂ emissions for that year. In 2016, we had adequate SO₂ allowances to meet generation and we expect to have enough to cover emissions under this program in 2017.

Cross-State Air Pollution Update Rule

In September 2016, the EPA finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of NOx emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We do not believe this rule will have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

Under the federal 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 PM, ozone, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. In September 2016, the KDHE recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as greenhouse gases (GHG). Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en banc. Despite the stay, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. In January 2017, the EPA denied our Petition for Reconsideration and Administrative Stay of the CPP. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual (CCR) handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Residuals

In the course of operating our coal generation plants, we produce CCRs, including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. We have recorded an ARO for our current estimate for closure of ash disposal ponds but may be required to record additional AROs in the future due to changes in existing CRR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or consolidated financial results could be material. See Note 15, “Asset Retirement Obligations,” for additional information.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has recently completed the process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP has determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, we paid the SPP in November 2016 $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately $360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $5.0 million in 2016, $2.8 million in 2015 and $2.8 million in 2014. We record our investment in the NDT fund at fair value, which approximated $200.1 million and $184.1 million as of December 31, 2016 and 2015, respectively.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Wolf Creek is in discussions with the DOE to determine which of its incremental costs may be reimbursable. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Nuclear Insurance

We maintain nuclear liability, property and accidental outage insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of $3.2 billion for nuclear events ($1.8 billion of non-nuclear events) plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and accidental outage insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within 12 months from the date of the first act. In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we insure against public nuclear liability claims resulting from nuclear incidents to the required limit of public liability, which is approximately $13.4 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.0 billion is provided through mandatory participation in an industry-wide retrospective assessment program. For incidents after January 1, 2017, this commercial insurance limit increased to $450.0 million. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (our share is $59.8 million), payable at no more than $19.0 million (our share is $8.9 million) per incident per year per reactor for any commercial U.S. nuclear reactor qualifying incident. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018. In addition, Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property and Accidental Outage Insurance

The owners of Wolf Creek carry decontamination liability, nuclear property damage and premature nuclear decommissioning liability insurance for Wolf Creek totaling approximately $2.8 billion. Insurance coverage for non-nuclear property damage accidents total approximately $2.3 billion. In the event of an extraordinary nuclear accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to help cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $37.5 million (our share is $17.6 million).

Nuclear Insurance Considerations

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2016, our share of Wolf Creek’s nuclear fuel commitments was approximately $16.5 million for uranium concentrates expiring in 2017, $2.5 million for conversion expiring in 2017, $80.3 million for uranium hexafluoride expiring in 2024, $81.6 million for enrichment expiring in 2027 and $29.7 million for fabrication expiring in 2025. In January 2017, Wolf Creek entered into a new nuclear fuel agreement resulting in an additional commitment, at our share, of approximately $16.4 million for uranium concentrates expiring 2024 and $1.7 million for conversion expiring 2024.

As of December 31, 2016, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $659.4 million. The contracts are for plants that we operate and expire at various times through 2020.

As of December 31, 2016, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately $105.8 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,328 MW expiring in 2028 through 2036. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $140.1 million.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

Legal Liability

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the ARO is capitalized and depreciated over the remaining life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.

We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (KGE’s 47% share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds, close ash landfills and dispose of polychlorinated biphenyl (PCB)-contaminated oil. ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement may be conditional on a future event that may or may not be within the control of the entity. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have significant impact on the AROs reflected on our consolidated balance sheet.

The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.



	As of December 31,
	2016			2015
	(In Thousands)
Beginning ARO	$	275,285		$	230,668
Increase in ARO liabilities	—			34,440
Liabilities settled	(5,372		)	(1,553		)
Accretion expense	14,165			12,964
Revisions in estimated cash flows	39,873			(1,234		)
Ending ARO	$	323,951		$	275,285

In 2015, we recorded an approximately $34.4 million increase in our ARO in response to the EPA’s published rule to regulate CCRs. In 2016, we revised our ARO to include an additional $39.9 million to recognize costs associated with closure and post-closure of ash disposal ponds. See Note 14, “Commitments and Contingencies - Regulation of Coal Combustion Residuals,” for additional information.

We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was placed into service.

The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.”

We operate, as permitted by the state of Kansas, ash landfills and ash disposal ponds at several of our power plants. The retirement obligations for the ash landfills and ash disposal ponds were determined based upon the date each landfill was originally placed in service.

PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.

Non-Legal Liability - Cost of Removal

We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2016 and 2015, we had $5.7 million and $53.8 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

Legal Proceedings	12 Months Ended
Legal Proceedings	Dec. 31, 2016
Legal Proceedings [Abstract]
Legal Proceedings	LEGAL PROCEEDINGS We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 4 and 14, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information. Pending Merger Following the announcement of the merger agreement, two putative class action complaints (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas. The consolidated putative class action complaint, filed on July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that (i) the merger consideration deprives our shareholders of fair consideration for their shares, (ii) the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, (iii) the disclosures are misleading and/or omit material information necessary for our shareholders to make an informed decision whether to vote in favor of the proposed transaction and (iv) if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the merger, (ii) rescission of the merger agreement or rescissory damages, (iii) a directive to members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties and (iv) an award for costs and disbursements, including attorneys’ fees and experts’ fees. The putative derivative complaint, filed on July 5, 2016, and as amended on August 25, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as a nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that the disclosures are false or misleading due to the omission of certain information. The complaint seeks, among other remedies, (i) a direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, (ii) a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the merger agreement, (iv) the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, (v) award for costs, including attorneys’ fees and experts’ fees, and (vi) the imposition of an injunction against the defendants and others from consummating the merger on the terms proposed. On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases. In exchange, the parties in the putative derivative complaint agreed that we would make supplemental disclosures to the shareholders, which disclosures were made in a Form 8-K filed on September 21, 2016, and the parties in the consolidated putative class action agreed that we would (i) make the disclosures in the Form 8-K filed on September 21, 2016, and (ii) grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in the our sale process. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety.

Common Stock

12 Months Ended

Dec. 31, 2016

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Common and Preferred Stock

COMMON STOCK

General

Westar Energy’s Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2016 and 2015, Westar Energy had issued 141.8 million shares and 141.4 million shares, respectively.

Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2016 and 2015, Westar Energy issued 0.4 million shares and 0.5 million shares, respectively, through the DSPP and other stock-based plans operated under the long-term incentive and share award plan. As of December 31, 2016 and 2015, a total of 1.0 million shares and 1.2 million shares, respectively, were available under the DSPP registration statement.

Issuances

In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy’s common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013 an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under each agreement.

In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. Both agreements expired in March 2016. The maximum amount that Westar Energy could have offered and sold under the master agreement was the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy could have offered and sold shares of its common stock from time to time. The agent received a commission equal to 1% of the sales price of all shares sold under the agreements.

The following table summarizes our common stock activity pursuant to the two forward sale agreements. There was no common stock sale activity under these agreements in 2016.



	Year Ended December 31,
	2015	2014
Shares that could be settled at beginning of year	9,160,500	12,052,976
Transactions settled (a)	9,160,500	2,892,476
Shares that could be settled at end of year	—	9,160,500
_______________
(a) The shares settled during the years ended December 31, 2015 and 2014, were settled with a physical settlement amount of approximately $254.6 million and $82.9 million, respectively.

The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.

Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

Variable Interest Entities [Abstract]

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
-SubTopic 10
-Section S99
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=65877616&loc=d3e177068-122764

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(d))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(29))
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+ Details

Variable Interest Entities

12 Months Ended

Dec. 31, 2016

Variable Interest Entities Disclosure [Text Block]

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 JEC and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a redemption and reissuance of the $162.1 million in outstanding bonds maturing March 2021. See Note 10, “Long-term Debt,” for additional information.

Financial Statement Impact

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



	As of December 31,
	2016		2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	257,904	$	268,239
Regulatory assets (a)	10,396		9,088

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,209		138,097

_______________

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

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

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

Leases

12 Months Ended

Dec. 31, 2016

Leases [Abstract]

Leases

LEASES

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.

Rental expense and estimated future commitments under operating leases are as follows.



Year Ended December 31,	Total Operating Leases
	(In Thousands)
Rental expense:
2014	$	14,143
2015	14,035
2016	13,563

Future commitments:
2017	$	13,007
2018	11,659
2019	10,274
2020	7,615
2021	5,776
Thereafter	7,845
Total future commitments	$	56,176

Capital Leases

We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.

Assets recorded under capital leases are listed below.



	As of December 31,
	2016			2015
	(In Thousands)
Vehicles	$	15,595		$	17,345
Computer equipment	1,073			1,204
Generation plant	40,048			40,048
Accumulated amortization	(13,542		)	(13,477		)
Total capital leases	$	43,174		$	45,120

Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.



Year Ended December 31,	Total Capital Leases
	(In Thousands)
2017	$	5,803
2018	5,722
2019	5,101
2020	4,443
2021	3,942
Thereafter	52,496
	77,507
Amounts representing imputed interest	(29,900		)
Present value of net minimum lease payments under capital leases	47,607
Less: Current portion	3,179
Total long-term obligation under capital leases	$	44,428

Quarterly Results (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Results (Unaudited)

QUARTERLY RESULTS (UNAUDITED)

Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.



2016	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	569,450	$	621,448	$	764,654	$	606,535
Net income (a)	68,708		76,144		158,553		57,795
Net income attributable to Westar Energy, Inc. (a)	65,585		72,340		154,720		53,932

Per Share Data (a):

Basic:
Earnings available	$	0.46	$	0.51	$	1.09	$	0.38

Diluted:
Earnings available	$	0.46	$	0.51	$	1.08	$	0.38

Cash dividend declared per common share	$	0.38	$	0.38	$	0.38	$	0.38
Market price per common share:
High	$	50.38	$	57.25	$	56.95	$	57.50
Low	$	40.01	$	48.92	$	52.52	$	54.41

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.



2015	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	590,807	$	589,563	$	732,829	$	545,965
Net income (a)	53,163		66,243		140,564		41,826
Net income attributable to Westar Energy, Inc. (a)	50,980		63,710		138,003		39,235

Per Share Data (a):

Basic:
Earnings available	$	0.38	$	0.47	$	0.97	$	0.28

Diluted:
Earnings available	$	0.38	$	0.46	$	0.97	$	0.28

Cash dividend declared per common share	$	0.36	$	0.36	$	0.36	$	0.36
Market price per common share:
High	$	44.03	$	39.65	$	40.22	$	43.56
Low	$	36.58	$	33.88	$	34.17	$	37.55

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2016

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

WESTAR ENERGY, INC.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS



Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (a)			Balance at End of Period
	(In Thousands)
Year ended December 31, 2014
Allowances deducted from assets for doubtful accounts	$	4,596	$	9,752	$	(9,039	)	$	5,309

Year ended December 31, 2015
Allowances deducted from assets for doubtful accounts	$	5,309	$	8,614	$	(8,629	)	$	5,294

Year ended December 31, 2016
Allowances deducted from assets for doubtful accounts	$	5,294	$	12,197	$	(10,824	)	$	6,667

_______________


(a)	Result from write-offs of accounts receivable.

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2016

Principles Of Consolidation

Principles of Consolidation

Use Of Management's Estimates

Use of Management’s Estimates

Regulatory Accounting

Cash And Cash Equivalents

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

Fuel Inventory And Supplies

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost.

Property, Plant And Equipment

Property, Plant and Equipment



	Year Ended December 31,
	2016			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	9,964		$	3,505		$	12,044
Equity funds	11,630			2,075			17,029
Total	$	21,594		$	5,580		$	29,073
Average AFUDC Rates	4.2		%	2.7		%	6.7		%

Allowance For Funds Used During Construction

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

Depreciation

Depreciable lives of property, plant and equipment are as follows.



	Years
Fossil fuel generating facilities	6	to	78
Nuclear fuel generating facility	55	to	71
Wind generating facilities	19	to	20
Transmission facilities	15	to	75
Distribution facilities	22	to	68
Other	5	to	30

Nuclear Fuel

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.



	As of December 31,
	2016			2015
	(In Thousands)
Cash surrender value of policies	$	1,267,349		$	1,299,408
Borrowings against policies	(1,137,360		)	(1,168,794		)
Corporate-owned life insurance, net	$	129,989		$	130,614

Revenue Recognition

Allowance For Doubtful Accounts

Allowance for Doubtful Accounts

Income Taxes

Sales Tax

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.

Earnings Per Share

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



	Year Ended December 31,
	2016		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	361,200	$	301,796	$	322,325
Less: Net income attributable to noncontrolling interests	14,623		9,867		9,066
Net income attributable to Westar Energy, Inc.	346,577		291,929		313,259
Less: Net income allocated to RSUs	714		646		790
Net income allocated to common stock	$	345,863	$	291,283	$	312,469

Weighted average equivalent common shares outstanding – basic	142,067,558		137,957,515		130,014,941
Effect of dilutive securities:
RSUs	407,123		299,198		181,397
Forward sale agreements	—		1,021,510		2,628,187
Weighted average equivalent common shares outstanding – diluted (a)	142,474,681		139,278,223		132,824,525

Earnings per common share, basic	$	2.43	$	2.11	$	2.40
Earnings per common share, diluted	$	2.43	$	2.09	$	2.35

_______________


(a)	For the years ended December 31, 2016, 2015 and 2014, we had no antidilutive securities.

Supplemental Cash Flow Information



	Year Ended December 31,
	2016		2015			2014
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	139,029	$	161,484		$	160,292
Interest on financing activities of VIEs	5,846		10,430			12,183
Income taxes, net of refunds	13,103		(410		)	458
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	151,474		105,169			143,192
Property, plant and equipment of VIEs	—		—			(7,342		)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	9,685		10,453			9,155
Deconsolidation of VIEs	—		—			(7,342		)
Assets acquired through capital leases	2,744		3,130			8,717

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Fuel Inventory and Supplies

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



	As of December 31,
	2016		2015
	(In Thousands)
Fuel inventory	$	107,086	$	113,438
Supplies	193,039		187,856
Fuel inventory and supplies	$	300,125	$	301,294

Allowance For Funds Used During Construction

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



	Year Ended December 31,
	2016			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	9,964		$	3,505		$	12,044
Equity funds	11,630			2,075			17,029
Total	$	21,594		$	5,580		$	29,073
Average AFUDC Rates	4.2		%	2.7		%	6.7		%

Depreciable Lives of Property, Plant and Equipment

Depreciable lives of property, plant and equipment are as follows.



