10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2015

OR

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

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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	141,337,536 shares
(Class)	(Outstanding at October 27, 2015)

1

TABLE OF CONTENTS

PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Cash Flows	9
	Condensed Consolidated Statements of Changes in Equity	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	42
PART II. Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
Signature		45

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2014 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2014
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligations
BACT	Best Available Control Technology
CAA	Clean Air Act
CCB	Coal combustion byproducts
CO	Carbon monoxide
CO2	Carbon dioxide
COLI	Corporate-owned life insurance
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
EPA	Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
FPA	Federal Power Act
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gas
JEC	Jeffrey Energy Center
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
KGE	Kansas Gas and Electric Company
La Cygne	La Cygne Generating Station
MATS	Mercury and Air Toxics Standards
Moody’s	Moody’s Investors Service
MWh	Megawatt hour(s)
NAAQS	National Ambient Air Quality Standards
NDT	Nuclear Decommissioning Trust
NOx	Nitrogen oxides
PM	Particulate matter
PPB	Parts per billion
PSD	Prevention of Significant Deterioration
RECA	Retail energy cost adjustment
ROE	Return on equity
RSU	Restricted share unit
RTO	Regional transmission organization
S&P	Standard & Poor’s Ratings Services
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
TEC	Tecumseh Energy Center
TFR	Transmission formula rate
VIE	Variable interest entity
Wolf Creek	Wolf Creek Generating Station

3

FORWARD-LOOKING STATEMENTS

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

- amount, type and timing of capital expenditures,

- earnings,

- cash flow,

- liquidity and capital resources,

- litigation,

- accounting matters,

- possible corporate restructurings, acquisitions and dispositions,

- 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,

- additional regulation due to Nuclear Regulatory Commission 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 and information and operating systems security considerations,

- changes in accounting requirements and other accounting matters,

- changes in the energy markets in which we participate resulting from 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,

4

- reduced demand for coal-based energy because of actual or potential 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, and

- other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2014 (2014 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 Securities and Exchange Commission.

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 2014 Form 10-K. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in our 2014 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

5

PART I.    FINANCIAL INFORMATION

ITEM I.    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

	As of		As of
	September 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,829	$	4,556
Accounts receivable, net of allowance for doubtful accounts of $3,519 and $5,309, respectively	288,764		267,327
Fuel inventory and supplies	276,689		247,406
Deferred tax assets	22,861		29,636
Prepaid expenses	16,380		15,793
Regulatory assets	125,562		105,549
Other	23,598		30,655
Total Current Assets	757,683		700,922
PROPERTY, PLANT AND EQUIPMENT, NET	8,379,029		8,162,908
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	270,822		278,573
OTHER ASSETS:
Regulatory assets	735,474		754,229
Nuclear decommissioning trust	181,756		185,016
Other	259,315		265,353
Total Other Assets	1,176,545		1,204,598
TOTAL ASSETS	$	10,584,079	$	10,347,001
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Short-term debt	303,600		257,600
Accounts payable	175,309		219,351
Accrued dividends	49,781		44,971
Accrued taxes	122,791		74,356
Accrued interest	60,844		79,707
Regulatory liabilities	47,432		55,142
Other	90,627		90,571
Total Current Liabilities	878,693		849,631
LONG-TERM LIABILITIES:
Long-term debt, net	2,941,889		3,215,539
Long-term debt of variable interest entities, net	138,134		166,565
Deferred income taxes	1,601,511		1,475,487
Unamortized investment tax credits	208,760		211,040
Regulatory liabilities	259,545		288,343
Accrued employee benefits	518,307		532,622
Asset retirement obligations	286,389		230,668
Other	74,930		75,799
Total Long-Term Liabilities	6,029,465		6,196,063
COMMITMENTS AND CONTINGENCIES (See Notes 3, 10 and 12)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,268,889 shares and 131,687,454 shares, respective to each date	706,344		658,437
Paid-in capital	1,999,204		1,781,120
Retained earnings	957,721		855,299
Total Westar Energy, Inc. Shareholders’ Equity	3,663,269		3,294,856
Noncontrolling Interests	12,652		6,451
Total Equity	3,675,921		3,301,307
TOTAL LIABILITIES AND EQUITY	$	10,584,079	$	10,347,001

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

6

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,
	2015			2014
REVENUES	$	732,829		$	764,040
OPERATING EXPENSES:
Fuel and purchased power	163,943			200,755
SPP network transmission costs	57,487			55,720
Operating and maintenance	80,444			84,213
Depreciation and amortization	77,184			72,279
Selling, general and administrative	60,485			60,977
Taxes other than income tax	37,682			34,677
Total Operating Expenses	477,225			508,621
INCOME FROM OPERATIONS	255,604			255,419
OTHER INCOME (EXPENSE):
Investment earnings	314			1,655
Other income	637			14,991
Other expense	(5,392		)	(6,242		)
Total Other (Expense) Income	(4,441		)	10,404
Interest expense	44,306			44,531
INCOME BEFORE INCOME TAXES	206,857			221,292
Income tax expense	66,293			71,532
NET INCOME	140,564			149,760
Less: Net income attributable to noncontrolling interests	2,561			2,378
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	138,003		$	147,382
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.97		$	1.13
Diluted earnings per common share	$	0.97		$	1.10
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	141,622,697			130,196,193
Diluted	141,838,178			133,028,787
DIVIDENDS DECLARED PER COMMON SHARE	$	0.36		$	0.35

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

7

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Nine Months Ended September 30,
	2015			2014
REVENUES	$	1,913,199		$	2,005,264
OPERATING EXPENSES:
Fuel and purchased power	459,504			539,373
SPP network transmission costs	171,651			163,211
Operating and maintenance	248,263			277,841
Depreciation and amortization	228,529			213,270
Selling, general and administrative	179,567			179,633
Taxes other than income tax	113,047			104,248
Total Operating Expenses	1,400,561			1,477,576
INCOME FROM OPERATIONS	512,638			527,688
OTHER INCOME (EXPENSE):
Investment earnings	4,427			7,208
Other income	18,572			26,566
Other expense	(13,737		)	(14,192		)
Total Other Income	9,262			19,582
Interest expense	134,120			138,075
INCOME BEFORE INCOME TAXES	387,780			409,195
Income tax expense	127,810			132,643
NET INCOME	259,970			276,552
Less: Net income attributable to noncontrolling interests	7,277			6,742
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	252,693		$	269,810
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	1.84		$	2.08
Diluted earnings per common share	$	1.82		$	2.04
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	136,686,263			129,525,618
Diluted	138,181,585			132,199,583
DIVIDENDS DECLARED PER COMMON SHARE	$	1.08		$	1.05

