10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

Kansas	48-0290150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

818 South Kansas Avenue, Topeka, Kansas 66612	(785) 575-6300
(Address, including Zip code and telephone number, including area code, of registrant’s principal executive offices)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes    X       No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes    X      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company (as defined in Rule 12b-2 of the Act).

Large accelerated filer    X     Accelerated filer     Non-accelerated filer      Smaller reporting company   Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes     No    X  

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $5.00 per share	142,233,136 shares
(Class)	(Outstanding at May 1, 2018)

1

TABLE OF CONTENTS

PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Cash Flows	8
	Condensed Consolidated Statements of Changes in Equity	9
	Notes to Condensed Consolidated Financial Statements	10
	1. Description of Business	10
	2. Summary of Significant Accounting Policies	10
	3. Pending Merger	14
	4. Revenue	16
	5. Rate Matters and Regulation	18
	6. Financial Instruments and Investments	19
	7. Taxes	21
	8. Pension and Post-Retirement Benefit Plans	22
	9. Wolf Creek Pension and Post-Retirement Benefit Plans	23
	10. Commitments and Contingencies	24
	11. Legal Proceedings	27
	12. Variable Interest Entity	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
PART II. Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	41
Signature		42

2

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.

Abbreviation or Acronym	Definition
2017 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2017
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
CAA	Clean Air Act
CCR	Coal combustion residual
CO2	Carbon dioxide
COLI	Corporate-owned life insurance
CPP	Clean Power Plan
CURB	Citizens’ Utility Ratepayer Board
CWA	Clean Water Act
DOE	Department of Energy
ELG	Effluent limitations guidelines
EPA	Environmental Protection Agency
Exchange Act	Securities and Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission
FMBs	First mortgage bonds
GHG	Greenhouse gas
Great Plains Energy	Great Plains Energy Incorporated
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health & Environment
KGE	Kansas Gas and Electric Company
La Cygne	La Cygne Generating Station
Merger	Pending merger of equals between Westar Energy, Inc. and Great Plains Energy Incorporated
Moody’s	Moody’s Investors Service
MPSC	Missouri Public Service Commission
NAAQS	National Ambient Air Quality Standards
NAV	Net Asset Value
NDT	Nuclear Decommissioning Trust
NRC	Nuclear Regulatory Commission
NSPS	New Source Performance Standard
PM	Particulate matter
RSU	Restricted share unit
RTO	Regional transmission organization
SO2	Sulfur dioxide
S&P	Standard & Poor’s Ratings Services
SPP	Southwest Power Pool, Inc.
TCJA	Tax Cuts and Jobs Act
TFR	Transmission formula rate
VIE	Variable interest entity
Wolf Creek	Wolf Creek Generating Station
WOTUS	Waters of the United States

3

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Form 10-Q are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:

- the pending merger of equals (merger) between Westar Energy, Inc. and Great Plains Energy Incorporated (Great Plains Energy), including the expected timing of closing the merger and costs expected to be incurred in connection with the merger,

- amount, type and timing of capital expenditures,

- earnings,

- cash flow,

- liquidity and capital resources,

- litigation,

- accounting and tax matters,

- compliance with debt and other restrictive covenants,

- interest rates and dividends,

- environmental matters,

- regulatory matters,

- nuclear operations, and

- the overall economy of our service area and its impact on our customers’ demand for electricity and their ability to pay for service.

What happens in each case could vary materially from what we expect because of such things as:

- risks related to operating in a heavily regulated industry that is subject to unpredictable political, legislative, judicial and regulatory developments, which can impact our operations, results of operations, and financial condition,

- the difficulty of predicting the magnitude and timing of changes in demand for electricity, including with respect to emerging competing services and technologies and conservation and energy efficiency measures,

- the impact of weather conditions, including as it relates to sales of electricity and prices of energy commodities,

- equipment damage from storms and extreme weather,

- economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy,

- the impact of changes in market conditions on employee benefit liability calculations and funding obligations, as well as actual and assumed investment returns on invested plan assets,

- the impact of changes in estimates regarding our Wolf Creek Generating Station (Wolf Creek) decommissioning obligation,

- the existence or introduction of competition into markets in which we operate,

- the impact of changing laws and regulations relating to air and greenhouse gas (GHG) emissions, water emissions, waste management and other environmental matters,

- risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated,

- cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business,

- availability of generating capacity and the performance of our generating plants,

- changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown or required modification of nuclear generating facilities,

- uncertainties with respect to procurement of nuclear fuel and related services, which are dependent on a single supplier,

- additional regulation due to Nuclear Regulatory Commission (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek’s performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,

- uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal,

- homeland security and information and operating systems security considerations,

4

- risks arising from changes in federal and state tax laws, regulations and interpretations, and related actions by regulatory commissions,

- changes in accounting requirements and other accounting matters,

- changes in the energy markets in which we participate, such as the development and implementation of real time and next day trading markets, and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations (RTOs) and independent system operators,

- reduced demand for coal-based energy because of actual or perceived climate impacts and the development of alternate energy sources,

- current and future litigation, regulatory investigations, proceedings or inquiries,

- cost of fuel used in generation and wholesale electricity prices,

- certain risks and uncertainties associated with the merger, including, without limitation, those related to:

- the timing of, and the conditions imposed by, regulatory approvals required for the merger,

- the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement or could otherwise cause the failure of the merger to close,

- the outcome of any legal proceedings, regulatory proceedings or enforcement matters that have been or may be instituted in connection with the merger,

- the receipt of an unsolicited offer from another party to acquire our assets or capital stock (or those of Great Plains Energy) that could interfere with the proposed merger,

- the timing to consummate the proposed merger,

- disruption from the proposed merger making it more difficult to maintain relationships with customers, employees, regulators or suppliers,

- the diversion of management time and attention on the merger,

- the amount of costs, fees, expenses and charges related to the merger,

- the possibility that the expected value creation from the merger will not be realized, or will not be realized within the expected time period,

- difficulties related to the integration of the two companies,

- the credit ratings of the combined company following the merger, and

- the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations) that could adversely affect our participation in the merger, and

- other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2017 (2017 Form 10-K), including in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other reports we file from time to time with the SEC.

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our 2017 Form 10-K and the other reports we file from time to time with the SEC. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our condensed consolidated financial results may be included in our 2017 Form 10-K and the other reports we file from time to time with the SEC. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

5

PART I. FINANCIAL INFORMATION

ITEM I.    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

	As of			As of
	March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,166		$	3,432
Accounts receivable, net of allowance for doubtful accounts of $9,288 and $6,716, respectively	244,411			290,652
Fuel inventory and supplies	286,831			293,562
Prepaid expenses	20,566			16,425
Regulatory assets	95,580			99,544
Other	24,694			23,435
Total Current Assets	683,248			727,050
PROPERTY, PLANT AND EQUIPMENT, NET	9,589,164			9,553,755
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITY, NET	174,500			176,279
OTHER ASSETS:
Regulatory assets	681,036			685,355
Nuclear decommissioning trust	241,153			237,102
Other	251,268			244,827
Total Other Assets	1,173,457			1,167,284
TOTAL ASSETS	$	11,620,369		$	11,624,368
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entity	$	30,337		$	28,534
Short-term debt	289,800			275,700
Accounts payable	139,308			204,186
Accrued dividends	53,888			53,830
Accrued taxes	132,593			87,727
Accrued interest	91,741			72,693
Regulatory liabilities	11,220			11,602
Other	81,462			89,445
Total Current Liabilities	830,349			823,717
LONG-TERM LIABILITIES:
Long-term debt, net	3,688,257			3,687,555
Long-term debt of variable interest entity, net	51,096			81,433
Deferred income taxes	824,699			815,743
Unamortized investment tax credits	256,406			257,093
Regulatory liabilities	1,110,055			1,093,974
Accrued employee benefits	533,318			541,364
Asset retirement obligations	382,791			379,989
Other	78,952			83,063
Total Long-Term Liabilities	6,925,574			6,940,214
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 142,233,103 shares and 142,094,275 shares, respective to each date	711,166			710,471
Paid-in capital	2,022,451			2,024,396
Retained earnings	1,176,095			1,173,255
Total Westar Energy, Inc. Shareholders’ Equity	3,909,712			3,908,122
Noncontrolling Interests	(45,266		)	(47,685		)
Total Equity	3,864,446			3,860,437
TOTAL LIABILITIES AND EQUITY	$	11,620,369		$	11,624,368

The accompanying notes are an integral part of these condensed consolidated financial statements.

6

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended March 31,
	2018			2017
REVENUES	$	600,204		$	572,574
OPERATING EXPENSES:
Fuel and purchased power	135,507			113,855
SPP network transmission costs	67,594			60,674
Operating, maintenance and administrative	139,993			135,319
Depreciation and amortization	89,641			88,625
Taxes other than income tax	43,939			42,716
Total Operating Expenses	476,674			441,189
INCOME FROM OPERATIONS	123,530			131,385
OTHER INCOME (EXPENSE):
Investment earnings	999			3,155
Other income	1,951			1,300
Other expense	(10,561		)	(10,352		)
Total Other Expense	(7,611		)	(5,897		)
Interest expense	43,841			41,095
INCOME BEFORE INCOME TAXES	72,078			84,393
Income tax expense	9,174			20,911
NET INCOME	62,904			63,482
Less: Net income attributable to noncontrolling interests	2,419			3,821
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	60,485		$	59,661
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic and diluted earnings per common share	$	0.42		$	0.42
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,635,490			142,436,622
Diluted	142,651,580			142,695,606
DIVIDENDS DECLARED PER COMMON SHARE	$	0.40		$	0.40

The accompanying notes are an integral part of these condensed consolidated financial statements.

7

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2018			2017
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	62,904		$	63,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	89,641			88,625
Amortization of nuclear fuel	7,716			8,069
Amortization of deferred regulatory gain from sale leaseback	(1,374		)	(1,374		)
Amortization of corporate-owned life insurance	5,501			5,901
Non-cash compensation	2,507			2,468
Net deferred income taxes and credits	3,803			19,011
Allowance for equity funds used during construction	(1,097		)	(775		)
Payments for asset retirement obligations	(1,943		)	(961		)
Income from corporate-owned life insurance	(671		)	(1,311		)
Changes in working capital items:
Accounts receivable	46,241			51,547
Fuel inventory and supplies	6,885			(10,581		)
Prepaid expenses and other current assets	3,886			28,311
Accounts payable	(24,219		)	(23,135		)
Accrued taxes	48,674			47,775
Other current liabilities	(11,833		)	(54,223		)
Changes in other assets	(724		)	3,290
Changes in other liabilities	23,731			10,606
Cash Flows from Operating Activities	259,628			236,725
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(174,765		)	(175,400		)
Purchase of securities - trusts	(85,429		)	(4,191		)
Sale of securities - trusts	86,060			5,720
Investment in corporate-owned life insurance	(998		)	(913		)
Proceeds from investment in corporate-owned life insurance	2,559			1,414
Other investing activities	(1,608		)	(2,354		)
Cash Flows used in Investing Activities	(174,181		)	(175,724		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	14,100			(140,407		)
Proceeds from long-term debt	—			296,475
Retirements of long-term debt	—			(125,000		)
Retirements of long-term debt of variable interest entity	(28,534		)	(26,840		)
Repayment of capital leases	(950		)	(800		)
Borrowings against cash surrender value of corporate-owned life insurance	721			910
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(1,735		)	—
Issuance of common stock	—			470
Distributions to shareholders of noncontrolling interests	—			(5,760		)
Cash dividends paid	(57,438		)	(52,750		)
Other financing activities	(3,877		)	(7,006		)
Cash Flows used in Financing Activities	(77,713		)	(60,708		)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	7,734			293
CASH, CASH EQUIVALENTS AND RESTRICTED CASH:
Beginning of period, including restricted cash of $88 and $90, respectively	3,520			3,156
End of period, including restricted cash of $88 and $90, respectively	$	11,254		$	3,449

The accompanying notes are an integral part of these condensed consolidated financial statements.

8

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Westar Energy, Inc. Shareholders
		Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2016		141,791,153	$	708,956	$	2,018,317		$	1,078,602		$	27,315		$	3,833,190
Net income		—	—		—			59,661			3,821			63,482
Issuance of stock		8,646	43		427			—			—			470
Issuance of stock for compensation and reinvested dividends		247,834	1,239		1,110			—			—			2,349
Tax withholding related to stock compensation		—	—		(7,006		)	—			—			(7,006		)
Dividends declared on common stock ($0.40 per share)		—	—		—			(57,995		)	—			(57,995		)
Stock compensation expense		—	—		2,439			—			—			2,439
Distributions to shareholders of noncontrolling interests		—	—		—			—			(5,760		)	(5,760		)
Balance as of March 31, 2017		142,047,633	$	710,238	$	2,015,287		$	1,080,268		$	25,376		$	3,831,169
Balance as of December 31, 2017		142,094,275	$	710,471	$	2,024,396		$	1,173,255		$	(47,685	)	$	3,860,437
Net income		—	—		—			60,485			2,419			62,904
Issuance of stock for compensation and reinvested dividends		138,828	695		(546		)	—			—			149
Tax withholding related to stock compensation		—	—		(3,877		)	—			—			(3,877		)
Dividends declared on common stock ($0.40 per share)		—	—		—			(57,645		)	—			(57,645		)
Stock compensation expense		—	—		2,478			—			—			2,478
Balance as of March 31, 2018		142,233,103	$	711,166	$	2,022,451		$	1,176,095		$	(45,266	)	$	3,864,446

The accompanying notes are an integral part of these condensed consolidated financial statements.

9

WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 710,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2017 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months endedMarch 31, 2018, are not necessarily indicative of the results to be expected for the full year.

10

Fuel Inventory and Supplies

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Fuel inventory	$	89,125	$	94,039
Supplies	197,706		199,523
Fuel inventory and supplies	$	286,831	$	293,562

Allowance for Funds Used During Construction

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

	Three Months Ended March 31,
	2018			2017
	(Dollars In Thousands)
Borrowed funds	$	1,403		$	1,853
Equity funds	1,097			775
Total	$	2,500		$	2,628
Average AFUDC Rates	3.6		%	2.2		%

Earnings Per Share

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

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

11

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

	Three Months Ended March 31,
	2018		2017
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	62,904	$	63,482
Less: Net income attributable to noncontrolling interests	2,419		3,821
Net income attributable to Westar Energy, Inc.	60,485		59,661
Less: Net income allocated to RSUs	104		108
Net income allocated to common stock	$	60,381	$	59,553
Weighted average equivalent common shares outstanding – basic	142,635,490		142,436,622
Effect of dilutive securities:
RSUs	16,090		258,984
Weighted average equivalent common shares outstanding – diluted (a)	142,651,580		142,695,606
Earnings per common share, basic	$	0.42	$	0.42
Earnings per common share, diluted	$	0.42	$	0.42

_______________

(a)We had no antidilutive securities for the three months endedMarch 31, 2018 and 2017.

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	33,043		$	35,644
Interest on financing activities of VIEs	1,319			1,696
Income taxes, net of refunds	(231		)	(13,000		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	29,790			97,196
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	149			2,349
Assets acquired through capital leases	48			293

Revenue Recognition

Revenue is recognized primarily at the time we deliver electricity or provide transmission service to customers. The time of delivery of electricity is generally when our obligation to provide service is satisfied. Sales tax and franchise fees that we collect concurrent with revenue-producing activities are excluded from revenue. For more information on revenue recognition, see Note 4, “Revenue.”

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We determine the amount of electricity delivered to 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 energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $68.2 million and $76.7 million as of March 31, 2018, and December 31, 2017, respectively.

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. For the three months ended March 31, 2018 and 2017, we recorded bad debt expense related to contracts with customers of $4.0 million and $3.2 million, respectively.

