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 ~~September~~March 3031, ~~2017~~2018



[ ]	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,~~094~~233,~~176~~136 shares
(Class)		(Outstanding at ~~October~~May 251, ~~2017~~2018)

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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	98
	Condensed Consolidated Statements of Changes in Equity	109
	Notes to Condensed Consolidated Financial Statements	1110
	1. Description of Business	1110
	2. Summary of Significant Accounting Policies	1110
	3. Pending Merger	14
	4. Rate Matters and Regulation	16
	4. Revenue	16
	5. Financial Instruments and Trading Securities	16
	5. Rate Matters and Regulation	18
	6. Financial Investments	19
	6. Financial Instruments and Investments	19
	7. Debt Financing	21
	7. Taxes	21
	8. Taxes	21
	8. Pension and Post-Retirement Benefit Plans	22
	9. Pension and Post-Retirement Benefit Plans	22
	9. Wolf Creek Pension and Post-Retirement Benefit Plans	23
	10. Wolf Creek Pension and Post-Retirement Benefit Plans	23
	10. Commitments and Contingencies	24
	11. Commitments and Contingencies	24
	11. Legal Proceedings	27
	12. Asset Retirement Obligations	27
	12. Variable Interest Entity	28
	13. Legal Proceedings	27
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
	14. Variable Interest Entities	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 4.	Controls and Procedures	40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43
PART II. Other Information
Item 1.	Legal Proceedings	4341
Item 1A.	Risk Factors	4441
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4441
Item 3.	Defaults Upon Senior Securities	4441
Item 4.	Mine Safety Disclosures	4441
Item 5.	Other Information	4541
Item 6.	Exhibits	4541
Signature		4642

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GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition
2016 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2016
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
HSR Act		Hart-Scott-Rodino Antitrust Improvements Act
JEC		Jeffrey Energy Center
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
NOx		Nitrogen oxides
NRC		Nuclear Regulatory Commission
NSPS		New Source Performance Standard
PM		Particulate matter
RECA		Retail energy cost adjustment
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

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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 ~~the~~ 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,

- our inability to fully utilize expected tax credits,

- changes in accounting requirements and other accounting matters,

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- ~~changes~~risks inarising ~~the~~from ~~energy~~changes ~~markets~~ in ~~which~~federal ~~we participate such as the development~~ and ~~implementation~~state oftax ~~real~~laws, ~~time~~regulations and ~~next day trading markets~~interpretations, and ~~the~~related ~~effect~~actions ~~of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms~~ by ~~regional~~regulatory ~~transmission organizations (RTOs) and independent system operators~~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:

- receipt of approval from our shareholders and shareholders of Great Plains Energy,


-	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, ~~2016~~2017 (~~2016~~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 ~~2016~~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 ~~2016~~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.

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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
	September 30, 2017			December 31, 2016
	March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	311,~~388~~166		$	3,~~066~~432
Accounts receivable, net of allowance for doubtful accounts of $4,658 and $6,667, respectively	308,275			288,579
Accounts receivable, net of allowance for doubtful accounts of $9,288 and $6,716, respectively	244,411			290,652
Fuel inventory and supplies	~~285~~286,~~074~~831			~~300~~293,~~125~~562
Taxes receivable	—			13,000
Prepaid expenses	20,566			16,425
Prepaid expenses	15,781			16,528
Regulatory assets	95,580			99,544
Regulatory assets	94,777			117,383
Other	24,694			23,435
Other	25,754			29,701
Total Current Assets	683,248			727,050
Total Current Assets	733,049			768,382
PROPERTY, PLANT AND EQUIPMENT, NET	9,589,164			9,553,755
PROPERTY, PLANT AND EQUIPMENT, NET	9,494,023			9,248,359
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITY, NET	174,500			176,279
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	178,058			257,904
OTHER ASSETS:
Regulatory assets	~~748~~681,~~934~~036			~~762~~685,~~479~~355
Nuclear decommissioning trust	~~229~~241,~~927~~153			~~200~~237,~~122~~102
Other	~~241~~251,~~384~~268			~~249~~244,~~828~~827
Total Other Assets	1,~~220~~173,~~245~~457			1,~~212~~167,~~429~~284
TOTAL ASSETS	$	11,~~625~~620,~~375~~369		$	11,~~487~~624,~~074~~368
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	125,000
Current maturities of long-term debt of variable interest entity	$	30,337		$	28,534
Current maturities of long-term debt of variable interest entities	28,534			26,842
Short-term debt	289,800			275,700
Short-term debt	189,100			366,700
Accounts payable	139,308			204,186
Accounts payable	147,933			220,522
Accrued dividends	53,888			53,830
Accrued dividends	53,770			52,885
Accrued taxes	132,593			87,727
Accrued taxes	114,317			85,729
Accrued interest	91,741			72,693
Accrued interest	64,851			72,519
Regulatory liabilities	11,220			11,602
Regulatory liabilities	14,068			15,760
Other	81,462			89,445
Other	74,273			81,236
Total Current Liabilities	830,349			823,717
Total Current Liabilities	686,846			1,047,193
LONG-TERM LIABILITIES:
Long-term debt, net	3,~~686~~688,~~852~~257			3,~~388~~687,~~670~~555
Long-term debt of variable interest entities, net	81,433			111,209
Long-term debt of variable interest entity, net	51,096			81,433
Deferred income taxes	1824,~~866,583~~699			1815,~~752,776~~743
Unamortized investment tax credits	~~208~~256,~~597~~406			~~210~~257,~~654~~093
Regulatory liabilities	~~237~~1,~~065~~110,055			~~223~~1,~~693~~093,974
Accrued employee benefits	~~497~~533,~~298~~318			~~512~~541,~~412~~364
Asset retirement obligations	~~397~~382,~~505~~791			~~323~~379,~~951~~989
Other	8478,~~296~~952			83,~~326~~063
Total Long-Term Liabilities	76,~~059~~925,~~629~~574			6,~~606~~940,~~691~~214
COMMITMENTS AND CONTINGENCIES (See Notes 11 and 13)
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 142,094,176 shares and 141,791,153 shares, respective to each date	710,471			708,956
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,~~072~~451			2,~~018~~024,~~317~~396
Retained earnings	1,~~196~~176,~~460~~095			1,~~078~~173,~~602~~255
Total Westar Energy, Inc. Shareholders’ Equity	3,~~929~~909,~~003~~712			3,~~805~~908,~~875~~122
Noncontrolling Interests	(5045,~~103~~266		)	27(47,~~315~~685		)
Total Equity	3,~~878~~864,~~900~~446			3,~~833~~860,~~190~~437
TOTAL LIABILITIES AND EQUITY	$	11,~~625~~620,~~375~~369		$	11,~~487~~624,~~074~~368

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,
	Three Months Ended March 31,
	2017			2016
	2018			2017
REVENUES	$	~~794~~600,~~327~~204		$	~~764~~572,~~654~~574
OPERATING EXPENSES:
Fuel and purchased power	~~189~~135,~~804~~507			~~155~~113,~~673~~855
SPP network transmission costs	6267,~~578~~594			5760,~~939~~674
Operating and maintenance	79,856			86,758
Operating, maintenance and administrative	139,993			135,319
Depreciation and amortization	9489,~~668~~641			8488,~~972~~625
Selling, general and administrative	65,630			60,582
Taxes other than income tax	43,939			42,716
Taxes other than income tax	41,815			48,154
Total Operating Expenses	476,674			441,189
Total Operating Expenses	534,351			494,078
INCOME FROM OPERATIONS	123,530			131,385
INCOME FROM OPERATIONS	259,976			270,576
OTHER INCOME (EXPENSE):
Investment earnings	~~2,593~~999			23,~~619~~155
Other income	31,~~849~~951			131,~~353~~300
Other expense	(610,~~493~~561		)	(510,~~887~~352		)
Total Other (Expense) Income	(51		)	10,085
Total Other Expense	(7,611		)	(5,897		)
Interest expense	43,~~458~~841			4041,~~897~~095
INCOME BEFORE INCOME TAXES	~~216~~72,~~467~~078			~~239~~84,~~764~~393
Income tax expense	559,~~743~~174			8120,~~211~~911
NET INCOME	~~160~~62,~~724~~904			~~158~~63,~~553~~482
Less: Net income attributable to noncontrolling interests	2,~~418~~419			3,~~833~~821
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	~~158~~60,~~306~~485		$	~~154~~59,~~720~~661
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.11		$	1.09
Basic and diluted earnings per common share	$	0.42		$	0.42
Diluted earnings per common share	$	1.11		$	1.08
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,~~472~~635,~~987~~490			142,~~090~~436,~~706~~622
Diluted	142,~~516~~651,~~049~~580			142,~~577~~695,~~945~~606
DIVIDENDS DECLARED PER COMMON SHARE	$	0.40		$	0.3840

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
REVENUES	$	1,976,222		$	1,955,552
OPERATING EXPENSES:
Fuel and purchased power	415,449			374,361
SPP network transmission costs	185,015			173,925
Operating and maintenance	248,211			250,135
Depreciation and amortization	277,322			252,838
Selling, general and administrative	182,367			192,762
Taxes other than income tax	126,421			145,529
Total Operating Expenses	1,434,785			1,389,550
INCOME FROM OPERATIONS	541,437			566,002
OTHER INCOME (EXPENSE):
Investment earnings	8,384			6,916
Other income	5,672			26,212
Other expense	(14,457		)	(14,338		)
Total Other (Expense) Income	(401		)	18,790
Interest expense	128,232			121,011
INCOME BEFORE INCOME TAXES	412,804			463,781
Income tax expense	112,559			160,376
NET INCOME	300,245			303,405
Less: Net income attributable to noncontrolling interests	10,213			10,760
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	290,032		$	292,645
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	2.03		$	2.06
Diluted earnings per common share	$	2.03		$	2.05
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	142,458,586			142,039,320
Diluted	142,495,896			142,413,189
DIVIDENDS DECLARED PER COMMON SHARE	$	1.20		$	1.14