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

8

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	259,970		$	276,552
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	228,529			213,270
Amortization of nuclear fuel	18,528			18,218
Amortization of deferred regulatory gain from sale leaseback	(4,121		)	(4,121		)
Amortization of corporate-owned life insurance	15,309			15,510
Non-cash compensation	6,280			6,034
Net deferred income taxes and credits	126,602			134,714
Stock-based compensation excess tax benefits	(1,231		)	(790		)
Allowance for equity funds used during construction	(2,034		)	(13,345		)
Changes in working capital items:
Accounts receivable	(21,437		)	(50,084		)
Fuel inventory and supplies	(28,814		)	(5,703		)
Prepaid expenses and other	(22,742		)	8,693
Accounts payable	(4,979		)	(4,397		)
Accrued taxes	51,867			41,323
Other current liabilities	(66,000		)	(19,732		)
Changes in other assets	1,394			6,019
Changes in other liabilities	26,512			28,051
Cash Flows from Operating Activities	583,633			650,212
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(486,515		)	(648,933		)
Purchase of securities - trusts	(20,752		)	(6,582		)
Sale of securities - trusts	20,957			8,221
Investment in corporate-owned life insurance	(14,845		)	(16,250		)
Proceeds from investment in corporate-owned life insurance	65,962			23,989
Other investing activities	(781		)	(2,203		)
Cash Flows used in Investing Activities	(435,974		)	(641,758		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	46,000			67,206
Proceeds from long-term debt	—			417,943
Retirements of long-term debt	(275,000		)	(427,500		)
Retirements of long-term debt of variable interest entities	(27,933		)	(27,321		)
Repayment of capital leases	(1,759		)	(2,397		)
Borrowings against cash surrender value of corporate-owned life insurance	57,726			57,764
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(63,894		)	(22,737		)
Stock-based compensation excess tax benefits	1,231			790
Issuance of common stock	257,169			58,560
Distributions to shareholders of noncontrolling interests	(1,076		)	—
Cash dividends paid	(137,616		)	(127,364		)
Other financing activities	(3,234		)	(2,050		)
Cash Flows used in Financing Activities	(148,386		)	(7,106		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(727		)	1,348
CASH AND CASH EQUIVALENTS:
Beginning of period	4,556			4,487
End of period	$	3,829		$	5,835

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

9

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Westar Energy, Inc. Shareholders
	Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2013	128,254,229	$	641,271	$	1,696,727		$	724,776		$	5,757		$	3,068,531
Net income	—	—		—			269,810			6,742			276,552
Issuance of stock	2,068,510	10,343		48,217			—			—			58,560
Issuance of stock for compensation and reinvested dividends	335,202	1,676		5,021			—			—			6,697
Tax withholding related to stock compensation	—	—		(2,050		)	—			—			(2,050		)
Dividends on common stock ($1.05 per share)	—	—		—			(136,458		)	—			(136,458		)
Stock compensation expense	—	—		5,970			—			—			5,970
Tax benefit on stock compensation	—	—		790			—			—			790
Other	—	—		(1,215		)	—			—			(1,215		)
Balance as of September 30, 2014	130,657,941	$	653,290	$	1,753,460		$	858,128		$	12,499		$	3,277,377
Balance as of December 31, 2014	131,687,454	$	658,437	$	1,781,120		$	855,299		$	6,451		$	3,301,307
Net income	—	—		—			252,693			7,277			259,970
Issuance of stock	9,229,357	46,147		211,022			—			—			257,169
Issuance of stock for compensation and reinvested dividends	352,078	1,760		6,248			—			—			8,008
Tax withholding related to stock compensation	—	—		(3,234		)	—			—			(3,234		)
Dividends on common stock ($1.08 per share)	—	—		—			(150,271		)	—			(150,271		)
Stock compensation expense	—	—		6,212			—			—			6,212
Tax benefit on stock compensation	—	—		1,231			—			—			1,231
Distribution to shareholders of noncontrolling interests	—	—		—			—			(1,076		)	(1,076		)
Other	—	—		(3,395		)	—			—			(3,395		)
Balance as of September 30, 2015	141,268,889	$	706,344	$	1,999,204		$	957,721		$	12,652		$	3,675,921

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

10

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 699,000 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 variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the 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 2014 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 endedSeptember 30, 2015, are not necessarily indicative of the results to be expected for the full year.

11

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, 2015		December 31, 2014
	(In Thousands)
Fuel inventory	$	89,144	$	70,416
Supplies	187,545		176,990
Fuel inventory and supplies	$	276,689	$	247,406

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 consolidated statements of income as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	466		$	2,504		$	3,047		$	9,448
Equity funds	—			3,627			2,034			13,345
Total	$	466		$	6,131		$	5,081		$	22,793
Average AFUDC Rates	1.0		%	6.4		%	2.8		%	6.9		%

Earnings Per Share

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

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

12

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	140,564	$	149,760	$	259,970	$	276,552
Less: Net income attributable to noncontrolling interests	2,561		2,378		7,277		6,742
Net income attributable to Westar Energy, Inc.	138,003		147,382		252,693		269,810
Less: Net income allocated to RSUs	304		395		563		721
Net income allocated to common stock	$	137,699	$	146,987	$	252,130	$	269,089
Weighted average equivalent common shares outstanding – basic	141,622,697		130,196,193		136,686,263		129,525,618
Effect of dilutive securities:
RSUs	215,481		198,583		197,373		139,058
Forward sale agreements	—		2,634,011		1,297,949		2,534,907
Weighted average equivalent common shares outstanding – diluted (a)	141,838,178		133,028,787		138,181,585		132,199,583
Earnings per common share, basic	$	0.97	$	1.13	$	1.84	$	2.08
Earnings per common share, diluted	$	0.97	$	1.10	$	1.82	$	2.04

_______________

(a) We had no antidilutive securities for the three and nine months endedSeptember 30, 2015 and 2014.

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2015		2014
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	119,173	$	119,275
Interest on financing activities of VIEs	10,430		12,178
Income taxes, net of refunds	126		361
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	60,155		111,494
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	8,008		6,697
Assets acquired through capital leases	2,246		1,454

New Accounting Pronouncements

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

13

Revenue Recognition

In May 2014, the FASB issued guidance that addresses revenue from contracts with customers. 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. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

Presentation of Financial Statements

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, and do not expect this to have a material impact to our financial statements.

3. RATE MATTERS AND REGULATION

KCC Proceedings

In September 2015, the Kansas Corporation Commission (KCC) issued an order in our state general rate case allowing us to adjust our prices to include, among other things, additional investment in La Cygne Generating Station (La Cygne) environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million. The KCC also approved our request to file an abbreviated rate review within 12 months of the effective date of this order to update our prices to include additional capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in environmental projects during 2015.

In May 2015, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in environmental projects during 2014. The new prices became effective in June 2015 and are expected to increase our annual retail revenues by approximately $10.8 million. In October 2015, in connection with the state general rate case, the existing balance of costs associated with these investments were rolled into our base prices.

In March 2015, the KCC issued an order allowing us to adjust our prices to include updated transmission costs as reflected in the transmission formula rate (TFR) discussed below. The new prices became effective in April 2015 and are expected to increase our annual retail revenues by approximately $7.2 million.

In December 2014, 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 2015 and are expected to increase our annual retail revenues by approximately $4.9 million. In October 2015, in connection with the state general rate case, the existing balance of costs incurred for property taxes were rolled into our base prices.

FERC Proceedings

Our TFR that includes projected 2016 transmission capital expenditures and operating costs will become effective in January 2016 and is expected to increase our annual transmission revenues by approximately $21.6 million.

Our TFR that includes projected 2015 transmission capital expenditures and operating costs was effective in January 2015 and is expected to decrease our annual transmission revenues by approximately $4.6 million. This updated rate provided the basis for our request to the KCC to adjust our retail prices to include updated transmission costs as discussed above.