	Years
Fossil fuel generating facilities	6	to	78
Nuclear fuel generating facility	55	to	71
Wind generating facilities	19	to	20
Transmission facilities	15	to	75
Distribution facilities	22	to	68
Other	5	to	30

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.



	As of December 31,
	2016			2015
	(In Thousands)
Cash surrender value of policies	$	1,267,349		$	1,299,408
Borrowings against policies	(1,137,360		)	(1,168,794		)
Corporate-owned life insurance, net	$	129,989		$	130,614

Reconciliation Of Basic And Diluted Earnings Per Share

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



	Year Ended December 31,
	2016		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	361,200	$	301,796	$	322,325
Less: Net income attributable to noncontrolling interests	14,623		9,867		9,066
Net income attributable to Westar Energy, Inc.	346,577		291,929		313,259
Less: Net income allocated to RSUs	714		646		790
Net income allocated to common stock	$	345,863	$	291,283	$	312,469

Weighted average equivalent common shares outstanding – basic	142,067,558		137,957,515		130,014,941
Effect of dilutive securities:
RSUs	407,123		299,198		181,397
Forward sale agreements	—		1,021,510		2,628,187
Weighted average equivalent common shares outstanding – diluted (a)	142,474,681		139,278,223		132,824,525

Earnings per common share, basic	$	2.43	$	2.11	$	2.40
Earnings per common share, diluted	$	2.43	$	2.09	$	2.35

_______________


(a)	For the years ended December 31, 2016, 2015 and 2014, we had no antidilutive securities.

Supplemental Cash Flow Information



	Year Ended December 31,
	2016		2015			2014
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	139,029	$	161,484		$	160,292
Interest on financing activities of VIEs	5,846		10,430			12,183
Income taxes, net of refunds	13,103		(410		)	458
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	151,474		105,169			143,192
Property, plant and equipment of VIEs	—		—			(7,342		)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	9,685		10,453			9,155
Deconsolidation of VIEs	—		—			(7,342		)
Assets acquired through capital leases	2,744		3,130			8,717

Rate Matters And Regulation (Tables)

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

Schedule Of Regulatory Assets And Liabilities [Table Text Block]

Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.



	As of December 31,
	2016		2015
	(In Thousands)
Regulatory Assets:
Deferred employee benefit costs	$	381,129	$	353,785
Amounts due from customers for future income taxes, net	124,020		144,120
Debt reacquisition costs	115,502		121,631
Depreciation	63,171		65,797
Asset retirement obligations	35,487		31,996
Retail energy cost adjustment	32,451		—
Treasury yield hedges	25,927		25,634
Wolf Creek outage	20,316		16,561
Ad valorem tax	17,637		44,455
Disallowed plant costs	15,453		15,639
La Cygne environmental costs	14,370		15,446
Analog meter unrecovered investment	8,500		1,454
Energy efficiency program costs	7,097		7,922
Other regulatory assets	18,802		16,478
Total regulatory assets	$	879,862	$	860,918

Regulatory Liabilities:
Deferred regulatory gain from sale leaseback	$	70,065	$	75,560
Pension and other post-retirement benefits costs	37,172		32,181
Nuclear decommissioning	34,094		30,659
Jurisdictional allowance for funds used during construction	33,119		32,673
La Cygne leasehold dismantling costs	27,742		25,330
Kansas tax credits	13,142		12,857
Purchase power agreement	9,265		9,972
Removal costs	5,663		53,834
Retail energy cost adjustment	—		12,686
Other regulatory liabilities	9,191		7,059
Total regulatory liabilities	$	239,453	$	292,811

Financial Instruments and Trading Securities (Tables)

12 Months Ended

Dec. 31, 2016

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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



	As of December 31, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,430,000	$	3,597,441	$	3,080,000	$	3,259,533
Fixed-rate debt of VIEs	137,962		139,733		166,271		179,030

Fair Value Of Assets And Liabilities

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



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

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

Reconciliations Of Assets And Liabilities At Fair Value

Investments In Financial Instruments

The following table provides additional information on these investments.



	As of December 31, 2016				As of December 31, 2015				As of December 31, 2016
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,056	$	3,529	$	6,050	$	1,948	(a)	(a)
Alternative investment fund (b)	18,958		—		16,439		—		Quarterly	65 days
Real estate securities fund (b)	9,946		—		10,823		—		Quarterly	65 days
Total Nuclear Decommissioning Trust	$	33,960	$	3,529	$	33,312	$	1,948

_______________

(a)


(b)	There is a holdback on final redemptions.

Cost And Fair Value Of Available-For-Sale Securities

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)

12 Months Ended

Dec. 31, 2016

Investments [Abstract]

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



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

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

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



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

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

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Public Utility, Property, Plant and Equipment [Line Items]

Schedule of Public Utility Property, Plant, and Equipment

The following is a summary of our property, plant and equipment balance.



	As of December 31,
	2016			2015
	(In Thousands)
Electric plant in service	$	11,986,046		$	11,449,933
Electric plant acquisition adjustment	802,318			802,318
Accumulated depreciation	(4,404,977		)	(4,178,885		)
	8,383,387			8,073,366
Construction work in progress	773,095			349,402
Nuclear fuel, net	61,952			68,349
Plant to be retired, net (a)	29,925			33,785
Net property, plant and equipment	$	9,248,359		$	8,524,902

Variable Interest Entity [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Schedule of Public Utility Property, Plant, and Equipment

The following is a summary of property, plant and equipment of VIEs.



	As of December 31,
	2016			2015
	(In Thousands)
Electric plant of VIEs	$	497,999		$	497,999
Accumulated depreciation of VIEs	(240,095		)	(229,760		)
Net property, plant and equipment of VIEs	$	257,904		$	268,239

Joint Ownership of Utility Plants Joint Ownership of Utility Plants (Tables)

12 Months Ended

Dec. 31, 2016

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule of Jointly Owned Utility Plants

Information relative to our ownership interests in these facilities as of December 31, 2016, is shown in the table below.



Plant	In-Service Dates	Investment		Accumulated Depreciation		Construction Work in Progress		Net MW	Ownership Percentage
		(Dollars in Thousands)
La Cygne unit 1 (a)	June 1973	$	613,348	$	163,234	$	39,096	368	50
JEC unit 1 (a)	July 1978	817,402		203,410		7,131		670	92
JEC unit 2 (a)	May 1980	567,298		200,296		4,198		675	92
JEC unit 3 (a)	May 1983	740,170		325,701		4,108		659	92
Wolf Creek (b)	Sept. 1985	1,922,877		842,595		82,756		551	47
State Line (c)	June 2001	111,444		62,332		861		196	40
Total		$	4,772,539	$	1,797,568	$	138,150	3,119

_______________


(a)	Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.


(b)	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Short-term Debt Additional Information

Additional information regarding our short-term debt is as follows.



	Year Ended December 31,
	2016			2015
	(Dollars in Thousands)
Weighted average short-term debt outstanding	$	284,700		$	350,380
Weighted daily average interest rates, excluding fees	0.78		%	0.48		%

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-term Debt Outstanding

The following table summarizes our long-term debt outstanding.



	As of December 31,
	2016			2015
	(In Thousands)
Westar Energy
First mortgage bond series:
5.15% due 2017	$	125,000		$	125,000
5.10% due 2020	250,000			250,000
3.25% due 2025	250,000			250,000
2.55% due 2026	350,000			—
4.125% due 2042	550,000			550,000
4.10% due 2043	430,000			430,000
4.625% due 2043	250,000			250,000
4.25% due 2045	300,000			300,000
	2,505,000			2,155,000
Pollution control bond series:
Variable due 2032, 1.14% as of December 31, 2016; 0.02% as of December 31, 2015	45,000			45,000
Variable due 2032, 1.32% as of December 31, 2016; 0.02% as of December 31, 2015	30,500			30,500
	75,500			75,500

KGE
First mortgage bond series:
6.70% due 2019	300,000			300,000
6.15% due 2023	50,000			50,000
6.53% due 2037	175,000			175,000
6.64% due 2038	100,000			100,000
4.30% due 2044	250,000			250,000
	875,000			875,000
Pollution control bond series:
Variable due 2027, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	21,940			21,940
4.85% due 2031	—			50,000
2.50% due 2031	50,000			—
Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	14,500			14,500
Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015	10,000			10,000
	96,440			96,440

Total long-term debt	3,551,940			3,201,940
Unamortized debt discount (a)	(10,358		)	(10,374		)
Unamortized debt issuance expense (a)	(27,912		)	(27,616		)
Long-term debt due within one year	(125,000		)	—
Long-term debt, net	$	3,388,670		$	3,163,950

Variable Interest Entities
5.92% due 2019 (b)	$	1,157		$	4,223
5.647% due 2021 (b)	—			162,048
2.398% due 2021 (b)	136,805			—
Total long-term debt of variable interest entities	137,962			166,271
Unamortized debt premium (a)	89			135
Long-term debt of variable interest entities due within one year	(26,842		)	(28,309		)
Long-term debt of variable interest entities, net	$	111,209		$	138,097

_______________

(a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.

(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.

Schedule of Maturities of Long-term Debt

The principal amounts of our long-term debt maturities as of December 31, 2016, are as follows.



Year	Long-term debt		Long-term debt of VIEs
	(In Thousands)
2017	$	125,000	$	26,842
2018	—		28,538
2019	300,000		31,485
2020	250,000		32,254
2021	—		18,843
Thereafter	2,876,940		—
Total maturities	$	3,551,940	$	137,962

Income Tax Expense Components

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income tax expense is comprised of the following components.



	Year Ended December 31,
	2016			2015			2014
	(In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal	$	(1,007	)	$	327		$	416
State	318			341			(597		)
Deferred income taxes:
Federal	155,230			124,891			124,923
State	32,892			29,484			29,657
Investment tax credit amortization	(2,893		)	(3,043		)	(3,129		)
Income tax expense	$	184,540		$	152,000		$	151,270

Deferred Tax Assets and Liabilities

The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.



	As of December 31,
	2016		2015
	(In Thousands)
Deferred tax assets:
Tax credit carryforward (a)	$	265,750	$	266,963
Deferred employee benefit costs	137,337		122,757
Net operating loss carryforward (b)	86,693		129,232
Deferred state income taxes	73,294		67,307
Deferred compensation	31,981		27,266
Deferred regulatory gain on sale-leaseback	30,868		33,287
Alternative minimum tax carryforward (c)	29,412		26,725
Accrued liabilities	21,757		21,115
LaCygne dismantling cost	10,972		10,018
Disallowed costs	9,600		10,211
Capital loss carryforward	—		1,668
Other	47,200		41,319
Total gross deferred tax assets	744,864		757,868
Less: Valuation allowance	—		1,668
Deferred tax assets	$	744,864	$	756,200

Deferred tax liabilities:
Accelerated depreciation	$	1,925,270	$	1,787,457
Acquisition premium	147,868		155,881
Deferred employee benefit costs	137,337		122,757
Amounts due from customers for future income taxes, net	124,020		144,120
Deferred state income taxes	61,110		59,787
Debt reacquisition costs	41,753		42,314
Pension expense tracker	5,560		12,051
Other	54,722		23,263
Total deferred tax liabilities	$	2,497,640	$	2,347,630

Net deferred income tax liabilities	$	1,752,776	$	1,591,430

_______________

(a)


(b)	As of December 31, 2016, we had a federal net operating loss carryforward of $198.1 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2032 and ending in 2035.


(c)	As of December 31, 2016, we had available an alternative minimum tax credit carryforward of $29.4 million, which has an unlimited carryforward period.

Effective Income Tax Rate Reconciliation

The difference between the effective income tax rates and the federal statutory income tax rates are as follows.



	Year Ended December 31,
	2016		2015		2014
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
Effect of:
COLI policies	(4.2	)	(4.4	)	(4.0	)
State income taxes	4.0		4.3		4.0
Flow through depreciation for plant-related differences	3.1		2.6		2.0
Production tax credits	(1.8	)	(2.1	)	(2.1	)
Non-controlling interest	(0.9	)	(0.8	)	(0.7	)
AFUDC equity	(0.8	)	(0.2	)	(1.3	)
Amortization of federal investment tax credits	(0.5	)	(0.7	)	(0.7	)
Share based payments	(0.5	)	(0.1	)	—
Capital loss utilization carryforward	0.4		(0.1	)	(0.3	)
Liability for unrecognized income tax benefits	—		—		(0.2	)
Other	—		—		0.2
Effective income tax rate	33.8	%	33.5	%	31.9	%

Unrecognized Income Tax Benefits Reconciliation

A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:



	2016			2015			2014
	(In Thousands)
Unrecognized income tax benefits as of January 1	$	2,901		$	3,188		$	1,703
Additions based on tax positions related to the current year	434			410			872
Additions for tax positions of prior years	—			—			813
Reductions for tax positions of prior years	(1		)	(86		)	(200		)
Lapse of statute of limitations	(568		)	(611		)	—
Settlements	—			—			—
Unrecognized income tax benefits as of December 31	$	2,766		$	2,901		$	3,188

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

Schedule Of Benefit Obligation Fair Value Of Plan Assets And Amounts Recognized In Balance Sheet

The following tables summarize the status of our pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	965,193		$	1,030,645		$	126,284		$	141,516
Service cost	18,563			21,392			1,084			1,443
Interest cost	43,723			43,014			5,571			5,691
Plan participants’ contributions	—			—			395			582
Benefits paid	(63,540		)	(44,945		)	(7,697		)	(6,549		)
Actuarial losses (gains)	51,482			(90,644		)	3,926			(16,399		)
Amendments	(3,397		)	5,731			—			—
Benefit obligation, end of year (a)	$	1,012,024		$	965,193		$	129,563		$	126,284

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	653,945		$	661,141		$	115,416		$	121,349
Actual return on plan assets	45,181			(6,948		)	7,274			(208		)
Employer contributions	20,200			41,000			—			—
Plan participants’ contributions	—			—			356			534
Benefits paid	(60,852		)	(41,248		)	(7,427		)	(6,259		)
Fair value of plan assets, end of year	$	658,474		$	653,945		$	115,619		$	115,416