New Accounting Pronouncements

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

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is applied on a retrospective basis. The guidance permits and we elected upon adoption to use a practical expedient that allows us to use the amounts disclosed in Note 8, “Pension and Post-Retirement Benefit Plans,” for applying the retrospective presentation of the 2017 condensed consolidated statement of income. As a result, we retrospectively decreased operating, maintenance, and administrative expense by $5.0 million and increased other expense by $5.0 million for the three months endedMarch 31, 2017. The new standard is effective for annual periods beginning after December 15, 2017. We adopted the guidance for the Westar Energy pension and post-retirement benefit plans as of January 1, 2018, without a material impact on our condensed consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued 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 corporate-owned life insurance (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. Retrospective application is required. We adopted the guidance effective January 1, 2018, which resulted in retrospective reclassification of cash proceeds of $1.3 million from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities for the three months endedMarch 31, 2017. In addition, cash payments of $0.9 millionfor premiums on COLI policies were reclassified from cash outflows used in operating activities to cash outflows used in investing activities for the same period.

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In November 2016, the FASB issued ASU No. 2016-18, which requires that statement of cash flows explain the change for the period of restricted cash and restricted cash equivalents along with cash and cash equivalents. The guidance requires a retrospective transition method and is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018. As a result, we adjusted amounts previously reported for cash and cash equivalents to include restricted cash which resulted in an increase to beginning and ending cash, cash equivalents and restricted cash of $0.1 million for the three months endedMarch 31, 2017.

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 power purchase agreements, and will analyze the related impact. The standard permits an entity to elect a practical expedient for existing or expired contracts to forgo reassessing leases to determine whether each is in scope of the new standard and to forgo reassessing lease classification. We expect to elect this practical expedient upon implementation.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, which generally requires equity investments to be measured at fair value with changes in fair value recognized in net income. Under the new standard, equity securities are no longer to be classified as available-for-sale or trading securities. The guidance requires a modified retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018, without a material impact on our condensed consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018. The standard permits the use of either the retrospective application or modified retrospective method. We elected to use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Adoption of the standard did not have a material impact to our condensed consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard. For more information on revenue recognition, see Note 4, “Revenue.”

3. PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy that provided for the acquisition of us by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) rejected the prior transaction.

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On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into one share of common stock of a new holding company with a final name yet to be publicly announced. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately47.5% of the new holding company.

The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement limits our quarterly dividends declared to $0.40 per share.

The closing of the merger is subject to conditions including receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar Energy and its subsidiaries, taken as a whole); effectiveness of the registration statement for the shares of the new holding company’s common stock to be issued to our shareholders and Great Plains Energy’s shareholders upon consummation of the merger and approval of the listing of such shares on the New York Stock Exchange; the receipt of tax opinions by us and Great Plains Energy that the merger will be treated as a non-taxable event for U.S. federal income tax purposes; there being no shares of Great Plains Energy preference stock outstanding; and Great Plains Energy having not less than $1.25 billion in cash or cash equivalents on its balance sheet. The closing of the merger is also subject to other standard conditions, such as accuracy of representations and warranties, compliance with covenants and the absence of a material adverse effect on either company.

The merger agreement, which contains customary representations, warranties, and covenants, may be terminated by either party if the merger has not occurred by July 10, 2018. The termination date may be extended six months in order to obtain regulatory approvals.

On August 25, 2017, we and Great Plains Energy filed a joint application with the KCC requesting approval of the merger. The KCC subsequently approved a procedural schedule that provides for a KCC order on the proposed merger by June 5, 2018, although under Kansas law the KCC has until June 21, 2018, to issue the order. On March 7, 2018, we, Great Plains Energy, the KCC staff, the Citizens’ Utility Ratepayer Board (CURB), and certain other intervenors entered into a non-unanimous settlement agreement to settle issues related to the joint application. The settlement agreement is subject to review and approval by the KCC. Components of the settlement agreement are summarized below. The settlement agreement, if approved, is expected to impact our 2018 rate review.

• $23.0 million of bill credits in 2018 to our retail customers, which will reduce 2018 revenues by a corresponding amount

• An additional $8.6 million of annual bill credits to our retail customers between 2019 and 2022

• Reduction of our annual revenues by $22.5 million for estimated merger-related savings to be reflected in our 2018 rate review

• An annual earnings review and sharing program that will allow for sharing of earnings with customers if actual earnings are above a certain level, after recovery of the annual bill credits

• A return on equity recommendation of 9.3% in our 2018 rate review

• Limitation on debt capitalization (excluding short-term debt and debt due within one year) of 65% at the consolidated holding company and 60% at the utility operating companies

• A five-year prohibition against changing base rates, which could be reduced to three years if the ROE ordered by the KCC in the 2018 rate review is set lower than 9.3%

• The recovery of $23.2 million of transition costs to be included in our prices over a 10-year period

• We will forgo the ability to offset tax reform benefits with demonstrated under-earnings

• An annual quality of service performance reporting requirement

The settlement agreement also contains items that, if approved, are expected to impact the 2018 rate review for Kansas City Power & Light Company, a utility subsidiary of Great Plains Energy that operates in Kansas and Missouri.

On August 31, 2017, we and Great Plains Energy applied for approval of the merger from the MPSC. On January 12, 2018, we, Great Plains Energy, the MPSC staff and certain other intervenors entered into a non-unanimous stipulation and agreement to settle issues related to the joint application. On March 8, 2018, the stipulation and agreement with MPSC staff was amended to include additional intervenors. The stipulation and agreement is subject to review and approval by the MPSC.

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We and Great Plains Energy each gained shareholder approval of the proposed merger on November 21, 2017. We and Great Plains Energy received early termination of the statutory waiting period under the Hart-Scott-Rodino Antitrust Improvements Act on December 12, 2017. We and Great Plains Energy received FERC approval of the merger on February 28, 2018. On March 12, 2018, Wolf Creek received approval from the NRC for an indirect transfer of control of Wolf Creek’s operating license. On March 19, 2018, we and Great Plains Energy received Federal Communications Commission consent for various license transfers that are deemed to occur with the merger.

The amended and restated merger agreement provides that Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated due to (i) failure to receive regulatory approval prior to July 10, 2018, subject to an extension of up to six months, (ii) a non-appealable regulatory order enjoining the merger or (iii) Great Plains Energy’s failure to close after all conditions precedent to closing have been satisfied. In addition, we may be required to pay Great Plains Energy a termination fee of $190.0 million if the agreement is terminated by us under certain circumstances. Similarly, Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated by Great Plains Energy under certain circumstances.

In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our operating, maintenance and administrative expenses. During the three months endedMarch 31, 2018 and 2017, we incurred approximately $0.4 million of merger-related expenses. In the event that the merger is consummated, we estimate merger-related expenses for investment banking, legal, and other professional services will be approximately $45.0 million. In addition, we expect to incur an estimated $40.0 million of expenses for accelerated stock-based compensation, voluntary severance plan payments and payments pursuant to change in control agreements.

See also Note 11, “Legal Proceedings,” for more information on litigation related to the merger.

4. REVENUE

Kansas law gives the KCC general regulatory authority over our retail prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale electricity sales, including prices and the transmission of electric power. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs, including the cost of invested capital. For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of formulas that track changes in our costs, which reduces the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 5, “Rate Matters and Regulation,” for information regarding our rate proceedings with the KCC and FERC and potential related refund obligations.

We categorize revenue based on class of customer as discussed below.

Retail Revenue

We are the sole supplier of retail electricity within our service territory. We operate facilities necessary to generate, transmit and distribute electricity to our customers. We are required to provide electricity to customers in our service territory as requested by customers. Revenue is recognized over time as we satisfy our obligation, generally corresponding to the amount of electricity that we deliver to our customers.This method of recognizing revenue corresponds directly to the amount that we have the right to invoice our customers each month.

Retail revenue is impacted by things such as weather, rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand.

We further classify retail customers as residential, commercial, industrial and other customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways.

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Wholesale Revenue

We sell electricity and capacity (the ability to demand delivery of a maximum amount of electricity) at wholesale to electric cooperatives, municipalities, other electric utilities and RTOs,the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. We recognize revenue as we deliver the electricity and capacity that corresponds directly to the amount of consideration we expect to invoice. Revenues from these sales reduce retail electricity prices either annually through a formula or when base rates are determined at the time of a general rate review. Our wholesale revenues are impacted by, among other factors, demand, costs and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather. Our long-term contracts for wholesale capacity include variable transaction prices mostly based on peak demand for electricity and capacity of certain generating units. Terms on our long-term contracts for wholesale capacity expire between 2019 and 2039.

Transmission Revenue

We provide transmission service to the Southwest Power Pool, Inc. (SPP) by allowing it access to our transmission network. As new transmission lines are constructed, they are included in the transmission network available to the SPP. In exchange for providing access, the SPP pays us consideration determined by a formula rate approved by FERC, which includes the cost to construct and maintain the transmission lines and a return on our investment. The price for access to our transmission network is updated annually based on projected costs. Projections are updated to actual costs and the difference is included in subsequent year’s prices. We recognize revenue over time as we provide transmission service and as we have the right to invoice the SPP.

Other Revenue from Contracts with Customers

Other revenue derived from contracts with customers includes fees we earn for services provided to third parties and revenues earned by permitting other utilities to attach equipment to our utility poles. We recognize revenue when obligations under the terms of a contract with a customer are satisfied.

The following table categorizes our revenue by class of customer.

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
REVENUES:
Residential	$	180,285		$	169,290
Commercial	155,403			149,552
Industrial	93,460			94,589
Other retail	4,253			5,042
Total Retail Revenues	433,401			418,473
Wholesale	94,209			83,925
Transmission	71,926			70,729
Other	1,781			1,611
Total Revenue from Contracts with Customers	601,317			574,738
Other	(1,113		)	(2,164		)
Total Revenues	$	600,204		$	572,574

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5. RATE MATTERS AND REGULATION

KCC Proceedings

In March 2018, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2018 and are expected to increase our annual retail revenues by approximately $31.5 million.

In February 2018, we filed a rate application with the KCC to update our prices to include, among other things, costs associated with the completion of Western Plains Wind Farm, expiration of wholesale contracts currently reflected in retail prices as offsets to our retail cost of service, expiration of the 10-year period for production tax credits from our initial wind investments and an updated depreciation study. This rate application also includes savings due to the recently passed federal Tax Cuts and Jobs Act (TCJA), savings achieved from refinancing debt and a portion of the savings from the proposed merger with Great Plains Energy. If our rate application were to be approved, we estimate the new prices would decrease our annual revenues by approximately $2.0 million in September 2018, followed by an increase in our annual revenues of approximately $54.0 million in February 2019. However, we, Great Plains Energy, the KCC staff, CURB and certain other intervenors entered into a non-unanimous settlement agreement related to our merger application, which includes commitments from certain parties to the settlement agreement to accept specific merger-contingent conditions or take particular positions in our rate review. See Note 3, “Pending Merger,” for additional information. If our rate application is approved with the merger-contingent conditions related to a 9.3% ROE and the limited amount of merger-related savings and transition costs included in our prices, then we estimate the new prices would decrease our annual revenues by approximately $37.0 million in September 2018, as compared to the approximately $2.0 million reduction originally requested. This reduction would be followed by an increase in our annual revenues of approximately $54.0 million in February 2019, as previously stated above. Our revenues would be further reduced due to the payment of bill credits in 2018 through 2022 as discussed in Note 3, “Pending Merger.”

In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities. The KCC stated the passage of the TCJA has the potential to significantly reduce the cost of service for utilities, and it may impact the regulatory assets and liabilities of Kansas utilities. Therefore, beginning in January 2018, the KCC directed each regulated electric public utility that is taxable at the corporate level to accrue monthly, in a deferred revenue account, the portion of its revenue representing the difference between: (1) the cost of service as approved by the KCC in its most recent rate review; and (2) the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the corporate tax rate approved in the TCJA. The KCC also gave notice to taxable utilities operating in Kansas that the portion of their regulated revenue stream that reflects higher corporate tax rates should be considered interim and subject to refund, with interest. When the KCC’s evaluation of the impact of the TCJA is complete, if it is determined that a retail price decrease is proper and would have been proper as of the effective date of the TCJA, these amounts will be returned to customers. We believe it is probable that we will be required to return these amounts to customers. Therefore, we have recorded a $15.1 million regulatory liability as of March 31, 2018, and a corresponding decrease in revenues for the three months ended March 31, 2018.

In December 2017, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2018 and are expected to decrease our annual retail revenues by approximately$0.2 million.

FERC Proceedings

Our TFR that includes projected 2018 transmission capital expenditures and operating costs was effective in January 2018 and was expected to increase our annual transmission revenues by approximately $25.5 million. However, due to the passage of the TCJA, we requested permission from FERC to retroactively reflect the reduction in the federal corporate income tax rate in our 2018 prices. In April 2018, FERC granted our request and accordingly, we have recorded a $3.9 million regulatory liability as of March 31, 2018. This updated rate will provide the basis for a new request with the KCC to retroactively adjust our retail prices to include updated transmission costs as discussed above. We estimate the revised TFR will increase 2018 revenues by $2.3 million when compared to 2017.

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6. FINANCIAL INSTRUMENTS AND INVESTMENTS

Values of Financial Instruments

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

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

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

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

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

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

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

	As of March 31, 2018				As of December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,759,785	$	3,605,000	$	3,888,620
Fixed-rate debt of VIEs	81,433		80,557		109,967		110,756

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Recurring Fair Value Measurements

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

As of March 31, 2018	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,449	$	—	$	5,323	$	73,772
International equity funds	—		45,130		—		—		45,130
Core bond fund	—		37,492		—		—		37,492
High-yield bond fund	—		19,713		—		—		19,713
Emerging markets bond fund	—		17,337		—		—		17,337
Combination debt/equity/other fund	—		13,973		—		—		13,973
Alternative investments fund	—		—		—		22,521		22,521
Real estate securities fund	—		—		—		11,024		11,024
Cash equivalents	191		—		—		—		191
Total Nuclear Decommissioning Trust	191		202,094		—		38,868		241,153
Rabbi Trust:
Core bond fund	—		25,670		—		—		25,670
Combination debt/equity/other fund	—		6,418		—		—		6,418
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		32,088		—		—		32,244
Total Assets Measured at Fair Value	$	347	$	234,182	$	—	$	38,868	$	273,397
As of December 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,658	$	—	$	5,142	$	73,800
International equity funds	—		47,908		—		—		47,908
Core bond fund	—		33,250		—		—		33,250
High-yield bond fund	—		18,089		—		—		18,089
Emerging markets bond fund	—		17,345		—		—		17,345
Combination debt/equity/other fund	—		14,125		—		—		14,125
Alternative investments fund	—		—		—		21,669		21,669
Real estate securities fund	—		—		—		10,806		10,806
Cash equivalents	110		—		—		—		110
Total Nuclear Decommissioning Trust	110		199,375		—		37,617		237,102
Rabbi Trust:
Core bond fund	—		27,324		—		—		27,324
Combination debt/equity/other fund	—		6,831		—		—		6,831
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		34,155		—		—		34,311
Total Assets Measured at Fair Value	$	266	$	233,530	$	—	$	37,617	$	271,413

We hold equity and debt investments that we classify as securities in a trust for the purpose of funding the decommissioning of Wolf Creek and maintain a Rabbi trust to manage funds for the benefit of certain retired executive officers. We record net realized and unrealized gains and losses on the Nuclear Decommissioning Trust (NDT) in regulatory liabilities on our condensed consolidated balance sheets. We include net realized and unrealized gains or losses on the Rabbi trust in investment earnings on our condensed consolidated statements of income. For the three months endedMarch 31, 2018 and 2017, we recorded net unrealized losses of $0.1 million and net unrealized gains of $9.0 million, respectively, on the NDT assets still held as of March 31, 2018 and net unrealized losses of $0.4 million and net unrealized gains of $1.4 million, respectively, on the Rabbi trust assets still held as of March 31, 2018

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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 March 31, 2018				As of December 31, 2017				As of March 31, 2018
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,323	$	2,508	$	5,142	$	2,808	(a)	(a)
Alternative investments fund (b)	22,521		—		21,669		—		Quarterly	65 days
Real estate securities fund (b)	11,024		—		10,806		—		Quarterly	65 days
Total	$	38,868	$	2,508	$	37,617	$	2,808

_______________

(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. Three funds have begun to make distributions. Our initial investment in the fourth fund occurred in 2016.This fund’s term is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b) There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

7. TAXES

We recorded income tax expense of $9.2 million with an effective income tax rate of 13% for the three months endedMarch 31, 2018, and income tax expense of $20.9 million with an effective income tax rate of 25% for the same period of 2017. The decrease in the effective income tax rate for the three months endedMarch 31, 2018, was due primarily to the TCJA, which was signed into law in December 2017 and decreased the federal corporate income tax rate from 35% to 21%.