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016
	2018			2017
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	~~300~~62,~~245~~904		$	~~303~~63,~~405~~482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	~~277~~89,~~322~~641			~~252~~88,~~838~~625
Amortization of nuclear fuel	247,~~150~~716			228,~~518~~069
Amortization of deferred regulatory gain from sale leaseback	(41,~~121~~374		)	(41,~~121~~374		)
Gain on lease modification	(3,500		)	—
Amortization of corporate-owned life insurance	5,501			5,901
Amortization of corporate-owned life insurance	15,744			13,779
Non-cash compensation	2,507			2,468
Non-cash compensation	6,777			7,025
Net deferred income taxes and credits	3,803			19,011
Net deferred income taxes and credits	126,986			160,429
Allowance for equity funds used during construction	(1,097		)	(775		)
Allowance for equity funds used during construction	(1,094		)	(7,894		)
Payments for asset retirement obligations	(1,943		)	(961		)
Income from corporate-owned life insurance	(671		)	(1,311		)
Changes in working capital items:
Accounts receivable	~~(19~~46,~~696~~241		)	~~(64~~51,~~100~~547		)
Fuel inventory and supplies	156,~~515~~885			11(10,~~680~~581		)
Prepaid expenses and other current assets	613,~~287~~886			~~(385~~28,311		)
Accounts payable	(1024,~~044~~219		)	9(23,~~736~~135		)
Accrued taxes	3548,~~631~~674			4047,~~711~~775
Other current liabilities	(~~108~~11,~~503~~833		)	(6154,~~879~~223		)
Changes in other assets	~~20,085~~(724		)	(43,~~377~~290		)
Changes in other liabilities	523,~~538~~731			1310,~~208~~606
Cash Flows from Operating Activities	~~742~~259,~~322~~628			~~692~~236,~~573~~725
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(~~564~~174,~~622~~765		)	(~~821~~175,~~936~~400		)
Purchase of securities - trusts	(1585,~~262~~429		)	(434,~~252~~191		)
Sale of securities - trusts	1586,~~896~~060			445,~~326~~720
Investment in corporate-owned life insurance	(~~13,875~~998		)	(~~14,648~~913		)
Proceeds from investment in corporate-owned life insurance	~~265~~2,559			241,~~242~~414
Investment in affiliated company	—			(655		)
Other investing activities	(1,608		)	(2,354		)
Other investing activities	(3,411		)	(3,095		)
Cash Flows used in Investing Activities	(174,181		)	(175,724		)
Cash Flows used in Investing Activities	(581,009		)	(815,018		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	~~(177~~14,~~732~~100		)	(67140,~~402~~407		)
Proceeds from long-term debt	~~296,215~~—			~~396~~296,~~472~~475
Proceeds from long-term debt of variable interest entities	—			162,048
Retirements of long-term debt	—			(125,000		)
Retirements of long-term debt	(125,000		)	(50,000		)
Retirements of long-term debt of variable interest entity	(28,534		)	(26,840		)
Retirements of long-term debt of variable interest entities	(26,840		)	(190,357		)
Repayment of capital leases	(950		)	(800		)
Repayment of capital leases	(2,592		)	(2,327		)
Borrowings against cash surrender value of corporate-owned life insurance	721			910
Borrowings against cash surrender value of corporate-owned life insurance	53,422			55,952
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(1,735		)	—
Repayment of borrowings against cash surrender value of corporate-owned life insurance	—			(22,921		)
Issuance of common stock	—			470
Issuance of common stock	659			2,003
Distributions to shareholders of noncontrolling interests	—			(5,760		)
Distributions to shareholders of noncontrolling interests	(5,760		)	(2,551		)
Cash dividends paid	(57,438		)	(52,750		)
Cash dividends paid	(166,340		)	(152,787		)
Other financing activities	(3,877		)	(7,006		)
Other financing activities	(7,023		)	(4,979		)
Cash Flows used in Financing Activities	(77,713		)	(60,708		)
Cash Flows (used in) from Financing Activities	(160,991		)	123,151
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	7,734			293
NET INCREASE IN CASH AND CASH EQUIVALENTS	322			706
CASH, CASH EQUIVALENTS AND RESTRICTED CASH:
CASH AND CASH EQUIVALENTS:
Beginning of period, including restricted cash of $88 and $90, respectively	3,520			3,156
Beginning of period	3,066			3,231
End of period, including restricted cash of $88 and $90, respectively	$	11,254		$	3,449
End of period	$	3,388		$	3,937

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

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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 shares	~~Commonstock~~	Commonstock		~~Paid-incapital~~	Paid-incapital			~~Retainedearnings~~	Retainedearnings			~~Non-controllinginterests~~	Non-controllinginterests			~~Totalequity~~	Totalequity
Balance as of December 31, 2015	141,353,426		$	706,767		$	2,004,124			$	945,830			$	15,242			$	3,671,963
Balance as of December 31, 2016		141,791,153		$	708,956		$	2,018,317			$	1,078,602			$	27,315			$	3,833,190
Net income	—	—	—	—		—	—			~~292,645~~	59,661			~~10,760~~	3,821			~~303,405~~	63,482
Issuance of stock	~~40,441~~	8,646	~~202~~	43		~~1,801~~	427			—	—			—	—			~~2,003~~	470
Issuance of stock for compensation and reinvested dividends	~~350,016~~	247,834	~~1,750~~	1,239		~~5,565~~	1,110			—	—			—	—			~~7,315~~	2,349
Tax withholding related to stock compensation	—	—	—	—		~~(4,979~~	(7,006	)	)	—	—			—	—			~~(4,979~~	(7,006	)	)
Dividends declared on common stock($1.14 per share)	—		—			—				(163,002		)		—				(163,002		)
Dividends declared on common stock($0.40 per share)		—		—			—				(57,995		)		—				(57,995		)
Stock compensation expense	—	—	—	—		~~6,938~~	2,439			—	—			—	—			~~6,938~~	2,439
Distributions to shareholders of noncontrolling interests	—	—	—	—		—	—			—	—			~~(2,551~~	(5,760	)	)	~~(2,551~~	(5,760	)	)
Cumulative effect of accounting change - stock compensation	—		—			—				3,326				—				3,326
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 September 30, 2016	141,743,883		$	708,719		$	2,013,449			$	1,078,799			$	23,451			$	3,824,418
Balance as of December 31, 2017		142,094,275		$	710,471		$	2,024,396			$	1,173,255			$	(47,685	)		$	3,860,437
Balance as of December 31, 2016	141,791,153		$	708,956		$	2,018,317			$	1,078,602			$	27,315			$	3,833,190
Net income		—		—			—				60,485				2,419				62,904
Net income	—		—			—				290,032				10,213				300,245
Issuance of stock for compensation and reinvested dividends		138,828		695			(546		)		—				—				149
Issuance of stock	12,131		61			598				—				—				659
Tax withholding related to stock compensation		—		—			(3,877		)		—				—				(3,877		)
Issuance of stock for compensation and reinvested dividends	290,892		1,454			3,490				—				—				4,944
Dividends declared on common stock($0.40 per share)		—		—			—				(57,645		)		—				(57,645		)
Tax withholding related to stock compensation	—		—			(7,023		)		—				—				(7,023		)
Stock compensation expense		—		—			2,478				—				—				2,478
Dividends declared on common stock($1.20 per share)	—		—			—				(172,174		)		—				(172,174		)
Balance as of March 31, 2018		142,233,103		$	711,166		$	2,022,451			$	1,176,095			$	(45,266	)		$	3,864,446
Stock compensation expense	—		—			6,690				—				—				6,690
Deconsolidation of noncontrollinginterests	—		—			—				—				(81,871		)		(81,871		)
Distribution to shareholders of noncontrolling interests	—		—			—				—				(5,760		)		(5,760		)
Balance as of September 30, 2017	142,094,176		$	710,471		$	2,022,072			$	1,196,460			$	(50,103	)		$	3,878,900

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

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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 ~~707~~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 ~~entities~~entity (~~VIEs~~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 ~~2016~~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 ~~(RECA)~~ billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2017~~2018, are not necessarily indicative of the results to be expected for the full year.

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Fuel Inventory and Supplies

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

	As of		As of
	September 30, 2017		December 31, 2016
	March 31, 2018		December 31, 2017
	(In Thousands)
Fuel inventory	$	8789,~~429~~125	$	~~107~~94,~~086~~039
Supplies	197,~~645~~706		~~193~~199,~~039~~523
Fuel inventory and supplies	$	~~285~~286,~~074~~831	$	~~300~~293,~~125~~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 September 30,						Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016			2017			2016
	2018			2017
	(Dollars In Thousands)
Borrowed funds	$	1,~~210~~403		$	21,~~537~~853		$	~~3,958~~		$	~~6,884~~
Equity funds	~~321~~1,097			~~2,647~~775			~~1,094~~			~~7,894~~
Total	$	12,~~531~~500		$	52,~~184~~628		$	~~5,052~~		$	~~14,778~~
Average AFUDC Rates	23.26		%	32.62		%	~~2.0~~		%	~~4.2~~		%

Earnings Per Share

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

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

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

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

2017

2016

2017

2016

2018

2017

(Dollars In Thousands, Except Per Share Amounts)

Net income

~~160~~62,~~724~~904

~~158~~63,~~553~~482

~~300,245~~

~~303,405~~

Less: Net income attributable to noncontrolling interests

2,~~418~~419

3,~~833~~821

~~10,213~~

~~10,760~~

Net income attributable to Westar Energy, Inc.

~~158~~60,~~306~~485

~~154~~59,~~720~~661

~~290,032~~

~~292,645~~

Less: Net income allocated to RSUs

~~289~~104

~~325~~108

~~515~~

~~605~~

Net income allocated to common stock

~~158~~60,~~017~~381

~~154~~59,~~395~~553

~~289,517~~

~~292,040~~

Weighted average equivalent common shares outstanding – basic

142,~~472~~635,~~987~~490

142,~~090~~436,~~706~~622

~~142,458,586~~

~~142,039,320~~

Effect of dilutive securities:

RSUs

4316,~~062~~090

~~487~~258,~~239~~984

~~37,310~~

~~373,869~~

Weighted average equivalent common shares outstanding – diluted (a)

142,~~516~~651,~~049~~580

142,~~577~~695,~~945~~606

~~142,495,896~~

~~142,413,189~~

Earnings per common share, basic

10.1142

10.0942

~~2.03~~

~~2.06~~

Earnings per common share, diluted

10.1142

10.0842

~~2.03~~

~~2.05~~

_______________

(a) We had no antidilutive securities for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2017~~2018 and ~~2016~~2017.

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016
	2018			2017
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	~~108~~33,~~965~~043		$	~~100~~35,~~828~~644
Interest on financing activities of VIEs	31,~~061~~319			51,~~846~~696
Income taxes, net of refunds	(~~12,645~~231		)	(13,~~004~~000		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	~~112~~29,~~493~~790			9497,~~007~~196
Deconsolidation of property, plant and equipment of VIE	(72,901		)	—
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	~~4,944~~149			72,~~315~~349
Deconsolidation of VIE	(83,096		)	—
Assets acquired through capital leases	48			293
Assets acquired through capital leases	4,611			1,310

13Revenue 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 ~~pronouncements~~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 ~~to be~~ applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is ~~to be~~ applied on a retrospective basis. The 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 ended March 31, 2017. The new standard is effective for annual periods beginning after December 15, 2017. We ~~are~~adopted ~~evaluating~~ the guidance for the Westar Energy pension and dopost-retirement ~~not~~benefit ~~expect~~plans itas toof ~~have~~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 ended March 31, 2017. In addition, cash payments of $0.9 million for 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 ended March 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~~. Early~~; ~~application~~accordingly, ofwe adopted the new standard ison ~~permitted~~January ~~for fiscal years beginning after December 15~~1, ~~2016~~2018. The standard permits the use of either the retrospective application or modified retrospective method. We ~~will~~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. WeAdoption ~~have analyzed and documented the impact~~ of the ~~new revenue~~ standard ~~and~~did ~~related~~not ~~ASU’s~~have ~~for~~a ~~our~~material ~~significant~~impact ~~revenue~~to ~~streams~~our ~~including~~condensed ~~retail,~~consolidated ~~transmission~~financial ~~and~~statements ~~wholesale~~and, as ~~well~~a ~~as other less significant revenue streams. We also continue to monitor unresolved industry issues~~result, ~~including~~we ~~items~~recorded ~~related~~no tocumulative ~~contributions~~effect ~~in aid~~ of ~~construction,~~initially ~~collectability~~applying ~~and alternative revenue programs, and will analyze~~ the ~~related impacts to revenue recognition~~standard. WeFor ~~are~~more ~~finalizing~~information ~~our~~on ~~analysis of~~ revenue~~-related~~ ~~controls~~recognition, ~~and~~see ~~development~~Note ~~of revenue-related disclosure with an overarching emphasis on effective internal controls over financial reporting. Based upon our completed assessments~~4, ~~we do not expect the impact on our condensed consolidated financial statements to be material~~“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) ~~denied~~rejected ~~our~~the ~~and~~prior ~~Great Plains Energy’s merger application~~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 still to be determined. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into 0.5981 shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately 52.5% of the new holding company and Great Plains Energy’s shareholders are expected to own approximately 47.5% of the new holding company.