Funded status, end of year	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,260	)	$	(2,745	)	$	(284	)	$	(344	)
Noncurrent liability	(351,290		)	(308,503		)	(13,660		)	(10,524		)
Net amount recognized	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	282,462		$	254,085		$	(7,603	)	$	(12,208	)
Prior service cost	3,913			8,078			2,674			3,130
Net amount recognized	$	286,375		$	262,163		$	(4,929	)	$	(9,078	)

_______________

Schedule Of Benefit Obligations In Excess Of Fair Value Of Plan Assets And Assumptions Used For Benefit Obligation



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	1,012,024		$	965,193		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	905,661		$	864,263		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	129,563		$	126,284
Fair value of plan assets	—			—			115,619			115,416

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.25		%	4.60		%	4.15		%	4.51		%
Compensation rate increase	4.00		%	4.00		%	—			—

Schedule Of Net Benefit Costs And Assumptions Used For Net Periodic Cost

Following is additional information regarding our pension and post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2016			2015			2014			2016			2015			2014
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	18,563		$	21,392		$	16,218		$	1,084		$	1,443		$	1,381
Interest cost	43,723			43,014			41,600			5,571			5,691			6,351
Expected return on plan assets	(42,653		)	(40,236		)	(36,438		)	(6,835		)	(6,614		)	(6,576		)
Amortization of unrecognized:
Prior service costs	768			520			526			455			455			2,524
Actuarial loss (gain), net	20,577			32,131			19,362			(1,118		)	379			(742		)
Net periodic cost (benefit) before regulatory adjustment	40,978			56,821			41,268			(843		)	1,354			2,938
Regulatory adjustment (a)	14,528			6,886			15,479			(1,922		)	4,096			4,499
Net periodic cost (benefit)	$	55,506		$	63,707		$	56,747		$	(2,765	)	$	5,450		$	7,437

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain)	$	48,954		$	(43,459	)	$	162,569		$	3,486		$	(9,576	)	$	15,896
Amortization of actuarial (loss) gain	(20,577		)	(32,379		)	(19,362		)	1,118			(379		)	742
Current year prior service cost	(3,397		)	5,730			—			—			—			(7,834		)
Amortization of prior service costs	(768		)	(520		)	(526		)	(455		)	(455		)	(2,524		)
Other adjustments	—			352			—			—			—			—
Total recognized in regulatory assets	$	24,212		$	(70,276	)	$	142,681		$	4,149		$	(10,410	)	$	6,280

Total recognized in net periodic cost and regulatory assets	$	79,718		$	(6,569	)	$	199,428		$	1,384		$	(4,960	)	$	13,717

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate	4.60		%	4.17		%	5.07		%	4.51		%	4.10		%	4.88		%
Expected long-term return on plan assets	6.50		%	6.50		%	6.50		%	6.00		%	6.00		%	6.00		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%

_______________


(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.

Schedule Of Amounts To Be Amortized From Regulatory Assets To Net Periodic Cost

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	21,956	$	(780	)
Prior service cost	683		455
Total	$	22,639	$	(325	)

Schedule of Expected Benefit Payments

Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.



	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2017	$	25.2					$	—

Expected benefit payments:
2017	$	(55.7	)	$	(2.3	)	$	(7.8	)	$	(0.3	)
2018	(58.1		)	(2.3		)	(7.9		)	(0.3		)
2019	(60.2		)	(2.3		)	(8.1		)	(0.3		)
2020	(62.7		)	(2.2		)	(8.2		)	(0.2		)
2021	(64.4		)	(2.2		)	(8.3		)	(0.2		)
2022-2026	(325.1		)	(10.8		)	(40.2		)	(0.9		)

Schedule of Compensation Expense and Income Tax Benefits Related to Stock Compensation Arrangements

The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.



	Year Ended December 31,
	2016		2015		2014
	(In Thousands)
Compensation expense	$	9,237	$	8,250	$	7,193
Income tax benefits related to stock-based compensation arrangements	3,653		3,263		2,845

Other Postretirement Benefit Plans, Defined Benefit [Member]

Schedule of Allocation of Plan Assets

The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	61,055	$	—	$	—	$	61,055
International equity fund	—		15,034		—		—		15,034
Core bond funds	—		38,952		—		—		38,952
Cash equivalents	—		578		—		—		578
Total Assets Measured at Fair Value	$	—	$	115,619	$	—	$	—	$	115,619

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	59,946	$	—	$	—	$	59,946
International equity fund	—		14,419		—		—		14,419
Core bond funds	—		40,475		—		—		40,475
Cash equivalents	—		576		—		—		576
Total Assets Measured at Fair Value	$	—	$	115,416	$	—	$	—	$	115,416

Schedule of Allocation of Plan Assets

The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	168,407	$	—	$	23,580	$	191,987
International equity fund	—		83,738		—		—		83,738
Emerging market equity fund	—		21,055		—		—		21,055
Domestic bond fund	—		101,200		—		—		101,200
Core bond funds	—		86,109		—		—		86,109
High-yield bond fund	—		30,729		—		—		30,729
Emerging market bond fund	—		23,584		—		—		23,584
Combination debt/equity/other fund	—		37,851		—		—		37,851
Alternative investment funds	—		—		—		43,686		43,686
Real estate securities fund	—		—		—		32,390		32,390
Cash equivalents	—		6,145		—		—		6,145
Total Assets Measured at Fair Value	$	—	$	558,818	$	—	$	99,656	$	658,474

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
Assets:	(In Thousands)
Domestic equity funds	$	—	$	165,506	$	—	$	25,277	$	190,783
International equity fund	—		75,453		—		—		75,453
Emerging market equity fund	—		20,798		—		—		20,798
Domestic bond fund	—		105,279		—		—		105,279
Core bond funds	—		99,726		—		—		99,726
High-yield bond fund	—		28,288		—		—		28,288
Emerging market bond fund	—		23,019		—		—		23,019
Combination debt/equity/other fund	—		36,151		—		—		36,151
Alternative investment funds	—		—		—		39,557		39,557
Real estate securities fund	—		—		—		30,173		30,173
Cash equivalents	—		4,718		—		—		4,718
Total Assets Measured at Fair Value	$	—	$	558,938	$	—	$	95,007	$	653,945

RSU Awards With Performance Measures [Member]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity

During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with performance measures was as follows.



	As of December 31,
	2016				2015				2014
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	299.1		$	36.00	345.1		$	32.31	350.1		$	30.35
Granted	100.9		46.03		94.8		40.26		126.1		35.97
Vested	(98.5	)	31.59		(109.0	)	28.99		(108.2	)	30.56
Forfeited	(3.8	)	41.57		(31.8	)	34.03		(22.9	)	30.70
Nonvested balance, end of year	297.7		40.79		299.1		36.00		345.1		32.31

RSU Awards With Only Service Requirements [Member]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity

During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with only service requirements was as follows.



	As of December 31,
	2016				2015				2014
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	309.9		$	35.21	342.2		$	31.38	352.5		$	28.38
Granted	99.3		46.35		115.7		39.50		131.5		34.53
Vested	(115.9	)	32.33		(115.4	)	28.77		(118.2	)	26.19
Forfeited	(3.9	)	40.95		(32.6	)	33.07		(23.6	)	30.00
Nonvested balance, end of year	289.4		40.11		309.9		35.21		342.2		31.38

Wolf Creek Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

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

Schedule Of Benefit Obligation Fair Value Of Plan Assets And Amounts Recognized In Balance Sheet

The following tables summarize the status of our pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	965,193		$	1,030,645		$	126,284		$	141,516
Service cost	18,563			21,392			1,084			1,443
Interest cost	43,723			43,014			5,571			5,691
Plan participants’ contributions	—			—			395			582
Benefits paid	(63,540		)	(44,945		)	(7,697		)	(6,549		)
Actuarial losses (gains)	51,482			(90,644		)	3,926			(16,399		)
Amendments	(3,397		)	5,731			—			—
Benefit obligation, end of year (a)	$	1,012,024		$	965,193		$	129,563		$	126,284

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	653,945		$	661,141		$	115,416		$	121,349
Actual return on plan assets	45,181			(6,948		)	7,274			(208		)
Employer contributions	20,200			41,000			—			—
Plan participants’ contributions	—			—			356			534
Benefits paid	(60,852		)	(41,248		)	(7,427		)	(6,259		)
Fair value of plan assets, end of year	$	658,474		$	653,945		$	115,619		$	115,416

Funded status, end of year	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,260	)	$	(2,745	)	$	(284	)	$	(344	)
Noncurrent liability	(351,290		)	(308,503		)	(13,660		)	(10,524		)
Net amount recognized	$	(353,550	)	$	(311,248	)	$	(13,944	)	$	(10,868	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	282,462		$	254,085		$	(7,603	)	$	(12,208	)
Prior service cost	3,913			8,078			2,674			3,130
Net amount recognized	$	286,375		$	262,163		$	(4,929	)	$	(9,078	)

_______________

Schedule Of Benefit Obligations In Excess Of Fair Value Of Plan Assets And Assumptions Used For Benefit Obligation



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	1,012,024		$	965,193		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	905,661		$	864,263		$	—		$	—
Fair value of plan assets	658,474			653,945			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	129,563		$	126,284
Fair value of plan assets	—			—			115,619			115,416

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.25		%	4.60		%	4.15		%	4.51		%
Compensation rate increase	4.00		%	4.00		%	—			—

Schedule Of Net Benefit Costs And Assumptions Used For Net Periodic Cost

Following is additional information regarding our pension and post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2016			2015			2014			2016			2015			2014
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	18,563		$	21,392		$	16,218		$	1,084		$	1,443		$	1,381
Interest cost	43,723			43,014			41,600			5,571			5,691			6,351
Expected return on plan assets	(42,653		)	(40,236		)	(36,438		)	(6,835		)	(6,614		)	(6,576		)
Amortization of unrecognized:
Prior service costs	768			520			526			455			455			2,524
Actuarial loss (gain), net	20,577			32,131			19,362			(1,118		)	379			(742		)
Net periodic cost (benefit) before regulatory adjustment	40,978			56,821			41,268			(843		)	1,354			2,938
Regulatory adjustment (a)	14,528			6,886			15,479			(1,922		)	4,096			4,499
Net periodic cost (benefit)	$	55,506		$	63,707		$	56,747		$	(2,765	)	$	5,450		$	7,437

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain)	$	48,954		$	(43,459	)	$	162,569		$	3,486		$	(9,576	)	$	15,896
Amortization of actuarial (loss) gain	(20,577		)	(32,379		)	(19,362		)	1,118			(379		)	742
Current year prior service cost	(3,397		)	5,730			—			—			—			(7,834		)
Amortization of prior service costs	(768		)	(520		)	(526		)	(455		)	(455		)	(2,524		)
Other adjustments	—			352			—			—			—			—
Total recognized in regulatory assets	$	24,212		$	(70,276	)	$	142,681		$	4,149		$	(10,410	)	$	6,280

Total recognized in net periodic cost and regulatory assets	$	79,718		$	(6,569	)	$	199,428		$	1,384		$	(4,960	)	$	13,717

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate	4.60		%	4.17		%	5.07		%	4.51		%	4.10		%	4.88		%
Expected long-term return on plan assets	6.50		%	6.50		%	6.50		%	6.00		%	6.00		%	6.00		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%

_______________


(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.

Schedule Of Amounts To Be Amortized From Regulatory Assets To Net Periodic Cost

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	21,956	$	(780	)
Prior service cost	683		455
Total	$	22,639	$	(325	)

Schedule of Expected Benefit Payments

Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.



	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2017	$	25.2					$	—

Expected benefit payments:
2017	$	(55.7	)	$	(2.3	)	$	(7.8	)	$	(0.3	)
2018	(58.1		)	(2.3		)	(7.9		)	(0.3		)
2019	(60.2		)	(2.3		)	(8.1		)	(0.3		)
2020	(62.7		)	(2.2		)	(8.2		)	(0.2		)
2021	(64.4		)	(2.2		)	(8.3		)	(0.2		)
2022-2026	(325.1		)	(10.8		)	(40.2		)	(0.9		)

Wolf Creek [Member]

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

Schedule Of Benefit Obligation Fair Value Of Plan Assets And Amounts Recognized In Balance Sheet

The following tables summarize the status of KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	206,418		$	210,320		$	7,793		$	8,240
Service cost	6,748			7,595			127			138
Interest cost	9,655			9,016			325			314
Plan participants’ contributions	—			—			989			934
Benefits paid	(6,974		)	(6,217		)	(1,531		)	(1,622		)
Actuarial losses (gains)	13,178			(14,296		)	(488		)	(211		)
Benefit obligation, end of year	$	229,025		$	206,418		$	7,215		$	7,793

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	121,622		$	124,660		$	105		$	6
Actual return on plan assets	8,967			(2,879		)	(4		)	—
Employer contributions	14,820			5,805			458			787
Plan participants’ contributions	—			—			989			934
Benefits paid	(6,721		)	(5,964		)	(1,531		)	(1,622		)
Fair value of plan assets, end of year	$	138,688		$	121,622		$	17		$	105

Funded status, end of year	$	(90,337	)	$	(84,796	)	$	(7,198	)	$	(7,688	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(248	)	$	(247	)	$	(538	)	$	(597	)
Noncurrent liability	(90,089		)	(84,549		)	(6,660		)	(7,091		)
Net amount recognized	$	(90,337	)	$	(84,796	)	$	(7,198	)	$	(7,688	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	66,324		$	56,747		$	(654	)	$	(184	)
Prior service cost	446			501			—			—
Net amount recognized	$	66,770		$	57,248		$	(654	)	$	(184	)

Schedule Of Benefit Obligations In Excess Of Fair Value Of Plan Assets And Assumptions Used For Benefit Obligation



	Pension Benefits						Post-retirement Benefits
As of December 31,	2016			2015			2016			2015
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	229,025		$	206,418		$	—		$	—
Fair value of plan assets	138,688			121,622			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	201,963		$	180,718		$	—		$	—
Fair value of plan assets	138,688			121,622			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	7,215		$	7,793
Fair value of plan assets	—			—			17			105

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.26		%	4.61		%	3.95		%	4.27		%
Compensation rate increase	4.00		%	4.00		%	—		%	—		%

Schedule Of Net Benefit Costs And Assumptions Used For Net Periodic Cost

Following is additional information regarding KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2016			2015			2014			2016			2015			2014
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	6,748		$	7,595		$	5,695		$	127		$	138		$	173
Interest cost	9,655			9,016			8,469			325			314			464
Expected return on plan assets	(9,722		)	(9,044		)	(8,084		)	—			—			—
Amortization of unrecognized:
Prior service costs	55			57			58			—			—			—
Actuarial loss (gain), net	4,357			5,930			2,987			(14		)	3			165
Net periodic cost before regulatory adjustment	11,093			13,554			9,125			438			455			802
Regulatory adjustment (a)	1,886			(1,485		)	2,328			—			—			—
Net periodic cost	$	12,979		$	12,069		$	11,453		$	438		$	455		$	802

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain)	$	13,934		$	(2,373	)	$	38,833		$	(484	)	$	(211	)	$	(1,881	)
Amortization of actuarial (gain) loss	(4,357		)	(5,930		)	(2,987		)	14			(3		)	(165		)
Amortization of prior service cost	(55		)	(57		)	(58		)	—			—			—
Total recognized in regulatory assets	$	9,522		$	(8,360	)	$	35,788		$	(470	)	$	(214	)	$	(2,046	)

Total recognized in net periodic cost and regulatory assets	$	22,501		$	3,709		$	47,241		$	(32	)	$	241		$	(1,244	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate	4.61		%	4.20		%	5.11		%	4.27		%	3.89		%	4.70		%
Expected long-term return on plan assets	7.50		%	7.50		%	7.50		%	—		%	—		%	—		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	—		%	—		%	—		%

_______________


(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.