As of March 31, 2018, and December 31, 2017, our unrecognized income tax benefits totaled $1.7 million. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of March 31, 2018, and December 31, 2017, we had no amounts and $0.1 million, respectively, accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either March 31, 2018, or December 31, 2017.

As of March 31, 2018, and December 31, 2017, we had recorded $0.5 million and $0.4 million, respectively, for probable assessments of taxes other than income taxes.

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8. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,826		$	5,218		$	279		$	271
Interest cost (a)	10,207			10,621			1,183			1,314
Expected return on plan assets (a)	(11,091		)	(10,760		)	(1,728		)	(1,718		)
Amortization of unrecognized:
Prior service costs (a)	166			171			114			114
Actuarial loss (gain), net (a)	6,485			5,489			(135		)	(195		)
Net periodic cost (benefit) before regulatory adjustment	11,593			10,739			(287		)	(214		)
Regulatory adjustment (b)	2,849			3,288			(434		)	(478		)
Net periodic cost (benefit)	$	14,442		$	14,027		$	(721	)	$	(692	)

 _______________

(a) The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

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

During the three months endedMarch 31, 2018 and 2017, we contributed $12.5 million and $7.0 million, respectively, to the Westar Energy pension trust.

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9. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,220		$	1,950		$	36		$	37
Interest cost	2,478			2,475			61			70
Expected return on plan assets	(2,891		)	(2,643		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,656			1,245			(14		)	(13		)
Net periodic cost before regulatory adjustment	3,477			3,041			83			94
Regulatory adjustment (a)	(49		)	247			—			—
Net periodic cost	$	3,428		$	3,288		$	83		$	94

 _______________

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

During the three months endedMarch 31, 2018 and 2017, we did not fund Wolf Creek’s pension plan.

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10. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.

Cross-State Air Pollution Update Rule

In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxides 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 revised the existing ozone season allowance budgets for Missouri and Oklahoma and established an ozone season budget for Kansas. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit but the rule remains in effect. We do not believe this rule will have a material impact on our operations and condensed consolidated financial results.

National Ambient Air Quality Standards

Under the CAA, the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, nitrogen dioxide (NO₂) (a precursor to ozone), carbon monoxide and sulfur dioxide (SO₂), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment (KDHE) recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as attainment/unclassifiable. In November 2017, the EPA designated all counties in the State of Kansas as attainment/unclassifiable. We do not believe this will have a material impact on our condensed 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 attainment/unclassifiable with the standard. We do not believe this will have a material impact on our operations or condensed consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants.  Tecumseh Energy Center is our only generating station that meets these criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule that governs the next round of the designations. Also in January 2017, KDHE recommended the EPA change the designation of the area surrounding the facility from unclassifiable to attainment/unclassifiable. In August 2017, the EPA indicated they would address this area redesignation request in a separate action. By agreeing to the 2,000 ton per year limitation, no further characterization of the area surrounding the plant is required.

We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and condensed consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and condensed consolidated financial results.

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Greenhouse Gases

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

In October 2015, the EPA published a rule establishing new source performance standards (NSPS) for GHGs that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. Legal challenges to the GHG NSPS have been filed in the D.C. Circuit by various states and industry members. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including us, in the D.C. Circuit. The CPP was stayed by the Supreme Court in February 2016 and, accordingly, is not currently being implemented by the states.

In April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details. Also in April 2017, the EPA published a notice in the Federal Register that it was initiating administrative reviews of the CPP and the GHG NSPS.

In October 2017, the EPA issued a proposed rule to repeal the CPP. The proposed rule indicates the CPP exceeds EPA’s authority and the EPA has not determined whether they will issue a replacement rule. The EPA is soliciting comments on the legal interpretations contained in this rulemaking. Comments were due in April 2018.

In December 2017, the EPA issued an advance notice of proposed rulemaking. This proposed rulemaking was issued by the EPA because it is considering the possibility of changing certain aspects of the CPP and the EPA is soliciting feedback on specific areas that could be changed. Comments on these proposed areas of change were due to the EPA in February 2018.

Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes effluent limitations guidelines (ELG) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending the EPA’s review. In September 2017, the EPA finalized a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for bottom ash transport water and flue gas desulfurization wastewater. These compliance dates have been postponed for two years while the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers or cooling lakes that can be classified as closed cycle cooling. We do not expect the impact from this rule to be material.

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In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States (WOTUS) for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states and others have filed lawsuits challenging the WOTUS rule. In February 2018, the EPA and the U.S. Corps of Engineers finalized a rule adding an applicability date to the 2015 rule, which makes the implementation date of the rule February 2020. In July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. Final action on the proposed rule is expected in 2018. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results.

Regulation of Coal Combustion Residuals

In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017 and 2018. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. Electric generation industry participants requested and the EPA has granted a request to reconsider portions of the final CCR regulation. In March 2018, the EPA proposed the Phase I CCR Remand Rule in order to modify portions of the 2015 rulemaking. This rule, should it become final, could introduce additional flexibility in CCR compliance. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or condensed consolidated financial results could be material.

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 has elected to build a dry cask storage facility to expand its existing on-site spent nuclear fuel storage, which is expected to provide additional capacity prior to 2025. Wolf Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE begun accepting spent nuclear fuel. As a co-owner of Wolf Creek, in 2017 we received $0.8 million of the settlement representing reimbursement of costs incurred through 2015 for project planning, and in March 2018 we received $0.5 million for costs incurred between January 2016 and June 2017. We expect the majority of the remaining cost to construct the dry cask storage facility that would not have otherwise been incurred will be reimbursed by the DOE. 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.

TCJA Refund Liability

In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities and directed Kansas utilities to record a liability for the difference between the cost of service as approved in its most recent rate review and the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the rate approved in the TCJA. We believe it is probable that we will be required to return these amounts to customers. We also believe it is probable that we will be required to return amounts to our transmission customers. See Note 5, “Rate Matters and Regulation,” for additional information.

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11. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our condensed consolidated financial results. See Notes 5 and 10, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.

Pending Merger

Following the announcement of the original merger agreement in May 2016, two putative class action petitions (which were consolidated and superseded by a consolidated class action petition) and one putative derivative petition challenging the original merger were filed in the District Court of Shawnee County, Kansas. In September 2016, the plaintiffs in both actions agreed in principle to dismiss the actions in exchange for our agreement to make supplemental disclosures to shareholders in connection with the original merger agreement and grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in a sale process that was conducted as part of the original merger agreement. As described below, after the announcement of the revised merger agreement, the plaintiffs in the consolidated putative class action moved to amend their petition, and the plaintiff in the putative derivative case refiled his petition.

The consolidated putative class action petition, originally filed July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This petition named as defendants Westar Energy, the members of our board of directors and Great Plains Energy.

On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an amended petition. The petition as amended now includes an additional plaintiff. The petition challenges the revised proposed merger and alleges a claim of breach of fiduciary duty against our board of directors and a claim of aiding and abetting that alleged breach against us and Great Plains Energy. The lawsuit seeks injunctive relief declaring the action maintainable as a class action and certifying that the plaintiffs are the class representatives; preliminarily and permanently enjoining the defendants from closing the merger unless we implement a procedure to obtain a merger agreement providing fair and reasonable terms and consideration to the plaintiffs and the class; rescinding the merger agreement or granting the plaintiffs and the class rescissory damages; directing our board of directors to account to the plaintiffs and the class for damages suffered as a result of the alleged breach of fiduciary duty; awarding the plaintiffs reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The petition alleges inadequacies in our joint proxy statement concerning the revised proposed transaction and the degree to which our board of directors solicited or considered offers from prior bidders after the proposed original merger was denied by the KCC, and claims that the consideration our stockholders stand to receive in connection with the revised proposed transaction is unfair. Plaintiffs have added two new defendants, Monarch Energy Holding, Inc. and King Energy, Inc., whom they allege aided and abetted our board of directors in breaching their fiduciary duties.

On October 18, 2017, the putative derivative petition, captioned Braunstein v. Chandler et al., Case No. 2017-CV-000692, was re-filed in the District Court of Shawnee County, Kansas. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy, and subsidiaries of Great Plains Energy, with Westar Energy named as a nominal defendant. The petition asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with actions taken after the KCC rejected the proposed original merger. It also asserts that Great Plains Energy and subsidiaries of Great Plains Energy aided and abetted such breaches of fiduciary duties. The petition alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that members of our board of directors committed waste by not collecting termination fees that may have been payable following the KCC’s rejection of the original merger agreement. The petition seeks, among other remedies, an order enjoining the merger on the terms proposed and directing that the director defendants exercise their fiduciary duties to obtain a transaction, which is in the best interests of us and our shareholders, a declaration that the proposed merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement if consummated, the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and an award for costs, including attorneys’ fees and experts’ fees.

In addition, on September 21, 2017, a putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned David Pill v. Westar Energy, Inc. et al, Civil Action No. 17-4086. The federal class action complaint challenges the merger and alleges violations of sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as

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amended (Exchange Act). The complaint seeks an order declaring that the action is maintainable as a class action and certifying that the plaintiff is the class representative; preliminarily and permanently enjoining defendants from consummating the mergers or, if consummated, setting them aside and awarding rescissory damages; directing the defendants to file a registration statement on Form S-4 that corrects alleged misstatements; directing our board of directors to account to plaintiff and the class for their damages; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other further relief as the court deems proper.

On October 6, 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned Robert L. Reese v. Westar Energy, Inc. et al, Civil Action No. 2:17-cv-02584. This federal class action complaint challenges the proposed merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act. The complaint seeks an order enjoining the board and other parties from proceeding with, consummating, or closing the merger or, if consummated, setting it aside and awarding rescissory damages; directing the board to disseminate a registration statement that corrects alleged misstatements and includes all material facts the plaintiff asserts are missing; declaring that the defendants violated sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper.

On November 16, 2017, the parties in each of the actions 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 for the supplemental disclosures that we filed in a Form 8-K on November 16, 2017. 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. The outcome of litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation.

12. VARIABLE INTEREST ENTITY

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trust holding our 50% interest in La Cygne unit 2 is a VIE 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 entity. We also continuously assess whether we are the primary beneficiary of the VIE with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.

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.

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Financial Statement Impact

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entity, net	$	174,500	$	176,279
Liabilities:
Current maturities of long-term debt of variable interest entity	$	30,337	$	28,534
Accrued interest (a)	—		659
Long-term debt of variable interest entity, net	51,096		81,433

_______________

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

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Certain matters discussed in Management’s Discussion and Analysis are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. See “Forward-Looking Statements” and “Item 1A. Risk Factors” for additional information.

INTRODUCTION

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail to customers in Kansas under the regulation of the KCC. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas under the regulation of FERC. We have contracts for the sale or purchase of wholesale electricity with other utilities.

In Management’s Discussion and Analysis, we discuss our operating results for the three months endedMarch 31, 2018, compared to the same period of 2017, our general financial condition and significant changes that occurred during 2018. As you read Management’s Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Proposed Merger with Great Plains Energy

On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into one share of common stock of a new holding company with a final name yet to be publicly announced. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately47.5% of the new holding company. We currently expect to close the transaction in the first half of 2018. For more information, see Notes 3 and 11 of the Notes to Condensed Consolidated Financial Statements, “Pending Merger” and “Legal Proceedings,” respectively, and “Item 1A. Risk Factors.”

Tax Cuts and Jobs Act

The TCJA, which was signed into law in December 2017, significantly reforms the Internal Revenue Code and is generally effective January 1, 2018.  The TCJA contains significant changes to federal corporate income taxation, including, in general and among other things, reducing the federal corporate income tax rate from 35% to 21%, limiting the deduction for net operating losses, eliminating net operating loss carrybacks and eliminating our use of bonus depreciation on new capital investments.

Changes to income tax expense that are included in our prices occur through either rate review, by updating prices through formulas for transmission and wholesale prices or other regulatory action. We expect that future price changes for providing retail and wholesale electricity and transmission service will retroactively apply the lower 2018 income tax expense. Due to the nature of the regulatory process, and the inherent delay in our ability to adjust our prices, we have collected revenues in 2018 that is reflective of the higher corporate tax rate in effect prior to the passage of the TCJA. Therefore, we have reflected the expectation of retroactive application of lower prices in 2018 revenues and, correspondingly, we have accrued a regulatory liability representing our obligation to return these amounts to customers once the new prices are approved or otherwise take effect. As a result, revenues have decreased by $19.0 million for the three months endedMarch 31, 2018, which is mostly offset with the associated decrease in income tax expense.

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Earnings Per Share

Following is a summary of our net income and basic EPS.

	Three Months Ended March 31,
	2018		2017		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	60,485	$	59,661	$	824
Earnings per common share, basic	0.42		0.42		—

Net income and basic EPS were relatively unchanged for the three months endedMarch 31, 2018, compared to the same period in 2017. Higher retail sales, due primarily to favorable weather, were offset by higher operating, maintenance and administrative expense and taxes other than income taxes. See the discussion under “—Operating Results” below for additional information.

Current Trends and Uncertainties

The following is an update to and is to be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2017 Form 10-K.

Environmental Regulation

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have generally become more stringent over time and are expensive to implement. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. See Note 10 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies,” for a discussion of environmental costs, laws, regulations and other contingencies.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our condensed consolidated financial statements, which have been prepared in conformity with the instructions to Form 10-Q and Article 10 of Regulation S-X. Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted in our 2017 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2017, through March 31, 2018, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2017 Form 10-K.

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OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways.

Wholesale: Sales of electricity to electric cooperatives, municipalities, other electric utilities and RTOs, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Revenues from these sales reduce retail electricity prices either annually through a formula or when base rates are determined at the time of a general rate review.

Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.

Other Revenue from Contracts with Customers: Includes fees we earn for services provided to third parties and revenues earned by permitting other utilities to attach equipment to our utility poles.

Electric utility revenues are impacted by things such as rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather.

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Three Months EndedMarch 31, 2018, Compared to Three Months EndedMarch 31, 2017

Below we discuss our operating results for the three months endedMarch 31, 2018, compared to the results for the three months endedMarch 31, 2017. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.