The closing of the merger is subject to conditions including, among others, approval of our shareholders representing a majority of the outstanding shares of our common stock; approval of Great Plains Energy’s shareholders representing two-thirds of the outstanding shares of Great Plains Energy common stock; clearance under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act); receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals

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doOn ~~not~~July ~~result~~9, ~~in a material adverse effect on Great Plains Energy or us~~2017, ~~after~~we ~~giving~~entered ~~effect~~into toan ~~the~~amended ~~merger,~~and ~~measured~~restated onagreement ~~the size~~ and ~~scale~~plan of ~~Westar~~merger ~~Energy~~with ~~and~~Great ~~its~~Plains ~~subsidiaries,~~Energy ~~taken~~that asprovides for a ~~whole);~~merger ~~effectiveness~~ of ~~the~~equals ~~registration~~between ~~statement for~~ the ~~shares~~two ofcompanies. Upon ~~the~~closing, ~~new~~each ~~holding company’s common stock to be~~ issued ~~to our shareholders~~ and ~~Great~~outstanding ~~Plains~~share ~~Energy’s~~of ~~shareholders~~our ~~upon~~common ~~consummation~~stock ofwill ~~the~~be ~~merger~~converted ~~and~~into ~~approval~~one ofshare ~~the listing~~ of ~~such~~common ~~shares~~stock ~~on the New York Stock Exchange; the receipt~~ of ~~tax~~a ~~opinions~~new byholding uscompany ~~and~~with ~~Great~~a ~~Plains~~final ~~Energy~~name ~~that~~yet ~~the~~to ~~merger will~~ be ~~treated~~publicly ~~as a non-taxable event for U~~announced.S. ~~federal~~Upon ~~income~~closing, ~~tax~~each ~~purposes;~~issued ~~there~~and ~~being~~outstanding noshare ~~shares~~ of Great Plains Energy ~~preference~~common stock ~~outstanding;~~will ~~and~~be ~~Great~~converted ~~Plains~~into ~~Energy having not less than $1~~0.255981 ~~billion~~shares inof ~~cash~~common orstock ~~cash~~of ~~equivalents~~the onnew ~~its~~holding ~~balance sheet~~company. ~~The~~Following ~~closing~~completion of the merger, isour ~~also~~shareholders ~~subject~~are expected to ~~other~~own ~~standard~~approximately ~~conditions,~~52.5% ~~such~~of asthe ~~accuracy~~new ofholding ~~representations~~company and ~~warranties,~~Great ~~compliance~~Plains ~~with~~Energy’s ~~covenants~~shareholders ~~and~~are ~~the~~expected ~~absence~~to ofown aapproximately ~~material~~47.5% ~~adverse~~of ~~effect~~the onnew ~~either~~holding company.

~~Either~~The ~~party may terminate the amended and restated~~ merger agreement ifincludes ~~the~~certain ~~merger~~restrictions isand ~~not~~limitations ~~consummated~~on byour ~~July 10,~~ability ~~2018, subject~~ to andeclare ~~extension~~dividend ~~of up to six months~~payments. ~~Either~~The ~~party~~merger ~~may also terminate the~~ agreement iflimits our ~~shareholders~~quarterly ordividends ~~Great~~declared ~~Plains~~to ~~Energy’s shareholders do not approve the merger or an order that prohibits the merger becomes final and non-appealable~~$0. ~~There~~40 ~~are~~per also termination rights for both parties in certain cases if the other party’s board of directors changes its recommendation to its shareholders regarding approval of the merger, or the other party accepts an alternative, superior offershare.

OnThe ~~August~~closing 25of the merger is subject to conditions including receipt of all required regulatory approvals from, ~~2017~~among others, wethe 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 ~~filed~~or aus, ~~joint~~after ~~application~~giving ~~with~~effect to the ~~KCC~~merger, ~~requesting~~measured ~~approval~~on the size and scale of ~~the~~Westar ~~merger. On~~Energy ~~August~~and ~~31,~~its ~~2017~~subsidiaries, wetaken ~~and~~as ~~Great~~a ~~Plains~~whole); ~~Energy~~effectiveness ~~applied~~of the registration statement for ~~approval~~the shares of the ~~merger~~new ~~from~~holding ~~the~~company’s ~~MPSC. On~~common ~~September 1,~~stock ~~2017,~~to webe issued to our shareholders and Great Plains Energy’s ~~filed~~shareholders aupon ~~joint~~consummation ~~application~~of ~~for~~the merger and approval of the ~~merger~~listing ~~with~~of ~~FERC. On~~such ~~September 5,~~shares ~~2017,~~on ~~Wolf~~the ~~Creek~~New ~~filed~~York aStock ~~request~~Exchange; ~~with~~the receipt of tax opinions by us and Great Plains Energy that the ~~NRC~~merger towill ~~approve~~be antreated ~~indirect~~as ~~transfer~~a ofnon-taxable ~~control~~event for U.S. federal income tax purposes; there being no shares of ~~Wolf~~Great ~~Creek’s~~Plains ~~operating~~Energy ~~license. We~~preference stock outstanding; and Great Plains Energy ~~each~~having ~~scheduled~~not ~~special~~less ~~meetings~~than ~~for~~$1.25 ~~our~~billion ~~respective~~in ~~shareholders~~cash or cash equivalents on ~~November 21,~~its ~~2017~~balance sheet. The closing of the merger is also subject to ~~vote~~other onstandard conditions, such as accuracy of representations and warranties, compliance with covenants and the ~~proposed~~absence ~~merger~~of a material adverse effect on either company.

The ~~amended and restated~~ merger agreement, ~~provides~~which ~~that~~contains ~~Great~~customary ~~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~~representations, ~~2018~~warranties, ~~subject~~and ~~to an extension of up to six months~~covenants, ~~(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 useither ~~under~~party ~~certain~~if circumstances, such as entering into a definitive acquisition agreement with respect to a superior proposal or by Great Plains Energy as a result of our board of directors changing its recommendation of the merger ~~prior~~has tonot ~~our~~occurred ~~shareholder approval having been obtained. Similarly, Great Plains Energy may be required to pay us a termination fee of $190.0 million if the agreement is terminated~~ by ~~Great Plains Energy under certain circumstances~~July 10, such as entering into a definitive acquisition agreement with respect to a superior proposal or by us as a result of Great Plains Energy’s board of directors changing its recommendation of the merger prior to its shareholder approval having been obtained2018. The ~~Additionally,~~termination ifdate ~~the agreement is terminated by either Great Plains Energy or us as a result of Great Plains Energy’s shareholders not approving the agreement, Great Plains Energy~~ may be ~~required~~extended tosix ~~pay~~months usin aorder ~~termination~~to ~~fee~~obtain ofregulatory ~~$80~~approvals.~~0 million.~~

InOn ~~connection~~August ~~with~~25, ~~the merger~~2017, we ~~have~~and ~~incurred,~~Great ~~and~~Plains ~~expect~~Energy tofiled ~~incur~~a ~~additional,~~joint ~~merger-related~~application ~~expenses~~with the KCC requesting approval of the merger. ~~These~~The ~~expenses~~KCC ~~are~~subsequently ~~included~~approved ina ~~our~~procedural ~~selling,~~schedule ~~general,~~that ~~and~~provides ~~administrative~~for ~~expenses. During~~a ~~2016,~~KCC weorder ~~incurred~~on ~~approximately~~the ~~$10.2~~proposed merger by June ~~million~~5, of2018, ~~merger-related~~although ~~expenses. During~~under Kansas law the ~~three~~KCC ~~and~~has ~~nine~~until ~~months~~June ~~ended~~21, ~~September 30~~2018, ~~2017~~to issue the order. On March 7, 2018, we, ~~incurred~~Great ~~approximately~~Plains ~~$7.8 million~~Energy, ~~and~~the ~~$8.6~~KCC ~~million~~staff, ~~respectively~~the Citizens’ Utility Ratepayer Board (CURB), ofand ~~merger~~certain other intervenors entered into a non-unanimous settlement agreement to settle issues related ~~expenses~~to the joint application. InThe settlement agreement is subject to review and approval by the ~~event~~KCC. Components ~~that~~of the ~~merger~~settlement isagreement ~~consummated~~are summarized below. The settlement agreement, weif ~~expect~~approved, ~~total~~is ~~merger-related~~expected ~~expenses~~to ~~will~~impact beour ~~approximately~~2018 ~~$45~~rate review.~~0 million.~~

~~See~~• ~~also~~$23.0 ~~Note~~million ~~13,~~of ~~“Legal~~bill ~~Proceedings,”~~credits ~~for~~in ~~more~~2018 ~~information~~to onour ~~litigation~~retail ~~related~~customers, towhich ~~the~~will ~~merger.~~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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4We and Great Plains Energy each gained shareholder approval of the proposed merger on November 21, 2017. ~~RATE~~We ~~MATTERS~~and ~~AND~~Great ~~REGULATION~~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 ended March 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 ~~October~~March ~~2016~~2018, wethe ~~filed~~KCC issued an ~~abbreviated~~order ~~rate~~allowing ~~review~~us ~~with the KCC~~ to ~~update~~adjust our retail prices to include ~~capital~~updated ~~costs~~transmission ~~related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek,~~ costs ~~related~~as toreflected ~~programs to improve grid resiliency and costs associated with investments~~ in ~~other environmental projects during 2015. In May 2017, we entered into a settlement agreement with~~ the ~~major~~transmission ~~parties~~formula ~~to the~~ rate ~~review~~(TFR). ~~In June 2017, the agreement was approved by the KCC.~~ The new prices were effective ~~June~~in ~~2017~~April 2018 and are expected to increase our annual retail revenues by approximately $1631.45 million.

In ~~March~~February ~~2017~~2018, ~~the~~we ~~KCC~~filed ~~issued~~a anrate ~~order~~application ~~allowing~~with usthe KCC to ~~adjust~~update our ~~retail~~ prices to include, ~~updated~~among ~~transmission~~other things, costs asassociated 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 ~~transmission~~10-year ~~formula~~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 (~~TFR~~TCJA), savings achieved from refinancing debt and a portion of the savings from the proposed merger with Great Plains Energy. ~~The~~If our rate application were to be approved, we estimate the new prices ~~were~~would ~~effective~~decrease our annual revenues by approximately $2.0 million in ~~April~~September ~~2017~~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 ~~are~~certain ~~expected~~other intervenors entered into a non-unanimous settlement agreement related to ~~increase~~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 ~~annual~~rate ~~retail~~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 $1237.70 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 ~~December~~January ~~2016~~2018, the KCC ~~approved~~issued an order ~~allowing~~to usinvestigate the effect of the TCJA on regulated utilities. The KCC stated the passage of the TCJA has the potential to ~~adjust~~significantly ~~our~~reduce ~~prices~~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 ~~include~~accrue ~~costs~~monthly, ~~incurred~~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 ~~property~~federal corporate income taxes been based upon the corporate tax rate approved in the TCJA. The ~~new~~KCC ~~prices~~also ~~were~~gave ~~effective~~notice to taxable utilities operating in ~~January~~Kansas ~~2017~~that ~~and~~the ~~are~~portion ~~expected~~of their regulated revenue stream that reflects higher corporate tax rates should be considered interim and subject to ~~decrease~~refund, ~~our~~with ~~annual~~interest. When the KCC’s evaluation of the impact of the TCJA is complete, if it is determined that a retail ~~revenues~~price bydecrease ~~approximately~~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 $2615.81 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 ~~will~~was ~~become~~ effective in January 2018 and iswas expected to increase our annual transmission revenues by approximately $2625.15 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.

Our TFR that includes projected 2017 transmission capital expenditures and operating costs was effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above. 18

~~5. FINANCIAL~~Table ~~INSTRUMENTS~~of ~~AND TRADING SECURITIES~~Contents

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.