14

In August 2014, the KCC filed a complaint against us with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA).  The complaint sought to lower our base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, we filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, during the nine months ended September 30, 2015, we recorded a liability of $11.2 million for our estimated refund obligation from the refund effective date of August 20, 2014 through September 30, 2015, of which $2.5 million was recorded in the three months ended September 30, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately $11.0 million on an annualized basis as a result of the reduced ROE.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:

• 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 measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or 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. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

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

All of our level 2 investments are held in investment funds that are measured at fair value using daily net asset values. In addition, we maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

15

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, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,830,000	$	3,071,423	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs	166,271		178,586		194,204		213,579

16

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, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	48,651	$	5,979	$	54,630
International equity funds	—		30,689		—		30,689
Core bond fund	—		19,707		—		19,707
High-yield bond fund	—		13,183		—		13,183
Emerging market bond fund	—		11,628		—		11,628
Other fixed income fund	—		4,923		—		4,923
Combination debt/equity/other funds	—		18,938		—		18,938
Alternative investment fund	—		—		17,538		17,538
Real estate securities fund	—		—		10,403		10,403
Cash equivalents	117		—		—		117
Total Nuclear Decommissioning Trust	117		147,719		33,920		181,756
Trading Securities:
Domestic equity funds	—		17,250		—		17,250
International equity fund	—		4,308		—		4,308
Core bond fund	—		11,505		—		11,505
Cash equivalents	159		—		—		159
Total Trading Securities	159		33,063		—		33,222
Total Assets Measured at Fair Value	$	276	$	180,782	$	33,920	$	214,978
As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	54,925	$	6,047	$	60,972
International equity funds	—		30,791		—		30,791
Core bond fund	—		19,289		—		19,289
High-yield bond fund	—		13,198		—		13,198
Emerging market bond fund	—		10,988		—		10,988
Other fixed income fund	—		4,779		—		4,779
Combination debt/equity/other funds	—		18,141		—		18,141
Alternative investment fund	—		—		16,970		16,970
Real estate securities fund	—		—		9,548		9,548
Cash equivalents	340		—		—		340
Total Nuclear Decommissioning Trust	340		152,111		32,565		185,016
Trading Securities:
Domestic equity funds	—		18,698		—		18,698
International equity fund	—		4,252		—		4,252
Core bond fund	—		12,379		—		12,379
Cash equivalents	168		—		—		168
Total Trading Securities	168		35,329		—		35,497
Total Assets Measured at Fair Value	$	508	$	187,440	$	32,565	$	220,513

17

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2015.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities  Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2015	$	5,910		$	17,425	$	10,042		$	33,377
Total realized and unrealized gains included in:
Regulatory liabilities	273			113		361			747
Purchases	200			—		103			303
Sales	(404		)	—		(103		)	(507		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920
Balance as of December 31, 2014	$	6,047		$	16,970	$	9,548		$	32,565
Total realized and unrealized gains included in:
Regulatory liabilities	836			568		855			2,259
Purchases	300			—		299			599
Sales	(1,204		)	—		(299		)	(1,503		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2014.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2014	$	6,288		$	16,446	$	9,026		$	31,760
Total realized and unrealized gains included in:
Regulatory liabilities	113			377		245			735
Purchases	95			—		92			187
Sales	(126		)	—		(92		)	(218		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464
Balance as of December 31, 2013	$	5,817		$	15,675	$	8,511		$	30,003
Total realized and unrealized gains included in:
Regulatory liabilities	722			1,148		760			2,630
Purchases	191			—		257			448
Sales	(360		)	—		(257		)	(617		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464

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Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the three and nine months endedSeptember 30, 2015 and 2014, attributed to level 3 assets and liabilities. See Note 3, “Rate Matters and Regulation,” in the 2014 Form 10-K for additional information regarding our regulatory assets and liabilities.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund		Net Balance
	(In Thousands)
Total unrealized gains (losses):
Three months ended September 30, 2015	$	(132	)	$	113	$	259	$	240
Three months ended September 30, 2014	(13		)	377		154		518
Nine months ended September 30, 2015	(368		)	567		556		755
Nine months ended September 30, 2014	362			1,149		503		2,014

Some of our investments in the Nuclear Decommissioning Trust (NDT) and our trading securities portfolio are measured at net asset value 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, 2015				As of December 31, 2014				As of September 30, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,979	$	2,048	$	6,047	$	2,348	(a)	(a)
Alternative investment fund (b)	17,538		—		16,970		—		Quarterly	65 days
Real estate securities fund	10,403		—		9,548		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	33,920		2,048		32,565		2,348
Trading Securities:
Domestic equity funds	17,250		—		18,698		—		Upon Notice	1 day
International equity funds	4,308		—		4,252		—		Upon Notice	1 day
Core bond fund	11,505		—		12,379		—		Upon Notice	1 day
Total Trading Securities	33,063		—		35,329		—
Total	$	66,983	$	2,048	$	67,894	$	2,348

_______________

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

(b) There is a holdback on final redemptions.

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Price Risk

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

Interest Rate Risk

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

5. FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of September 30, 2015, and December 31, 2014, we measured the fair value of trust assets at $33.2 million and $35.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months endedSeptember 30, 2015, we recorded an unrealized loss of $1.5 million on assets still held. For the nine months endedSeptember 30, 2015, we recorded an unrealized loss of $0.8 million on assets still held. For the three and nine months endedSeptember 30, 2014, we recorded an unrealized loss of $0.1 million and an unrealized gain of $1.5 million on assets still held, respectively.

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, 2015, and December 31, 2014.

Using the specific identification method to determine cost, we realized a loss of$0.5 million during the three months endedSeptember 30, 2015, and a loss of$1.0 million during the nine months endedSeptember 30, 2015, on our available-for-sale securities. We realized no gains or losses on our available-for-sale securities for the three months endedSeptember 30, 2014, and a gain of $0.2 million for the nine months endedSeptember 30, 2014. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

20

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, 2015, and December 31, 2014.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2015
Domestic equity funds	$	42,418	$	12,218	$	(6	)	$	54,630	30	%
International equity funds	30,685		1,218		(1,214		)	30,689		17	%
Core bond fund	19,397		310		—			19,707		11	%
High-yield bond fund	14,106		—		(923		)	13,183		7	%
Emerging market bond fund	14,295		—		(2,667		)	11,628		6	%
Other fixed income fund	4,948		—		(25		)	4,923		3	%
Combination debt/equity/other funds	16,213		3,474		(749		)	18,938		10	%
Alternative investment fund	15,000		2,538		—			17,538		10	%
Real estate securities fund	10,918		—		(515		)	10,403		6	%
Cash equivalents	117		—		—			117		<1%
Total	$	168,097	$	19,758	$	(6,099	)	$	181,756	100	%
As of December 31, 2014
Domestic equity funds	$	46,126	$	14,853	$	(7	)	$	60,972	33	%
International equity funds	27,521		3,683		(413		)	30,791		17	%
Core bond fund	18,811		478		—			19,289		10	%
High-yield bond fund	13,342		—		(144		)	13,198		7	%
Emerging market bond fund	12,556		—		(1,568		)	10,988		6	%
Other fixed income fund	4,798		—		(19		)	4,779		3	%
Combination debt/equity/other funds	14,975		3,786		(620		)	18,141		10	%
Alternative investment fund	15,000		1,970		—			16,970		9	%
Real estate securities fund	10,619		—		(1,071		)	9,548		5	%
Cash equivalents	340		—		—			340		<1%
Total	$	164,088	$	24,770	$	(3,842	)	$	185,016	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 ofSeptember 30, 2015, and December 31, 2014.