	Three Months Ended March 31,
	2018			2017			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	180,285		$	169,290		$	10,995		6.5
Commercial	155,403			149,552			5,851			3.9
Industrial	93,460			94,589			(1,129		)	(1.2	)
Other retail	4,253			5,042			(789		)	(15.6	)
Total Retail Revenues	433,401			418,473			14,928			3.6
Wholesale	94,209			83,925			10,284			12.3
Transmission	71,926			70,729			1,197			1.7
Other	1,781			1,611			170			10.6
Total Revenues from Contracts with Customers	601,317			574,738			26,579			4.6
Other	(1,113		)	(2,164		)	1,051			48.6
Total Revenues	600,204			572,574			27,630			4.8
OPERATING EXPENSES:
Fuel and purchased power	135,507			113,855			21,652			19.0
SPP network transmission costs	67,594			60,674			6,920			11.4
Operating, maintenance and administrative	139,993			135,319			4,674			3.5
Depreciation and amortization	89,641			88,625			1,016			1.1
Taxes other than income tax	43,939			42,716			1,223			2.9
Total Operating Expenses	476,674			441,189			35,485			8.0
INCOME FROM OPERATIONS	123,530			131,385			(7,855		)	(6.0	)
OTHER INCOME (EXPENSE):
Investment earnings	999			3,155			(2,156		)	(68.3	)
Other income	1,951			1,300			651			50.1
Other expense	(10,561		)	(10,352		)	(209		)	(2.0	)
Total Other Expense	(7,611		)	(5,897		)	(1,714		)	(29.1	)
Interest expense	43,841			41,095			2,746			6.7
INCOME BEFORE INCOME TAXES	72,078			84,393			(12,315		)	(14.6	)
Income tax expense	9,174			20,911			(11,737		)	(56.1	)
NET INCOME	62,904			63,482			(578		)	(0.9	)
Less: Net income attributable to noncontrolling interests	2,419			3,821			(1,402		)	(36.7	)
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	60,485		$	59,661		$	824		1.4
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.42		$	0.42		$	—		—
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.42		$	0.42		$	—		—

33

Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP RTO. As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin, a non-GAAP measure, as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. The following table summarizes our gross margin for the three months endedMarch 31, 2018 and 2017.

	Three Months Ended March 31,
	2018		2017		Change			% Change
	(Dollars in Thousands)
Revenues	$	600,204	$	572,574	$	27,630		4.8
Less: Fuel and purchased power expense	135,507		113,855		21,652			19.0
SPP network transmission costs	67,594		60,674		6,920			11.4
Gross Margin	$	397,103	$	398,045	$	(942	)	(0.2	)

The following table reflects changes in electricity sales for the three months endedMarch 31, 2018 and 2017. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.

	Three Months Ended March 31,
	2018	2017	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,472	1,354	118		8.7
Commercial	1,697	1,617	80		4.9
Industrial	1,359	1,334	25		1.9
Other retail	14	20	(6	)	(30.0	)
Total Retail	4,542	4,325	217		5.0
Wholesale	2,901	2,491	410		16.5
Total	7,443	6,816	627		9.2

Gross margin decreased for the three months endedMarch 31, 2018, compared to the same period in 2017, due primarily to us recording a refund obligation for the change in the corporate income tax rate caused by the passage of the TCJA. See Note 5 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” for additional information. Partially offsetting this decrease is an increase in retail sales, which was attributable to colder winter weather. During the three months endedMarch 31, 2018, compared to the same period in 2017, there were approximately 25% more heating degree days.

34

Income from operations, which is calculated and presented in accordance with GAAP in our condensed consolidated statements of income, is the most directly comparable measure to our presentation of gross margin. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the three months endedMarch 31, 2018 and 2017.

	Three Months Ended March 31,
	2018		2017		Change			% Change
	(Dollars in Thousands)
Income from operations	$	123,530	$	131,385	$	(7,855	)	(6.0	)
Plus: Operating, maintenance and administrative expense	139,993		135,319		4,674			3.5
Depreciation and amortization expense	89,641		88,625		1,016			1.1
Taxes other than income tax	43,939		42,716		1,223			2.9
Gross margin	$	397,103	$	398,045	$	(942	)	(0.2	)

Operating Expenses and Other Income and Expense Items

	Three Months Ended March 31,
	2018		2017		Change		% Change
	(Dollars in Thousands)
Operating, maintenance and administrative expense	$	139,993	$	135,319	$	4,674	3.5

Operating, maintenance and administrative expense increased for the three months endedMarch 31, 2018, compared to the same period in 2017, due primarily to:

• a $2.8 million increase in employee benefit costs attributable primarily to increased medical claims; and

• a $1.3 million increase due to the start of operation of our Western Plains Wind Farm in March 2017; however,

• partially offsetting these increases was a $2.0 million decrease in steam generation operating and maintenance costs due primarily to a planned outage at La Cygne in 2017.

	Three Months Ended March 31,
	2018		2017		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	43,939	$	42,716	$	1,223	2.9

Taxes other than income tax increased for the three months endedMarch 31, 2018, compared to the same period in 2017, due primarily to a $1.0 million increase in property tax expense, which is offset in retail revenues.

	Three Months Ended March 31,
	2018		2017		Change			% Change
	(Dollars in Thousands)
Investment earnings	$	999	$	3,155	$	(2,156	)	(68.3	)

Investment earnings decreased due primarily to having recorded losses of $0.4 million on investments in a trust to fund retirement benefits compared to recording gains of $1.4 million in 2017.

35

	Three Months Ended March 31,
	2018		2017		Change		% Change
	(Dollars in Thousands)
Interest expense	$	43,841	$	41,095	$	2,746	6.7

Interest expense increased due primarily to a $1.7 million increase in interest expense on long-term debt as a result of the issuance of first mortgage bonds (FMBs) in March 2017 and a $0.5 million decrease in debt AFUDC.

	Three Months Ended March 31,
	2018		2017		Change			% Change
	(Dollars in Thousands)
Income tax expense	$	9,174	$	20,911	$	(11,737	)	(56.1	)

Income tax expense decreased for the three months endedMarch 31, 2018, compared to the same period in 2017, due primarily to a decrease in the federal corporate income tax rate from 35% to 21% as a result of the TCJA and increases in tax benefits from production tax credits.

FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of March 31, 2018, compared to December 31, 2017.

	As of			As of
	March 31, 2018			December 31, 2017			Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	776,616		$	784,899		$	(8,283	)	(1.1	)
Regulatory liabilities	1,121,275			1,105,576			15,699			1.4
Net regulatory liabilities	$	(344,659	)	$	(320,677	)	$	(23,982	)	(7.5	)

Total regulatory assets decreased due primarily to a $9.7 million decrease in deferred employee benefit costs.

Total regulatory liabilities increased due primarily to recording $19.0 million in revenue subject to refund to customers due to lowering the federal corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018, as a result of the passage of the TCJA.

	As of		As of
	March 31, 2018		December 31, 2017		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entity	$	30,337	$	28,534	$	1,803		6.3
Long-term debt of variable interest entity	51,096		81,433		(30,337		)	(37.3	)
Total long-term debt of variable interest entity	$	81,433	$	109,967	$	(28,534	)	(25.9	)

Total long-term debt of VIEs decreased due to the VIE that holds La Cygne leasehold interest having made principal payments totaling $28.5 million.

36

	As of		As of
	March 31, 2018		December 31, 2017		Change		% Change
	(Dollars in Thousands)
Short-term debt	$	289,800	$	275,700	$	14,100	5.1

Short-term debt increased due to increases in issuances of commercial paper used primarily to fund capital expenditures, working capital and other corporate purposes.

	As of		As of
	March 31, 2018		December 31, 2017		Change		% Change
	(Dollars in Thousands)
Accrued taxes	$	132,593	$	87,727	$	44,866	51.1

Accrued taxes increased due primarily to a $40.5 million increase in accrued property taxes due to timing of payments.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy’s commercial paper program and revolving credit facilities and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings and proceeds from the issuance of debt securities in the capital markets. When such balances are of sufficient size and it makes economic sense to do so, we also use proceeds from the issuance of long-term debt securities to repay short-term borrowings, which are principally related to investments in capital equipment and the redemption of bonds and for working capital and general corporate purposes. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in “—Operating Results” above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets.

Short-Term Borrowings

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 and cannot exceed the capacity under 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. As of May 1, 2018, Westar Energy had $308.2 million of commercial paper issued and outstanding.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. The $730.0 million facility will expire in September 2019, $20.7 million of which expired in September 2017. In December 2017, Westar Energy extended the term of the $270.0 million credit facility by one year to terminate in February 2019. As long as there is no default under the facilities, the $730.0 million facility may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE FMBs. Total combined borrowings under the revolving credit facilities and the commercial paper program may not exceed $1.0 billion at any given time. As of May 1, 2018, no amounts were borrowed and $40.4 million in letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date.

Debt Covenants

We were in compliance with our debt covenants as of March 31, 2018.

37

Impact of Credit Ratings on Debt Financing

Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Services (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate each agency’s assessment of our ability to pay interest and principal when due on our securities.

In general, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy’s revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy’s ability to borrow under the credit facilities and commercial paper program are not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical financial ratios, such as funds from operations to total debt and operating cash flow to debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices.

As of May 1, 2018, our ratings with the agencies are as shown in the table below.

	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Commercial Paper	Rating Outlook
Moody’s	A2	A2	P-2	Stable
S&P	A	A	A-2	Positive

Summary of Cash Flows

	Three Months Ended March 31,
	2018			2017			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	259,628		$	236,725		$	22,903		9.7
Investing activities	(174,181		)	(175,724		)	1,543			0.9
Financing activities	(77,713		)	(60,708		)	(17,005		)	(28.0	)
Net change in cash, cash equivalents and restricted cash	$	7,734		$	293		$	7,441		(a)

_______________

(a) Change greater than 1,000%  

Cash Flows from Operating Activities

Cash flows from operating activities increased due primarily to our having received $18.5 million more from retail customers, received $11.9 million more in 2018 for wholesale power sales and transmission services, and paid $9.9 million less for coal and natural gas. Partially offsetting these increases was our having received a $13.0 million income tax refund in 2017, with no similar benefit in 2018, and paid $11.0 million more in 2018 for purchase power and transmission services.

Cash Flows used in Investing Activities

Cash flows used in investing activities decreased due primarily to our having received $1.1 million more from our investment in COLI and our having invested $0.6 million less in additions to property, plant and equipment.

38

Cash Flows used in Financing Activities

Cash flows used in financing activities increased due primarily to our having issued $296.5 million less in long-term debt. Partially offsetting these increases was our having issued $154.5 million more in commercial paper and having redeemed $125.0 million of long-term debt in 2017.

Pension Contribution

During the three months endedMarch 31, 2018, we contributed $12.5 million to the Westar Energy pension trust. No payments were made to fund the Wolf Creek pension plan during the same period.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2017, through March 31, 2018, our off-balance sheet arrangements did not change materially. For additional information, see our 2017 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2017, through March 31, 2018, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2017 Form 10-K.

OTHER INFORMATION

Changes in Prices

See Note 5 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” for information on our prices.

New Accounting Pronouncements

See Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for information on accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including changes in commodity prices, counterparty credit, interest rates and debt and equity instrument values. From December 31, 2017, to March 31, 2018, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2017 Form 10-K for additional information.

39

ITEM 4. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Exchange Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting during the three months endedMarch 31, 2018, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

40

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 1A. RISK FACTORS

     There were no material changes in our risk factors from December 31, 2017, through March 31, 2018. For additional information, see our 2017 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. In accordance with SEC guidance, we may also use the Investor Relations section of our website (http://www.WestarEnergy.com, under “Investors”) to communicate with investors about our company. It is possible that the financial and other information we post there could be deemed to be material information. The information on our website is not part of this document.

ITEM 6. EXHIBITS

31(a)	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended March 31, 2018
31(b)	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended March 31, 2018
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended March 31, 2018 (furnished and not to be considered filed as part of the Form 10-Q)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

41

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		WESTAR ENERGY, INC.
Date:	May 8, 2018	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

42

EX-31.A

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended March 31, 2018, of Westar Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

a. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 8, 2018	By:	/s/   Mark A. Ruelle
			Mark A. Ruelle
			President and Chief Executive Officer
			Westar Energy, Inc.

EX-31.B

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended March 31, 2018, of Westar Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 8, 2018	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer
			Westar Energy, Inc.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Westar Energy, Inc. (the Company) on Form 10-Q for the quarter ended March 31, 2018 (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 8, 2018	By:	/s/   Mark A. Ruelle
			Mark A. Ruelle
			President and Chief Executive Officer

Date:	May 8, 2018	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

XML

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2018	May 01, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Trading Symbol	WR
Entity Registrant Name	WESTAR ENERGY INC /KS
Entity Central Index Key	0000054507
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		142,233,136

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 11,166	$ 3,432
Accounts receivable, net of allowance for doubtful accounts	244,411	290,652
Fuel inventory and supplies	286,831	293,562
Prepaid expenses	20,566	16,425
Regulatory assets	95,580	99,544
Other	24,694	23,435
Total Current Assets	683,248	727,050
Property, plant and equipment, net	9,589,164	9,553,755
OTHER ASSETS:
Regulatory assets	681,036	685,355
Nuclear decommissioning trust	241,153	237,102
Other	251,268	244,827
Total Other Assets	1,173,457	1,167,284
TOTAL ASSETS	11,620,369	11,624,368
CURRENT LIABILITIES:
Short-term debt	289,800	275,700
Accounts payable	139,308	204,186
Accrued dividends	53,888	53,830
Accrued taxes	132,593	87,727
Accrued interest	91,741	72,693
Regulatory liabilities	11,220	11,602
Other	81,462	89,445
Total Current Liabilities	830,349	823,717
LONG-TERM LIABILITIES:
Long-term debt, net	3,688,257	3,687,555
Deferred income taxes	824,699	815,743
Unamortized investment tax credits	256,406	257,093
Regulatory liabilities	1,110,055	1,093,974
Accrued employee benefits	533,318	541,364
Asset retirement obligations	382,791	379,989
Other	78,952	83,063
Total Long-Term Liabilities	6,925,574	6,940,214
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value $5 per share	711,166	710,471
Paid-in capital	2,022,451	2,024,396
Retained earnings	1,176,095	1,173,255
Total Westar Energy, Inc. Shareholders' Equity	3,909,712	3,908,122
Noncontrolling Interests	(45,266)	(47,685)
Total Equity	3,864,446	3,860,437
TOTAL LIABILITIES AND EQUITY	11,620,369	11,624,368
Variable Interest Entity [Member]
CURRENT ASSETS:
Property, plant and equipment, net	174,500	176,279
CURRENT LIABILITIES:
Current maturities of long-term debt	30,337	28,534
Accrued interest	0	659
LONG-TERM LIABILITIES:
Long-term debt, net	$ 51,096	$ 81,433

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Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Allowance for doubtful accounts	$ 9,288	$ 6,716
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	142,233,103	142,094,275
Common stock, shares outstanding	142,233,103	142,094,275

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Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES	$ 600,204	$ 572,574
OPERATING EXPENSES:
Fuel and purchased power	135,507	113,855
SPP network transmission cost	67,594	60,674
Operating, maintenance, and administrative	139,993	135,319
Depreciation and amortization	89,641	88,625
Taxes other than income tax	43,939	42,716
Total Operating Expenses	476,674	441,189
INCOME FROM OPERATIONS	123,530	131,385
OTHER INCOME (EXPENSE):
Investment earnings (losses)	999	3,155
Other income	1,951	1,300
Other expense	(10,561)	(10,352)
Total Other Income	(7,611)	(5,897)
Interest expense	43,841	41,095
INCOME BEFORE INCOME TAXES	72,078	84,393
Income tax expense	9,174	20,911
NET INCOME	62,904	63,482
Less: Net income attributable to noncontrolling interests	2,419	3,821
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 60,485	$ 59,661
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 0.42	$ 0.42
Earnings Per Share, Diluted	$ 0.42	$ 0.42
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	142,635,490	142,436,622
Weighted Average Number of Shares Outstanding, Diluted	142,651,580	142,695,606
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.40	$ 0.40