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

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

As of September 30, 2017

As of December 31, 2016

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,~~857~~759,~~763~~785

3,~~430~~605,000

3,~~597~~888,~~441~~620

Fixed-rate debt of VIEs

~~109~~81,~~967~~433

~~110~~80,~~586~~557

~~137~~109,~~962~~967

~~139~~110,~~733~~756

1719

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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 September 30, 2017	Level 1		Level 2		Level 3		NAV		Total
As of March 31, 2018	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	6468,~~855~~449	$	—	$	5,~~139~~323	$	6973,~~994~~772
International equity funds	—		4645,~~020~~130		—		—		4645,~~020~~130
Core bond fund	—		3237,~~914~~492		—		—		3237,~~914~~492
High-yield bond fund	—		1719,~~866~~713		—		—		1719,~~866~~713
Emerging markets bond fund	—		17,~~617~~337		—		—		17,~~617~~337
Combination debt/equity/other fund	—		13,~~688~~973		—		—		13,~~688~~973
Alternative investments fund	—		—		—		2122,~~063~~521		2122,~~063~~521
Real estate securities fund	—		—		—		1011,~~594~~024		1011,~~594~~024
Cash equivalents	~~171~~191		—		—		—		~~171~~191
Total Nuclear Decommissioning Trust	~~171~~191		~~192~~202,~~960~~094		—		3638,~~796~~868		~~229~~241,~~927~~153
Trading Securities:
Rabbi Trust:
Domestic equity funds	—		17,883		—		—		17,883
Core bond fund	—		25,670		—		—		25,670
International equity fund	—		4,491		—		—		4,491
Combination debt/equity/other fund	—		6,418		—		—		6,418
Core bond fund	—		11,789		—		—		11,789
Cash equivalents	156		—		—		—		156
Total Trading Securities	—		34,163		—		—		34,163
Total Rabbi Trust	156		32,088		—		—		32,244
Total Assets Measured at Fair Value	$	~~171~~347	$	~~227~~234,~~123~~182	$	—	$	3638,~~796~~868	$	~~264~~273,~~090~~397
As of December 31, 2016	Level 1		Level 2		Level 3		NAV		Total
As of December 31, 2017	Level 1		Level 2		Level 3		NAV		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	5668,~~312~~658	$	—	$	5,~~056~~142	$	6173,~~368~~800
International equity funds	—		3547,~~944~~908		—		—		3547,~~944~~908
Core bond fund	—		2733,~~423~~250		—		—		2733,~~423~~250
High-yield bond fund	—		18,~~188~~089		—		—		18,~~188~~089
Emerging markets bond fund	—		1417,~~738~~345		—		—		1417,~~738~~345
Combination debt/equity/other fund	—		1314,~~484~~125		—		—		1314,~~484~~125
Alternative investments fund	—		—		—		1821,~~958~~669		1821,~~958~~669
Real estate securities fund	—		—		—		910,~~946~~806		910,~~946~~806
Cash equivalents	73110		—		—		—		73110
Total Nuclear Decommissioning Trust	73110		~~166~~199,~~089~~375		—		3337,~~960~~617		~~200~~237,~~122~~102
Trading Securities:
Rabbi Trust:
Domestic equity funds	—		18,364		—		—		18,364
Core bond fund	—		27,324		—		—		27,324
International equity fund	—		4,467		—		—		4,467
Combination debt/equity/other fund	—		6,831		—		—		6,831
Core bond fund	—		11,504		—		—		11,504
Cash equivalents	156		—		—		—		156
Total Trading Securities	156		34,335		—		—		34,491
Total Rabbi Trust	156		34,155		—		—		34,311
Total Assets Measured at Fair Value	$	~~229~~266	$	~~200~~233,~~424~~530	$	—	$	3337,~~960~~617	$	~~234~~271,~~613~~413

18We 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 ended March 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 ~~Nuclear Decommissioning Trust (~~NDT) are measured at NAV and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations, these investments may have redemption restrictions. The following table provides additional information on these investments.

As of September 30, 2017

As of December 31, 2016

As of September 30, 2017

As of March 31, 2018

As of December 31, 2017

As of March 31, 2018

Fair Value

UnfundedCommitments

Fair Value

UnfundedCommitments

RedemptionFrequency

Length ofSettlement

(In Thousands)

Nuclear Decommissioning Trust:

Domestic equity funds

5,~~139~~323

2,~~929~~508

5,~~056~~142

32,~~529~~808

(a)

Alternative investments fund (b)

2122,~~063~~521

—

1821,~~958~~669

—

Quarterly

65 days

Real estate securities fund (b)

1011,~~594~~024

—

910,~~946~~806

—

Quarterly

65 days

Total

3638,~~796~~868

2,~~929~~508

3337,~~960~~617

32,~~529~~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. ~~Two~~Three funds have begun to make distributions. Our initial investment in the ~~third fund occurred in 2013. Our initial investment in the~~ fourth fund occurred in ~~the second quarter of~~ 2016. ~~The~~This ~~term of the third and fourth~~ 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 ~~and entering into treasury yield hedge transactions~~. We may also use other financial derivative instruments such as entering into treasury yield hedge transactions and interest rate swaps.

67. ~~FINANCIAL INVESTMENTS~~TAXES

We ~~report~~recorded ~~our~~income ~~investments~~tax inexpense ~~equity~~of ~~and~~$9.2 ~~debt~~million ~~securities~~with atan ~~fair~~effective ~~value~~income ~~and~~tax ~~use~~rate ~~the~~of ~~specific~~13% ~~identification~~for ~~method~~the tothree ~~determine~~months ~~their~~ended ~~realized~~March 31, ~~gains~~2018, and ~~losses~~income tax expense of $20. We9 ~~classify~~million ~~these~~with ~~investments~~an aseffective ~~either~~income ~~trading~~tax ~~securities~~rate orof ~~available-~~25% for~~-sale~~ ~~securities~~the assame ~~described~~period ~~below~~of 2017. The decrease in the effective income tax rate for the three months ended March 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%.

~~Trading~~As ~~Securities~~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.

~~We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations.~~ As of ~~September~~March 3031, ~~2017~~2018, and December 31, ~~2016~~2017, we ~~measured~~had ~~the~~no ~~fair~~amounts ~~value of trust assets at $34.2 million~~ and $340.51 million, respectively~~. We~~, ~~include~~accrued ~~unrealized~~for ~~gains~~interest orrelated ~~losses~~to ~~on these securities in investment earnings on~~ our ~~condensed~~unrecognized ~~consolidated statements of~~ income~~. For~~ ~~the~~tax ~~three and nine months ended September 30, 2017, we recorded an unrealized gain of $1~~benefits.~~0 million and $3.5 million, respectively, on assets still held in the trust.~~ ~~For~~We ~~the~~accrued ~~three~~no ~~and~~penalties ~~nine~~at ~~months~~either ~~ended September~~March 3031, ~~2016~~2018, weor ~~recorded an unrealized gain of $1.0~~December ~~million and $2.2 million~~31, ~~respectively, on assets still held in the trust~~2017.

19As 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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Available-for-Sale Securities

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

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

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

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2017:
Domestic equity funds	$	55,387	$	15,227	$	(620	)	$	69,994	30	%
International equity funds	35,937		10,083		—			46,020		20	%
Core bond fund	32,980		—		(66		)	32,914		14	%
High-yield bond fund	17,450		416		—			17,866		8	%
Emerging markets bond fund	17,186		431		—			17,617		8	%
Combination debt/equity/other fund	8,068		5,620		—			13,688		6	%
Alternative investments fund	15,000		6,063		—			21,063		9	%
Real estate securities fund	9,500		1,094		—			10,594		5	%
Cash equivalents	171		—		—			171		<1%
Total	$	191,679	$	38,934	$	(686	)	$	229,927	100	%
As of December 31, 2016:
Domestic equity funds	$	53,192	$	8,295	$	(119	)	$	61,368	31	%
International equity funds	34,502		2,075		(633		)	35,944		18	%
Core bond fund	27,952		—		(529		)	27,423		14	%
High-yield bond fund	18,358		—		(170		)	18,188		9	%
Emerging markets bond fund	16,397		—		(1,659		)	14,738		7	%
Combination debt/equity/other fund	9,171		4,313		—			13,484		7	%
Alternative investments fund	15,000		3,958		—			18,958		9	%
Real estate securities fund	9,500		446		—			9,946		5	%
Cash equivalents	73		—		—			73		<1%
Total	$	184,145	$	19,087	$	(3,110	)	$	200,122	100	%

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

	Less than 12 Months					12 Months or Greater					Total
	Fair Value		GrossUnrealizedLosses			Fair Value		GrossUnrealizedLosses			Fair Value		GrossUnrealizedLosses
	(In Thousands)
As of September 30, 2017:
Domestic equity funds	$	1,809	$	(337	)	$	1,904	$	(283	)	$	3,713	$	(620	)
Core bond fund	32,914		(66		)	—		—			32,914		(66		)
Total	$	34,723	$	(403	)	$	1,904	$	(283	)	$	36,627	$	(686	)
As of December 31, 2016:
Domestic equity funds	$	1,788	$	(119	)	$	—	$	—		$	1,788	$	(119	)
International equity funds	—		—			7,489		(633		)	7,489		(633		)
Core bond fund	27,423		(529		)	—		—			27,423		(529		)
High-yield bond fund	—		—			18,188		(170		)	18,188		(170		)
Emerging markets bond fund	—		—			14,738		(1,659		)	14,738		(1,659		)
Total	$	29,211	$	(648	)	$	40,415	$	(2,462	)	$	69,626	$	(3,110	)

7. DEBT FINANCING

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

In March 2017, Westar Energy issued $300.0 million in principal amount of FMBs bearing a stated interest at 3.10% and maturing April 2027.

8. TAXES

We recorded income tax expense of $55.7 million with an effective income tax rate of 26% for the three months ended September 30, 2017, and income tax expense of $81.2 million with an effective income tax rate of 34% for the same period of 2016. We recorded income tax expense of $112.6 million with an effective income tax rate of 27% for the nine months ended September 30, 2017, and income tax expense of $160.4 million with an effective income tax rate of 35% for the same period of 2016. The decrease in the effective income tax rate for the three and nine months ended September 30, 2017, was due primarily to lower income before income taxes, an increase in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service, and a favorable deferred tax true-up related to plant differences.

As of September 30, 2017, and December 31, 2016, our unrecognized income tax benefits totaled $1.6 million and $2.8 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of September 30, 2017, we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2016. We accrued no penalties at either September 30, 2017, or December 31, 2016.

As of September 30, 2017, and December 31, 2016, we had recorded $0.2 million and $1.5 million, respectively, for probable assessments of taxes other than income taxes.

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98. PENSION AND POST-RETIREMENT BENEFIT PLANS

The following ~~tables~~table ~~summarize~~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 September 30,	2017			2016			2017			2016
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,~~218~~826		$	45,~~633~~218		$	~~271~~279		$	271
Interest cost	10,621			10,922			1,314			1,392
Interest cost (a)	10,207			10,621			1,183			1,314
Expected return on plan assets	(10,760		)	(10,664		)	(1,718		)	(1,708		)
Expected return on plan assets (a)	(11,091		)	(10,760		)	(1,728		)	(1,718		)
Amortization of unrecognized:
Prior service costs	171			174			114			113
Prior service costs (a)	166			171			114			114
Actuarial loss (gain), net	5,489			5,146			(195		)	(279		)
Actuarial loss (gain), net (a)	6,485			5,489			(135		)	(195		)
Net periodic cost (benefit) before regulatory adjustment	1011,~~739~~593			10,~~211~~739			(~~214~~287		)	(~~211~~214		)
Regulatory adjustment (a)	3,288			3,306			(478		)	(486		)
Regulatory adjustment (b)	2,849			3,288			(434		)	(478		)
Net periodic cost (benefit)	$	14,~~027~~442		$	1314,~~517~~027		$	(~~692~~721	)	$	(~~697~~692	)

_______________

(a) The ~~regulatory~~components ~~adjustment~~of ~~represents~~net ~~the~~periodic ~~difference~~benefit ~~between~~cost ~~current~~other ~~period~~than ~~pension~~service orcost ~~post-retirement~~are ~~benefit~~included ~~expense~~in ~~and~~ the ~~amount~~line ofitem ~~such~~other expense ~~recognized~~ in ~~setting~~the ~~our~~condensed ~~prices~~consolidated statements of income.

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


(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 ended March ~~_______________~~31, 2018 and 2017, we contributed $12.5 million and $7.0 million, respectively, to the Westar Energy pension trust.

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

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

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109. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. The following ~~tables~~table ~~summarize~~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 September 30,	2017			2016			2017			2016
Three Months Ended March 31,	2018			2017			2018			2017
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	12,~~950~~220		$	1,~~687~~950		$	3736		$	3137
Interest cost	2,~~475~~478			2,~~413~~475			7061			8170
Expected return on plan assets	(2,~~643~~891		)	(2,~~431~~643		)	—			—
Amortization of unrecognized:
Prior service costs	14			14			—			—
Actuarial loss (gain), net	1,~~245~~656			1,~~090~~245			(1314		)	(313		)
Net periodic cost before regulatory adjustment	3,~~041~~477			23,~~773~~041			9483			~~109~~94
Regulatory adjustment (a)	~~247~~(49		)	~~483~~247			—			—
Net periodic cost	$	3,~~288~~428		$	3,~~256~~288		$	9483		$	~~109~~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.