Schedule Of Amounts To Be Amortized From Regulatory Assets To Net Periodic Cost

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	4,979	$	(50	)
Prior service cost	55		—
Total	$	5,034	$	(50	)

Schedule of Health Care Cost Trend Rates

For measurement purposes, the assumed annual health care cost growth rates were as follows.



	As of December 31,
	2016		2015
Health care cost trend rate assumed for next year	6.5	%	7.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%

Year that the rate reaches the ultimate trend rate	2020		2020

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.



	One-Percentage- Point Increase			One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	(7	)	$	7
Effect on post-retirement benefit obligation	(126		)	133

Schedule of Allocation of Plan Assets

The following table provides the fair value of KGE’s 47% share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.



As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	34,586	$	—	$	—	$	34,586
International equity funds	—		43,269		—		—		43,269
Core bond funds	—		35,048		—		—		35,048
Real estate securities fund	—		—		—		6,948		6,948
Alternative investment fund	—		14,073		—		4,164		18,237
Cash equivalents	—		600		—		—		600
Total Assets Measured at Fair Value	$	—	$	127,576	$	—	$	11,112	$	138,688

As of December 31, 2015	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	30,503	$	—	$	—	$	30,503
International equity funds	—		37,682		—		—		37,682
Core bond funds	—		30,287		—		—		30,287
Real estate securities fund	—		6,123		—		6,434		12,557
Commodities fund	—		5,811		—		—		5,811
Alternative investment fund	—		—		—		4,258		4,258
Cash equivalents	—		524		—		—		524
Total Assets Measured at Fair Value	$	—	$	110,930	$	—	$	10,692	$	121,622

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets

Schedule of Expected Benefit Payments

The following table shows our expected cash flows for KGE’s 47% share of Wolf Creek’s pension and post-retirement benefit plans for future years.



Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2017	$	10.8					$	0.6

Expected benefit payments:
2017	$	(7.2	)	$	(0.3	)	$	(2.0	)	$	—
2018	(8.1		)	(0.3		)	(2.3		)	—
2019	(9.0		)	(0.3		)	(2.6		)	—
2020	(9.8		)	(0.3		)	(2.9		)	—
2021	(10.7		)	(0.3		)	(3.2		)	—
2022 - 2026	(66.0		)	(1.3		)	(20.2		)	—

Common Stock (Tables)

12 Months Ended

Dec. 31, 2016

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Forward Contracts Indexed to Issuer's Equity [Table Text Block]

The following table summarizes our common stock activity pursuant to the two forward sale agreements. There was no common stock sale activity under these agreements in 2016.



	Year Ended December 31,
	2015	2014
Shares that could be settled at beginning of year	9,160,500	12,052,976
Transactions settled (a)	9,160,500	2,892,476
Shares that could be settled at end of year	—	9,160,500
_______________
(a) The shares settled during the years ended December 31, 2015 and 2014, were settled with a physical settlement amount of approximately $254.6 million and $82.9 million, respectively.

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2016

Variable Interest Entities [Abstract]

Assets And Liabilities In Relation To VIEs

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



	As of December 31,
	2016		2015
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	257,904	$	268,239
Regulatory assets (a)	10,396		9,088

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,842	$	28,309
Accrued interest (b)	867		2,457
Long-term debt of variable interest entities, net	111,209		138,097

_______________

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

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

Operating Leases, Minimum Annual Rental Payments

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

Leases (Tables)

12 Months Ended

Dec. 31, 2016

Leases [Abstract]

Rental expense and estimated future commitments under operating leases are as follows.



Year Ended December 31,	Total Operating Leases
	(In Thousands)
Rental expense:
2014	$	14,143
2015	14,035
2016	13,563

Future commitments:
2017	$	13,007
2018	11,659
2019	10,274
2020	7,615
2021	5,776
Thereafter	7,845
Total future commitments	$	56,176

Assets Recorded Under Capital Leases

Assets recorded under capital leases are listed below.



	As of December 31,
	2016			2015
	(In Thousands)
Vehicles	$	15,595		$	17,345
Computer equipment	1,073			1,204
Generation plant	40,048			40,048
Accumulated amortization	(13,542		)	(13,477		)
Total capital leases	$	43,174		$	45,120

Capital Leases, Minimum Annual Rental Payments

Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.



Year Ended December 31,	Total Capital Leases
	(In Thousands)
2017	$	5,803
2018	5,722
2019	5,101
2020	4,443
2021	3,942
Thereafter	52,496
	77,507
Amounts representing imputed interest	(29,900		)
Present value of net minimum lease payments under capital leases	47,607
Less: Current portion	3,179
Total long-term obligation under capital leases	$	44,428

Quarterly Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.



2016	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	569,450	$	621,448	$	764,654	$	606,535
Net income (a)	68,708		76,144		158,553		57,795
Net income attributable to Westar Energy, Inc. (a)	65,585		72,340		154,720		53,932

Per Share Data (a):

Basic:
Earnings available	$	0.46	$	0.51	$	1.09	$	0.38

Diluted:
Earnings available	$	0.46	$	0.51	$	1.08	$	0.38

Cash dividend declared per common share	$	0.38	$	0.38	$	0.38	$	0.38
Market price per common share:
High	$	50.38	$	57.25	$	56.95	$	57.50
Low	$	40.01	$	48.92	$	52.52	$	54.41

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.



2015	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	590,807	$	589,563	$	732,829	$	545,965
Net income (a)	53,163		66,243		140,564		41,826
Net income attributable to Westar Energy, Inc. (a)	50,980		63,710		138,003		39,235

Per Share Data (a):

Basic:
Earnings available	$	0.38	$	0.47	$	0.97	$	0.28

Diluted:
Earnings available	$	0.38	$	0.46	$	0.97	$	0.28

Cash dividend declared per common share	$	0.36	$	0.36	$	0.36	$	0.36
Market price per common share:
High	$	44.03	$	39.65	$	40.22	$	43.56
Low	$	36.58	$	33.88	$	34.17	$	37.55

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the yea

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Average annual composite basis group depreciation rates	2.40%	2.50%	2.40%
Unbilled revenue	$ 74.4	$ 66.0
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Accumulated amortization	40.0	59.1
Nuclear fuel charged to fuel and purchased power expense	$ 26.8	$ 27.3	$ 27.3

Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Total	$ 300,125	$ 301,294
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utilitiy Inventory	107,086	113,438
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utilitiy Inventory	$ 193,039	$ 187,856

Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Additions	$ 21,594	$ 5,580	$ 29,073
Allowance for Funds Used During Construction, Capitalized Interest	$ 9,964	$ 3,505	$ 12,044
Average AFUDC rates	4.20%	2.70%	6.70%

Summary Of Significant Accounting Policies (Depreciable Lives of PP&E) (Details)	12 Months Ended
	Dec. 31, 2016
Minimum [Member]
Depreciable Lives [Line Items]
Transmission facilities, estimated useful life	15 years
Distribution facilities, estimated useful life	22 years
Other property, plant and equipment, estimated useful life	5 years
Maximum [Member]
Depreciable Lives [Line Items]
Transmission facilities, estimated useful life	75 years
Distribution facilities, estimated useful life	68 years
Other property, plant and equipment, estimated useful life	30 years
Fossil Fuel Plant [Member] \| Minimum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	6 years
Fossil Fuel Plant [Member] \| Maximum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	78 years
Nuclear Plant [Member] \| Minimum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	55 years
Nuclear Plant [Member] \| Maximum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	71 years
Other Plant in Service [Member] \| Minimum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	19 years
Other Plant in Service [Member] \| Maximum [Member]
Depreciable Lives [Line Items]
Generating facilities, estimated useful life	20 years

Summary Of Significant Accounting Policies (Cash Surrender Value of Life Insurance) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Cash Surrender Value of Life Insurance	$ 1,267,349	$ 1,299,408
Borrowings against policies	(1,137,360)	(1,168,794)
Corporate-owned life insurance, net	$ 129,989	$ 130,614

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Less: Net income attributable to noncontrolling interests

Net income

$ 361,200

$ 301,796

$ 322,325

14,623

9,867

9,066

Net income attributable to Westar Energy, Inc.

346,577

291,929

313,259

Participating Securities, Distributed and Undistributed Earnings (Loss), Diluted

714

646

790

Net income allocated to common stock

$ 345,863

$ 291,283

$ 312,469

Weighted average equivalent common shares outstanding - basic

142,067,558

137,957,515

130,014,941

RSUs

407,123

299,198

181,397

Forward sale agreements

1,021,510

2,628,187

Weighted average equivalent common shares outstanding - diluted

^[1]

142,474,681

139,278,223

132,824,525

Basic earnings per common share

$ 0.38

^[2]

$ 1.09

$ 0.51

$ 0.46

$ 0.28

$ 0.97

$ 0.47

$ 0.38

$ 2.43

$ 2.11

$ 2.40

Diluted earnings per common share

$ 0.38

$ 1.08

$ 0.51

$ 0.46

$ 0.28

$ 0.97

$ 0.46

$ 0.38

$ 2.43

$ 2.09

$ 2.35

Antidilutive shares

[1]	(a)For the years ended December 31, 2016, 2015 and 2014, we had no antidilutive securities.
[2]	(a)Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Paid For (Received From)
Interest on financing activities	$ 139,029	$ 161,484	$ 160,292
Income taxes, net of refunds	13,103	(410)	458
Noncash Investing and Financing Transactions
Property, plant and equipment additions	(151,474)	(105,169)	(143,192)
Issuance of common stock for reinvested dividends and compensation plans	9,685	10,453	9,155
Assets acquired through capital leases	2,744	3,130	8,717
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	5,846	10,430	12,183
Noncash Investing and Financing Transactions
Property, plant and equipment additions	0	0	(7,342)
Debt of VIEs	$ 0	$ 0	$ (7,342)

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Excess Tax Benefit from Share-based Compensation, Operating Activities		$ 1.3	$ 0.9
Stock-based compensation excess tax benefits	$ 3.3	$ 1.3	$ 0.9

Pending Merger Pending Merger (Narrative) - USD ($) $ / shares in Units, $ in Millions			9 Months Ended	12 Months Ended
	Jun. 28, 2016	May 29, 2016	Sep. 30, 2016	Dec. 31, 2016
Business Combination [Line Items]
Public Utilities, Kansas time limit for KCC review	300 days
Public Utilities, time limit for FERC action				180 days
Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio, Minimum		0.2709
Business Combination, Share Conversion Ratio, Maximum		0.3148
Business Combination, Share Conversion Ratio, Trading Period		20 days
Business Combination Merger Contract Termination Fee		$ 180.0
Business Combination, Acquisition Related Costs				$ 10.2
Business Combination, Expected Acquisition Related Costs			$ 30.0
Great Plains Energy, Inc. Merger [Member] \| Cash Consideration per Share [Member]
Business Combination [Line Items]
Business Acquisition, Share Price		$ 51.00
Business Acquisition, Dividend Restriction		0.40
Business Acquisition, Dividend Increase Restriction		0.08
Great Plains Energy, Inc. Merger [Member] \| Total Consideration per Share [Member]
Business Combination [Line Items]
Business Acquisition, Share Price		$ 60.00
Failure to obtain regulatory approvals, paid to Westar Energy [Member] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		$ 380.0
end date occurred and Westar Energy enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Domain] \| Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee		$ 280.0

Rate Matters And Regulation (Regulatory Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 879,862	$ 860,918
Regulatory Liabilities	239,453	292,811
Deferred Regulatory Gain From Sale Leaseback [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	70,065	75,560
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	5,663	53,834
Jurisdictional Allowance for Funds Used During Construction [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	33,119	32,673
Pension and Other Post-retirement Benefit Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	37,172	32,181
Nuclear Decommissioning [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	34,094	30,659
Dismantling Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	27,742	25,330
Kansas Tax Credits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	13,142	12,857
Retail Energy Cost Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	0	12,686
Long-term Contract for Purchase of Electric Power [Domain]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	9,265	9,972
Other Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	9,191	7,059
Other Pension Plans, Postretirement or Supplemental Plans, Defined Benefit [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	354,600
Pension Cost [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	26,500
Deferred Employee Benefit Costs Amortization Expense, Next Twelve Months	6,800
Deferred Employee Benefit Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	381,129	353,785
Deferred Employee Benefit Costs Amortization Expense, Next Twelve Months	27,900
Amounts Due From Customers For Future Income Taxes, Net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	124,020	144,120
Debt Reacquisition Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	115,502	121,631
Depreciation [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	63,171	65,797
Ad Valorem Tax [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	17,637	44,455
Asset Retirement Obligation [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	35,487	31,996
Cash Flow Hedging [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets		25,634
Nuclear Refueling [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	20,316	16,561
Disallowed Plant Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	15,453	15,639
Analog meter unrecovered investment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	8,500	1,454
Environmental Costs [Member] [Domain]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	14,370	15,446
Energy Efficiency Program Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	7,097	7,922
Other Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	18,802	16,478
Deferred Fuel Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	32,451	$ 0
Cash Flow Hedging [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 25,927

Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Thousands			1 Months Ended			12 Months Ended
	Oct. 26, 2016	Jun. 28, 2016	Jan. 31, 2017	Mar. 31, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2016	Jan. 31, 2016	Jun. 30, 2015	Apr. 01, 2015	Jan. 31, 2015	Jun. 30, 2014	Apr. 30, 2014	Jan. 01, 2014
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities						$ 239,453	$ 292,811
Depreciation, Amortization and Accretion, Net						338,519	310,591	$ 286,442
Estimated Increase In Annual Retail Revenues For Environmental Costs											$ 10,800			$ 11,000
Estimated Increase In Annual Retail Revenues For Transmission Costs									$ 7,000			$ 7,200			$ 41,000
Estimated Increase In Annual Revenues For Property Tax										$ 5,000			$ 4,900			$ 12,700
Public Utilities, Kansas time limit for KCC review		300 days
Estimated Increase In Annual Transmission Revenues						$ 24,000	4,600	$ 44,300
La Cygne Generating Station [Member]
Regulatory Assets and Liabilities [Line Items]
Ownership Percentage						50.00%
Other Pension Plans, Postretirement or Supplemental Plans, Defined Benefit [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities						$ 7,400
Deferred Employee Benefit Costs [Member]
Regulatory Assets and Liabilities [Line Items]
intangible liabilities, amortization expense, next twelve months						600
Pension Cost [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities						29,800
intangible liabilities, amortization expense, next twelve months						3,400
Retail Energy Cost Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities						$ 0	12,686
Regulatory Liability, Amortization Period						1 year
Postretirement Benefit Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities						$ 37,172	$ 32,181
Pension Cost [Member]
Regulatory Assets and Liabilities [Line Items]
Deferred Employee Benefit Costs Amortization Expense, Next Twelve Months						$ 6,800
Regulatory Asset, Amortization Period						5 years
Deferred Employee Benefit Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Deferred Employee Benefit Costs Amortization Expense, Next Twelve Months						$ 27,900
Ad Valorem Tax [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Asset, Amortization Period						1 year
Analog meter unrecovered investment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Asset, Amortization Period						5 years
Energy Efficiency Program Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Asset, Amortization Period						1 year
Retail Energy Cost Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Asset, Amortization Period						1 year
FERC 206 [Member] \| Incentive Return on Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Return on Equity, Percentage				0.50%
FERC 206 [Member] \| Total Return on Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Return on Equity, Percentage				10.30%
FERC 206 [Member] \| Base Return on Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Return on Equity, Percentage				9.80%
Federal Energy Regulatory Commission [Member] \| Kansas Corporation Commission [Member]
Regulatory Assets and Liabilities [Line Items]
Loss Contingency Accrual						$ 1,200
Kansas Corporation Commission [Member] \| General Rate Case [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 78,300
Kansas Corporation Commission [Member] \| Abbreviated Rate Case [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 17,400
Public Utilities, Kansas time limit for KCC review	240 days
Kansas Corporation Commission [Member] \| FERC 206 [Member]
Regulatory Assets and Liabilities [Line Items]
Loss Contingency Accrual						$ 1,300
RSU Awards With Only Service Requirements [Member]
Regulatory Assets and Liabilities [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition						1 year 10 months
RSU Awards With Performance Measures [Member]
Regulatory Assets and Liabilities [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition						1 year 8 months
Subsequent Event [Member]
Regulatory Assets and Liabilities [Line Items]
Estimated Increase In Annual Revenues For Property Tax			$ 26,800
Subsequent Event [Member] \| Federal Energy Regulatory Commission [Member] \| Electric Transmission [Member]
Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 29,600

Financial Instruments and Trading Securities (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Carrying Value	$ 3,551,940	$ 3,201,940
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	3,430,000	3,080,000
Fair Value	3,597,441	3,259,533
Fixed Rate Debt Of Variable Interest Entities [Member]
Debt Instrument [Line Items]
Carrying Value	137,962	166,271
Fair Value	$ 139,733	$ 179,030

Financial Instruments and Trading Securities (Reconciliations Of Assets And Liabilities At Fair Value) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	$ 200,122	$ 184,057
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period	15 years
Domestic Equity [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	$ 61,368	56,922
Alternative Investments [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	18,958	16,439
Real Estate Securities [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	9,946	10,823
Fair Value [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	33,960	33,312
Fair Value [Member] \| Domestic Equity [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	5,056	6,050
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	3,529	1,948
Fair Value [Member] \| Alternative Investments [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	18,958	16,439
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	0	0
Fair Value [Member] \| Real Estate Securities [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Total Nuclear Decommissioning Trust	9,946	10,823
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 0	$ 0

Financial Instruments and Trading Securities (Investments In Financial Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period	15 years
Total Nuclear Decommissioning Trust	$ 200,122	$ 184,057
Total Trading Securities, Assets	34,491	33,888
Total	234,613	217,945
Fair Value [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	33,960	33,312
Decommissioning Trust Assets [Member] \| Fair Value [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	3,529	1,948
Alternative Investments [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	18,958	16,439
Alternative Investments [Member] \| Fair Value [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	18,958	16,439
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 0	0
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Real Estate Securities [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	$ 9,946	10,823
Real Estate Securities [Member] \| Fair Value [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	9,946	10,823
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 0	0
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Domestic Equity [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	$ 61,368	56,922
Total Trading Securities, Assets	18,364	17,876
Domestic Equity [Member] \| Fair Value [Member]
Financial And Derivative Instruments, Trading Securities, Energy Marketing And Risk Management [Line Items]
Total Nuclear Decommissioning Trust	5,056	6,050
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 3,529	$ 1,948

Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Total Trading Securities, Assets	$ 34,491	$ 33,888
Unrealized gains (losses) on trading securities	2,500	400	$ 2,600
Realized gains (losses) on available-for-sale-securities	(1,500)	(900)	$ 100
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Schedule of Available-for-sale Securities [Line Items]
Benefit obligation for certain retirement benefits	$ 26,800	$ 27,400

Financial Investments (Cost And Fair Value Of Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 184,145	$ 177,048
Gross Unrealized Gain	19,087	13,351
Gross Unrealized Loss	(3,110)	(6,342)
Fair Value	$ 200,122	$ 184,057
Allocation	100.00%	100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 53,192	$ 49,488
Gross Unrealized Gain	8,295	7,436
Gross Unrealized Loss	(119)	(2)
Fair Value	$ 61,368	$ 56,922
Allocation	31.00%	32.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 34,502	$ 33,458
Gross Unrealized Gain	2,075	1,372
Gross Unrealized Loss	(633)	(1,235)
Fair Value	$ 35,944	$ 33,595
Allocation	18.00%	18.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 27,952	$ 26,397
Gross Unrealized Gain	0	0
Gross Unrealized Loss	(529)	(421)
Fair Value	$ 27,423	$ 25,976
Allocation	14.00%	14.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 18,358	$ 17,047
Gross Unrealized Gain	0	0
Gross Unrealized Loss	(170)	(1,759)
Fair Value	$ 18,188	$ 15,288
Allocation	9.00%	8.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 16,397	$ 16,306
Gross Unrealized Gain	0	0
Gross Unrealized Loss	(1,659)	(2,722)
Fair Value	$ 14,738	$ 13,584
Allocation	7.00%	7.00%
Combination Debt and Equity Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,171	$ 8,239
Gross Unrealized Gain	4,313	3,104
Gross Unrealized Loss	0	0
Fair Value	$ 13,484	$ 11,343
Allocation	7.00%	6.00%
Alternative Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 15,000	$ 15,000
Gross Unrealized Gain	3,958	1,439
Gross Unrealized Loss	0	0
Fair Value	$ 18,958	$ 16,439
Allocation	9.00%	9.00%
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 9,500	$ 11,026
Gross Unrealized Gain	446	0
Gross Unrealized Loss	0	(203)
Fair Value	$ 9,946	$ 10,823
Allocation	5.00%	6.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 73	$ 87
Gross Unrealized Gain	0	0
Gross Unrealized Loss	0	0
Fair Value	$ 73	$ 87

Financial Investments (Fair Value And Gross Unrealized Losses Of Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	$ 1,788	$ 0
Gross Unrealized Losses, Less than 12 Months	(119)	0
Fair Value, 12 Months or Greater	0	668
Gross Unrealized Losses, 12 Months or Greater	0	(2)
Fair Value, Total	1,788	668
Gross Unrealized Losses, Total	(119)	(2)
Real Estate [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months		0
Gross Unrealized Losses, Less than 12 Months		0
Fair Value, 12 Months or Greater		10,823
Gross Unrealized Losses, 12 Months or Greater		(203)
Fair Value, Total		10,823
Gross Unrealized Losses, Total		(203)
Summary of Investments, Other than Investments in Related Parties [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	29,211	41,264
Gross Unrealized Losses, Less than 12 Months	(648)	(2,180)
Fair Value, 12 Months or Greater	40,415	31,792
Gross Unrealized Losses, 12 Months or Greater	(2,462)	(4,162)
Fair Value, Total	69,626	73,056
Gross Unrealized Losses, Total	(3,110)	(6,342)
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0	0
Gross Unrealized Losses, Less than 12 Months	0	0
Fair Value, 12 Months or Greater	7,489	6,717
Gross Unrealized Losses, 12 Months or Greater	(633)	(1,235)
Fair Value, Total	7,489	6,717
Gross Unrealized Losses, Total	(633)	(1,235)
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0	15,288
Gross Unrealized Losses, Less than 12 Months	0	(1,759)
Fair Value, 12 Months or Greater	18,188	0
Gross Unrealized Losses, 12 Months or Greater	(170)	0
Fair Value, Total	18,188	15,288
Gross Unrealized Losses, Total	(170)	(1,759)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	27,423	25,976
Gross Unrealized Losses, Less than 12 Months	(529)	(421)
Fair Value, 12 Months or Greater	0	0
Gross Unrealized Losses, 12 Months or Greater	0	0
Fair Value, Total	27,423	25,976
Gross Unrealized Losses, Total	(529)	(421)
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0	0
Gross Unrealized Losses, Less than 12 Months	0	0
Fair Value, 12 Months or Greater	14,738	13,584
Gross Unrealized Losses, 12 Months or Greater	(1,659)	(2,722)
Fair Value, Total	14,738	13,584
Gross Unrealized Losses, Total	$ (1,659)	$ (2,722)

Property, Plant And Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Electric plant in service	$ 11,986,046	$ 11,449,933
Electric plant acquisition adjustment	(802,318)	(802,318)
Accumulated depreciation	(4,404,977)	(4,178,885)
Electric plant, net	8,383,387	8,073,366
Construction work in progress	773,095	349,402
Nuclear fuel, net	61,952	68,349
Plant to be retired, net	29,925	33,785
Property, plant and equipment, net	9,248,359	8,524,902
Variable Interest Entity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Electric plant in service	497,999	497,999
Accumulated depreciation	(240,095)	(229,760)
Property, plant and equipment, net	$ 257,904	$ 268,239

Property, Plant And Equipment (Depreciation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation	$ 316.7	$ 287.9	$ 263.8
Variable Interest Entity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation	$ 9.5	$ 9.6	$ 9.7

Joint Ownership of Utility Plants Joint Ownership of Utility Plants (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Jointly Owned Utility Plant Interests [Line Items]

Accumulated Depreciation on VIE Investment in Property, Plant and Equipment

47.00%

$ (4,404,977)

$ (4,178,885)

3,119

$ 138,150

1,797,568

Jointly Owned Utility Plant Interests [Line Items]

$ 4,772,539

La Cygne unit 1 [Member]

^[1]

50.00%

^[1]

368

^[1]

$ 39,096

^[1]

163,234

Jointly Owned Utility Plant Interests [Line Items]

^[1]

$ 613,348

JEC unit 1 [Member]

^[1]

92.00%

^[1]

670

^[1]

$ 7,131

^[1]

203,410

Jointly Owned Utility Plant Interests [Line Items]

^[1]

$ 817,402

JEC unit 2 [Member]

^[1]

92.00%

^[1]

675

^[1]

$ 4,198

^[1]

200,296

Jointly Owned Utility Plant Interests [Line Items]

^[1]

$ 567,298

JEC unit 3 [Member]

^[1]

92.00%

^[1]

659

^[1]

$ 4,108

^[1]

325,701

Jointly Owned Utility Plant Interests [Line Items]

^[1]

$ 740,170

Wolf Creek [Member]

^[2]

47.00%

^[2]

551

^[2]

$ 82,756

^[2]

842,595

Jointly Owned Utility Plant Interests [Line Items]

^[2]

$ 1,922,877

State Line [Member]

^[3]

40.00%

^[3]

196

^[3]

$ 861

^[3]

62,332

Jointly Owned Utility Plant Interests [Line Items]

^[3]

$ 111,444

La Cygne unit 2 [Member]

La Cygne Generating Station [Member]

324

Jointly Owned Utility Plant Interests [Line Items]

Variable Interest Entity Percentage of Asset Held

50.00%

Jeffrey Energy Center [Member]

Jointly Owned Utility Plant Interests [Line Items]

Variable Interest Entity Percentage of Asset Held

8.00%

Variable Interest Entity, Primary Beneficiary [Member]

Jointly Owned Utility Plant Interests [Line Items]

Accumulated Depreciation on VIE Investment in Property, Plant and Equipment

$ (240,095)

$ (229,760)

Variable Interest Entity, Primary Beneficiary [Member] | La Cygne Generating Station [Member]

Jointly Owned Utility Plant Interests [Line Items]

VIE Investment in Property, Plant and Equipment

392,100

Accumulated Depreciation on VIE Investment in Property, Plant and Equipment

$ (208,700)

[1]	Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.
[2]	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
[3]	Jointly owned with Empire District Electric Company.