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Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 11,254	$ 3,449
Restricted Cash	88	90
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	62,904	63,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	89,641	88,625
Amortization of nuclear fuel	7,716	8,069
Amortization of deferred regulatory gain from sale leaseback	(1,374)	(1,374)
Amortization of corporate-owned life insurance	5,501	5,901
Non-cash compensation	2,507	2,468
Net deferred income taxes and credits	3,803	19,011
Allowance for equity funds used during construction	(1,097)	(775)
Asset Retirement Obligation, Cash Paid to Settle	(1,943)	(961)
Income from corporate-owned life insurance income	(671)	(1,311)
Changes in working capital items:
Accounts receivable	46,241	51,547
Fuel inventory and supplies	6,885	(10,581)
Prepaid expenses and other current assets	3,886	28,311
Accounts payable	(24,219)	(23,135)
Accrued taxes	48,674	47,775
Other current liabilities	(11,833)	(54,223)
Changes in other assets	(724)	3,290
Changes in other liabilities	23,731	10,606
Cash Flows from Operating Activities	259,628	236,725
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(174,765)	(175,400)
Purchase of securities - trusts	(85,429)	(4,191)
Sale of securities - trusts	86,060	5,720
Investment in corporate-owned life insurance	998	913
Proceeds from investment in corporate-owned life insurance	2,559	1,414
Other investing activities	(1,608)	(2,354)
Cash Flows used in Investing Activities	(174,181)	(175,724)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	14,100	(140,407)
Proceeds from long-term debt	0	296,475
Retirements of long-term debt	0	(125,000)
Repayment of capital leases	(950)	(800)
Borrowings against cash surrender value of corporate-owned life insurance	721	910
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(1,735)	0
Issuance of common stock	0	470
Distributions to shareholders of noncontrolling interests		(5,760)
Cash dividends paid	(57,438)	(52,750)
Other financing activities	(3,877)	(7,006)
Cash Flows from Financing Activities	(77,713)	(60,708)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	7,734	293
CASH, CASH EQUIVALENTS AND RESTRICTED CASH:
Beginning of period	3,432
End of period	11,166
Variable Interest Entity [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Retirements of long-term debt	(28,534)	(26,840)
Noncontrolling Interest [Member]
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	2,419	3,821
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Distributions to shareholders of noncontrolling interests	$ 0	$ (5,760)

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Consolidated Statements Of Changes In Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Beginning Balance at Dec. 31, 2016	$ 3,833,190	$ 708,956	$ 2,018,317	$ 1,078,602	$ 27,315
Beginning Balance (Shares) at Dec. 31, 2016		141,791,153
Net income	63,482	$ 0	0	59,661	3,821
Issuance of stock	470	$ 43	427	0	0
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		247,834
Issuance of stock (shares)		8,646
Issuance Of Stock For Compensation And Reinvested Dividends	2,349	$ 1,239	1,110
Tax withholding related to stock compensation	(7,006)		7,006
Dividends declared on common stock	(57,995)	0	0	(57,995)	0
Stock compensation expense	2,439		2,439
Distributions to shareholders of noncontrolling interests	(5,760)				(5,760)
Ending Balance at Mar. 31, 2017	3,831,169	$ 710,238	2,015,287	1,080,268	25,376
Ending Balance (Shares) at Mar. 31, 2017		142,047,633
Beginning Balance at Dec. 31, 2017	3,860,437	$ 710,471	2,024,396	1,173,255	(47,685)
Beginning Balance (Shares) at Dec. 31, 2017		142,094,275
Net income	62,904	$ 0	0	60,485	2,419
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		138,828
Issuance Of Stock For Compensation And Reinvested Dividends	149	$ 695	(546)
Tax withholding related to stock compensation	(3,877)		3,877
Dividends declared on common stock	(57,645)	0	0	(57,645)	0
Stock compensation expense	2,478		2,478
Distributions to shareholders of noncontrolling interests					0
Ending Balance at Mar. 31, 2018	$ 3,864,446	$ 711,166	$ 2,022,451	$ 1,176,095	$ (45,266)
Ending Balance (Shares) at Mar. 31, 2018		142,233,103

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Consolidated Statements Of Changes in Equity Parenthetical (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.40	$ 0.40

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Description Of Business

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description Of Business

DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 710,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

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Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2017 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months endedMarch 31, 2018, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory and Supplies

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Fuel inventory	$	89,125	$	94,039
Supplies	197,706		199,523
Fuel inventory and supplies	$	286,831	$	293,562

Allowance for Funds Used During Construction

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

	Three Months Ended March 31,
	2018			2017
	(Dollars In Thousands)
Borrowed funds	$	1,403		$	1,853
Equity funds	1,097			775
Total	$	2,500		$	2,628
Average AFUDC Rates	3.6		%	2.2		%

Earnings Per Share

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

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

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

	Three Months Ended March 31,
	2018		2017
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	62,904	$	63,482
Less: Net income attributable to noncontrolling interests	2,419		3,821
Net income attributable to Westar Energy, Inc.	60,485		59,661
Less: Net income allocated to RSUs	104		108
Net income allocated to common stock	$	60,381	$	59,553
Weighted average equivalent common shares outstanding – basic	142,635,490		142,436,622
Effect of dilutive securities:
RSUs	16,090		258,984
Weighted average equivalent common shares outstanding – diluted (a)	142,651,580		142,695,606
Earnings per common share, basic	$	0.42	$	0.42
Earnings per common share, diluted	$	0.42	$	0.42

_______________

(a)We had no antidilutive securities for the three months endedMarch 31, 2018 and 2017.

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	33,043		$	35,644
Interest on financing activities of VIEs	1,319			1,696
Income taxes, net of refunds	(231		)	(13,000		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	29,790			97,196
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	149			2,349
Assets acquired through capital leases	48			293

Revenue Recognition

Revenue is recognized primarily at the time we deliver electricity or provide transmission service to customers. The time of delivery of electricity is generally when our obligation to provide service is satisfied. Sales tax and franchise fees that we collect concurrent with revenue-producing activities are excluded from revenue. For more information on revenue recognition, see Note 4, “Revenue.”

We determine the amount of electricity delivered to 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 energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $68.2 million and $76.7 million as of March 31, 2018, and December 31, 2017, respectively.

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. For the three months ended March 31, 2018 and 2017, we recorded bad debt expense related to contracts with customers of $4.0 million and $3.2 million, respectively.

New Accounting Pronouncements

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

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is applied on a retrospective basis. The guidance permits and we elected upon adoption to use a practical expedient that allows us to use the amounts disclosed in Note 8, “Pension and Post-Retirement Benefit Plans,” for applying the retrospective presentation of the 2017 condensed consolidated statement of income. As a result, we retrospectively decreased operating, maintenance, and administrative expense by $5.0 million and increased other expense by $5.0 million for the three months endedMarch 31, 2017. The new standard is effective for annual periods beginning after December 15, 2017. We adopted the guidance for the Westar Energy pension and post-retirement benefit plans as of January 1, 2018, without a material impact on our condensed consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued 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 corporate-owned life insurance (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. Retrospective application is required. We adopted the guidance effective January 1, 2018, which resulted in retrospective reclassification of cash proceeds of $1.3 million from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities for the three months endedMarch 31, 2017. In addition, cash payments of $0.9 millionfor premiums on COLI policies were reclassified from cash outflows used in operating activities to cash outflows used in investing activities for the same period.

In November 2016, the FASB issued ASU No. 2016-18, which requires that statement of cash flows explain the change for the period of restricted cash and restricted cash equivalents along with cash and cash equivalents. The guidance requires a retrospective transition method and is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018. As a result, we adjusted amounts previously reported for cash and cash equivalents to include restricted cash which resulted in an increase to beginning and ending cash, cash equivalents and restricted cash of $0.1 million for the three months endedMarch 31, 2017.

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 power purchase agreements, and will analyze the related impact. The standard permits an entity to elect a practical expedient for existing or expired contracts to forgo reassessing leases to determine whether each is in scope of the new standard and to forgo reassessing lease classification. We expect to elect this practical expedient upon implementation.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, which generally requires equity investments to be measured at fair value with changes in fair value recognized in net income. Under the new standard, equity securities are no longer to be classified as available-for-sale or trading securities. The guidance requires a modified retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018, without a material impact on our condensed consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018. The standard permits the use of either the retrospective application or modified retrospective method. We elected to use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Adoption of the standard did not have a material impact to our condensed consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard. For more information on revenue recognition, see Note 4, “Revenue.”

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Pending Merger Pending Merger (Notes)

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy that provided for the acquisition of us by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) rejected the prior transaction.

On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into one share of common stock of a new holding company with a final name yet to be publicly announced. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately47.5% of the new holding company.

The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement limits our quarterly dividends declared to $0.40 per share.

The closing of the merger is subject to conditions including receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar Energy and its subsidiaries, taken as a whole); effectiveness of the registration statement for the shares of the new holding company’s common stock to be issued to our shareholders and Great Plains Energy’s shareholders upon consummation of the merger and approval of the listing of such shares on the New York Stock Exchange; the receipt of tax opinions by us and Great Plains Energy that the merger will be treated as a non-taxable event for U.S. federal income tax purposes; there being no shares of Great Plains Energy preference stock outstanding; and Great Plains Energy having not less than $1.25 billion in cash or cash equivalents on its balance sheet. The closing of the merger is also subject to other standard conditions, such as accuracy of representations and warranties, compliance with covenants and the absence of a material adverse effect on either company.

The merger agreement, which contains customary representations, warranties, and covenants, may be terminated by either party if the merger has not occurred by July 10, 2018. The termination date may be extended six months in order to obtain regulatory approvals.

On August 25, 2017, we and Great Plains Energy filed a joint application with the KCC requesting approval of the merger. The KCC subsequently approved a procedural schedule that provides for a KCC order on the proposed merger by June 5, 2018, although under Kansas law the KCC has until June 21, 2018, to issue the order. On March 7, 2018, we, Great Plains Energy, the KCC staff, the Citizens’ Utility Ratepayer Board (CURB), and certain other intervenors entered into a non-unanimous settlement agreement to settle issues related to the joint application. The settlement agreement is subject to review and approval by the KCC. Components of the settlement agreement are summarized below. The settlement agreement, if approved, is expected to impact our 2018 rate review.

• $23.0 million of bill credits in 2018 to our retail customers, which will reduce 2018 revenues by a corresponding amount

• An additional $8.6 million of annual bill credits to our retail customers between 2019 and 2022

• Reduction of our annual revenues by $22.5 million for estimated merger-related savings to be reflected in our 2018 rate review

• An annual earnings review and sharing program that will allow for sharing of earnings with customers if actual earnings are above a certain level, after recovery of the annual bill credits

• A return on equity recommendation of 9.3% in our 2018 rate review

• Limitation on debt capitalization (excluding short-term debt and debt due within one year) of 65% at the consolidated holding company and 60% at the utility operating companies

• A five-year prohibition against changing base rates, which could be reduced to three years if the ROE ordered by the KCC in the 2018 rate review is set lower than 9.3%

• The recovery of $23.2 million of transition costs to be included in our prices over a 10-year period

• We will forgo the ability to offset tax reform benefits with demonstrated under-earnings

• An annual quality of service performance reporting requirement

The settlement agreement also contains items that, if approved, are expected to impact the 2018 rate review for Kansas City Power & Light Company, a utility subsidiary of Great Plains Energy that operates in Kansas and Missouri.

On August 31, 2017, we and Great Plains Energy applied for approval of the merger from the MPSC. On January 12, 2018, we, Great Plains Energy, the MPSC staff and certain other intervenors entered into a non-unanimous stipulation and agreement to settle issues related to the joint application. On March 8, 2018, the stipulation and agreement with MPSC staff was amended to include additional intervenors. The stipulation and agreement is subject to review and approval by the MPSC.

We and Great Plains Energy each gained shareholder approval of the proposed merger on November 21, 2017. We and Great Plains Energy received early termination of the statutory waiting period under the Hart-Scott-Rodino Antitrust Improvements Act on December 12, 2017. We and Great Plains Energy received FERC approval of the merger on February 28, 2018. On March 12, 2018, Wolf Creek received approval from the NRC for an indirect transfer of control of Wolf Creek’s operating license. On March 19, 2018, we and Great Plains Energy received Federal Communications Commission consent for various license transfers that are deemed to occur with the merger.

The amended and restated merger agreement provides that Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated due to (i) failure to receive regulatory approval prior to July 10, 2018, subject to an extension of up to six months, (ii) a non-appealable regulatory order enjoining the merger or (iii) Great Plains Energy’s failure to close after all conditions precedent to closing have been satisfied. In addition, we may be required to pay Great Plains Energy a termination fee of $190.0 million if the agreement is terminated by us under certain circumstances. Similarly, Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated by Great Plains Energy under certain circumstances.

In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our operating, maintenance and administrative expenses. During the three months endedMarch 31, 2018 and 2017, we incurred approximately $0.4 million of merger-related expenses. In the event that the merger is consummated, we estimate merger-related expenses for investment banking, legal, and other professional services will be approximately $45.0 million. In addition, we expect to incur an estimated $40.0 million of expenses for accelerated stock-based compensation, voluntary severance plan payments and payments pursuant to change in control agreements.

See also Note 11, “Legal Proceedings,” for more information on litigation related to the merger.

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Revenue (Notes)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE

Kansas law gives the KCC general regulatory authority over our retail prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale electricity sales, including prices and the transmission of electric power. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs, including the cost of invested capital. For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of formulas that track changes in our costs, which reduces the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 5, “Rate Matters and Regulation,” for information regarding our rate proceedings with the KCC and FERC and potential related refund obligations.

We categorize revenue based on class of customer as discussed below.

Retail Revenue

We are the sole supplier of retail electricity within our service territory. We operate facilities necessary to generate, transmit and distribute electricity to our customers. We are required to provide electricity to customers in our service territory as requested by customers. Revenue is recognized over time as we satisfy our obligation, generally corresponding to the amount of electricity that we deliver to our customers.This method of recognizing revenue corresponds directly to the amount that we have the right to invoice our customers each month.

Retail revenue is impacted by things such as weather, rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand.

We further classify retail customers as residential, commercial, industrial and other customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways.

Wholesale Revenue

We sell electricity and capacity (the ability to demand delivery of a maximum amount of electricity) at wholesale to electric cooperatives, municipalities, other electric utilities and RTOs,the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. We recognize revenue as we deliver the electricity and capacity that corresponds directly to the amount of consideration we expect to invoice. Revenues from these sales reduce retail electricity prices either annually through a formula or when base rates are determined at the time of a general rate review. Our wholesale revenues are impacted by, among other factors, demand, costs and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather. Our long-term contracts for wholesale capacity include variable transaction prices mostly based on peak demand for electricity and capacity of certain generating units. Terms on our long-term contracts for wholesale capacity expire between 2019 and 2039.

Transmission Revenue

We provide transmission service to the Southwest Power Pool, Inc. (SPP) by allowing it access to our transmission network. As new transmission lines are constructed, they are included in the transmission network available to the SPP. In exchange for providing access, the SPP pays us consideration determined by a formula rate approved by FERC, which includes the cost to construct and maintain the transmission lines and a return on our investment. The price for access to our transmission network is updated annually based on projected costs. Projections are updated to actual costs and the difference is included in subsequent year’s prices. We recognize revenue over time as we provide transmission service and as we have the right to invoice the SPP.

Other Revenue from Contracts with Customers

Other revenue derived from contracts with customers includes fees we earn for services provided to third parties and revenues earned by permitting other utilities to attach equipment to our utility poles. We recognize revenue when obligations under the terms of a contract with a customer are satisfied.