	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2015
Domestic equity funds	$	—	$	—		$	564	$	(6	)	$	564	$	(6	)
International equity funds	—		—			6,236		(1,214		)	6,236		(1,214		)
High-yield bond fund	13,183		(923		)	—		—			13,183		(923		)
Emerging market bond fund	—		—			11,628		(2,667		)	11,628		(2,667		)
Other fixed income fund	4,923		(25		)	—		—			4,923		(25		)
Combination debt/equity/other funds	—		—			6,289		(749		)	6,289		(749		)
Real estate securities fund	—		—			10,403		(515		)	10,403		(515		)
Total	$	18,106	$	(948	)	$	35,120	$	(5,151	)	$	53,226	$	(6,099	)
As of December 31, 2014
Domestic equity funds	$	—	$	—		$	263	$	(7	)	$	263	$	(7	)
International equity funds	5,905		(413		)	—		—			5,905		(413		)
High-yield bond fund	13,198		(144		)	—		—			13,198		(144		)
Emerging market bond fund	—		—			10,988		(1,568		)	10,988		(1,568		)
Other fixed income funds	4,779		(19		)	—		—			4,779		(19		)
Combination debt/equity/other funds	—		—			5,892		(620		)	5,892		(620		)
Real estate securities fund	—		—			9,548		(1,071		)	9,548		(1,071		)
Total	$	23,882	$	(576	)	$	26,691	$	(3,266	)	$	50,573	$	(3,842	)

6. DEBT FINANCING

In September 2015, Westar Energy extended the term of its $730.0 million credit facility to September 2019, $20.7 million of which will expire in September 2017. As of September 30, 2015, Westar Energy had no borrowed amounts and $19.2 million of letters of credit outstanding under this revolving credit facility. As of December 31, 2014, Westar Energy had no borrowed amounts and $15.6 million of letters of credit outstanding under this revolving credit facility.

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

In February 2014, Westar Energy extended the term of its $270.0 million credit facility to February 2017,

$20.0 million of which was set to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. As of September 30, 2015, and December 31, 2014, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

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

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7. TAXES

We recorded income tax expense of $66.3 million with an effective income tax rate of 32% for the three months endedSeptember 30, 2015, and income tax expense of $71.5 million with an effective income tax rate of 32% for the same period of 2014. We recorded income tax expense of $127.8 million with an effective income tax rate of 33% for the nine months endedSeptember 30, 2015, and income tax expense of $132.6 million with an effective income tax rate of 32% for the same period of 2014.

As of September 30, 2015, and December 31, 2014, our unrecognized income tax benefits totaled $2.7 million and $3.2 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of September 30, 2015, and December 31, 2014, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either September 30, 2015, or December 31, 2014.

As of September 30, 2015, and December 31, 2014, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Effective January 1, 2014, we adopted new regulations released by the Internal Revenue Service and the United States Treasury Department regarding deduction and capitalization of expenditures related to tangible property, including the tax treatment of, among other things, materials and supplies and the determination of whether expenditures with respect to tangible property are a deductible repair or must be capitalized, and regulations regarding dispositions of property under the Modified Accelerated Cost Recovery System. The adoption of these regulations did not have a material impact on our consolidated financial results.

23

8. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,348		$	4,055		$	361		$	345
Interest cost	10,753			10,400			1,422			1,588
Expected return on plan assets	(10,059		)	(9,109		)	(1,654		)	(1,644		)
Amortization of unrecognized:
Prior service costs	130			131			114			631
Actuarial loss (gain), net	8,033			5,690			95			(185		)
Net periodic cost before regulatory adjustment	14,205			11,167			338			735
Regulatory adjustment (a)	1,548			4,002			1,013			1,124
Net periodic cost	$	15,753		$	15,169		$	1,351		$	1,859

 _______________

(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,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	16,044		$	12,164		$	1,082		$	1,036
Interest cost	32,261			31,200			4,268			4,763
Expected return on plan assets	(31,177		)	(27,328		)	(4,961		)	(4,932		)
Amortization of unrecognized:
Prior service costs	390			394			342			1,893
Actuarial loss (gain), net	23,746			15,371			284			(556		)
Net periodic cost before regulatory adjustment	41,264			31,801			1,015			2,204
Regulatory adjustment (a)	4,880			12,005			3,038			3,371
Net periodic cost	$	46,144		$	43,806		$	4,053		$	5,575

 _______________

(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 endedSeptember 30, 2015 and 2014, we contributed $29.7 million and $26.4 million, respectively, to the Westar Energy pension trust.

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9. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,899		$	1,424		$	34	$	43
Interest cost	2,254			2,117			79		116
Expected return on plan assets	(2,261		)	(2,021		)	—		—
Amortization of unrecognized:
Prior service costs	14			14			—		—
Actuarial loss, net	1,482			747			1		41
Net periodic cost before regulatory adjustment	3,388			2,281			114		200
Regulatory adjustment (a)	(304		)	501			—		—
Net periodic cost	$	3,084		$	2,782		$	114	$	200

 _______________

(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,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,696		$	4,271		$	103	$	130
Interest cost	6,761			6,352			236		347
Expected return on plan assets	(6,783		)	(6,063		)	—		—
Amortization of unrecognized:
Prior service costs	43			43			—		—
Actuarial loss, net	4,448			2,240			2		124
Net periodic cost before regulatory adjustment	10,165			6,843			341		601
Regulatory adjustment (a)	(912		)	1,502			—		—
Net periodic cost	$	9,253		$	8,345		$	341	$	601

 _______________

(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 endedSeptember 30, 2015 and 2014, we funded $4.5 million and $2.4 million of Wolf Creek’s pension plan contributions, respectively.

10. COMMITMENTS AND CONTINGENCIES

Federal Clean Air Act

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

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

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Cross-State Air Pollution Rule

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce emissions of SO₂ and NOx. In April 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia Circuit that had vacated CSAPR and remanded CSAPR back to the U.S. Court of Appeals for further proceedings consistent with the U.S. Supreme Court decision.

In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion to lift the CSAPR stay. In October 2014, the U.S. Court of Appeals granted the motion to lift the CSAPR stay and established a schedule to hear arguments on the remaining outstanding issues, which began in March 2015. In July 2015, the U.S. Court of Appeals found the EPA erred in certain SO₂ and ozone season NOx emissions budgets for several states and sent these back to the EPA for reconsideration, but upheld the remainder of the rule. During the CSAPR stay, we installed various emission controls at our generation facilities that we expect reduces the impact of CSAPR. We are unable to determine the full impact of reinstatement, and any possible revisions, of CSAPR. However, we are prepared to comply with CSAPR in its current form.

National Ambient Air Quality Standards

Under the federal CAA, the EPA sets National Ambient Air Quality Standards (NAAQS) for certain emissions considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015 the EPA strengthened the ozone NAAQS by lowering the standards from the current 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations, but it could be material. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.

In 2010, the EPA revised the NAAQS for both NOx and 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, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016.  Tecumseh Energy Center (TEC) is our only generating station that meets this criteria. We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Byproducts of burning coal and other fossil fuels include carbon dioxide (CO₂) and other gases referred to as GHGs, which are believed by many to contribute to climate change. 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.

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In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. In October 2015, the EPA also 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 in the U.S. Court of Appeals for D.C. Circuit in October 2015, and more challenges are expected. We are evaluating the CPP and cannot at this time determine the impact of the CPP on our operations or consolidated financial results, but we believe the costs to comply could be material.