Short-Term Debt (Details) $ in Thousands	12 Months Ended
Short-Term Debt (Details) $ in Thousands	Dec. 31, 2016 USD ($) days	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 01, 2014 USD ($)	Sep. 29, 2011 USD ($)
Short-term Debt [Line Items]
Short-term debt amount outstanding	$ 366,700	$ 250,300
Weighted average amount outstanding	$ 284,700	$ 350,380
Weighted daily average interest rate, excluding fees	0.78%	0.48%
Interest expense on short-term debt	$ 3,600	$ 3,000	$ 2,000
Commercial Paper and Revolving LIne of Credit [Member]
Short-term Debt [Line Items]
Short-Term Debt Maximum Borrowings	$ 1,000,000
Weighted average interest rate	0.96%	0.77%
Commercial Paper [Member]
Short-term Debt [Line Items]
Short-Term Debt Maximum Borrowings	$ 1,000,000
Commercial paper program, Maximim maturity period \| days	365
Short-term debt amount outstanding	$ 366,700	$ 250,300
Revolving Credit Facility Lender One [Member]
Short-term Debt [Line Items]
Expected extended amount for line of credit					$ 1,000,000
Line of credit facility expiration date	Sep. 29, 2019
Line of Credit Facility, Increase(Decrease) in Maximum Borrowing Capacity	$ 20,700
Issued letters of credit	12,300	19,200
Secured revolving credit facility	730,000
Secured revolving credit facility borrowed	0	0
Revolving Credit Facility Lender Two [Member]
Short-term Debt [Line Items]
Expected extended amount for line of credit					$ 400,000
Issued letters of credit	0	0
Secured revolving credit facility				$ 270,000
Secured revolving credit facility borrowed	$ 0	$ 0

Long-Term Debt (Details) - USD ($)
$ in Thousands

Dec. 31, 2016

Jun. 20, 2016

Dec. 31, 2015

Nov. 30, 2015

Long-term debt due within one year

$ 3,551,940

$ 3,201,940

(125,000)

Unamortized Debt Issuance Expense

^[1]

(27,912)

(27,616)

Unamortized debt discount, Net

^[1]

(10,358)

(10,374)

Long-term debt, net

3,388,670

3,163,950

Westar Energy [Member] | Secured Debt [Member]

2,505,000

2,155,000

Westar Energy [Member] | Secured Debt [Member] | 5.15% First Mortgage Bonds Due 2017 [Member]

75,500

Westar Energy [Member] | Secured Debt [Member] | 5.10% First Mortgage Bonds Due 2020 [Member]

125,000

Westar Energy [Member] | Secured Debt [Member] | Debt Instrument 8890 [Member] [Domain]

250,000

Westar Energy [Member] | Secured Debt [Member] | Debt Instrument 8920 [Member]

250,000

$ 250,000

Westar Energy [Member] | Secured Debt [Member] | 4.125% First Mortgage Bonds Due 2042 [Member]

350,000

$ 350,000

Westar Energy [Member] | Secured Debt [Member] | Debt Intrument 8860 [Member]

550,000

Westar Energy [Member] | Secured Debt [Member] | Debt Instrument 8870 [Member]

430,000

Westar Energy [Member] | Secured Debt [Member] | Debt Instrument 8900 [Member] [Domain]

250,000

Westar Energy [Member] | Secured Debt [Member] | Pollution Control Bonds Variable Due 2032 [Member]

300,000

$ 300,000

Westar Energy [Member] | Secured Debt [Member] | Pollution Control Bonds Variable Due 2032 [Member]

45,000

KGE Member [Domain] | Secured Debt [Member]

30,500

875,000

KGE Member [Domain] | Secured Debt [Member] | 6.53% First Mortgage Bonds Due 2037 [Member]

96,440

KGE Member [Domain] | Secured Debt [Member] | 6.15% First Mortgage Bonds Due 2023 [Member]

175,000

KGE Member [Domain] | Secured Debt [Member] | 6.64% First Mortgage Bonds Due 2038 [Member]

50,000

KGE Member [Domain] | Secured Debt [Member] | Debt Instrument 8880 [Member] [Domain]

100,000

KGE Member [Domain] | Secured Debt [Member] | 6.70% First Mortgage Bonds Due 2019 [Member]

250,000

KGE Member [Domain] | Secured Debt [Member] | Pollution Control Bonds Variable Due 2027 [Member]

300,000

KGE Member [Domain] | Secured Debt [Member] | Pollution Control Bonds Variable Due 2032 [Member]

21,940

KGE Member [Domain] | Secured Debt [Member] | Pollution Control Bonds Variable Due 2032 [Member]

14,500

KGE Member [Domain] | Secured Debt [Member] | 4.85% Pollution Control Bonds Due 2031 [Member]

10,000

KGE Member [Domain] | Secured Debt [Member] | Debt Instrument 8910 [Member]

50,000

Variable Interest Entity [Member]

50,000

Long-term debt due within one year

137,962

166,271

(26,842)

(28,309)

Unamortized debt discount, Net

^[1]

135

Long-term debt, net

111,209

138,097

Variable Interest Entity [Member] | Variable Interest Entity 5.92% due 2019 [Member]

Variable Interest Entity [Member] | Variable Interest Entity 5.647% due 2021 [Member]

^[2]

1,157

4,223

Variable Interest Entity [Member] | Debt Instrument Thirty-one [Member]

^[2]

162,048

Deferred Tax Liabilities, Net

^[2]

$ 136,805

$ 0

[1]	We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
[2]	Portions of our payments related to this debt reduce the principal balances each year until maturity.

Long-term Debt Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 3,551,940	$ 3,201,940
2013	125,000
2014	0
2015	300,000
2016	250,000
2017	0
Thereafter	2,876,940
Variable Interest Entity, Primary Beneficiary [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	137,962	$ 166,271
2013	26,842
2014	28,538
2015	31,485
2016	32,254
2017	18,843
Thereafter	$ 0

Long-term Debt (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended				12 Months Ended
	Jan. 31, 2017	Nov. 30, 2015	Aug. 31, 2015	Jan. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 20, 2016	Jun. 01, 2016	Feb. 16, 2016
Debt Instrument [Line Items]
Variable Rate Tax-Exempt Bonds					$ 121,900
Long-term Debt, Gross					3,551,940	$ 3,201,940
Repayments of Long-term Debt					(50,000)	(635,891)	$ (427,500)
Interest expense on long-term debt					141,400	152,700	158,800
Variable Interest Entity, Primary Beneficiary [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					137,962	166,271
Repayments of Long-term Debt					(190,357)	(27,933)	(27,479)
Interest expense on long-term debt					4,200	9,800	$ 11,400
Westar Energy [Member] \| First Mortgage Bond Series [Member]
Debt Instrument [Line Items]
Remaining Borrowing Capacity					931,600
Westar Energy [Member] \| Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					2,505,000	2,155,000
Westar Energy [Member] \| Secured Debt [Member] \| 5.15% First Mortgage Bonds Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					125,000	125,000
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument 8920 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					350,000	0		$ 350,000
Debt Instrument, Interest Rate, Stated Percentage								2.55%
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument 8890 [Member] [Domain]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 250,000			250,000	250,000
Debt Instrument, Interest Rate, Stated Percentage		3.25%
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument 8900 [Member] [Domain]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 300,000			300,000	300,000
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Westar Energy [Member] \| Secured Debt [Member] \| 8.625% First Mortgage Bonds Due 2018 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ (300,000)
Debt Instrument, Interest Rate, Stated Percentage		8.625%
Repayment of Long-term Debt with Call Premium		$ 360,900
Westar Energy [Member] \| Secured Debt [Member] \| 5.875% First Mortgage Bonds Due 2036 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ (150,000)
Debt Instrument, Interest Rate, Stated Percentage			5.875%
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument Three [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt				$ (125,000)
Debt Instrument, Interest Rate, Stated Percentage				5.95%
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument 8870 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					250,000	250,000
Westar Energy [Member] \| Secured Debt [Member] \| Debt Instrument Twenty-Nine [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					550,000	550,000
KGE [Member] \| Secured Debt [Member] \| Debt Instrument 8910 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross									$ 50,000
Debt Instrument, Interest Rate, Refunded Stated Percentage									2.50%
Debt Instrument, Interest Rate, Stated Percentage									4.85%
KGE Member [Domain] \| First Mortgage Bond Series [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capicity					3,500,000
Remaining Borrowing Capacity					1,500,000
KGE Member [Domain] \| Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					$ 875,000	$ 875,000
KGE Member [Domain] \| La Cygne Generating Station [Member] \| Debt Instrument La Cygne [Member] [Domain] [Domain]
Debt Instrument [Line Items]
Long-term Debt, Gross										$ 162,100
KGE Member [Domain] \| Variable Interest Entity, Primary Beneficiary [Member] \| Debt Instrument La Cygne [Member] [Domain] [Domain]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Refunded Stated Percentage										2.398%
Debt Instrument, Interest Rate, Stated Percentage										5.647%
Subsequent Event [Member] \| Westar Energy [Member] \| Secured Debt [Member] \| 5.15% First Mortgage Bonds Due 2017 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ (125,000)
Debt Instrument, Interest Rate, Stated Percentage	5.15%

Taxes (Components of Income Tax Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income taxes:
Federal	$ (1,007)	$ 327	$ 416
State	318	341	(597)
Deferred income taxes:
Federal	155,230	124,891	124,923
State	32,892	29,484	29,657
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount	(2,893)	(3,043)	(3,129)
Income tax expense	$ 184,540	$ 152,000	$ 151,270

Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)
$ in Thousands

Dec. 31, 2016

Dec. 31, 2015

Income Tax Contingency [Line Items]

$ 1,752,776

$ 1,591,430

Deferred tax assets:

Business tax credit carryforward

^[1]

265,750

266,963

Deferred employee benefit costs

137,337

122,757

Net operating loss carryforward

^[2]

86,693

129,232

Deferred state income taxes

73,294

67,307

Deferred regulatory gain on sale-leaseback

30,868

33,287

Alternative minimum tax carryforward

^[3]

29,412

26,725

Deferred compensation

31,981

27,266

Accrued liabilities

21,757

21,115

Disallowed costs

9,600

10,211

Deferred Tax Assets, Dismantling Costs

10,972

10,018

Capital loss carryforward

1,668

Other

47,200

41,319

Total gross deferred tax assets

744,864

757,868

Less: Valuation allowance

^[4]

1,668

Deferred tax assets

744,864

756,200

Deferred tax liabilities:

Accelerated depreciation

1,925,270

1,787,457

Deferred employee benefit costs

137,337

122,757

Acquisition premium

147,868

155,881

Amounts due from customers for future income taxes, net

124,020

144,120

Deferred state income taxes

61,110

59,787

Pension expense tracker

5,560

12,051

Debt reacquisition costs

41,753

42,314

Other

54,722

23,263

Total deferred tax liabilities

2,497,640

$ 2,347,630

Internal Revenue Service (IRS) [Member]

Deferred tax assets:

Business tax credit carryforward

88,400

Deferred tax liabilities:

Operating Loss Carryforwards

198,100

State and Local Jurisdiction [Member]

Deferred tax assets:

Business tax credit carryforward

$ 177,300

[1]	Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2016), we had available federal general business tax credits of $88.4 million and state investment tax credits of $177.3 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2036. The state investment tax credits expire beginning in 2021 and ending in 2032.
[2]	As of December 31, 2016, we had a federal net operating loss carryforward of $198.1 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2032 and ending in 2035.
[3]	As of December 31, 2016, we had available an alternative minimum tax credit carryforward of $29.4 million, which has an unlimited carryforward period.
[4]	.

Taxes (Effective Income Tax Reconciliation) (Details)	12 Months Ended
Taxes (Effective Income Tax Reconciliation) (Details)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate
Statutory federal income tax rate	35.00%	35.00%	35.00%
Corporate-owned life insurance policies	(4.20%)	(4.40%)	(4.00%)
State income taxes	4.00%	4.30%	4.00%
Production tax credits	(1.80%)	(2.10%)	(2.10%)
Non-controlling interest	(0.90%)	(0.80%)	(0.70%)
Flow through depreciation for plant-related differences	3.10%	2.60%	2.00%
AFUDC equity	(0.80%)	(0.20%)	(1.30%)
Amortization of federal investment tax credits	(0.50%)	(0.70%)	(0.70%)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Percent	(0.50%)	(0.10%)	(0.00%)
Capital loss utilization	0.40%	(0.10%)	(0.30%)
Liability for unrecognized income tax benefits	0.00%	0.00%	(0.20%)
Other	0.00%	0.00%	0.20%
Effective income tax rate	33.80%	33.50%	31.90%

Taxes (Unrecognized Tax Benefits) (Details) - USD ($)	12 Months Ended
Taxes (Unrecognized Tax Benefits) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized income tax benefits at January 1	$ 2,901,000	$ 3,188,000	$ 1,703,000
Additions based on tax positions related to the current year	434,000	410,000	872,000
Additions for tax positions of prior years	0	0	813,000
Reductions for tax positions of prior years	(1,000)	(86,000)	(200,000)
Lapse of statute of limitations	(568,000)	(611,000)	0
Settlements	0	0	0
Unrecognized income tax benefits at December 31	2,766,000	2,901,000	3,188,000
The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate	2,700,000	2,900,000	$ 3,200,000
Accrued interest related to unrecognized income tax benefits	0	0
Penalties accrued	0
Taxes other than income taxes	$ 1,500,000	$ 1,500,000

Employee Benefit Plans (Funded Status) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Total Trading Securities, Assets

$ 34,491

$ 33,888

965,193

^[1]

1,030,645

18,563

21,392

$ 16,218

43,723

43,014

41,600

63,540

44,945

51,482

(90,644)

1,012,024

^[1]

965,193

^[1]

1,030,645

653,945

661,141

45,181

(6,948)

20,200

41,000

60,852

41,248

658,474

653,945

661,141

Amounts Recognized in the Balance Sheets Consist of:

(353,550)

(311,248)

(2,260)

(2,745)