The following table categorizes our revenue by class of customer.

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
REVENUES:
Residential	$	180,285		$	169,290
Commercial	155,403			149,552
Industrial	93,460			94,589
Other retail	4,253			5,042
Total Retail Revenues	433,401			418,473
Wholesale	94,209			83,925
Transmission	71,926			70,729
Other	1,781			1,611
Total Revenue from Contracts with Customers	601,317			574,738
Other	(1,113		)	(2,164		)
Total Revenues	$	600,204		$	572,574

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Rate Matters And Regulation

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Rate Matters And Regulation

RATE MATTERS AND REGULATION

KCC Proceedings

In March 2018, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2018 and are expected to increase our annual retail revenues by approximately $31.5 million.

In February 2018, we filed a rate application with the KCC to update our prices to include, among other things, costs associated with the completion of Western Plains Wind Farm, expiration of wholesale contracts currently reflected in retail prices as offsets to our retail cost of service, expiration of the 10-year period for production tax credits from our initial wind investments and an updated depreciation study. This rate application also includes savings due to the recently passed federal Tax Cuts and Jobs Act (TCJA), savings achieved from refinancing debt and a portion of the savings from the proposed merger with Great Plains Energy. If our rate application were to be approved, we estimate the new prices would decrease our annual revenues by approximately $2.0 million in September 2018, followed by an increase in our annual revenues of approximately $54.0 million in February 2019. However, we, Great Plains Energy, the KCC staff, CURB and certain other intervenors entered into a non-unanimous settlement agreement related to our merger application, which includes commitments from certain parties to the settlement agreement to accept specific merger-contingent conditions or take particular positions in our rate review. See Note 3, “Pending Merger,” for additional information. If our rate application is approved with the merger-contingent conditions related to a 9.3% ROE and the limited amount of merger-related savings and transition costs included in our prices, then we estimate the new prices would decrease our annual revenues by approximately $37.0 million in September 2018, as compared to the approximately $2.0 million reduction originally requested. This reduction would be followed by an increase in our annual revenues of approximately $54.0 million in February 2019, as previously stated above. Our revenues would be further reduced due to the payment of bill credits in 2018 through 2022 as discussed in Note 3, “Pending Merger.”

In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities. The KCC stated the passage of the TCJA has the potential to significantly reduce the cost of service for utilities, and it may impact the regulatory assets and liabilities of Kansas utilities. Therefore, beginning in January 2018, the KCC directed each regulated electric public utility that is taxable at the corporate level to accrue monthly, in a deferred revenue account, the portion of its revenue representing the difference between: (1) the cost of service as approved by the KCC in its most recent rate review; and (2) the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the corporate tax rate approved in the TCJA. The KCC also gave notice to taxable utilities operating in Kansas that the portion of their regulated revenue stream that reflects higher corporate tax rates should be considered interim and subject to refund, with interest. When the KCC’s evaluation of the impact of the TCJA is complete, if it is determined that a retail price decrease is proper and would have been proper as of the effective date of the TCJA, these amounts will be returned to customers. We believe it is probable that we will be required to return these amounts to customers. Therefore, we have recorded a $15.1 million regulatory liability as of March 31, 2018, and a corresponding decrease in revenues for the three months ended March 31, 2018.

In December 2017, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2018 and are expected to decrease our annual retail revenues by approximately$0.2 million.

FERC Proceedings

Our TFR that includes projected 2018 transmission capital expenditures and operating costs was effective in January 2018 and was expected to increase our annual transmission revenues by approximately $25.5 million. However, due to the passage of the TCJA, we requested permission from FERC to retroactively reflect the reduction in the federal corporate income tax rate in our 2018 prices. In April 2018, FERC granted our request and accordingly, we have recorded a $3.9 million regulatory liability as of March 31, 2018. This updated rate will provide the basis for a new request with the KCC to retroactively adjust our retail prices to include updated transmission costs as discussed above. We estimate the revised TFR will increase 2018 revenues by $2.3 million when compared to 2017.

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Financial Instruments and Investments

3 Months Ended

Mar. 31, 2018

Financial And Derivative Instruments and Investments [Abstract]

Financial And Derivative Instruments And Investments

FINANCIAL INSTRUMENTS AND INVESTMENTS

Values of Financial Instruments

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

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

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

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

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

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

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

	As of March 31, 2018				As of December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,759,785	$	3,605,000	$	3,888,620
Fixed-rate debt of VIEs	81,433		80,557		109,967		110,756

Recurring Fair Value Measurements

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

As of March 31, 2018	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,449	$	—	$	5,323	$	73,772
International equity funds	—		45,130		—		—		45,130
Core bond fund	—		37,492		—		—		37,492
High-yield bond fund	—		19,713		—		—		19,713
Emerging markets bond fund	—		17,337		—		—		17,337
Combination debt/equity/other fund	—		13,973		—		—		13,973
Alternative investments fund	—		—		—		22,521		22,521
Real estate securities fund	—		—		—		11,024		11,024
Cash equivalents	191		—		—		—		191
Total Nuclear Decommissioning Trust	191		202,094		—		38,868		241,153
Rabbi Trust:
Core bond fund	—		25,670		—		—		25,670
Combination debt/equity/other fund	—		6,418		—		—		6,418
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		32,088		—		—		32,244
Total Assets Measured at Fair Value	$	347	$	234,182	$	—	$	38,868	$	273,397
As of December 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,658	$	—	$	5,142	$	73,800
International equity funds	—		47,908		—		—		47,908
Core bond fund	—		33,250		—		—		33,250
High-yield bond fund	—		18,089		—		—		18,089
Emerging markets bond fund	—		17,345		—		—		17,345
Combination debt/equity/other fund	—		14,125		—		—		14,125
Alternative investments fund	—		—		—		21,669		21,669
Real estate securities fund	—		—		—		10,806		10,806
Cash equivalents	110		—		—		—		110
Total Nuclear Decommissioning Trust	110		199,375		—		37,617		237,102
Rabbi Trust:
Core bond fund	—		27,324		—		—		27,324
Combination debt/equity/other fund	—		6,831		—		—		6,831
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		34,155		—		—		34,311
Total Assets Measured at Fair Value	$	266	$	233,530	$	—	$	37,617	$	271,413

We hold equity and debt investments that we classify as securities in a trust for the purpose of funding the decommissioning of Wolf Creek and maintain a Rabbi trust to manage funds for the benefit of certain retired executive officers. We record net realized and unrealized gains and losses on the Nuclear Decommissioning Trust (NDT) in regulatory liabilities on our condensed consolidated balance sheets. We include net realized and unrealized gains or losses on the Rabbi trust in investment earnings on our condensed consolidated statements of income. For the three months endedMarch 31, 2018 and 2017, we recorded net unrealized losses of $0.1 million and net unrealized gains of $9.0 million, respectively, on the NDT assets still held as of March 31, 2018 and net unrealized losses of $0.4 million and net unrealized gains of $1.4 million, respectively, on the Rabbi trust assets still held as of March 31, 2018

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 March 31, 2018				As of December 31, 2017				As of March 31, 2018
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,323	$	2,508	$	5,142	$	2,808	(a)	(a)
Alternative investments fund (b)	22,521		—		21,669		—		Quarterly	65 days
Real estate securities fund (b)	11,024		—		10,806		—		Quarterly	65 days
Total	$	38,868	$	2,508	$	37,617	$	2,808

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(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. Three funds have begun to make distributions. Our initial investment in the fourth fund occurred in 2016.This fund’s term is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b) There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

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Taxes

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Taxes

TAXES

We recorded income tax expense of $9.2 million with an effective income tax rate of 13% for the three months endedMarch 31, 2018, and income tax expense of $20.9 million with an effective income tax rate of 25% for the same period of 2017. The decrease in the effective income tax rate for the three months endedMarch 31, 2018, was due primarily to the TCJA, which was signed into law in December 2017 and decreased the federal corporate income tax rate from 35% to 21%.

As of March 31, 2018, and December 31, 2017, our unrecognized income tax benefits totaled $1.7 million. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of March 31, 2018, and December 31, 2017, we had no amounts and $0.1 million, respectively, accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either March 31, 2018, or December 31, 2017.

As of March 31, 2018, and December 31, 2017, we had recorded $0.5 million and $0.4 million, respectively, for probable assessments of taxes other than income taxes.

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Pension and Post-Retirement Benefit Plans

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,826		$	5,218		$	279		$	271
Interest cost (a)	10,207			10,621			1,183			1,314
Expected return on plan assets (a)	(11,091		)	(10,760		)	(1,728		)	(1,718		)
Amortization of unrecognized:
Prior service costs (a)	166			171			114			114
Actuarial loss (gain), net (a)	6,485			5,489			(135		)	(195		)
Net periodic cost (benefit) before regulatory adjustment	11,593			10,739			(287		)	(214		)
Regulatory adjustment (b)	2,849			3,288			(434		)	(478		)
Net periodic cost (benefit)	$	14,442		$	14,027		$	(721	)	$	(692	)

 _______________

(a) The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

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

During the three months endedMarch 31, 2018 and 2017, we contributed $12.5 million and $7.0 million, respectively, to the Westar Energy pension trust.

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Wolf Creek Pension and Post-Retirement Benefit Plans

3 Months Ended

Mar. 31, 2018

Defined Benefit Plan [Abstract]

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,220		$	1,950		$	36		$	37
Interest cost	2,478			2,475			61			70
Expected return on plan assets	(2,891		)	(2,643		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,656			1,245			(14		)	(13		)
Net periodic cost before regulatory adjustment	3,477			3,041			83			94
Regulatory adjustment (a)	(49		)	247			—			—
Net periodic cost	$	3,428		$	3,288		$	83		$	94

 _______________

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

During the three months endedMarch 31, 2018 and 2017, we did not fund Wolf Creek’s pension plan.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Environmental Matters

Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.

Cross-State Air Pollution Update Rule

In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxides 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 revised the existing ozone season allowance budgets for Missouri and Oklahoma and established an ozone season budget for Kansas. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit but the rule remains in effect. We do not believe this rule will have a material impact on our operations and condensed consolidated financial results.

National Ambient Air Quality Standards

Under the CAA, the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, nitrogen dioxide (NO₂) (a precursor to ozone), carbon monoxide and sulfur dioxide (SO₂), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment (KDHE) recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as attainment/unclassifiable. In November 2017, the EPA designated all counties in the State of Kansas as attainment/unclassifiable. We do not believe this will have a material impact on our condensed 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 attainment/unclassifiable with the standard. We do not believe this will have a material impact on our operations or condensed consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants.  Tecumseh Energy Center is our only generating station that meets these criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule that governs the next round of the designations. Also in January 2017, KDHE recommended the EPA change the designation of the area surrounding the facility from unclassifiable to attainment/unclassifiable. In August 2017, the EPA indicated they would address this area redesignation request in a separate action. By agreeing to the 2,000 ton per year limitation, no further characterization of the area surrounding the plant is required.

We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and condensed consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and condensed consolidated financial results.

Greenhouse Gases

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

In October 2015, the EPA published a rule establishing new source performance standards (NSPS) for GHGs that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. Legal challenges to the GHG NSPS have been filed in the D.C. Circuit by various states and industry members. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including us, in the D.C. Circuit. The CPP was stayed by the Supreme Court in February 2016 and, accordingly, is not currently being implemented by the states.

In April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details. Also in April 2017, the EPA published a notice in the Federal Register that it was initiating administrative reviews of the CPP and the GHG NSPS.

In October 2017, the EPA issued a proposed rule to repeal the CPP. The proposed rule indicates the CPP exceeds EPA’s authority and the EPA has not determined whether they will issue a replacement rule. The EPA is soliciting comments on the legal interpretations contained in this rulemaking. Comments were due in April 2018.

In December 2017, the EPA issued an advance notice of proposed rulemaking. This proposed rulemaking was issued by the EPA because it is considering the possibility of changing certain aspects of the CPP and the EPA is soliciting feedback on specific areas that could be changed. Comments on these proposed areas of change were due to the EPA in February 2018.

Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes effluent limitations guidelines (ELG) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending the EPA’s review. In September 2017, the EPA finalized a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for bottom ash transport water and flue gas desulfurization wastewater. These compliance dates have been postponed for two years while the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers or cooling lakes that can be classified as closed cycle cooling. We do not expect the impact from this rule to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States (WOTUS) for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states and others have filed lawsuits challenging the WOTUS rule. In February 2018, the EPA and the U.S. Corps of Engineers finalized a rule adding an applicability date to the 2015 rule, which makes the implementation date of the rule February 2020. In July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. Final action on the proposed rule is expected in 2018. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results.

Regulation of Coal Combustion Residuals

In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017 and 2018. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. Electric generation industry participants requested and the EPA has granted a request to reconsider portions of the final CCR regulation. In March 2018, the EPA proposed the Phase I CCR Remand Rule in order to modify portions of the 2015 rulemaking. This rule, should it become final, could introduce additional flexibility in CCR compliance. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or condensed consolidated financial results could be material.

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 has elected to build a dry cask storage facility to expand its existing on-site spent nuclear fuel storage, which is expected to provide additional capacity prior to 2025. Wolf Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE begun accepting spent nuclear fuel. As a co-owner of Wolf Creek, in 2017 we received $0.8 million of the settlement representing reimbursement of costs incurred through 2015 for project planning, and in March 2018 we received $0.5 million for costs incurred between January 2016 and June 2017. We expect the majority of the remaining cost to construct the dry cask storage facility that would not have otherwise been incurred will be reimbursed by the DOE. 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.

TCJA Refund Liability

In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities and directed Kansas utilities to record a liability for the difference between the cost of service as approved in its most recent rate review and the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the rate approved in the TCJA. We believe it is probable that we will be required to return these amounts to customers. We also believe it is probable that we will be required to return amounts to our transmission customers. See Note 5, “Rate Matters and Regulation,” for additional information.

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Legal Proceedings

3 Months Ended

Mar. 31, 2018

Legal Proceedings [Abstract]

Legal Proceedings

LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our condensed consolidated financial results. See Notes 5 and 10, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.

Pending Merger

Following the announcement of the original merger agreement in May 2016, two putative class action petitions (which were consolidated and superseded by a consolidated class action petition) and one putative derivative petition challenging the original merger were filed in the District Court of Shawnee County, Kansas. In September 2016, the plaintiffs in both actions agreed in principle to dismiss the actions in exchange for our agreement to make supplemental disclosures to shareholders in connection with the original merger agreement and grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in a sale process that was conducted as part of the original merger agreement. As described below, after the announcement of the revised merger agreement, the plaintiffs in the consolidated putative class action moved to amend their petition, and the plaintiff in the putative derivative case refiled his petition.

The consolidated putative class action petition, originally filed July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This petition named as defendants Westar Energy, the members of our board of directors and Great Plains Energy.

On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an amended petition. The petition as amended now includes an additional plaintiff. The petition challenges the revised proposed merger and alleges a claim of breach of fiduciary duty against our board of directors and a claim of aiding and abetting that alleged breach against us and Great Plains Energy. The lawsuit seeks injunctive relief declaring the action maintainable as a class action and certifying that the plaintiffs are the class representatives; preliminarily and permanently enjoining the defendants from closing the merger unless we implement a procedure to obtain a merger agreement providing fair and reasonable terms and consideration to the plaintiffs and the class; rescinding the merger agreement or granting the plaintiffs and the class rescissory damages; directing our board of directors to account to the plaintiffs and the class for damages suffered as a result of the alleged breach of fiduciary duty; awarding the plaintiffs reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The petition alleges inadequacies in our joint proxy statement concerning the revised proposed transaction and the degree to which our board of directors solicited or considered offers from prior bidders after the proposed original merger was denied by the KCC, and claims that the consideration our stockholders stand to receive in connection with the revised proposed transaction is unfair. Plaintiffs have added two new defendants, Monarch Energy Holding, Inc. and King Energy, Inc., whom they allege aided and abetted our board of directors in breaching their fiduciary duties.