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

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

_______________

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

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

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1110. COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

Cross-State Air Pollution Update Rule

In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen ~~oxide~~oxides ~~(NOx)~~ emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule ~~will~~revised ~~revise~~ the existing ozone season allowance budgets for Missouri and Oklahoma and established an ozone season budget for Kansas. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit 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 ~~federal Clean Air Act (~~CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, ~~NOx~~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. ~~The~~In ~~EPA~~November ~~was required to make attainment/nonattainment designations for the revised standards by October~~ 2017, ~~with an option to extend this deadline by one year. However,~~ the EPA ~~failed~~designated toall ~~issue~~counties ~~these~~in ~~designations by~~ the ~~October~~State ~~2017 deadline. If the EPA agrees with the recommended designations for the state~~ of Kansas, weas attainment/unclassifiable. We do not believe this will have a material impact on our condensed consolidated financial results.

Various states and others are challenging the revised 2015 ozone NAAQS in the D.C. Circuit. In April 2017, at the request of the EPA, the court issued an order holding the case in abeyance because the new administration is planning to review the 2015 ozone NAAQS and will determine whether to reconsider all or a portion of the rule. In October 2017, environmental groups sent a notice to the EPA of their intent to sue for failure to make the required area designations by the October 2017 deadline.

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

In 2010, the EPA revised the NAAQS for SO2. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO2 emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets ~~this~~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. InThe ~~February~~CPP ~~2016,~~was ~~after~~stayed ~~the~~by ~~U.S. Court of Appeals for~~ the ~~D.C. Circuit denied requests to stay the CPP, the U.S.~~ Supreme Court ~~issued~~in anFebruary ~~order~~2016 ~~granting~~and, ~~a stay of the rule pending resolution of the legal challenges. In September 2016~~accordingly, ~~oral~~is ~~arguments~~not ~~were~~currently ~~heard~~being ~~before~~implemented anby ~~en banc panel of D.C. Circuit judges and a decision on~~ the ~~legal challenges is pending~~states.

In ~~March~~April 2017, ~~President Trump signed an Executive Order instructing~~ the EPA topublished ~~immediately~~in ~~review~~ the ~~CPP~~Federal ~~and~~Register ~~GHG~~a ~~NSPS, and “if appropriate . . . as soon as practicable . . . publish for~~ notice ~~and~~of ~~comment~~withdrawal ~~proposed~~of ~~rules suspending, revising or rescinding those rules.” On~~ the ~~same~~proposed ~~day~~CPP ~~the~~federal ~~Executive Order was signed~~plan, ~~the~~proposed ~~EPA~~model ~~filed~~trading ~~motions~~rules ~~with the D.C. Circuit asking the court to hold the challenges to the CPP~~ and ~~the~~proposed ~~GHG~~Clean ~~NSPS~~Energy inIncentive ~~abeyance~~Program ~~while~~design ~~the EPA completes its administrative review of the rules and issues any forthcoming rulemakings~~details. InAlso in April 2017, the ~~court issued orders to hold the cases in abeyance for 60 days and requested briefing on whether the cases should be remanded to the~~ EPA orpublished ~~continue~~a tonotice ~~be held~~ in ~~abeyance. In May 2017, all parties in~~ the ~~case~~Federal ~~filed~~Register ~~supplemental~~that ~~briefs~~it ~~stating~~was ~~their~~initiating ~~positions~~administrative ~~regarding~~reviews ~~remanding~~of the ~~rule~~CPP ~~back~~and to the ~~EPA~~GHG ~~or continuing to hold the case in abeyance~~NSPS.

~~Also~~In inOctober ~~April~~ 2017, the EPA ~~published~~issued ~~in the Federal Register~~ a ~~notice~~proposed ofrule ~~withdrawal~~to ofrepeal the ~~proposed~~ CPP. The ~~federal plan,~~ proposed ~~model~~rule ~~trading~~indicates ~~rules and proposed Clean Energy Incentive Program design details, in light of~~ the ~~Executive~~CPP ~~Order~~exceeds ~~and the agency~~EPA’s ~~review~~authority ofand the ~~CPP. Also~~EPA inhas ~~April~~not ~~2017,~~determined ~~the~~whether ~~EPA~~they ~~published~~will issue a ~~notice~~replacement inrule. The ~~the~~EPA ~~Federal Register that it~~ is ~~initiating~~soliciting ~~administrative~~comments ~~reviews~~on of the ~~CPP~~legal ~~and~~interpretations ~~the~~contained ~~GHG~~in ~~NSPS~~this inrulemaking. Comments ~~light~~were ofdue ~~the~~in ~~Executive~~April ~~Order~~2018.

In ~~October~~December 2017, the EPA issued aan ~~proposed~~advance ~~rule~~notice toof ~~repeal~~proposed ~~the CPP~~rulemaking. ~~The~~This proposed ~~rule~~rulemaking ~~indicates~~was ~~the~~issued ~~CPP~~by ~~exceeds~~the EPA’s ~~authority~~because ~~and~~it ~~the~~is ~~EPA~~considering ~~has~~the ~~not~~possibility ~~determined~~of ~~whether~~changing orcertain ~~not~~aspects ~~they~~of ~~will~~the ~~issue~~CPP aand ~~replacement~~the ~~rule. The~~ EPA is soliciting ~~comments~~feedback on ~~the~~specific ~~legal~~areas ~~interpretations~~that ~~contained~~could inbe ~~this rulemaking~~changed. Comments on ~~the~~these proposed ~~rule~~areas ~~are~~of ~~due~~change inwere ~~December~~due ~~2017. On the same day the EPA issued its proposal~~ to ~~repeal~~ the ~~CPP, the~~ EPA ~~filed a motion~~ in ~~the~~February D2018.C. Circuit to extend the abeyance period for the rulemaking challenges until the conclusion of the new rulemaking. Certain states and environmental groups have opposed the EPA’s motion and asked the court to issue its ruling on the CPP.

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

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes effluent limitations guidelines (~~ELGs~~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 ~~2018~~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 ~~our~~regulating ~~operations~~authority orinterpretation, ~~condensed~~which ~~consolidated~~could ~~financial~~impact ~~results~~several permitting programs. Various states and others have filed lawsuits challenging the WOTUS rule. In February 2018, ~~but~~the ~~believe~~EPA ~~costs~~and the U.S. Corps of Engineers finalized a rule adding an applicability date to ~~comply~~the ~~could~~2015 berule, ~~material~~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.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States (WOTUS) for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states and others have filed lawsuits challenging the WOTUS rule in district courts and courts of appeals across the country. The appellate court challenges have been consolidated in the U.S. Court of Appeals for the Sixth Circuit and, in October 2015, the Sixth Circuit issued an order that temporarily stays implementation of the WOTUS rule nationwide pending the outcome of the various legal challenges. In July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results.

Regulation of Coal Combustion Residuals

In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017 and 2018. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. Electric generation industry participants requested and the EPA has granted a request to reconsider portions of the final CCR regulation. 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.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. In 2016, the SPP completed a process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are generation interconnection or transmission service projects that benefit SPP members and that are paid for directly by a sponsor without customer support. The SPP determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, in November 2016 we paid the SPP $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. In October 2017, the SPP issued revised allocations and we believe we will receive a small refund.

Storage of Spent Nuclear Fuel

InUnder ~~2010~~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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~~Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025~~11. ~~Wolf~~LEGAL Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE began accepting spent nuclear fuel. As a co-owner of Wolf Creek, we received $0.8 million of the settlement representing reimbursement of costs incurred through 2015 for project planning. Wolf Creek submitted a settlement claim to the DOE in August 2017 for costs incurred between January 2016 and June 2017, with our share of the claim being approximately $0.5 million. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity. PROCEEDINGS

12We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We ~~ASSET~~believe ~~RETIREMENT~~that ~~OBLIGATIONS~~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.

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

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

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

13. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our condensed consolidated financial results. See Note 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information.

Pending Merger

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

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

On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an amended petition. The 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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~~On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an~~ amended ~~petition. The~~(Exchange ~~proposed petition now includes an additional plaintiff~~Act). The ~~petition~~complaint 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~~an ~~relief~~order declaring that the action is maintainable as a class action and certifying that the ~~plaintiffs~~plaintiff ~~are~~is the class ~~representatives~~representative; preliminarily and permanently enjoining ~~the~~ defendants from ~~closing~~consummating the ~~merger~~mergers ~~unless~~or, weif ~~implement~~consummated, asetting ~~procedure~~them toaside ~~obtain a merger agreement providing fair~~ and ~~reasonable~~awarding ~~terms~~rescissory ~~and~~damages; ~~consideration~~directing to the ~~plaintiffs~~defendants ~~and~~to ~~the~~file ~~class;~~a ~~rescinding~~registration ~~the~~statement ~~merger~~on ~~agreement~~Form orS-4 ~~granting~~that ~~the~~corrects ~~plaintiffs~~alleged ~~and the class rescissory damages~~misstatements; directing our board of directors to account to ~~the~~plaintiff ~~plaintiffs~~ and the class for ~~damages~~their ~~suffered as a result of the alleged breach of fiduciary duty~~damages; awarding ~~the plaintiffs~~ reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other ~~equitable~~further relief as the court deems proper. ~~The~~ proposed amended petition alleges inadequacies in our joint proxy statement concerning the revised proposed transaction and the degree to which our board of directors solicited or considered offers from prior bidders after the proposed original merger was denied by the KCC, and claims that the consideration our stockholders stand to receive in connection with the revised proposed transaction is unfair. Plaintiffs have added two new defendants, Monarch Energy Holding, Inc. and King Energy, Inc., whom they allege aided and abetted our board of directors in breaching their fiduciary duties.

On October 186, 2017, ~~the~~another putative ~~derivative~~class ~~petition,~~action ~~captioned~~lawsuit ~~Braunstein v. Chandler et al., Case No. 2017-CV-000692,~~ was ~~re-~~filed in the United States District Court offor ~~Shawnee County, Kansas. This putative derivative action names as defendants~~ the ~~members~~District of ~~our board of directors~~Kansas, ~~Great~~captioned ~~Plains~~Robert ~~Energy,~~L. ~~and~~Reese ~~subsidiaries~~v. ofWestar ~~Great Plains~~ Energy, ~~with~~Inc. ~~Westar~~et ~~Energy~~al, ~~named~~Civil asAction aNo. ~~nominal defendant~~2:17-cv-02584. ~~The~~This ~~petition~~federal ~~asserts~~class ~~that~~action ~~the~~complaint ~~members~~challenges ~~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~~alleges violations of ~~Great~~sections ~~Plains~~14(a) ~~Energy aided~~ and ~~abetted~~20(a) ~~such breaches~~ of ~~fiduciary~~the ~~duties~~Exchange Act. The ~~petition~~complaint ~~alleges,~~seeks ~~among~~an ~~other~~order ~~things,~~enjoining ~~that~~ the ~~members of our~~ board ofand ~~directors~~other ~~failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third~~ parties from ~~submitting~~proceeding ~~potentially~~with, ~~superior proposals~~consummating, ~~and~~or ~~that~~closing ~~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~~or, ~~among~~if ~~other remedies~~consummated, ansetting ~~order~~it ~~enjoining~~aside ~~the~~and ~~merger~~awarding onrescissory ~~the~~damages; ~~terms proposed and~~ directing ~~that~~ the ~~director~~board ~~defendants exercise their fiduciary duties~~ to ~~obtain~~disseminate a ~~transaction~~registration ~~which~~statement isthat incorrects ~~the~~alleged ~~best~~misstatements ~~interests of us~~ and ~~our~~includes ~~shareholders,~~all amaterial ~~declaration~~facts ~~that~~ the ~~proposed~~plaintiff ~~merger~~asserts ~~was~~are ~~entered~~missing; ~~into~~declaring inthat ~~breach of~~ the ~~fiduciary duties of the~~ defendants ~~and~~violated issections ~~therefore~~14(a) ~~unlawful~~ and ~~unenforceable,~~20(a) ~~rescission~~ of the ~~merger~~Exchange ~~agreement~~Act ifand ~~consummated,~~Rule ~~the~~14a-9; ~~imposition~~awarding ofreasonable acosts ~~constructive~~and ~~trust~~disbursements ~~in favor~~ of the ~~plaintiff~~action, onincluding ~~behalf~~reasonable ofattorneys’ ~~us,~~fees ~~upon~~and ~~any~~expert ~~benefits~~fees; ~~improperly~~and ~~received~~granting byother ~~the~~equitable ~~named~~relief ~~defendants~~ as athe ~~result~~court ofdeems ~~their wrongful conduct, and an award for costs, including attorneys’ fees and experts’ fees~~proper.