Under regulations formerly known as the Tailoring Rule, the EPA regulates GHG emissions from certain stationary sources. The regulations are implemented pursuant to two federal CAA programs, the Prevention of Significant Deterioration (PSD) and Title V Operating Permit Programs, that impose recordkeeping and monitoring requirements and also mandate the implementation of best available control technology (BACT) for projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for other pollutants. Therefore, if future modifications to our sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our future operations or consolidated financial results as we would not be required to implement BACT until we construct a new major source or make a major modification of an existing major source. The cost of compliance, however, could be material.

Mercury and Air Toxics Standards

In 2012, the Mercury and Air Toxics Standards (MATS) rule became effective. Under the MATS rule the EPA regulates the emissions of mercury, non-mercury metals, acid gases and organics. MATS required compliance to begin in April 2015, three years after the effective date. Sources could petition their state air regulatory agency to ask for an additional year to prepare for compliance. We petitioned the KDHE and our petition request was granted. Our current compliance date is April 2016 for all of our MATS affected units.

In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. On remand, the court could instruct the EPA on the cost benefit analysis needed to support the rule, vacate the rule in its entirety or take other action. MATS will remain in effect during the remand proceedings unless a stay is requested and granted. There will not be a material impact on our operations or consolidated financial results if MATS in its current form becomes a final rule. We are unable to predict the impact on our operations or consolidated financial results if MATS is vacated and the EPA proposes a replacement rule.

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 released in final, pre-publication form in September 2015. We are evaluating the final, pre-publication rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but it may be material.

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

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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 for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. We are currently evaluating the final rule. The resulting impact of the rule could have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), 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 CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and potential closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $48.8 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 11, “Asset Retirement Obligations,” for additional information.

Renewable Energy Standard

In May 2015, Kansas repealed a state mandate to maintain a minimum amount of renewable energy sources, effective January 1, 2016.

Storage of Spent Nuclear Fuel

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

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. 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.

FERC Proceedings

See Note 3, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.

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11. ASSET RETIREMENT OBLIGATIONS

In June 2015, we recorded an approximately $48.8 million increase in our ARO in response to the EPA’s published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant. See Note 10, “Commitments and Contingencies - Regulation of Coal Combustion Byproducts,” for additional information.

The change in the balance of our ARO liability from December 31, 2014, through September 30, 2015, is summarized in the following table.

	(In Thousands)
Balance as of December 31, 2014	$	230,668
Liabilities incurred	48,767
Liabilities settled	(1,312		)
Accretion expense	9,500
Revisions in estimated cash flows	(1,234		)
Balance as of September 30, 2015	$	286,389

12. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Note 3, “Rate Matters and Regulation,” and Note 10, “Commitments and Contingencies,” for additional information.

13. COMMON STOCK

During the nine months endedSeptember 30, 2015, Westar Energy issued 9.2 million shares of common stock with a

physical settlement amount of $254.6 million to settle all outstanding forward sale transactions. Westar Energy used the proceeds from this transaction to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

14. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne

unit 2 are VIEs of which we are the primary beneficiary.

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

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8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

Financial Statement Impact

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

	As of		As of
	September 30, 2015		December 31, 2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	270,822	$	278,573
Regulatory assets (a)	8,777		7,882
Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Accrued interest (b)	68		2,961
Long-term debt of variable interest entities, net	138,134		166,565

_______________

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

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

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

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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” above for additional information.

INTRODUCTION

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central U.S. under the regulation of the KCC and FERC.

In Management’s Discussion and Analysis, we discuss our operating results for the three and nine months endedSeptember 30, 2015, compared to the same periods of 2014, our general financial condition and significant changes that occurred during 2015. 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

Earnings Per Share

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	138,003	$	147,382	$	(9,379	)	$	252,693	$	269,810	$	(17,117	)
Earnings per common share, basic	$	0.97	$	1.13	$	(0.16	)	$	1.84	$	2.08	$	(0.24	)

Net income decreased for the three months ended September 30, 2015, compared to the same period in 2014, due primarily to our having recorded $10.7 million less in corporate-owned life insurance (COLI) benefits. In addition, we recorded a $2.5 million reduction to transmission revenues for our estimated refund obligation associated with a FERC proceeding. See Note 3 to the Condensed Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of this proceeding. Further, we recorded an expense of approximately $2.0 million to write off capital project costs that will no longer be completed related to planned retirements of generating units.

Net income decreased for the nine months ended September 30, 2015, compared to the same period in 2014, due primarily to a decreased energy marketing margin of $12.7 million due to greater volatility in 2014 of power prices in some of the wholesale markets in which we buy and sell power. An $11.2 million reduction to transmission revenues for our estimated refund obligation associated with the FERC proceeding referred to in the prior paragraph also reduced net income.

Basic EPS decreased for the three and nine months ended September 30, 2015, compared to the same periods in 2014, due to the issuance of common stock and for the reasons described above. See Note 13 to the Condensed Consolidated Financial Statements, “Common Stock,” for additional information regarding our issuances of common stock.

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Settlement of State General Rate Case

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

Retirement of Generating Units

In October 2015, we announced plans to retire three older, smaller generating units at Lawrence Energy Center, TEC and Hutchinson Energy Center with a combined capability of 354 megawatts by the end of 2015.

Current Trends

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 2014 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 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 consolidated financial results, including those relating to:

• further regulation of GHGs by the EPA, including regulations pursuant to the CPP, and future legislation that could be proposed by the U.S. Congress;

• various proposed and expected regulations governing air emissions including those relating to NAAQS (particularly those relating to PM, NOx, ozone, CO and SO₂) and the CSAPR;

• the definition of Waters of the United States for purposes of the CWA; and,

• the regulation of CCB.

See Note 10 to the Condensed Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.

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 2014 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, 2014, through September 30, 2015, we did not experience any significant changes in our critical accounting estimates. For additional information, see our 2014 Form 10-K.

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OPERATING RESULTS

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

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways, 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 either included in the RECA or used in the determination of base rates at the time of our next general rate case.

Transmission: Reflects transmission revenues, including those based on tariffs with the Southwest Power Pool (SPP).

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes transactions unrelated to the production of our generating assets and fees we earn for services that we provide for third parties.

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 and Nine Months EndedSeptember 30, 2015, Compared to Three and Nine Months EndedSeptember 30, 2014

Below we discuss our operating results for the three and nine months endedSeptember 30, 2015, compared to the results for the three and nine months endedSeptember 30, 2014. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.