On October 18, 2017, the putative derivative petition, captioned Braunstein v. Chandler et al., Case No. 2017-CV-000692, was re-filed in the District Court of Shawnee County, Kansas. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy, and subsidiaries of Great Plains Energy, with Westar Energy named as a nominal defendant. The petition asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with actions taken after the KCC rejected the proposed original merger. It also asserts that Great Plains Energy and subsidiaries of Great Plains Energy aided and abetted such breaches of fiduciary duties. The petition alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that members of our board of directors committed waste by not collecting termination fees that may have been payable following the KCC’s rejection of the original merger agreement. The petition seeks, among other remedies, an order enjoining the merger on the terms proposed and directing that the director defendants exercise their fiduciary duties to obtain a transaction, which is in the best interests of us and our shareholders, a declaration that the proposed merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement if consummated, the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and an award for costs, including attorneys’ fees and experts’ fees.

In addition, on September 21, 2017, a putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned David Pill v. Westar Energy, Inc. et al, Civil Action No. 17-4086. The federal class action complaint challenges the merger and alleges violations of sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended (Exchange Act). The complaint seeks an order declaring that the action is maintainable as a class action and certifying that the plaintiff is the class representative; preliminarily and permanently enjoining defendants from consummating the mergers or, if consummated, setting them aside and awarding rescissory damages; directing the defendants to file a registration statement on Form S-4 that corrects alleged misstatements; directing our board of directors to account to plaintiff and the class for their damages; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other further relief as the court deems proper.

On October 6, 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned Robert L. Reese v. Westar Energy, Inc. et al, Civil Action No. 2:17-cv-02584. This federal class action complaint challenges the proposed merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act. The complaint seeks an order enjoining the board and other parties from proceeding with, consummating, or closing the merger or, if consummated, setting it aside and awarding rescissory damages; directing the board to disseminate a registration statement that corrects alleged misstatements and includes all material facts the plaintiff asserts are missing; declaring that the defendants violated sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper.

On November 16, 2017, the parties in each of the actions 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 for the supplemental disclosures that we filed in a Form 8-K on November 16, 2017. 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. The outcome of litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2018

Variable Interest Entities [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITY

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trust holding our 50% interest in La Cygne unit 2 is a VIE 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 entity. We also continuously assess whether we are the primary beneficiary of the VIE with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.

50% Interest in La Cygne Unit 2

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

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

the agreement is greater than the fixed amount.

Financial Statement Impact

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entity, net	$	174,500	$	176,279
Liabilities:
Current maturities of long-term debt of variable interest entity	$	30,337	$	28,534
Accrued interest (a)	—		659
Long-term debt of variable interest entity, net	51,096		81,433

_______________

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

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

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Summary Of Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Trade and Other Accounts Receivable, Policy [Policy Text Block]

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. For the three months ended March 31, 2018 and 2017, we recorded bad debt expense related to contracts with customers of $4.0 million and $3.2 million, respectively.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Revenue is recognized primarily at the time we deliver electricity or provide transmission service to customers. The time of delivery of electricity is generally when our obligation to provide service is satisfied. Sales tax and franchise fees that we collect concurrent with revenue-producing activities are excluded from revenue. For more information on revenue recognition, see Note 4, “Revenue.”

We determine the amount of electricity delivered to 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 energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $68.2 million and $76.7 million as of March 31, 2018, and December 31, 2017, respectively.

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

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

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is applied on a retrospective basis. The guidance permits and we elected upon adoption to use a practical expedient that allows us to use the amounts disclosed in Note 8, “Pension and Post-Retirement Benefit Plans,” for applying the retrospective presentation of the 2017 condensed consolidated statement of income. As a result, we retrospectively decreased operating, maintenance, and administrative expense by $5.0 million and increased other expense by $5.0 million for the three months endedMarch 31, 2017. The new standard is effective for annual periods beginning after December 15, 2017. We adopted the guidance for the Westar Energy pension and post-retirement benefit plans as of January 1, 2018, without a material impact on our condensed consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued 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 corporate-owned life insurance (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. Retrospective application is required. We adopted the guidance effective January 1, 2018, which resulted in retrospective reclassification of cash proceeds of $1.3 million from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities for the three months endedMarch 31, 2017. In addition, cash payments of $0.9 millionfor premiums on COLI policies were reclassified from cash outflows used in operating activities to cash outflows used in investing activities for the same period.

In November 2016, the FASB issued ASU No. 2016-18, which requires that statement of cash flows explain the change for the period of restricted cash and restricted cash equivalents along with cash and cash equivalents. The guidance requires a retrospective transition method and is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018. As a result, we adjusted amounts previously reported for cash and cash equivalents to include restricted cash which resulted in an increase to beginning and ending cash, cash equivalents and restricted cash of $0.1 million for the three months endedMarch 31, 2017.

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 power purchase agreements, and will analyze the related impact. The standard permits an entity to elect a practical expedient for existing or expired contracts to forgo reassessing leases to determine whether each is in scope of the new standard and to forgo reassessing lease classification. We expect to elect this practical expedient upon implementation.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, which generally requires equity investments to be measured at fair value with changes in fair value recognized in net income. Under the new standard, equity securities are no longer to be classified as available-for-sale or trading securities. The guidance requires a modified retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018, without a material impact on our condensed consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018. The standard permits the use of either the retrospective application or modified retrospective method. We elected to use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Adoption of the standard did not have a material impact to our condensed consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard. For more information on revenue recognition, see Note 4, “Revenue.”

Principles Of Consolidation

Principles of Consolidation

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

Use Of Management's Estimates

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months endedMarch 31, 2018, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory And Supplies

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost.

Allowance For Funds Used During Construction

Allowance for Funds Used During Construction

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

Earnings Per Share

Earnings Per Share

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

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

Supplemental Cash Flow Information

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	33,043		$	35,644
Interest on financing activities of VIEs	1,319			1,696
Income taxes, net of refunds	(231		)	(13,000		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	29,790			97,196
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	149			2,349
Assets acquired through capital leases	48			293

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Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Schedule of Utility Inventory

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Fuel inventory	$	89,125	$	94,039
Supplies	197,706		199,523
Fuel inventory and supplies	$	286,831	$	293,562

Allowance For Funds Used During Construction

on the accompanying condensed consolidated statements of income as follows:

	Three Months Ended March 31,
	2018			2017
	(Dollars In Thousands)
Borrowed funds	$	1,403		$	1,853
Equity funds	1,097			775
Total	$	2,500		$	2,628
Average AFUDC Rates	3.6		%	2.2		%

Reconciliation Of Basic And Diluted EPS

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

	Three Months Ended March 31,
	2018		2017
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	62,904	$	63,482
Less: Net income attributable to noncontrolling interests	2,419		3,821
Net income attributable to Westar Energy, Inc.	60,485		59,661
Less: Net income allocated to RSUs	104		108
Net income allocated to common stock	$	60,381	$	59,553
Weighted average equivalent common shares outstanding – basic	142,635,490		142,436,622
Effect of dilutive securities:
RSUs	16,090		258,984
Weighted average equivalent common shares outstanding – diluted (a)	142,651,580		142,695,606
Earnings per common share, basic	$	0.42	$	0.42
Earnings per common share, diluted	$	0.42	$	0.42

_______________

(a)We had no antidilutive securities for the three months endedMarch 31, 2018 and 2017.

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	33,043		$	35,644
Interest on financing activities of VIEs	1,319			1,696
Income taxes, net of refunds	(231		)	(13,000		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	29,790			97,196
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	149			2,349
Assets acquired through capital leases	48			293

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Revenue (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from External Customers by Products and Services [Table Text Block]

The following table categorizes our revenue by class of customer.

	Three Months Ended March 31,
	2018			2017
	(In Thousands)
REVENUES:
Residential	$	180,285		$	169,290
Commercial	155,403			149,552
Industrial	93,460			94,589
Other retail	4,253			5,042
Total Retail Revenues	433,401			418,473
Wholesale	94,209			83,925
Transmission	71,926			70,729
Other	1,781			1,611
Total Revenue from Contracts with Customers	601,317			574,738
Other	(1,113		)	(2,164		)
Total Revenues	$	600,204		$	572,574

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Financial Instruments and Investments (Tables)

3 Months Ended

Mar. 31, 2018

Financial And Derivative Instruments and Investments [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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

	As of March 31, 2018				As of December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,605,000	$	3,759,785	$	3,605,000	$	3,888,620
Fixed-rate debt of VIEs	81,433		80,557		109,967		110,756

Fair Value Of Assets And Liabilities

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

As of March 31, 2018	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,449	$	—	$	5,323	$	73,772
International equity funds	—		45,130		—		—		45,130
Core bond fund	—		37,492		—		—		37,492
High-yield bond fund	—		19,713		—		—		19,713
Emerging markets bond fund	—		17,337		—		—		17,337
Combination debt/equity/other fund	—		13,973		—		—		13,973
Alternative investments fund	—		—		—		22,521		22,521
Real estate securities fund	—		—		—		11,024		11,024
Cash equivalents	191		—		—		—		191
Total Nuclear Decommissioning Trust	191		202,094		—		38,868		241,153
Rabbi Trust:
Core bond fund	—		25,670		—		—		25,670
Combination debt/equity/other fund	—		6,418		—		—		6,418
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		32,088		—		—		32,244
Total Assets Measured at Fair Value	$	347	$	234,182	$	—	$	38,868	$	273,397
As of December 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	68,658	$	—	$	5,142	$	73,800
International equity funds	—		47,908		—		—		47,908
Core bond fund	—		33,250		—		—		33,250
High-yield bond fund	—		18,089		—		—		18,089
Emerging markets bond fund	—		17,345		—		—		17,345
Combination debt/equity/other fund	—		14,125		—		—		14,125
Alternative investments fund	—		—		—		21,669		21,669
Real estate securities fund	—		—		—		10,806		10,806
Cash equivalents	110		—		—		—		110
Total Nuclear Decommissioning Trust	110		199,375		—		37,617		237,102
Rabbi Trust:
Core bond fund	—		27,324		—		—		27,324
Combination debt/equity/other fund	—		6,831		—		—		6,831
Cash equivalents	156		—		—		—		156
Total Rabbi Trust	156		34,155		—		—		34,311
Total Assets Measured at Fair Value	$	266	$	233,530	$	—	$	37,617	$	271,413

Investments In Financial Instruments

The following table provides additional information on these investments.

	As of March 31, 2018				As of December 31, 2017				As of March 31, 2018
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,323	$	2,508	$	5,142	$	2,808	(a)	(a)
Alternative investments fund (b)	22,521		—		21,669		—		Quarterly	65 days
Real estate securities fund (b)	11,024		—		10,806		—		Quarterly	65 days
Total	$	38,868	$	2,508	$	37,617	$	2,808

_______________

(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. Three funds have begun to make distributions. Our initial investment in the fourth fund occurred in 2016.This fund’s term 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.

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Pension and Post-Retirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,826		$	5,218		$	279		$	271
Interest cost (a)	10,207			10,621			1,183			1,314
Expected return on plan assets (a)	(11,091		)	(10,760		)	(1,728		)	(1,718		)
Amortization of unrecognized:
Prior service costs (a)	166			171			114			114
Actuarial loss (gain), net (a)	6,485			5,489			(135		)	(195		)
Net periodic cost (benefit) before regulatory adjustment	11,593			10,739			(287		)	(214		)
Regulatory adjustment (b)	2,849			3,288			(434		)	(478		)
Net periodic cost (benefit)	$	14,442		$	14,027		$	(721	)	$	(692	)

 _______________

(a) The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

(b) 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.

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

3 Months Ended

Mar. 31, 2018

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,826		$	5,218		$	279		$	271
Interest cost (a)	10,207			10,621			1,183			1,314
Expected return on plan assets (a)	(11,091		)	(10,760		)	(1,728		)	(1,718		)
Amortization of unrecognized:
Prior service costs (a)	166			171			114			114
Actuarial loss (gain), net (a)	6,485			5,489			(135		)	(195		)
Net periodic cost (benefit) before regulatory adjustment	11,593			10,739			(287		)	(214		)
Regulatory adjustment (b)	2,849			3,288			(434		)	(478		)
Net periodic cost (benefit)	$	14,442		$	14,027		$	(721	)	$	(692	)

 _______________

(a) The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

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

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,220		$	1,950		$	36		$	37
Interest cost	2,478			2,475			61			70
Expected return on plan assets	(2,891		)	(2,643		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,656			1,245			(14		)	(13		)
Net periodic cost before regulatory adjustment	3,477			3,041			83			94
Regulatory adjustment (a)	(49		)	247			—			—
Net periodic cost	$	3,428		$	3,288		$	83		$	94

 _______________

(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.

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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2018

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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

	As of		As of
	March 31, 2018		December 31, 2017
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entity, net	$	174,500	$	176,279
Liabilities:
Current maturities of long-term debt of variable interest entity	$	30,337	$	28,534
Accrued interest (a)	—		659
Long-term debt of variable interest entity, net	51,096		81,433

_______________

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

XML

Description Of Business (Details)	3 Months Ended
	Mar. 31, 2018 Customers
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of customers in Kansas	710,000

XML

Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Public Utilities, Inventory [Line Items]
Total	$ 286,831	$ 293,562
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utilities Inventory	89,125	94,039
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utilities Inventory	$ 197,706	$ 199,523

XML

Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
Borrowed funds	$ (1,403)	$ (1,853)
Equity funds	1,097	775
Total	$ 2,500	$ 2,628
Average AFUDC rates	3.60%	2.20%

XML

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
Net Income Allocated to RSUs	$ 104	$ 108
Net income allocated to common stock	$ 60,381	$ 59,553
Weighted Average Number of Shares Outstanding , Basic	142,635,490	142,436,622
RSUs	16,090	258,984
Weighted average equivalent common shares outstanding - diluted	142,651,580	142,695,606
Earnings Per Share, Basic	$ 0.42	$ 0.42
Earnings Per Share, Diluted	$ 0.42	$ 0.42
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	0	0

XML

Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Paid For (Received From)
Interest on financing activities	$ 33,043	$ 35,644
Income Taxes Paid, Net	(231)	(13,000)
Noncash Investing and Financing Transactions
Property, plant and equipment	29,790	97,196
Issuance of common stock for reinvested dividends and compensation plans	149	2,349
Assets acquired through capital leases	48	293
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 1,319	$ 1,696

XML

Summary Of Significant Accounting Policies Summary Of Significant Accounting Policies (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Unbilled Receivables, Current

$ 68,200

$ 76,700

Allowance for Doubtful Accounts Receivable

$ 4,000

$ 3,200

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

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

Compensation - Retirement Benefits

In March 2017, the FASB issued Accounting Standard Update (ASU) No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is applied on a retrospective basis. The guidance permits and we elected upon adoption to use a practical expedient that allows us to use the amounts disclosed in Note 8, “Pension and Post-Retirement Benefit Plans,” for applying the retrospective presentation of the 2017 condensed consolidated statement of income. As a result, we retrospectively decreased operating, maintenance, and administrative expense by $5.0 million and increased other expense by $5.0 million for the three months endedMarch 31, 2017. The new standard is effective for annual periods beginning after December 15, 2017. We adopted the guidance for the Westar Energy pension and post-retirement benefit plans as of January 1, 2018, without a material impact on our condensed consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued 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 corporate-owned life insurance (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. Retrospective application is required. We adopted the guidance effective January 1, 2018, which resulted in retrospective reclassification of cash proceeds of $1.3 million from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities for the three months endedMarch 31, 2017. In addition, cash payments of $0.9 millionfor premiums on COLI policies were reclassified from cash outflows used in operating activities to cash outflows used in investing activities for the same period.