InOn ~~addition,~~November ~~on September 21~~16, 2017, athe ~~putative~~parties ~~class~~in ~~action~~each ~~lawsuit~~of ~~was~~the ~~filed~~actions inindependently ~~the~~agreed ~~United~~to ~~States~~withdraw ~~District~~requests ~~Court~~ for ~~the~~injunctive ~~District~~relief ofand ~~Kansas. The~~otherwise ~~federal~~agreed ~~class~~in ~~action~~principle ~~complaint~~to ~~challenges~~dismissing the ~~merger~~actions ~~and~~with ~~alleges~~prejudice ~~violations~~and ofto ~~sections~~providing ~~14(a)~~releases, ~~and~~in ~~20(a)~~exchange offor the ~~Securities~~supplemental ~~Exchange~~disclosures ~~Act~~that ofwe ~~1934,~~filed asin ~~amended~~a ~~(Exchange~~Form ~~Act). The~~8-K ~~complaint~~on ~~seeks~~November an16, ~~order~~2017. These ~~declaring~~agreements ~~that~~do ~~the~~not ~~action~~constitute isany ~~maintainable~~admission asby aany ~~class~~of ~~action~~the ~~and~~defendants ~~certifying~~as ~~that~~to the ~~plaintiff~~merits isof ~~the~~any ~~class~~claims. In ~~representative; preliminarily and permanently enjoining defendants from consummating~~ the ~~mergers or~~future, ifthe ~~consummated,~~parties ~~setting~~will ~~them~~prepare ~~aside~~ and ~~awarding~~present ~~rescissory~~to ~~damages; directing~~ the ~~defendants~~court tofor ~~file~~approval aStipulations ~~registration~~of ~~statement~~Settlement ~~on Form S-4~~ that ~~corrects~~will, ~~alleged~~if ~~misstatements;~~accepted ~~directing~~by ~~our~~the ~~board~~court, ofsettle ~~directors to account to plaintiff and~~ the ~~class~~actions ~~for~~in their ~~damages;~~entirety. The ~~awarding~~outcome ~~reasonable~~of ~~costs~~litigation ~~and~~is ~~disbursements~~inherently ofuncertain. The ~~the~~defense ~~action,~~or ~~including~~settlement ~~reasonable~~of ~~attorneys’~~any ~~fees~~lawsuit ~~and~~or ~~expert~~claim ~~fees;~~that ~~and~~remains ~~granting~~unresolved ~~other~~at ~~further~~the ~~relief~~time as the ~~court~~merger ~~deems~~closes ~~proper.~~may ~~The~~adversely ~~case~~affect isthe ~~captioned~~combined ~~David~~company’s ~~Pill v. Westar Energy~~business, ~~Inc.~~financial etcondition ~~al,~~or ~~Civil~~results ~~Action~~of Nooperation. ~~17-4086.~~

~~On October 6, 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas~~12. ~~This~~VARIABLE ~~federal~~INTEREST class action complaint challenges the proposed merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act. The complaint seeks an order enjoining the board and other parties from proceeding with, consummating, or closing the merger or, if consummated, setting it aside and awarding rescissory damages; directing the board to disseminate a registration statement that corrects alleged misstatements and includes all material facts the plaintiff asserts are missing; declaring that the defendants violated sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The case is captioned Robert L. Reese v. Westar Energy, Inc. et al, Civil Action No. 2:17-cv-02584.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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14. VARIABLE INTEREST ENTITIES

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

8% Interest in Jeffrey Energy Center

Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We met the requirements to be considered the primary beneficiary of the trust until July 2017, when a contractual option to purchase the 8% interest in the plant covered by the lease expired. Accordingly, we deconsolidated the trust in the third quarter of 2017.

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

50% Interest in La Cygne Unit 2

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Financial Statement Impact

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

	As of		As of
	September 30, 2017		December 31, 2016
	March 31, 2018		December 31, 2017
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	178,058	$	257,904
Property, plant and equipment of variable interest entity, net	$	174,500	$	176,279
Regulatory assets (a)	—		10,396
Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,534	$	26,842
Current maturities of long-term debt of variable interest entity	$	30,337	$	28,534
Accrued interest (b)	—		867
Accrued interest (a)	—		659
Long-term debt of variable interest entities, net	81,433		111,209
Long-term debt of variable interest entity, net	51,096		81,433

_______________

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

~~(b) Included~~All of the liabilities noted in ~~accrued~~the ~~interest~~table onabove 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 ~~condensed~~general ~~consolidated~~credit. We ~~balance~~have ~~sheets~~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.

All of the liabilities noted in the table above relate to the purchase of the property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.29

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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 ~~and nine~~ months ended ~~September~~March 3031, ~~2017~~2018, compared to the same ~~periods~~period of ~~2016~~2017, our general financial condition and significant changes that occurred during ~~2017~~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 ~~still~~yet to be ~~determined~~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 approximately 47.5% 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 1311 of the Notes to Condensed Consolidated Financial Statements, “Pending Merger” and “Legal Proceedings,” respectively, and “Item “1A. Risk Factors.”

InTax ~~July~~Cuts ~~2017, we announced that we intend to retire Unit 7 at Tecumseh Energy Center, Units 3~~ and 4Jobs at Murray Gill Energy Center, and units 1 and 2 at Gordon Evans Energy Center in 2018, subject to the completion of the merger. The decision was based in part on lower demand for energy from the plants. The depreciable lives of the assets have been, and continue to be, based upon us operating as a stand-alone entity. Retiring these units or any other assets identified as part of integration planning could result in the write-down of obsolete inventory or the retirement of assets prior to the end of their estimated useful lives. Act

~~Earnings~~The ~~Per~~TCJA, ~~Share~~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.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017		2016		Change		2017		2016		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	158,306	$	154,720	$	3,586	$	290,032	$	292,645	$	(2,613	)
Earnings per common share, basic	1.11		1.09		0.02		2.03		2.06		(0.03		)

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 ended March 31, 2018, which is mostly offset with the associated decrease in income tax expense.

~~Net income and basic EPS increased for the three months ended September~~ 30, 2017, compared to the same period in 2016, due primarily to lower income tax expense of $25.5 million. Partially offsetting the lower income tax expense were lower retail sales attributable principally to milder weather, recording $10.1 million less in corporate-owned life insurance (COLI) benefits, and recording $9.7 million more in depreciation due in part to placing Western Plains Wind Farm in service.

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~~Net~~Earnings ~~income~~Per and basic EPS decreased for the nine months ended September 30, 2017, compared to the same period in 2016, due primarily to lower retail sales. The lower retail sales were attributable principally to milder weather. We also recorded $16.7 million less in corporate-owned life insurance (COLI) benefits and $24.5 million more in depreciation due in part to placing Western Plains Wind Farm in service. Partially offsetting these decreases to net income and basic EPS was a decrease in income tax expense of $47.8 million. Refer to Note 8 of the Notes to Condensed Consolidated Financial Statements, “Taxes,” for additional information on income tax expense.Share

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

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 2016 Form 10-K.



	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 ended March 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 1110 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 ~~2016~~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, ~~2016~~2017, through ~~September~~March 3031, ~~2017~~2018, we did not experience any significant changes in our critical accounting estimates. For additional information, see our ~~2016~~2017 Form 10-K.

3231

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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~~, net of revenue subject to refund~~.

Wholesale: Sales of electricity to electric cooperatives, municipalities, ~~and~~ 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 ~~are~~reduce ~~either~~retail ~~included~~electricity inprices ~~the~~either ~~RECA~~annually orthrough ~~used~~a informula ~~the~~or ~~determinations~~when of base rates are determined at the time of ~~our~~a ~~next~~ general rate review.

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

Other~~: Miscellaneous~~ ~~electric~~Revenue ~~revenues including ancillary service revenues and rent~~ from ~~electric~~Contracts ~~property~~with ~~leased~~Customers: toIncludes ~~others. This~~fees ~~category~~we ~~also~~earn ~~includes~~for ~~transactions~~services ~~unrelated~~provided to ~~the~~third ~~production~~parties ofand ~~our~~revenues ~~generating~~earned ~~assets~~by ~~and~~permitting ~~fees~~other weutilities ~~earn~~to ~~for~~attach ~~services~~equipment ~~that~~to weour ~~provide~~utility ~~for third parties~~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 Ended March 31, 2018, Compared to Three Months Ended March 31, 2017

Below we discuss our operating results for the three months ended March 31, 2018, compared to the results for the three months ended March 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		$	—		—

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~~Three~~Gross ~~and Nine Months Ended September 30, 2017, Compared to Three and Nine Months Ended September 30, 2016~~ Margin

~~Below~~Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we ~~discuss~~adjust our ~~operating~~retail ~~results~~prices ~~for~~to reflect changes in the ~~three~~costs of fuel and ~~nine~~purchased ~~months~~power. Fuel ~~ended~~and ~~September 30~~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, ~~2017~~changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, ~~compared~~SPP network transmission costs fluctuate due primarily to investments by us and other members of the ~~results~~SPP for upgrades to the ~~three~~transmission ~~and~~grid ~~nine~~within ~~months~~the ~~ended~~SPP ~~September 30~~RTO. As with fuel and purchased power costs, ~~2016~~changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. ~~Significant~~For these reasons, we believe gross margin is useful for understanding and analyzing changes in ~~results~~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 ~~operations~~fuel ~~shown~~and inpurchased power costs and amounts billed by the ~~table~~SPP ~~immediately~~for ~~below~~network ~~are~~transmission ~~further~~costs. Accordingly, ~~explained~~gross inmargin reflects transmission revenues and costs on a net basis. The following table summarizes our gross margin for the ~~descriptions~~three ~~that~~months ~~follow~~ended March 31, 2018 and 2017.