	Three Months Ended September 30,											Nine Months Ended September 30,
	2015			2014			Change			% Change		2015			2014			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	255,804		$	261,106		$	(5,302	)	(2.0	)	$	610,775		$	629,064		$	(18,289	)	(2.9	)
Commercial	213,461			223,588			(10,127		)	(4.5	)	550,761			562,882			(12,121		)	(2.2	)
Industrial	105,307			113,039			(7,732		)	(6.8	)	304,937			314,518			(9,581		)	(3.0	)
Other retail	1,620			(6,032		)	7,652			126.9		(5,503		)	(17,587		)	12,084			68.7
Total Retail Revenues	576,192			591,701			(15,509		)	(2.6	)	1,460,970			1,488,877			(27,907		)	(1.9	)
Wholesale	87,918			97,680			(9,762		)	(10.0	)	249,502			290,727			(41,225		)	(14.2	)
Transmission (a)	61,190			67,145			(5,955		)	(8.9	)	181,070			192,311			(11,241		)	(5.8	)
Other	7,529			7,514			15			0.2		21,657			33,349			(11,692		)	(35.1	)
Total Revenues	732,829			764,040			(31,211		)	(4.1	)	1,913,199			2,005,264			(92,065		)	(4.6	)
OPERATING EXPENSES:
Fuel and purchased power	163,943			200,755			(36,812		)	(18.3	)	459,504			539,373			(79,869		)	(14.8	)
SPP network transmission costs	57,487			55,720			1,767			3.2		171,651			163,211			8,440			5.2
Operating and maintenance	80,444			84,213			(3,769		)	(4.5	)	248,263			277,841			(29,578		)	(10.6	)
Depreciation and amortization	77,184			72,279			4,905			6.8		228,529			213,270			15,259			7.2
Selling, general and administrative	60,485			60,977			(492		)	(0.8	)	179,567			179,633			(66		)	—
Taxes other than income tax	37,682			34,677			3,005			8.7		113,047			104,248			8,799			8.4
Total Operating Expenses	477,225			508,621			(31,396		)	(6.2	)	1,400,561			1,477,576			(77,015		)	(5.2	)
INCOME FROM OPERATIONS	255,604			255,419			185			0.1		512,638			527,688			(15,050		)	(2.9	)
OTHER INCOME (EXPENSE):
Investment earnings	314			1,655			(1,341		)	(81.0	)	4,427			7,208			(2,781		)	(38.6	)
Other income	637			14,991			(14,354		)	(95.8	)	18,572			26,566			(7,994		)	(30.1	)
Other expense	(5,392		)	(6,242		)	850			13.6		(13,737		)	(14,192		)	455			3.2
Total Other (Expense) Income	(4,441		)	10,404			(14,845		)	(142.7	)	9,262			19,582			(10,320		)	(52.7	)
Interest expense	44,306			44,531			(225		)	(0.5	)	134,120			138,075			(3,955		)	(2.9	)
INCOME BEFORE INCOME TAXES	206,857			221,292			(14,435		)	(6.5	)	387,780			409,195			(21,415		)	(5.2	)
Income tax expense	66,293			71,532			(5,239		)	(7.3	)	127,810			132,643			(4,833		)	(3.6	)
NET INCOME	140,564			149,760			(9,196		)	(6.1	)	259,970			276,552			(16,582		)	(6.0	)
Less: Net income attributable to noncontrolling interests	2,561			2,378			183			7.7		7,277			6,742			535			7.9
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	138,003		$	147,382		$	(9,379	)	(6.4	)	$	252,693		$	269,810		$	(17,117	)	(6.3	)
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.97		$	1.13		$	(0.16	)	(14.2	)	$	1.84		$	2.08		$	(0.24	)	(11.5	)
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.97		$	1.10		$	(0.13	)	(11.8	)	$	1.82		$	2.04		$	(0.22	)	(10.8	)

_______________

(a) Includes revenue from an SPP network transmission tariff corresponding to our SPP network transmission costs. For the three and nine months endedSeptember 30, 2015, these costs, less administration fees of $14.8 million and $43.8 million, respectively, were returned to us as revenue. For the three and nine months endedSeptember 30, 2014, these costs, less administration fees of $13.0 million and $37.8 million, respectively, were returned to us as revenue.

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Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP RTO. As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin 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 endedSeptember 30, 2015 and 2014.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars In Thousands)
Revenues	$	732,829	$	764,040	$	(31,211	)	(4.1	)	$	1,913,199	$	2,005,264	$	(92,065	)	(4.6	)
Less: Fuel and purchased power expense	163,943		200,755		(36,812		)	(18.3	)	459,504		539,373		(79,869		)	(14.8	)
SPP network transmission costs	57,487		55,720		1,767			3.2		171,651		163,211		8,440			5.2
Gross Margin	$	511,399	$	507,565	$	3,834		0.8		$	1,282,044	$	1,302,680	$	(20,636	)	(1.6	)

The following table reflects changes in electricity sales for the three and nine months endedSeptember 30, 2015 and 2014. 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 September 30,						Nine Months Ended September 30,
	2015	2014	Change		% Change		2015	2014	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	2,168	2,104	64		3.0		5,108	5,229	(121	)	(2.3	)
Commercial	2,221	2,190	31		1.4		5,787	5,792	(5	)	(0.1	)
Industrial	1,463	1,467	(4	)	(0.3	)	4,195	4,252	(57	)	(1.3	)
Other retail	21	20	1		5.0		63	64	(1	)	(1.6	)
Total Retail	5,873	5,781	92		1.6		15,153	15,337	(184	)	(1.2	)
Wholesale	2,200	2,467	(267	)	(10.8	)	6,817	6,946	(129	)	(1.9	)
Total	8,073	8,248	(175	)	(2.1	)	21,970	22,283	(313	)	(1.4	)

Gross margin increased for the three months ended September 30, 2015, compared to the same period in 2014, due primarily to more retail electricity sales principally as a result of warmer weather, which particularly impacts residential and commercial electricity sales. As measured by cooling degree days, the weather during the three months ended September 30, 2015, was approximately 11% warmer than the same period in 2014. A $2.5 million reduction to transmission revenues for our estimated refund obligation associated with a FERC proceeding partially offset the increase in gross margin. See Note 3 to the Condensed Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of this proceeding.

Gross margin decreased during the nine months ended September 30, 2015, compared to the same period of 2014, due primarily to a decreased energy marketing margin of $12.7 million due to greater volatility in 2014 of power prices in some of the wholesale markets in which we buy and sell power. An $11.2 million reduction to transmission revenues for our estimated refund obligation associated with a FERC proceeding also reduced gross margin. See Note 3 to the Condensed Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of this proceeding. Also contributing to the decrease in gross margin was lower retail electricity sales. The lower retail electric sales were due partly to milder weather, primarily warmer winter weather. During the nine months ended September 30, 2015, compared to the same period of 2014, there were approximately 16% fewer heating degree days and 7% more cooling degree days.

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Income from operations is the most directly comparable measure to our presentation of gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. 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 endedSeptember 30, 2015 and 2014.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars In Thousands)
Gross margin	$	511,399	$	507,565	$	3,834		0.8		$	1,282,044	$	1,302,680	$	(20,636	)	(1.6	)
Less: Operating and maintenance expense	80,444		84,213		(3,769		)	(4.5	)	248,263		277,841		(29,578		)	(10.6	)
Depreciation and amortization expense	77,184		72,279		4,905			6.8		228,529		213,270		15,259			7.2
Selling, general and administrative expense	60,485		60,977		(492		)	(0.8	)	179,567		179,633		(66		)	—
Taxes other than income tax	37,682		34,677		3,005			8.7		113,047		104,248		8,799			8.4
Income from operations	$	255,604	$	255,419	$	185		0.1		$	512,638	$	527,688	$	(15,050	)	(2.9	)

Operating Expenses and Other Income and Expense Items

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	80,444	$	84,213	$	(3,769	)	(4.5	)	$	248,263	$	277,841	$	(29,578	)	(10.6	)

Operating and maintenance expense decreased for the three months ended September 30, 2015, compared to the same period in 2014, due primarily to our having incurred $3.1 million lower transmission and distribution maintenance expense and $1.6 million lower generation maintenance expense. The lower maintenance expense was partially offset by an approximate $2.0 million write off of capital project costs that will no longer be completed related to planned retirements of generating units.