(351,290)

(308,503)

Amounts Recognized in Regulatory Assets Consist of:

(353,550)

(311,248)

282,462

254,085

3,913

8,078

Other Postretirement Benefit Plans, Defined Benefit [Member]

286,375

262,163

126,284

^[1]

141,516

1,084

1,443

1,381

5,571

5,691

6,351

395

582

7,697

6,549

3,926

(16,399)

129,563

^[1]

126,284

^[1]

141,516

115,416

121,349

7,274

(208)

(356)

(534)

7,427

6,259

115,619

115,416

$ 121,349

Amounts Recognized in the Balance Sheets Consist of:

(13,944)

(10,868)

(284)

(344)

(13,660)

(10,524)

Amounts Recognized in Regulatory Assets Consist of:

(13,944)

(10,868)

(7,603)

(12,208)

2,674

3,130

Supplemental Employee Retirement Plans, Defined Benefit [Member]

(4,929)

(9,078)

27,400

Discount Rate [Member] | Pension Benefits [Member]

26,800

$ 27,400

Discount Rate [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

50,200

Highest Paid Consecutive Months [Member]

$ 5,000

Defined Benefit Plan, Assumptions Used in Calculations, Narrative Description

Months Used Prior to Retirement [Member]

Defined Benefit Plan, Assumptions Used in Calculations, Narrative Description

120

[1]

Employee Benefit Plans (Plans With a Projected Benefit Obligation and Accumulated Benefit Obligation in Excess of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 1,012,024	$ 965,193
Fair value of plan assets	658,474	653,945
Accumulated benefit obligation	905,661	864,263
Fair value of plan assets	$ 658,474	$ 653,945
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.25%	4.60%
Compensation rate increase	4.00%	4.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 129,563	$ 126,284
Fair value of plan assets	$ 115,619	$ 115,416
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.15%	4.51%
Compensation rate increase	0.00%	0.00%

Employee Benefit Plans (Net Periodic Costs And Other Changes Recognized in Regulatory Assets) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 18,563

$ 21,392

$ 16,218

43,723

43,014

41,600

(42,653)

(40,236)

(36,438)

Actuarial loss/(gain), net

768

520

526

20,577

32,131

19,362

40,978

56,821

41,268

^[1]

14,528

6,886

15,479

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

55,506

63,707

56,747

Amortization of actuarial (loss)/gain

48,954

(43,459)

162,569

(20,577)

(32,379)

(19,362)

(3,397)

5,730

(768)

(520)

(526)

Other adjustments

352

Total recognized in net periodic cost and regulatory assets

24,212

(70,276)

142,681

$ 79,718

$ (6,569)

$ 199,428

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.60%

4.17%

5.07%

6.50%

Other Postretirement Benefit Plans, Defined Benefit [Member]

4.00%

$ 1,084

$ 1,443

$ 1,381

5,571

5,691

6,351

(6,835)

(6,614)

(6,576)

Actuarial loss/(gain), net

455

2,524

(1,118)

379

(742)

(843)

1,354

2,938

^[1]

(1,922)

4,096

4,499

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

(2,765)

5,450

7,437

Amortization of actuarial (loss)/gain

3,486

(9,576)

15,896

1,118

(379)

742

(7,834)

(455)

(2,524)

Other adjustments

Total recognized in net periodic cost and regulatory assets

4,149

(10,410)

6,280

$ 1,384

$ (4,960)

$ 13,717

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.51%

4.10%

4.88%

6.00%

4.00%

[1]	(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.

Employee Benefit Plans (Estimated Amounts From Regulatory Assets Into Net Periodic Cost) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated Future Change in Regulatory Assets, Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost	$ 21,956
Estimated Future Change in Regulatory Assets, Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost	(683)
Total	22,639
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated Future Change in Regulatory Assets, Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost	(780)
Estimated Future Change in Regulatory Assets, Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost	(455)
Total	$ (325)

Employee Benefit Plans (Assumed Annual Health Care Cost Growth Rates) (Details)	12 Months Ended
	Dec. 31, 2016 Rate
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	1.00%

Employee Benefit Plans (One Percentage Change In Assumed Health Care Cost Growth Rates Effects) (Details)	12 Months Ended
	Dec. 31, 2016 Rate
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	1.00%

Employee Benefit Plans (Expected Cash Flows Related To Pension and Post-Retirement Benefit Plans) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Plan Trust [Member] \| Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	$ 25.2
2014	(55.7)
2015	(58.1)
2016	(60.2)
2017	(62.7)
2018	(64.4)
2019 - 2022	(325.1)
Plan Trust [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	0.0
2014	(7.8)
2015	(7.9)
2016	(8.1)
2017	(8.2)
2018	(8.3)
2019 - 2022	(40.2)
Company Assets [Member] \| Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	(2.3)
2015	(2.3)
2016	(2.3)
2017	(2.2)
2018	(2.2)
2019 - 2022	(10.8)
Company Assets [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	(0.3)
2015	(0.3)
2016	(0.3)
2017	(0.2)
2018	(0.2)
2019 - 2022	$ (0.9)

Employee Benefit Plans (Compensation expense and income tax benefits related to stock-based compensation arrangements included in net income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Allocated Share-based Compensation Expense	$ 9,237	$ 8,250	$ 7,193
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 3,653	$ 3,263	$ 2,845

Employee Benefit Plans (RSU activity for awards) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
RSU Awards With Only Service Requirements [Member]
Defined Benefit Plan Disclosure [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 5,000,000	$ 4,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 5,200,000	$ 4,700,000	$ 3,900,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested balance, beginning of year	309,900	342,200	352,500
Granted	99,300	115,700	131,500
Vested	(115,900)	(115,400)	(118,200)
Forfeited	(3,900)	(32,600)	(23,600)
Nonvested balance, end of year	289,400	309,900	342,200
Weighted Average Grant Date Fair Value, beginning of year	$ 35.21	$ 31.38	$ 28.38
Grants in Period, Weighted Average Grant Date Fair Value	46.35	39.50	34.53
Vested in Period, Weighted Average Grant Date Fair Value	32.33	28.77	26.19
Forfeited in Period, Weighted Average Grant Date Fair Value	40.95	33.07	30.00
Weighted Average Grant Date Fair Value, end of year	$ 40.11	$ 35.21	$ 31.38
RSU Awards With Performance Measures [Member]
Defined Benefit Plan Disclosure [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 4,500,000	$ 4,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 7,500,000	$ 3,100,000	$ 500,000.0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested balance, beginning of year	299,100	345,100	350,100
Granted	100,900	94,800	126,100
Vested	(98,500)	(109,000)	(108,200)
Forfeited	(3,800)	(31,800)	(22,900)
Nonvested balance, end of year	297,700	299,100	345,100
Weighted Average Grant Date Fair Value, beginning of year	$ 36.00	$ 32.31	$ 30.35
Grants in Period, Weighted Average Grant Date Fair Value	46.03	40.26	35.97
Vested in Period, Weighted Average Grant Date Fair Value	31.59	28.99	30.56
Forfeited in Period, Weighted Average Grant Date Fair Value	41.57	34.03	30.70
Weighted Average Grant Date Fair Value, end of year	$ 40.79	$ 36.00	$ 32.31

Employee Benefit Plans (Textual) (Details) - USD ($)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

May 19, 2011

Total Trading Securities, Assets

$ 34,491,000

$ 33,888,000

Defined Benefit Plan Target Allocation Percentage Of Assets Of Any One Industry

25.00%

401k Savings Plan Matching Contributions

$ 8,000,000

$ 7,700,000

$ 7,000,000

Percentage of RSU Award, Minimum

0.00%

Percentage of RSU Award, Maximum

200.00%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum

16.90%

14.60%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum

22.40%

19.10%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum

0.90%

1.00%

141,791,153

141,353,426

Level 2 [Member]

Total Trading Securities, Assets

$ 34,335,000

$ 33,729,000

Pension Plans, Defined Benefit [Member]

Benefit obligation for certain retirement benefits

63,540,000

44,945,000

1,012,024,000

^[1]

965,193,000

^[1]

1,030,645,000

Other Postretirement Benefit Plans, Defined Benefit [Member]

Benefit obligation for certain retirement benefits

7,697,000

6,549,000

129,563,000

^[1]

126,284,000

^[1]

$ 141,516,000

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Benefit obligation for certain retirement benefits

$ 26,800,000

$ 27,400,000

KGE [Member]

Subsidiary Interest in Defined Benefit Plans

47.00%

Debt Securities [Member] | Pension Plans, Defined Benefit [Member]

Debt Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

39.00%

Equity Securities [Member] | Pension Plans, Defined Benefit [Member]

35.00%

Equity Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

39.00%

Alternative Investments [Member] | Pension Plans, Defined Benefit [Member]

65.00%

Other Investments [Member] | Pension Plans, Defined Benefit [Member]

12.00%

Long Term Incentive and Share Award [Member]

10.00%

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized

8,300,000

Share-based Compensation Arrangement by Share-based Payment Award, Shares Awarded

5,200,000

Long Term Incentive and Share Award Plan Executive Stock For Compensation Program [Member]

Common Stock Dividends, Shares

170

296

403

RSU Awards With Performance Measures [Member]

2,110

2,024

1,944

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 4,500,000

$ 4,000,000

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition

1 year 8 months

Share-based Compensation Award Fair Value, Vested During Period

$ 7,500,000

3,100,000

$ 500,000.0

RSU Awards With Only Service Requirements [Member]

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 5,000,000

4,500,000

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition

1 year 10 months

Share-based Compensation Award Fair Value, Vested During Period

$ 5,200,000

$ 4,700,000

$ 3,900,000

[1]

Wolf Creek Employee Benefit Plans (Funded Status) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Wolf Creek [Member]

$ 121,622

138,688

$ 121,622

965,193

^[1]

1,030,645

18,563

21,392

$ 16,218

43,723

43,014

41,600

(63,540)

(44,945)

51,482

(90,644)

Amendments

(3,397)

5,731

1,012,024

^[1]

965,193

^[1]

1,030,645

653,945

661,141

45,181

(6,948)

20,200

41,000

60,852

41,248

658,474

653,945

661,141

Amounts Recognized in the Balance Sheet Consist of:

(353,550)

(311,248)

(2,260)

(2,745)

(351,290)

(308,503)

Amounts Recognized in Regulatory Assets Consist of:

(353,550)

(311,248)

282,462

254,085

3,913

8,078

Pension Benefits [Member] | Wolf Creek [Member]

286,375

262,163

206,418

210,320

6,748

7,595

5,695

9,655

9,016

8,469

(6,974)

(6,217)

13,178

(14,296)

229,025

206,418

210,320

121,622

124,660

8,967

(2,879)

14,820

5,805

(6,721)

(5,964)

138,688

121,622

124,660

Amounts Recognized in the Balance Sheet Consist of:

(90,337)

(84,796)

(248)

(247)

(90,089)

(84,549)

Amounts Recognized in Regulatory Assets Consist of:

(90,337)

(84,796)

66,324

56,747

446

501

Other Postretirement Benefit Plans, Defined Benefit [Member]

66,770

57,248

126,284

^[1]

141,516

1,084

1,443

1,381

5,571

5,691

6,351

395

582

(7,697)

(6,549)

3,926

(16,399)

Amendments

129,563

^[1]

126,284

^[1]

141,516

115,416

121,349

7,274

(208)

356

534

7,427

6,259

115,619

115,416

121,349

Amounts Recognized in the Balance Sheet Consist of:

(13,944)

(10,868)

(284)

(344)

(13,660)

(10,524)

Amounts Recognized in Regulatory Assets Consist of:

(13,944)

(10,868)

(7,603)

(12,208)

2,674

3,130

Other Postretirement Benefit Plans, Defined Benefit [Member] | Wolf Creek [Member]

(4,929)

(9,078)

7,793

8,240

127

138

173

325

314

464

989

934

(1,531)

(1,622)

(488)

(211)

7,215

7,793

8,240

105

(4)

458

787

989

934

(1,531)

(1,622)

105

$ 6

Amounts Recognized in the Balance Sheet Consist of:

(7,198)

(7,688)

(538)

(597)

(6,660)

(7,091)

Amounts Recognized in Regulatory Assets Consist of:

(7,198)

(7,688)

(654)

(184)

Discount Rate [Member] | Pension Benefits [Member]

(654)

$ (184)

Discount Rate [Member] | Pension Benefits [Member] | Wolf Creek [Member]

50,200

Discount Rate [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

11,200

Discount Rate [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | Wolf Creek [Member]

5,000

$ 200

[1]

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Plans With a Projected Benefit Obligation and Accumulated Benefit Obligation in Excess of Plan Assets) (Details) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 1,012,024	$ 965,193
Fair value of plan assets	658,474	653,945
Accumulated benefit obligation	905,661	864,263
Fair value of plan assets	$ 658,474	$ 653,945
Discount rate	4.25%	4.60%
Compensation rate increase	4.00%	4.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 129,563	$ 126,284
Fair value of plan assets	$ 115,619	$ 115,416
Discount rate	4.15%	4.51%
Compensation rate increase	0.00%	0.00%
Wolf Creek [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 229,025	$ 206,418
Fair value of plan assets	138,688	121,622
Accumulated benefit obligation	201,963	180,718
Fair value of plan assets	$ 138,688	$ 121,622
Discount rate	4.26%	4.61%
Compensation rate increase	4.00%	4.00%
Wolf Creek [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 7,215	$ 7,793
Fair value of plan assets	$ 17	$ 105
Discount rate	3.95%	4.27%
Compensation rate increase	0.00%	0.00%

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Net Periodic Costs And Other Changes Recognized in Regulatory Assets) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 18,563

$ 21,392

$ 16,218

43,723

43,014

41,600

(42,653)

(40,236)

(36,438)

768

520

526

20,577

32,131

19,362

40,978

56,821

41,268

^[1]

14,528

6,886

15,479

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

55,506

63,707

56,747

48,954

(43,459)

162,569

(20,577)

(32,379)

(19,362)

(3,397)

5,730

(768)

(520)

(526)

Total recognized in net periodic cost and regulatory assets

24,212

(70,276)

142,681

$ 79,718

$ (6,569)