	Three Months Ended September 30,											Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016			Change			% Change		2017			2016			Change			% Change
	2018			2017			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
	(Dollars in Thousands)
REVENUES:
Revenues	$	600,204		$	572,574		$	27,630		4.8
Residential	$	278,138		$	282,272		$	(4,134	)	(1.5	)	$	642,449		$	664,400		$	(21,951	)	(3.3	)
Less: Fuel and purchased power expense	135,507			113,855			21,652			19.0
Commercial	219,414			218,377			1,037			0.5		557,232			572,247			(15,015		)	(2.6	)
SPP network transmission costs	67,594			60,674			6,920			11.4
Industrial	117,721			106,021			11,700			11.0		324,227			314,723			9,504			3.0
Gross Margin	$	397,103		$	398,045		$	(942	)	(0.2	)
Other retail	149			7,883			(7,734		)	(98.1	)	(22,293		)	(23,002		)	709			3.1
Total Retail Revenues	615,422			614,553			869			0.1		1,501,615			1,528,368			(26,753		)	(1.8	)
Wholesale	102,113			86,421			15,692			18.2		242,524			220,520			22,004			10.0
Transmission	69,504			58,462			11,042			18.9		209,097			188,996			20,101			10.6
Other	7,288			5,218			2,070			39.7		22,986			17,668			5,318			30.1
Total Revenues	794,327			764,654			29,673			3.9		1,976,222			1,955,552			20,670			1.1
OPERATING EXPENSES:
Fuel and purchased power	189,804			155,673			34,131			21.9		415,449			374,361			41,088			11.0
SPP network transmission costs	62,578			57,939			4,639			8.0		185,015			173,925			11,090			6.4
Operating and maintenance	79,856			86,758			(6,902		)	(8.0	)	248,211			250,135			(1,924		)	(0.8	)
Depreciation and amortization	94,668			84,972			9,696			11.4		277,322			252,838			24,484			9.7
Selling, general and administrative	65,630			60,582			5,048			8.3		182,367			192,762			(10,395		)	(5.4	)
Taxes other than income tax	41,815			48,154			(6,339		)	(13.2	)	126,421			145,529			(19,108		)	(13.1	)
Total Operating Expenses	534,351			494,078			40,273			8.2		1,434,785			1,389,550			45,235			3.3
INCOME FROM OPERATIONS	259,976			270,576			(10,600		)	(3.9	)	541,437			566,002			(24,565		)	(4.3	)
OTHER INCOME (EXPENSE):
Investment earnings	2,593			2,619			(26		)	(1.0	)	8,384			6,916			1,468			21.2
Other income	3,849			13,353			(9,504		)	(71.2	)	5,672			26,212			(20,540		)	(78.4	)
Other expense	(6,493		)	(5,887		)	(606		)	(10.3	)	(14,457		)	(14,338		)	(119		)	(0.8	)
Total Other (Expense) Income	(51		)	10,085			(10,136		)	(100.5	)	(401		)	18,790			(19,191		)	(102.1	)
Interest expense	43,458			40,897			2,561			6.3		128,232			121,011			7,221			6.0
INCOME BEFORE INCOME TAXES	216,467			239,764			(23,297		)	(9.7	)	412,804			463,781			(50,977		)	(11.0	)
Income tax expense	55,743			81,211			(25,468		)	(31.4	)	112,559			160,376			(47,817		)	(29.8	)
NET INCOME	160,724			158,553			2,171			1.4		300,245			303,405			(3,160		)	(1.0	)
Less: Net income attributable to noncontrolling interests	2,418			3,833			(1,415		)	(36.9	)	10,213			10,760			(547		)	(5.1	)
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	158,306		$	154,720		$	3,586		2.3		$	290,032		$	292,645		$	(2,613	)	(0.9	)
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.11		$	1.09		$	0.02		1.8		$	2.03		$	2.06		$	(0.03	)	(1.5	)
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	1.11		$	1.08		$	0.03		2.8		$	2.03		$	2.05		$	(0.02	)	(1.0	)

The following table reflects changes in electricity sales for the three months ended March 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 ended March 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 ended March 31, 2018, compared to the same period in 2017, there were approximately 25% more heating degree days.

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~~Gross~~Income ~~Margin~~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 ended March 31, 2018 and 2017.

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 and nine months ended September 30, 2017 and 2016.



	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	)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars In Thousands)
Revenues	$	794,327	$	764,654	$	29,673		3.9		$	1,976,222	$	1,955,552	$	20,670		1.1
Less: Fuel and purchased power expense	189,804		155,673		34,131			21.9		415,449		374,361		41,088			11.0
SPP network transmission costs	62,578		57,939		4,639			8.0		185,015		173,925		11,090			6.4
Gross Margin	$	541,945	$	551,042	$	(9,097	)	(1.7	)	$	1,375,758	$	1,407,266	$	(31,508	)	(2.2	)

Operating Expenses and Other Income and Expense Items

The following table reflects changes in electricity sales for the three and nine months ended September 30, 2017 and 2016. 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
	(Dollars in Thousands)
Operating, maintenance and administrative expense	$	139,993	$	135,319	$	4,674	3.5

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017	2016	Change		% Change		2017	2016	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	2,081	2,209	(128	)	(5.8	)	4,828	5,097	(269	)	(5.3	)
Commercial	2,156	2,230	(74	)	(3.3	)	5,588	5,763	(175	)	(3.0	)
Industrial	1,563	1,444	119		8.2		4,319	4,137	182		4.4
Other retail	12	19	(7	)	(36.8	)	56	60	(4	)	(6.7	)
Total Retail	5,812	5,902	(90	)	(1.5	)	14,791	15,057	(266	)	(1.8	)
Wholesale	3,128	2,389	739		30.9		7,612	5,960	1,652		27.7
Total	8,940	8,291	649		7.8		22,403	21,017	1,386		6.6

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

~~Gross~~• ~~margin~~a ~~decreased~~$2.8 ~~for~~million ~~the~~increase ~~three and nine months ended September 30, 2017, compared to the same periods~~ in ~~2016,~~employee ~~due~~benefit ~~primarily~~costs ~~to lower retail sales. The lower retail sales were~~ attributable ~~principally~~primarily to ~~more~~increased ~~mild~~medical ~~weather,~~claims; ~~which particularly impacts residential~~ and commercial customers. During the three and nine months ended September 30, 2017, compared to the same period in 2016, there were approximately 11% and 12%, respectively, fewer cooling degree days. During the nine months ended September 30, 2017, compared to the same period in 2016, there were approximately 7% fewer heating degree days. Partially offsetting the impact of less favorable weather for both periods was improved sales to industrial customers due partially to a few of our larger, lower margin chemical and oil customers who experienced improved global demand for their products as well as improved sales to the construction segment taking advantage of the more mild weather.


•	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 ended March 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.

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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 and nine months ended September 30, 2017 and 2016.



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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars In Thousands)
Income from operations	$	259,976	$	270,576	$	(10,600	)	(3.9	)	$	541,437	$	566,002	$	(24,565	)	(4.3	)
Plus: Operating and maintenance expense	79,856		86,758		(6,902		)	(8.0	)	248,211		250,135		(1,924		)	(0.8	)
Depreciation and amortization expense	94,668		84,972		9,696			11.4		277,322		252,838		24,484			9.7
Selling, general and administrative expense	65,630		60,582		5,048			8.3		182,367		192,762		(10,395		)	(5.4	)
Taxes other than income tax	41,815		48,154		(6,339		)	(13.2	)	126,421		145,529		(19,108		)	(13.1	)
Gross margin	$	541,945	$	551,042	$	(9,097	)	(1.7	)	$	1,375,758	$	1,407,266	$	(31,508	)	(2.2	)

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.

Operating Expenses and Other Income and Expense Items



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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	79,856	$	86,758	$	(6,902	)	(8.0	)	$	248,211	$	250,135	$	(1,924	)	(0.8	)

Income tax expense decreased for the three months ended March 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.

~~Operating~~FINANCIAL ~~and maintenance expense decreased for the three months ended September 30, 2017, compared to the same period in 2016, due primarily to:~~ CONDITION

•A anumber ~~$5.5~~of ~~million~~factors ~~decrease~~affected inamounts ~~distribution~~recorded ~~operations~~on ~~and~~our ~~maintenance~~balance ~~expense~~sheet ~~due~~as ~~primarily~~of toMarch 31, ~~executing~~2018, ~~our~~compared ~~vegetation~~to ~~management~~December 31, ~~strategy earlier in~~ 2017;.

• a $1.7 million decrease in nuclear operating and maintenance costs; and



	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 $19.5 7 million decrease in ~~steam~~deferred ~~generation~~employee ~~operating~~benefit ~~and maintenance~~ costs;. ~~however,~~

•Total ~~partially~~regulatory ~~offsetting~~liabilities ~~these~~increased ~~decreases~~due ~~was~~primarily ato recording $219.40 million ~~increase~~in revenue subject to refund to customers due to lowering the ~~start~~federal ofcorporate ~~operation~~income oftax ~~our~~rate ~~Western~~from ~~Plains~~35 ~~Wind~~percent ~~Farm~~to in21 ~~March~~percent, ~~2017~~effective January 1, 2018, as a result of the passage of the TCJA.

Operating and maintenance expense decreased for the nine months ended September 30, 2017, compared to the same period in 2016, due primarily to:



	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 along-term ~~$7.7~~debt ~~million~~of ~~decrease~~VIEs indecreased ~~nuclear~~due ~~operating~~to ~~and~~the ~~maintenance~~VIE ~~costs~~that ~~due~~holds ~~primarily~~La toCygne ~~receiving~~leasehold ainterest ~~legal~~having ~~settlement~~made ~~for~~principal ~~Wolf~~payments ~~Creek;~~totaling ~~and~~$28.5 million.

• a $1.8 million decrease in distribution operations and maintenance expense; however,

• partially offsetting these decreases was a $6.3 million increase due to the start of operation of our Western Plains Wind Farm in March 2017; and

• a $1.6 million increase in steam generation operating and maintenance costs.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017		2016		Change		% Change	2017		2016		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	94,668	$	84,972	$	9,696	11.4	$	277,322	$	252,838	$	24,484	9.7

Depreciation and amortization expense increased during the three and nine months ended September 30, 2017, compared to the same periods in 2016, due in part to the start of operation of our Western Plains Wind Farm in March 2017.

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	Three Months Ended September 30,							Nine Months Ended September 30,
	As of		As of
	2017		2016		Change		% Change	2017		2016		Change			% Change
	March 31, 2018		December 31, 2017		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	65,630	$	60,582	$	5,048	8.3	$	182,367	$	192,762	$	(10,395	)	(5.4	)
Short-term debt	$	289,800	$	275,700	$	14,100	5.1

~~Selling,~~Short-term ~~general~~debt ~~and~~increased ~~administrative~~due ~~expense~~to ~~increased~~increases ~~during~~in ~~the~~issuances ~~three~~of ~~months~~commercial ~~ended~~paper ~~September 30,~~used ~~2017,~~primarily ~~compared~~ to ~~the~~fund ~~same~~capital ~~period~~expenditures, inworking ~~2016,~~capital ~~due~~and ~~primarily~~other ~~to:~~corporate purposes.

•an increase of merger-related expenses of $5.9 million; however,



	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 ~~partially~~taxes ~~offsetting~~increased ~~this~~due ~~increase~~primarily ~~was~~to a ~~decrease~~$40.5 million increase in ~~outside~~accrued ~~services~~property taxes due to timing of $1payments.~~8 million.~~

Selling, general and administrative expense decreased during the nine months ended September 30, 2017, compared to the same period in 2016, due primarily to:

•a decrease in outside services of $5.0 million;

•a decrease in employee benefit costs of $2.0 million attributable partially to our having fewer employees; and

•a decrease of merger-related expenses of $1.2 million.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars in Thousands)
Taxes other than income tax	$	41,815	$	48,154	$	(6,339	)	(13.2	)	$	126,421	$	145,529	$	(19,108	)	(13.1	)

Taxes other than income tax decreased for the three and nine months ended September 30, 2017, compared to the same periods in 2016, due primarily to a decrease of $6.3 million and $18.9 million, respectively, in property tax expense amortization. This represents the amortization of the regulatory asset comprised of actual costs incurred for property taxes in the prior year in excess of amounts collected in our prices in the prior year. These decreases are mostly offset in retail revenues.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars in Thousands)
Other income	$	3,849	$	13,353	$	(9,504	)	(71.2	)	$	5,672	$	26,212	$	(20,540	)	(78.4	)

Other income decreased for the three and nine months ended September 30, 2017, compared to the same periods in 2016, due primarily to:

•our having recorded $10.1 million and $16.7 million, respectively, less in COLI benefits; and

•a decrease in equity AFUDC of $2.3 million and $6.8 million, respectively, however,

• partially offsetting these decreases was an increase of $3.5 million related to the deconsolidation of the trust holding our 8% interest in JEC.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017		2016		Change		% Change	2017		2016		Change		% Change
	(Dollars in Thousands)
Interest expense	$	43,458	$	40,897	$	2,561	6.3	$	128,232	$	121,011	$	7,221	6.0

Interest expense increased for the three months ended September 30, 2017, compared to the same period in 2016, due primarily to a decrease in debt AFUDC of $1.3 million. Interest expense increased for the nine months ended September 30, 2017, compared to the same period in 2016, due primarily to an increase in interest expense on long-term debt of $5.1 million primarily as a result of the issuance of FMBs during March 2017 and a decrease in debt AFUDC of $2.9 million.

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	Three Months Ended September 30,									Nine Months Ended September 30,
	2017		2016		Change			% Change		2017		2016		Change			% Change
	(Dollars in Thousands)
Income tax expense	$	55,743	$	81,211	$	(25,468	)	(31.4	)	$	112,559	$	160,376	$	(47,817	)	(29.8	)

Income tax expense decreased for the three and nine months ended September 30, 2017, compared to the same periods in 2016, due primarily to:

• a reduction in income tax expense of $9.2 million and $20.1 million, respectively, from lower income before income taxes;

• an increase of $5.1 million and $16.6 million, respectively, in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service; and

• a favorable deferred tax true-up of $7.6 million related to plant differences.

FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of September 30, 2017, compared to December 31, 2016.

	As of		As of
	September 30, 2017		December 31, 2016		Change			% Change
	(Dollars in Thousands)
Property, plant and equipment of variable interest entities, net	$	178,058	$	257,904	$	(79,846	)	(31.0	)

Property, plant and equipment of variable interest entities, net decreased due primarily to deconsolidating the trust holding our 8% interest in JEC. See Note 14 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities” for additional information.

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	As of		As of
	September 30, 2017		December 31, 2016		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	843,711	$	879,862	$	(36,151	)	(4.1	)
Regulatory liabilities	251,133		239,453		11,680			4.9
Net regulatory assets	$	592,578	$	640,409	$	(47,831	)	(7.5	)

Total regulatory assets decreased due primarily to the following items:

• a $25.7 million decrease in deferred employee benefit costs;

• a $12.2 million decrease in amounts collected from our customers for the deferred cost of fuel and purchased power;

• a $11.2 million decrease in amounts due from customers for future income taxes; and

• a $10.5 million decrease in amounts deferred for Wolf Creek refueling and maintenance outages; however,

• partially offsetting these decreases was spending $20.9 million more than collected for the cost to remove retired plant assets; and

• a $15.9 million increase in AROs. See Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information.

Total regulatory liabilities increased due primarily to a $29.8 million increase in the fair value of the NDT. This increase was partially offset by the following items:

• approximately $10.0 million for accreting the Wolf Creek ARO and depreciating the capitalized Wolf Creek asset retirement cost;

• spending $5.7 million more than collected for the cost to remove retired plant assets; and

• amortizing $4.1 million of a deferred regulatory gain from a sale-leaseback of Unit 2 of the La Cygne generating station.

	As of		As of
	September 30, 2017		December 31, 2016		Change			% Change
	(Dollars in Thousands)
Short-term debt	$	189,100	$	366,700	$	(177,600	)	(48.4	)

Short-term debt decreased due primarily to Westar Energy issuing $300.0 million in principal amount of FMBs, the proceeds for which were used to repay a portion of commercial paper borrowings, and us retiring $125.0 million in principal amount of FMBs. See Note 7 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing” for additional information. Partially offsetting the decrease was issuances of commercial paper primarily used to fund capital expenditures.

	As of		As of
	September 30, 2017		December 31, 2016		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt	$	—	$	125,000	$	(125,000	)	(100.0	)
Long-term debt, net	3,686,852		3,388,670		298,182			8.8
Total long-term debt	$	3,686,852	$	3,513,670	$	173,182		4.9

In 2017, Westar Energy issued $300.0 million in principal amount of FMBs and retired $125.0 million in principal amount of FMBs. See Note 7 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing” for additional information.

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	As of		As of
	September 30, 2017		December 31, 2016		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	28,534	$	26,842	$	1,692		6.3
Long-term debt of variable interest entities	81,433		111,209		(29,776		)	(26.8	)
Total long-term debt of variable interest entities	$	109,967	$	138,051	$	(28,084	)	(20.3	)

Total long-term debt of VIEs decreased due primarily to the VIE that holds the La Cygne leasehold interests having made principal payments totaling $26.8 million. See Note 14 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” for additional information.

	As of		As of
	September 30, 2017		December 31, 2016		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,866,583	$	1,752,776	$	113,807	6.5

Deferred income taxes increased due primarily to the use of bonus and accelerated depreciation methods for income tax purposes.

	As of		As of
	September 30, 2017		December 31, 2016		Change		% Change
	(Dollars in Thousands)
Asset retirement obligations	$	397,505	$	323,951	$	73,554	22.7

AROs increased due primarily to revisions for asbestos and nuclear decommissioning of $25.2 million and $19.4 million, respectively, and a new obligation estimated at $13.5 million related to the completion of Western Plains Wind Farm. See Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations” for additional information.

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 ~~and equity~~ 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 ~~and equity~~ 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.

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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 ~~available~~ 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 ~~October~~May 251, ~~2017~~2018, Westar Energy had $~~167~~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. ~~The~~In December 2017, Westar Energy extended the term of the $270.0 million credit facility ~~will~~by ~~expire~~one year to terminate in February ~~2018~~2019. As long as there is no default under the facilities, the $730.0 ~~million~~ ~~and $270.0~~ million ~~facilities~~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 ~~October~~May 251, ~~2017~~2018, no amounts were borrowed and $1140.8 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.

Long-Term Debt Financing

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

In March 2017, Westar Energy issued $300.0 million in principal amount of FMBs bearing a stated interest at 3.10% and maturing April 2027.

Debt Covenants

We were in compliance with our debt covenants as of ~~September~~March 3031, ~~2017~~2018.

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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.

41As of May 1, 2018, our ratings with the agencies are as shown in the table below.

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	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

As of October 25, 2017, our ratings with the agencies are as shown in the table below.

	WestarEnergyFirstMortgageBondRating	KGEFirstMortgageBondRating	Westar Energy Commercial Paper	RatingOutlook
Moody’s	A2	A2	P-2	Stable
S&P (a)	A	A	A-2	Positive

_______________

(a) In July 2017, following the public announcement of the amended and restated agreement and plan of merger with Great Plains Energy, S&P revised its outlook for Westar Energy and KGE to positive from negative, pending the outcome of the merger.

Summary of Cash Flows

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016			Change			% Change
	2018			2017			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	~~742~~259,~~322~~628		$	~~692~~236,~~573~~725		$	4922,~~749~~903		79.27
Investing activities	(~~581~~174,~~009~~181		)	(~~815~~175,~~018~~724		)	~~234~~1,~~009~~543			280.79
Financing activities	(~~160~~77,~~991~~713		)	~~123~~(60,~~151~~708		)	(~~284~~17,~~142~~005		)	(~~230~~28.70	)
Net change in cash and cash equivalents	$	322		$	706		$	(384	)	(54.4	)
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 ~~principally~~primarily to our having received $3918.5 million more from retail customers, received $11.9 million more in 2018 for wholesale power sales and transmission services, ~~receiving~~and apaid $139.0 9 million ~~refund~~less for ~~income~~coal ~~taxes~~and ~~compared~~natural ~~to paying $13~~gas.~~0 million~~ ~~for~~Partially ~~the~~offsetting ~~same~~these ~~period~~increases inwas ~~2016,~~our ~~and~~having ~~paying~~received a $813.0 million ~~less~~income ~~for~~tax ~~coal~~refund ~~and~~in ~~natural~~2017, ~~gas. Partially~~with ~~offsetting~~no ~~these~~similar ~~increases~~benefit ~~was~~in ~~our~~2018, ~~paying~~and paid $2211.8 0 million more in ~~purchased~~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 ~~invested~~received $~~257~~1.3 1 million ~~less~~more infrom ~~additions~~our toinvestment ~~property,~~in ~~plant~~COLI and ~~equipment primarily related to the completion of construction of Western Plains Wind Farm; partially offset by~~ our having ~~received~~invested $~~24.~~0 .6 million ~~fewer~~less ~~proceeds~~in ~~from~~additions ~~our~~to ~~investment~~property, inplant ~~COLI~~and equipment.

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Cash Flows used in Financing Activities

Cash flows used in financing activities increased due ~~principally~~primarily to our having issued $~~162~~296.05 million less in long-term debt. ofPartially ~~VIEs,~~offsetting ~~issued~~these ~~$110.3 million~~increases ~~less~~was inour ~~commercial~~having ~~paper,~~ issued $~~100~~154.~~3 million less in long-term debt and redeemed $75.0~~5 million more in ~~long-term~~commercial ~~debt. Partially~~paper ~~offsetting~~and ~~these decreases was our~~ having redeemed $~~163~~125.50 million ~~less~~of in long-term debt ofin ~~VIEs~~2017.

Pension Contribution

During the ~~nine~~three months ended ~~September~~March 3031, ~~2017~~2018, we contributed $2012.65 million to the Westar Energy pension trust. We ~~funded~~No ~~$12.0 million~~payments ofwere made to fund the Wolf Creek’s pension plan ~~contributions~~ during the same period.

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OFF-BALANCE SHEET ARRANGEMENTS

From December 31, ~~2016~~2017, through ~~September~~March 3031, ~~2017~~2018, our off-balance sheet arrangements did not change materially. For additional information, see our ~~2016~~2017 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, ~~2016~~2017, through ~~September~~March 3031, ~~2017~~2018, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our ~~2016~~2017 Form 10-K.

OTHER INFORMATION

Changes in Prices

See Note 45 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, ~~2016~~2017, to ~~September~~March 3031, ~~2017~~2018, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our ~~2016~~2017 Form 10-K for additional information.

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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 ended ~~September~~March 3031, ~~2017~~2018, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 1110 and 1311 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

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ITEM 1A. RISK FACTORS

~~Our~~ There ~~2016~~were ~~Form~~no ~~10-K~~material ~~contains~~changes ~~descriptions~~in ofour risk factors ~~relating~~from toDecember us31, ~~as required by Item 503(c) of Regulation S-K. The risk factors under the heading “Risks Relating to the Pending Merger” included in the 2016 Form 10-K~~2017, ~~Item~~through ~~1A.~~March ~~Risk Factors~~31, ~~were replaced with the risk factors contained in Item 1A~~2018. ~~Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017.~~ ~~Except~~For asadditional ~~indicated below~~information, orsee ~~as otherwise described in filings we make from time to time with the SEC, including~~ our ~~Quarterly~~2017 ~~Report on~~ Form 10-~~Q for the quarter ended March 31, 2017, there were no material changes in our risk factors from December 31, 2016, through September 30, 2017~~K.

Pending litigation against us and Great Plains Energy could result in an injunction preventing the consummation of the proposed merger or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

Following the announcement of the original merger agreement, a putative derivative lawsuit was filed in the District Court of Shawnee County, Kansas against the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, alleging breaches of various fiduciary duties by members of our board of directors in connection with the original proposed transaction and alleging that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. The putative derivative petition was refiled in October 2017. Also following the announcement of the original merger agreement, two putative class action lawsuits (which were consolidated and superseded by a consolidated complaint) were filed in the District Court of Shawnee County, Kansas against Westar Energy, the members of our board of directors and Great Plains Energy, alleging breaches of various fiduciary duties by the members of our board of directors in connection with the proposed merger and alleging that we and Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. In September 2017, the lead plaintiffs moved to amend the class action petition with allegations similar to those made regarding the original merger agreement but focusing on the revised merger. Also in September 2017, a putative class action lawsuit was filed in the United States District Court for the District of Kansas challenging the merger and alleged disclosure violations under sections 14(a) and 20(a) of the Exchange Act. In October 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas. This federal class action complaint challenges the merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act.

Among other remedies, the plaintiffs seek to enjoin the proposed transaction, rescind the merger agreement, remedy alleged disclosure deficiencies, and unspecified damages and reimbursement of costs. The outcome of litigation is inherently uncertain, and we cannot predict how existing litigation will progress, or whether additional claims may result from the amended and restated merger agreement. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operations. See Note 13 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings,” for additional information.

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.

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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

2+		Amended and Restated Merger Agreement, dated as of July 9, 2017, by and among Westar Energy, Inc., Great Plains Energy Incorporated, Monarch Energy Holding, Inc., King Energy, Inc. and, solely for the purposes set forth therein, GP Star, Inc. (filed as Exhibit 2.1 to the Form 8-K filed on July 10, 2017)
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(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 September 30, 2017
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
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 September 30, 2017
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)
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2017 (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
+ The disclosure letters and related schedules to the agreement have been omitted. The registrant agrees to furnish supplementally a copy of any such schedules to the Securities and Exchange Commission upon request.

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Table of Contents

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.

4642

WESTAR ENERGY, INC.

~~October~~May 318, ~~2017~~2018

/s/ Anthony D. Somma

Anthony D. Somma

Senior Vice President, Chief Financial Officer and Treasurer

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