Operating and maintenance expense decreased for the nine months endedSeptember 30, 2015, compared to the same period in 2014, due primarily to:

• lower costs at Wolf Creek of $10.8 million, which were principally the result of higher operating and maintenance costs incurred during a 2014 scheduled outage;

• lower transmission and distribution maintenance expense of $8.4 million; and

• a $7.9 million decrease in operating and maintenance costs at our coal fired plants due primarily to a planned outage at JEC in 2014.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change		% Change	2015		2014		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	77,184	$	72,279	$	4,905	6.8	$	228,529	$	213,270	$	15,259	7.2

Depreciation and amortization expense increased during the three and nine months endedSeptember 30, 2015, compared to the same periods in 2014, due to additions at our power plants, including air quality controls, additions at Wolf Creek to enhance reliability and the addition of transmission facilities. Depreciation related to environmental equipment placed in-service at La Cygne, as approved by the KCC, was deferred until new retail prices became effective in late October 2015.

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	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change		% Change	2015		2014		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	37,682	$	34,677	$	3,005	8.7	$	113,047	$	104,248	$	8,799	8.4

Taxes other than income tax increased for the three and nine months endedSeptember 30, 2015, compared to the same periods in 2014, due primarily to increases of $3.0 million and $8.9 million, respectively, in property tax expense. These increases are mostly offset in retail revenues.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars in Thousands)
Other income	$	637	$	14,991	$	(14,354	)	(95.8	)	$	18,572	$	26,566	$	(7,994	)	(30.1	)

Other income decreased for the three and nine months endedSeptember 30, 2015, compared to the same periods in 2014, due primarily to a decrease in equity AFUDC of $3.6 million and $11.3 million, respectively. Contributing to the decrease for the three month period is our having recorded $10.7 million less in COLI benefits. However, we recorded $3.0 million more in COLI benefits for the nine months endedSeptember 30, 2015, compared to the same period the prior year.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars in Thousands)
Interest expense	$	44,306	$	44,531	$	(225	)	(0.5	)	$	134,120	$	138,075	$	(3,955	)	(2.9	)

Interest expense decreased for the nine months endedSeptember 30, 2015, compared to the same period in 2014, due primarily to a decrease in long-term interest expense of $10.0 million. However, partially offsetting this decrease was a reduction in debt AFUDC of $6.4 million.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
	(Dollars in Thousands)
Income tax expense	$	66,293	$	71,532	$	(5,239	)	(7.3	)	$	127,810	$	132,643	$	(4,833	)	(3.6	)

Income tax expense decreased due principally to lower income before income taxes.

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FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of September 30, 2015, compared to December 31, 2014.

	As of		As of
	September 30, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	276,689	$	247,406	$	29,283	11.8

Inventory increased due principally to a $20.1 million increase in coal inventory resulting from improved rail performance and a $10.6 million increase in material and supplies for improved substation reliability.

	As of		As of
	September 30, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	861,036	$	859,778	$	1,258		0.1
Regulatory liabilities	306,977		343,485		(36,508		)	(10.6	)
Net regulatory assets	$	554,059	$	516,293	$	37,766		7.3

Total regulatory assets increased due primarily to:

• a $13.2 million increase in deferred depreciation expense and carrying costs related to our capital investment associated with environmental upgrades at La Cygne;

• a $10.6 million increase in amounts deferred for Wolf Creek’s refueling and maintenance outages;

• a $7.0 million increase in amounts deferred for property taxes; and

• a $3.3 million increase in conditional AROs; however,

• partially offsetting these increases was a $33.9 million decrease in deferred employee benefit costs.

Total regulatory liabilities decreased due primarily to a $22.8 million decrease in amounts collected but not yet spent to dispose of plant assets and an $8.6 million decrease in our refund obligations related to amounts we have collected from our customers in excess of our actual cost of fuel and purchased power.

	As of		As of
	September 30, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	8,379,029	$	8,162,908	$	216,121	2.6

Property, plant and equipment, net of accumulated depreciation, increased due primarily to plant additions for air quality controls and an asset recorded related to a new ARO. See Note 11 to the Condensed Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information.

	As of		As of
	September 30, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Short-term debt	$	303,600	$	257,600	$	46,000	17.9

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

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	As of		As of
	September 30, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Long-term debt, net	$	2,941,889	$	3,215,539	$	(273,650	)	(8.5	)

Total long-term debt decreased due to Westar Energy redeeming $275.0 million in principal amount of first mortgage bonds. See Note 6 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing.”

	As of		As of
	September 30, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933	$	376		1.3
Long-term debt of variable interest entities	138,134		166,565		(28,431		)	(17.1	)
Total long-term debt of variable interest entities	$	166,443	$	194,498	$	(28,055	)	(14.4	)

Total long-term debt of variable interest entities decreased due to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $27.9 million.

	As of		As of
	September 30, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,601,511	$	1,475,487	$	126,024	8.5

Deferred income taxes increased due primarily to the use of accelerated depreciation methods and the utilization of previously deferred net operating losses during the period.

	As of		As of
	September 30, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Asset retirement obligations	$	286,389	$	230,668	$	55,721	24.2

AROs increased due primarily to a new ARO of approximately $48.8 million as a result of the CCB regulation published by the EPA. See Note 10 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies — Regulation of Coal Combustion Byproducts,” and Note 11 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information.

39

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.

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 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 may be used to temporarily fund capital expenditures, to redeem debt, for working capital and/or for other general corporate purposes. As of October 27, 2015, Westar Energy had $291.5 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. In September 2015, Westar Energy extended the term of the $730.0 million facility by one year to terminate in September 2019,

$20.7 million of which will expire in September 2017. In February 2014, Westar Energy extended the term of its $270.0 million credit facility to February 2017, $20.0 million of which was set to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. As long as there is no default under the facilities, the $730.0 million facility may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE first mortgage bonds. 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 27, 2015, no amounts were borrowed and $19.2 million in letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit had been issued under the $270.0 million facility as of the same date.

Long-Term Debt Financing

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

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

Debt Covenants

We remain in compliance with our debt covenants.

Impact of Credit Ratings on Debt Financing

Moody’s Investors Service (Moody’s), Standard & Poor’s Ratings Services (S&P) and Fitch Ratings (Fitch) 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.

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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 total debt to total capitalization and funds from operations to total 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.

In October 2015, Fitch upgraded its ratings for Westar Energy and KGE first mortgage bonds to A from A- and revised its rating for Westar Energy’s and KGE’s outlook to stable from positive.

As of October 27, 2015, our ratings with the agencies are as shown in the table below.

	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Commercial Paper	Rating Outlook
Moody’s	A2	A2	P-2	Stable
S&P	A	A	A-2	Stable
Fitch	A	A	F2	Stable

Common Stock

During the nine months endedSeptember 30, 2015, Westar Energy issued 9.2 million shares of common stock with a

physical settlement amount of $254.6 million to settle all outstanding forward sale transactions. Westar Energy used the proceeds from this transaction to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

Summary of Cash Flows

	Nine Months Ended September 30,
	2015			2014			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	583,633		$	650,212		$	(66,579	)	(10.2	)
Investing activities	(435,974		)	(641,758		)	205,784			32.1
Financing activities	(148,386		)	(7,106		)	(141,280		)	(a)
Net change in cash and cash equivalents	$	(727	)	$	1,348		$	(2,075	)	(153.9	)

______________

(a) Change greater than 1,000%

Cash Flows from Operating Activities

Cash flows from operating activities decreased due principally to our having received $40.2 million less for wholesale power salesand transmission services, our having received $34.4 million less from retail customers, our having paid $21.8 million more for the Wolf Creek refueling outage and our having received $13.9 million less for energy marketing activities. Partially offsetting these decreases was our having paid $34.2 million less for coal and natural gas.