$ 199,428

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.60%

4.17%

5.07%

6.50%

Pension Benefits [Member] | Wolf Creek [Member]

4.00%

$ 6,748

$ 7,595

$ 5,695

9,655

9,016

8,469

(9,722)

(9,044)

(8,084)

4,357

5,930

2,987

11,093

13,554

9,125

^[2]

1,886

(1,485)

2,328

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

12,979

12,069

11,453

13,934

(2,373)

38,833

(4,357)

(5,930)

(2,987)

(55)

(57)

(58)

Total recognized in net periodic cost and regulatory assets

9,522

(8,360)

35,788

$ 22,501

$ 3,709

$ 47,241

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.61%

4.20%

5.11%

7.50%

Other Postretirement Benefit Plans, Defined Benefit [Member]

4.00%

$ 1,084

$ 1,443

$ 1,381

5,571

5,691

6,351

(6,835)

(6,614)

(6,576)

455

2,524

(1,118)

379

(742)

(843)

1,354

2,938

^[1]

(1,922)

4,096

4,499

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

(2,765)

5,450

7,437

3,486

(9,576)

15,896

1,118

(379)

742

(7,834)

(455)

(2,524)

Total recognized in net periodic cost and regulatory assets

4,149

(10,410)

6,280

$ 1,384

$ (4,960)

$ 13,717

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.51%

4.10%

4.88%

6.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Wolf Creek [Member]

4.00%

$ 127

$ 138

$ 173

325

314

464

(14)

165

438

455

802

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

438

455

802

(484)

(211)

(1,881)

(3)

(165)

Total recognized in net periodic cost and regulatory assets

(470)

(214)

(2,046)

$ (32)

$ 241

$ (1,244)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

4.27%

3.89%

4.70%

0.00%

0.00%

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

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Estimated Amounts From Regulatory Assets Into Net Periodic Cost) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Pension Benefits [Member]
Actuarial loss	$ (21,956)
Prior service cost	(683)
Total	22,639
Pension Benefits [Member] \| Wolf Creek [Member]
Actuarial loss	(4,979)
Prior service cost	(55)
Total	5,034
Other Postretirement Benefit Plans, Defined Benefit [Member]
Actuarial loss	780
Prior service cost	(455)
Total	(325)
Other Postretirement Benefit Plans, Defined Benefit [Member] \| Wolf Creek [Member]
Actuarial loss	50
Prior service cost	0
Total	$ (50)

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Assumed Annual Health Care Cost Growth Rates) (Details)	12 Months Ended
	Dec. 31, 2016 Rate	Dec. 31, 2015
Health care cost trend rate assumed for next year	1.00%
Wolf Creek [Member]
Health care cost trend rate assumed for next year	6.50%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2020	2020

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (One Percentage Change In Assumed Health Care Cost Growth Rates Effects) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	1.00%
Wolf Creek [Member]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	6.50%	7.00%
Effect on total of service and interest cost from one-percentage-point increase	$ (7)
Effect on total of service and interest cost from one-percentage-point decrease	7
Effect on post-retirement benefit obligation from one-percentage-point increase	(126)
Effect on post-retirement benefit obligation from one-percentage-point decrease	$ 133

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Fair Value of Plan Assets) (Details) - Wolf Creek [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair value of pension plan assets	$ 138,688	$ 121,622
Level 1
Fair value of pension plan assets	0	0
Level 2
Fair value of pension plan assets	127,576	110,930
Level 3
Fair value of pension plan assets	0	0
Domestic Equity Securities [Member]
Fair value of pension plan assets	34,586	30,503
Domestic Equity Securities [Member] \| Level 1
Fair value of pension plan assets	0	0
Domestic Equity Securities [Member] \| Level 2
Fair value of pension plan assets	34,586	30,503
Domestic Equity Securities [Member] \| Level 3
Fair value of pension plan assets	0	0
International Equity Securities [Member]
Fair value of pension plan assets	43,269	37,682
International Equity Securities [Member] \| Level 1
Fair value of pension plan assets	0	0
International Equity Securities [Member] \| Level 2
Fair value of pension plan assets	43,269	37,682
International Equity Securities [Member] \| Level 3
Fair value of pension plan assets	0	0
Core Bonds [Member]
Fair value of pension plan assets	35,048	30,287
Core Bonds [Member] \| Level 1
Fair value of pension plan assets	0	0
Core Bonds [Member] \| Level 2
Fair value of pension plan assets	35,048	30,287
Core Bonds [Member] \| Level 3
Fair value of pension plan assets	0	0
Real Estate [Member]
Fair value of pension plan assets	6,948	12,557
Real Estate [Member] \| Level 1
Fair value of pension plan assets	0	0
Real Estate [Member] \| Level 2
Fair value of pension plan assets	0	6,123
Real Estate [Member] \| Level 3
Fair value of pension plan assets	0	0
Commodities [Member]
Fair value of pension plan assets		5,811
Commodities [Member] \| Level 1
Fair value of pension plan assets		0
Commodities [Member] \| Level 2
Fair value of pension plan assets		5,811
Commodities [Member] \| Level 3
Fair value of pension plan assets		0
Alternative Investments [Member]
Fair value of pension plan assets	18,237	4,258
Alternative Investments [Member] \| Level 1
Fair value of pension plan assets	0	0
Alternative Investments [Member] \| Level 2
Fair value of pension plan assets	14,073	0
Alternative Investments [Member] \| Level 3
Fair value of pension plan assets	0	0
Cash Equivalents [Member]
Fair value of pension plan assets	600	524
Cash Equivalents [Member] \| Level 1
Fair value of pension plan assets	0	0
Cash Equivalents [Member] \| Level 2
Fair value of pension plan assets	600	524
Cash Equivalents [Member] \| Level 3
Fair value of pension plan assets	0	0
Portion at Other than Fair Value Measurement [Member]
Fair value of pension plan assets	11,112	10,692
Portion at Other than Fair Value Measurement [Member] \| Domestic Equity Securities [Member]
Fair value of pension plan assets	0	0
Portion at Other than Fair Value Measurement [Member] \| International Equity Securities [Member]
Fair value of pension plan assets	0	0
Portion at Other than Fair Value Measurement [Member] \| Core Bonds [Member]
Fair value of pension plan assets	0	0
Portion at Other than Fair Value Measurement [Member] \| Real Estate [Member]
Fair value of pension plan assets	6,948	6,434
Portion at Other than Fair Value Measurement [Member] \| Commodities [Member]
Fair value of pension plan assets		0
Portion at Other than Fair Value Measurement [Member] \| Alternative Investments [Member]
Fair value of pension plan assets	4,164	4,258
Portion at Other than Fair Value Measurement [Member] \| Cash Equivalents [Member]
Fair value of pension plan assets	$ 0	$ 0

Wolf Creek Employee Benefit Plans Wolf Creek Employee Benefit Plans (Expected Cash Flows Related To Pension and Post-Retirement Benefit Plans) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Plan Trust [Member] \| Pension Benefits [Member]
Expected contributions:
2014	$ 25.2
Expected benefit payments:
2014	(55.7)
2015	(58.1)
2016	(60.2)
2017	(62.7)
2018	(64.4)
2019 - 2022	(325.1)
Plan Trust [Member] \| Pension Benefits [Member] \| Wolf Creek [Member]
Expected contributions:
2014	10.8
Expected benefit payments:
2014	(7.2)
2015	(8.1)
2016	(9.0)
2017	(9.8)
2018	(10.7)
2019 - 2022	(66.0)
Plan Trust [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Expected contributions:
2014	0.0
Expected benefit payments:
2014	(7.8)
2015	(7.9)
2016	(8.1)
2017	(8.2)
2018	(8.3)
2019 - 2022	(40.2)
Plan Trust [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member] \| Wolf Creek [Member]
Expected contributions:
2014	0.6
Expected benefit payments:
2014	(2.0)
2015	(2.3)
2016	(2.6)
2017	(2.9)
2018	(3.2)
2019 - 2022	(20.2)
Company Assets [Member] \| Pension Benefits [Member]
Expected benefit payments:
2014	(2.3)
2015	(2.3)
2016	(2.3)
2017	(2.2)
2018	(2.2)
2019 - 2022	(10.8)
Company Assets [Member] \| Pension Benefits [Member] \| Wolf Creek [Member]
Expected benefit payments:
2014	(0.3)
2015	(0.3)
2016	(0.3)
2017	(0.3)
2018	(0.3)
2019 - 2022	(1.3)
Company Assets [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Expected benefit payments:
2014	(0.3)
2015	(0.3)
2016	(0.3)
2017	(0.2)
2018	(0.2)
2019 - 2022	(0.9)
Company Assets [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member] \| Wolf Creek [Member]
Expected benefit payments:
2014	0.0
2015	0.0
2016	0.0
2017	0.0
2018	0.0
2019 - 2022	$ 0.0

Wolf Creek Employee Benefit Plans (Textual) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
401k Savings Plan Matching Contributions	$ 8.0	$ 7.7	$ 7.0
KGE [Member]
Subsidiary's interest, percentage	47.00%
Wolf Creek [Member]
401k Savings Plan Matching Contributions	$ 1.6	$ 1.6	$ 1.4
International Equity Securities [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	31.00%
Domestic Equity Securities [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	25.00%
Debt Securities [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	25.00%
Real Estate [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	10.00%
Commodity [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	5.00%
Other Investments [Member] \| Wolf Creek [Member]
Target Defined Benefit Plan Asset Allocations	4.00%

Commitments And Contingencies (Details) $ in Thousands	1 Months Ended	12 Months Ended
Commitments And Contingencies (Details) $ in Thousands	Jan. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) Y facilities phases MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Commitments And Contingencies [Line Items]
Loss Contingency Accrual, Payments		$ 7,600
Asset Retirement Obligation, Liabilities Incurred		0	$ 34,440
Aggregate Amount of Required Payments [Abstract]
2014		310,711
2015		73,149
2016		25,411
Thereafter		8,100
Total amount committed		$ 417,371
Nuclear Decommissioning [Abstract]
Site study frequency \| Y		3
Number of nuclear decommissioning phases \| phases		2
phase one of nuclear decommissioning plan \| phases		1
phase two of nuclear decommissioning plan \| phases		2
Estimated decommissioning costs		$ 360,000
Previously estimated decommissioning costs		296,200
Decommissioning fund deposits		5,000	2,800	$ 2,800
Total Nuclear Decommissioning Trust		200,122	$ 184,057
Nuclear Liability Insurance - Full Limit of Public Liability		13,400,000
Nuclear Liability Insurance - Maximum Available Commercial Insurance		375,000
Nuclear Liability Insurance - Industry-Wide Retrospective Assessment Program		13,000,000
Nuclear Liability Insurance - Owners' Insurance Amount Maximum		127,300
Nuclear Liability Insurance - Entity Share of Insurance Amount Maximum		59,800
Nuclear Liability Insurance - Owners' Insurance Amount, Per Incident		19,000
Nuclear Liability Insurance - Entity Share of Insurance Amount, Per Incident		8,900
Nuclear Liability Insurance - Owners' Property Insurance, Maximum		2,800,000
Nuclear Liability Insurance, Owners' Non-nuclear Property Insurance, Maximum		2,300,000
nuclear liability insurance - owner's property insurance assessment maximum		37,500
nuclear liability insurance - equity share, property insurance assessment maximum		$ 17,600
Purchase Power Agreements, Wind Generation \| MW		1,328
Number of Wind Generation Facilities \| facilities		9
Net Capacity, in MW \| MW		3,119
Uranium Concentrates [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		$ 16,500
Conversion [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		2,500
Uranium Hexafluoride [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		80,300
Enrichment [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		81,600
Fabrication [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		29,700
Coal and Coal Transportation [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		659,400
Natural Gas Transportation [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment		$ 105,800
Next Year [Member]
Nuclear Decommissioning [Abstract]
Other Commitments [Table Text Block]		140.1
Subsequent Event [Member]
Nuclear Decommissioning [Abstract]
Nuclear Liability Insurance - Maximum Available Commercial Insurance	$ 450,000
Subsequent Event [Member] \| Uranium Concentrates [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment	16,400
Subsequent Event [Member] \| Conversion [Member]
Nuclear Decommissioning [Abstract]
Long-term purchase commitment	$ 1,700
Nuclear Event [Member]
Nuclear Decommissioning [Abstract]
Nuclear Insurance Industry Aggregate Limit		$ 3,200,000
Non-Nuclear Event [Member]
Nuclear Decommissioning [Abstract]
Nuclear Insurance Industry Aggregate Limit		$ 1,800,000

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
KGE ownership share	47.00%
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning ARO	$ 275,285	$ 230,668
Liabilities settled	(5,372)	(1,553)
Accretion expense	14,165	12,964
Revised ARO estimate	39,873	(1,234)
Asset Retirement Obligation, Liabilities Incurred	0	34,440
Ending ARO	323,951	275,285
Regulatory liability - removal costs	239,453	292,811
Removal Costs [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory liability - removal costs	$ 5,663	$ 53,834

Common Stock (Common Stock Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Mar. 28, 2013

Common stock, shares authorized

275,000,000

Forward Sale Agreement, Maximum Amount Authorized

141,791,153

141,353,426

$ 500.0

Forward Sale Agreement, Maximum Shares Authorized

25,000,000

Commissions Paid, Percentage of Sales Price of Shares Sold

1.00%

Forward Contract Indexed To Issuers Equity, Indexed Shares For Period

^[1]

9,160,500

2,892,476

Forward Sale Agreement Entered in September Two Thousand And Thriteen [Member]

Forward Contract Indexed to Issuer's Equity, Shares

8,900,000

Commissions Paid, Percentage of Sales Price of Shares Sold

3.50%

Shares Borrowed Under Forward Contracts, Price Per Share

$ 31.15

Forward Sale Agreement Entered in September Two Thousand And Thriteen [Member] | Over Allotment [Member]

Forward Contract Indexed to Issuer's Equity, Shares

900,000

Base Allotment [Member] | Forward Sale Agreement Entered in September Two Thousand And Thriteen [Member]

Forward Contract Indexed to Issuer's Equity, Shares

8,000,000

Direct Stock Purchase Plan And Other Stock-Based Plans [Member]

400,000

500,000

DSPP [Member]