In November 2016, the FASB issued ASU No. 2016-18, which requires that statement of cash flows explain the change for the period of restricted cash and restricted cash equivalents along with cash and cash equivalents. The guidance requires a retrospective transition method and is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018. As a result, we adjusted amounts previously reported for cash and cash equivalents to include restricted cash which resulted in an increase to beginning and ending cash, cash equivalents and restricted cash of $0.1 million for the three months endedMarch 31, 2017.

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 power purchase agreements, and will analyze the related impact. The standard permits an entity to elect a practical expedient for existing or expired contracts to forgo reassessing leases to determine whether each is in scope of the new standard and to forgo reassessing lease classification. We expect to elect this practical expedient upon implementation.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, which generally requires equity investments to be measured at fair value with changes in fair value recognized in net income. Under the new standard, equity securities are no longer to be classified as available-for-sale or trading securities. The guidance requires a modified retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018, without a material impact on our condensed consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on January 1, 2018. The standard permits the use of either the retrospective application or modified retrospective method. We elected to use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Adoption of the standard did not have a material impact to our condensed consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard. For more information on revenue recognition, see Note 4, “Revenue.”

Operating, maintenance, and administrative

$ 139,993

135,319

Proceeds from investment in corporate-owned life insurance

2,559

1,414

Investment in corporate-owned life insurance

$ 998

913

Accounting Standards Update 2017-07 [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Operating, maintenance, and administrative

5,000

Operating, maintenance, and administrative

5,000

Accounting Standards Update 2016-15 [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Proceeds from investment in corporate-owned life insurance

1,300

Investment in corporate-owned life insurance

900

Accounting Standards Update 2016-18 [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Increase (Decrease) in Restricted Cash and Investments

$ 100

XML

Pending Merger Pending Merger (Narrative) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Jul. 09, 2017
Westar Energy [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio				1
Business Acquisition, Percentage of Voting Interests Acquired				52.50%
Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Share Conversion Ratio				0.5981
Business Acquisition, Dividend Restriction				$ 0.40
Business Combination, Acquisition Related Costs		$ 0.4	$ 0.4
Business Combination, Expected Acquisition Related Costs		40.0
Business Acquisition, Percentage of Voting Interests Acquired				47.50%
Required cash balance at closing of anticipated merger				$ 1,250.0
Great Plains Energy breaches merger agreement and enters into acquisition proposal within 12 months of termination [Member] [Domain] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				190.0
Failure to receive regulatory approval prior to end date and all conditions precedent to closing have been satisfied [Member] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				190.0
Westar Energy breaches agreement and enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Member] [Domain] | Westar Energy [Member]
Business Combination [Line Items]
Business Combination Merger Contract Termination Fee				$ 190.0
Kansas Corporation Commission [Member]
Business Combination [Line Items]
One time customer bill credit	$ 23.0
Merger annual bill credits	8.6
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 23.2
Public Utilities, Requested Return on Equity, Percentage	9.30%
Maximum [Member] | Great Plains Energy, Inc. Merger [Member]
Business Combination [Line Items]
Business Combination, Expected Acquisition Related Costs		$ 45.0
Holding Company [Member] | Maximum [Member] | Kansas Corporation Commission [Member]
Business Combination [Line Items]
Public Utilities, Requested Debt Capital Structure, Percentage	0.00%
Westar Energy [Member] | Maximum [Member] | Kansas Corporation Commission [Member]
Business Combination [Line Items]
Public Utilities, Requested Debt Capital Structure, Percentage	0.00%
Business Combination Savings [Member] | Kansas Corporation Commission [Member]
Business Combination [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 22.5

XML

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenue from Contract with Customer, Excluding Assessed Tax	$ 601,317	$ 574,738
Revenues	600,204	572,574
Residential [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	180,285	169,290
Commercial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	155,403	149,552
Industrial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	93,460	94,589
Other retail [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	4,253	5,042
Total retail [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	433,401	418,473
Wholesale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	94,209	83,925
Transmission [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	71,926	70,729
Other revenue [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	1,781	1,611
Other revenue [Member]
Revenues	$ (1,113)	$ (2,164)

XML

Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended
	Apr. 30, 2018	Mar. 31, 2018	Feb. 28, 2018	Mar. 31, 2018	Apr. 01, 2018	Jan. 31, 2017
Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Return on Equity, Percentage		9.30%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (23.2)
Federal Energy Regulatory Commission [Member] | Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 25.5
Federal Energy Regulatory Commission [Member] | Electric Transmission [Member] | Subsequent Event [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 2.3
Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		37.0
Kansas Corporation Commission [Member] | Subsequent Event [Member]
Regulatory Proceedings [Line Items]
Estimated Increase In Annual Retail Revenues For Transmission Costs					$ 31.5
Kansas Corporation Commission [Member] | Ad Valorem Tax [Member]
Regulatory Proceedings [Line Items]
Estimated Increase In Annual Revenues For Property Tax						$ 0.2
Phase One [Member] | Kansas Corporation Commission [Member] | General Rate Case [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 2.0
Phase Two [Member] | Kansas Corporation Commission [Member] | General Rate Case [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 54.0
Effect of TCJA [Domain] | Federal Energy Regulatory Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				3.9
Customer Refund Liability, Current		3.9		3.9
Effect of TCJA [Domain] | Kansas Corporation Commission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				15.1
Customer Refund Liability, Current		$ 15.1		$ 15.1

XML

Financial Instruments and Investments (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 3,605,000	$ 3,605,000
Fair Value	3,759,785	3,888,620
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	81,433	109,967
Fair Value	$ 80,557	$ 110,756

XML

Financial Instruments and Investments (Fair Value Of Assets And Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Financial and Derivative Instruments and Investments [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period	15 years
Nuclear decommissioning trust assets	$ 241,153	$ 237,102
Total assets measured at fair value	273,397	271,413
Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	73,772	73,800
International Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	45,130	47,908
Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	37,492	33,250
High-Yield Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	19,713	18,089
Emerging Market Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	17,337	17,345
Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	13,973	14,125
Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	22,521	21,669
Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	11,024	10,806
Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	191	110
fair value, inputs, net asset value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	38,868	37,617
Total assets measured at fair value	38,868	37,617
fair value, inputs, net asset value [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	5,323	5,142
fair value, inputs, net asset value [Member] | International Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
fair value, inputs, net asset value [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
fair value, inputs, net asset value [Member] | High-Yield Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
fair value, inputs, net asset value [Member] | Emerging Market Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
fair value, inputs, net asset value [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
fair value, inputs, net asset value [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	22,521	21,669
fair value, inputs, net asset value [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	11,024	10,806
fair value, inputs, net asset value [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	191	110
Total assets measured at fair value	347	266
Fair Value, Inputs, Level 1 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | International Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | High-Yield Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Emerging Market Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 1 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	191	110
Fair Value, Inputs, Level 2 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	202,094	199,375
Total assets measured at fair value	234,182	233,530
Fair Value, Inputs, Level 2 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	68,449	68,658
Fair Value, Inputs, Level 2 [Member] | International Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	45,130	47,908
Fair Value, Inputs, Level 2 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	37,492	33,250
Fair Value, Inputs, Level 2 [Member] | High-Yield Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	19,713	18,089
Fair Value, Inputs, Level 2 [Member] | Emerging Market Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	17,337	17,345
Fair Value, Inputs, Level 2 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	13,973	14,125
Fair Value, Inputs, Level 2 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 2 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 2 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Total assets measured at fair value	0	0
Fair Value, Inputs, Level 3 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | International Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | High-Yield Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Emerging Market Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	0	0
Fair Value, Inputs, Level 3 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	$ 0	$ 0

XML

Financial Instruments and Investments (Investments In Financial Instruments) (Details) - USD ($)		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Financial and Derivative Instruments and Investments [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period		15 years
Nuclear decommissioning trust assets		$ 241,153,000		$ 237,102,000
Total		273,397,000		271,413,000
Fair Value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		38,868,000		37,617,000
Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		37,492,000		33,250,000
Decommissioning Trust Assets [Member] | Fair Value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments		2,508,000		2,808,000
Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		73,772,000		73,800,000
Domestic Equity Funds [Member] | Fair Value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	[1]	5,323,000		5,142,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	[1]	2,508,000		2,808,000
Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		22,521,000		21,669,000
Alternative Funds [Member] | Fair Value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	[2]	22,521,000		21,669,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	[2]	$ 0		0
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period		65 days
Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		$ 11,024,000		10,806,000
Real Estate Securities Fund [Member] | Fair Value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets	[2]	11,024,000		10,806,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	[2]	$ 0		0
Investment redemption frequency		Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period		65 days
Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		$ 13,973,000		14,125,000
Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		191,000		110,000
Fair Value, Inputs, Level 1 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		191,000		110,000
Total		347,000		266,000
Fair Value, Inputs, Level 1 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 1 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 1 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 1 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 1 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 1 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		191,000		110,000
Fair Value, Inputs, Level 2 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		202,094,000		199,375,000
Total		234,182,000		233,530,000
Fair Value, Inputs, Level 2 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		37,492,000		33,250,000
Fair Value, Inputs, Level 2 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		68,449,000		68,658,000
Fair Value, Inputs, Level 2 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 2 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 2 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		13,973,000		14,125,000
Fair Value, Inputs, Level 2 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Total		0		0
Fair Value, Inputs, Level 3 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Fair Value, Inputs, Level 3 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
Rabbi Trust [Member]
Financial and Derivative Instruments and Investments [Line Items]
Unrealized Gain (Loss) on Securities		400,000	$ (1,400,000)
Total		32,244,000		34,311,000
Rabbi Trust [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		25,670,000		27,324,000
Rabbi Trust [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		6,418,000		6,831,000
Rabbi Trust [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		156,000		156,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		156,000		156,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 1 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 1 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 1 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		156,000		156,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		32,088,000		34,155,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 2 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		25,670,000		27,324,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 2 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		6,418,000		6,831,000
Rabbi Trust [Member] | Fair Value, Inputs, Level 2 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 3 [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 3 [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 3 [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
Rabbi Trust [Member] | Fair Value, Inputs, Level 3 [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
nuclear decommissioning trust [Member]
Financial and Derivative Instruments and Investments [Line Items]
Unrealized Gain (Loss) on Securities		100,000	$ (9,000,000)
fair value, inputs, net asset value [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		38,868,000		37,617,000
Total		38,868,000		37,617,000
fair value, inputs, net asset value [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
fair value, inputs, net asset value [Member] | Domestic Equity Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		5,323,000		5,142,000
fair value, inputs, net asset value [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		22,521,000		21,669,000
fair value, inputs, net asset value [Member] | Real Estate Securities Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		11,024,000		10,806,000
fair value, inputs, net asset value [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
fair value, inputs, net asset value [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Nuclear decommissioning trust assets		0		0
fair value, inputs, net asset value [Member] | Rabbi Trust [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
fair value, inputs, net asset value [Member] | Rabbi Trust [Member] | Core Bonds Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
fair value, inputs, net asset value [Member] | Rabbi Trust [Member] | Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		0		0
fair value, inputs, net asset value [Member] | Rabbi Trust [Member] | Cash Equivalents [Member]
Financial and Derivative Instruments and Investments [Line Items]
Total		$ 0		$ 0

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

[2] There is a holdback on final redemptions.

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Taxes Taxes (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Tax Contingency [Line Items]
Income tax expense	$ 9,174,000	$ 20,911,000
Effective income tax rate	13.00%	25.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%		35.00%
Liability for unrecognized income tax benefits	$ 1,700,000		$ 1,700,000
Interest on liability related to unrecognized income tax benefits	0		100,000
Penalties accrued for unrecognized income tax benefits	0		0
Accrual for taxes other than income taxes	$ 500,000		$ 400,000

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Pension and Post-Retirement Benefit Plans (Net Periodic Costs And Pension Contributions) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Components of Net Periodic Cost (Benefit):
Payment for Pension Benefits		$ 12,500	$ 7,000
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost		5,826	5,218
Interest cost	[1]	10,207	10,621
Expected return on plan assets	[1]	(11,091)	(10,760)
Prior service costs	[1]	166	171
Actuarial loss, net	[1]	6,485	5,489
Net periodic cost before regulatory adjustment		11,593	10,739
Regulatory adjustment	[2]	2,849	3,288
Net periodic cost		14,442	14,027
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost		279	271
Interest cost	[1]	1,183	1,314
Expected return on plan assets	[1]	(1,728)	(1,718)
Prior service costs	[1]	114	114
Actuarial loss, net	[1]	(135)	(195)
Net periodic cost before regulatory adjustment		(287)	(214)
Regulatory adjustment	[2]	(434)	(478)
Net periodic cost		$ (721)	$ (692)

[1] The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

[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.

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Wolf Creek Pension and Post-Retirement Benefit Plans Wolf Creek Pension and Post-Retirement Benefit Plans (Net Periodic Costs and Pension Contributions) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Components of Net Periodic Cost (Benefit):
Payment for Pension Benefits		$ 12,500	$ 7,000
Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Payment for Pension Benefits		$ 0	0
KGE [Member]
Subsidiary Interest in Defined Benefit Plans		47.00%
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost		$ 5,826	5,218
Interest cost	[1]	10,207	10,621
Expected return on plan assets	[1]	(11,091)	(10,760)
Prior service costs	[1]	166	171
Actuarial loss, net	[1]	6,485	5,489
Net periodic cost before regulatory adjustment		11,593	10,739
Regulatory adjustment	[2]	2,849	3,288
Net periodic cost		14,442	14,027
Pension Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost		2,220	1,950
Interest cost		2,478	2,475
Expected return on plan assets		(2,891)	(2,643)
Prior service costs		14	14
Actuarial loss, net		1,656	1,245
Net periodic cost before regulatory adjustment		3,477	3,041
Regulatory adjustment	[3]	(49)	247
Net periodic cost		3,428	3,288
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost		279	271
Interest cost	[1]	1,183	1,314
Expected return on plan assets	[1]	(1,728)	(1,718)
Prior service costs	[1]	114	114
Actuarial loss, net	[1]	(135)	(195)
Net periodic cost before regulatory adjustment		(287)	(214)
Regulatory adjustment	[2]	(434)	(478)
Net periodic cost		(721)	(692)
Post-Retirement Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost		36	37
Interest cost		61	70
Expected return on plan assets		0	0
Prior service costs		0	0
Actuarial loss, net		(14)	(13)
Net periodic cost before regulatory adjustment		83	94
Regulatory adjustment	[3]	0	0
Net periodic cost		$ 83	$ 94

[1] The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.

[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.

[3] 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.

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Commitments And Contingencies Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions	Mar. 01, 2018	Jun. 02, 2017
Commitments and Contingencies Disclosure [Abstract]
Settlement Assets, Current	$ 0.5	$ 0.8

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Variable Interest Entities (Narrative) (Details)	3 Months Ended
	Mar. 31, 2018 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Initial Consolidation, Gain (Loss)	$ 0
La Cygne Generating Station [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	50.00%
Agreement expiration date	Sep. 01, 2029

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Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Property, plant and equipment, net	$ 9,589,164	$ 9,553,755
Accrued interest	91,741	72,693
Long-term debt, net	3,688,257	3,687,555
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Property, plant and equipment, net	174,500	176,279
Current maturities of long-term debt	30,337	28,534
Accrued interest	0	659
Long-term debt, net	$ 51,096	$ 81,433

XML

Label	Element	Value
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	$ 3,156,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	3,520,000
Restricted Cash	us-gaap_RestrictedCash	90,000
Restricted Cash	us-gaap_RestrictedCash	$ 88,000