41

Cash Flows used in Investing Activities

Cash flows used in investing activities decreased due primarily to our having invested $162.4 million less in additions to property, plant and equipment and our having received $42.0 million more from our investment in COLI.

Cash Flows from Financing Activities

Cash flows used in financing activities increased due principally to our having issued $417.9 million less long-term debt, repaying $41.2 million more for borrowings against the cash surrender value of COLI and issuing $21.2 million less commercial paper during the nine months endedSeptember 30, 2015, compared to the same period in 2014. Partially offsetting these increases was our having issued $198.6 million more in common stock and redeeming $152.5 million less in long-term debt this year compared to the previous year.

Pension Contribution

During the nine months endedSeptember 30, 2015, we contributed $29.7 million to the Westar Energy pension trust. We funded $4.5 million of Wolf Creek’s pension plan contributions during the same period.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2014, through September 30, 2015, our off balance sheet arrangements did not change materially. For additional information, see our 2014 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2014, through September 30, 2015, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2014 Form 10-K.

OTHER INFORMATION

Changes in Prices

See Note 3 to the Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” for additional information.

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, 2014, to September 30, 2015, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2014 Form 10-K for additional information.

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.

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There were no changes in our internal control over financial reporting during the three months endedSeptember 30, 2015, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.    OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 3, 10 and 12 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 1A. RISK FACTORS

     There were no material changes in our risk factors from December 31, 2014, through September 30, 2015. For additional information, see our 2014 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

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

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ITEM 6. EXHIBITS

10	Third Extension Agreement dated as of September 17, 2015, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement
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, 2015
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, 2015
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2015 (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

44

SIGNATURE

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

		WESTAR ENERGY, INC.
Date:	November 3, 2015	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

45

EX-10

EXECUTION VERSION

THIRD EXTENSION AGREEMENT

THIS THIRD EXTENSION AGREEMENT, dated as of September 17, 2015 (this “Agreement”), among WESTAR ENERGY, INC., a Kansas corporation (the “Borrower”), Kansas Gas and Electric Company, a Kansas corporation (the “Guarantor”), the several banks and other financial institutions or entities from time to time parties to this Agreement (the “Lenders”), JPMORGAN CHASE BANK, N.A., as administrative agent (in such capacity, the “Administrative Agent”), CITIBANK, N.A., as syndication agent, and BANK OF AMERICA, N.A., THE BANK OF NEW YORK MELLON, THE BANK OF TOKYO-MITSUBISHI UFJ, LTD. and WELLS FARGO BANK, NATIONAL ASSOCIATION, as documentation agents.

RECITALS

A.    The Borrower, the banks and other financial institutions party thereto and the Administrative Agent are parties to that certain Fourth Amended and Restated Credit Agreement dated as of September 29, 2011, as amended by the First Extension Agreement, dated as of July 19, 2013 and as further amended by the Second Extension Agreement, dated as of September 18, 2014 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Capitalized terms used herein without definition shall have the meanings given to them in the Credit Agreement as they may be modified pursuant to this Agreement.

B.    The Borrower has requested a one-year extension of the Revolving Termination Date pursuant to Section 2.1(b) of the Credit Agreement and the Lenders signatory hereto have approved such request.

STATEMENT OF AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

I.EXTENSION

Pursuant to Section 2.1(b) of the Credit Agreement, the Borrower provided not less than 65 days’ written notice to the Administrative Agent prior to September 29, 2015 (the “Noticed Anniversary Date”) of its request to extend the Revolving Commitments. As of the date hereof, Lenders (the “Extending Lenders”) holding more than fifty percent (50%) of the Total Revolving Commitments, by executing this Agreement, have approved the Borrower’s request to extend its Revolving Commitments in the amount set forth on Schedule I hereto (such extended Revolving Commitments, the “Extended Revolving Commitments”) and, subject to the satisfaction of the conditions precedent set forth in Section II, the Revolving Termination Date as to the Extended Revolving Commitments of the Extending Lenders shall be extended to September 29, 2019 (it being understood and agreed that such extended Revolving Termination Date shall apply to each Extending Lender regardless of the Revolving Termination Date applicable to such Lender prior to giving effect to this Agreement). The Revolving Termination Date as to any Declining Lender remains unchanged (it being understood and agreed that a Lender shall be deemed an Extending Lender with respect to its Extended Revolving Commitments and a Declining Lender with respect to its Revolving Commitments, if any, that are not Extended Revolving Commitments).

II.CONDITIONS PRECEDENT

The extension of the Revolving Termination Date pursuant to Section I shall become effective as of the date when, and only when, each of the following conditions precedent shall have been satisfied (the “Extension Date”):

(i)The Administrative Agent (or its counsel) shall have received from the Borrower, the Guarantor, Extending Lenders constituting Required Lenders and from each Issuing Lender either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include facsimile or other electronic image scan transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(ii)The Borrower shall have paid:

(A)to the Administrative Agent, for the account of each Extending Lender, an extension fee in the amount of 0.06% of such Extending Lender’s Revolving Commitment as of the Extension Date, which extension fee once paid will be fully earned and nonrefundable; and

(B)all other fees and reasonable expenses of the Administrative Agent and the Lenders required under the Credit Agreement and any other Loan Document to be paid on or prior to the Extension Date (including reasonable fees and expenses of counsel) in connection with this Agreement.

(iii)The Administrative Agent shall have received a certificate, dated the Extension Date and signed by an authorized officer of the Borrower, confirming (i) no Default or Event of Default shall have occurred and be continuing on the Extension Date and after giving effect thereto and (ii) the representations and warranties set forth in Section III hereof, if not qualified as to materiality, shall be true and correct in all material respects and all other representations and warranties set forth in Section III hereof shall be true and correct, in each case on and as of the Extension Date with the same force and effect as if made on or as of the Extension Date (except for those representations and warranties or parts thereof that, by their terms, expressly relate solely to a specific date, in which case such representations and warranties, if not qualified as to materiality, shall be true and correct in all material respects and all such other representations and warranties shall be true and correct, in each case as of such specific date).

III.REPRESENTATIONS AND WARRANTIES

The Borrower represents and warrants to the Administrative Agent and the Lenders that (i) each of the representations and warranties contained in Section 3 of the Credit Agreement, if not qualified as to materiality, are true and correct in all material respects and all other representations and warranties set forth in Section 3 of the Credit Agreement are true and correct, in each case on and as of the Extension Date, both immediately before and after giving effect to this Agreement (except for those representations and warranties or parts thereof that, by their terms, expressly relate solely to a specific date, in which case such representations and warranties, if not qualified as to materiality, shall be true and correct in all material respects and all such

2

other representations and warranties shall be true and correct, in each case as of such specific date), (ii) this Agreement has been duly authorized, executed and delivered by the Borrower and constitutes the legal, valid and binding obligation of the Borrower enforceable against it in accordance with its terms and (iii) no Default or Event of Default shall have occurred and be continuing on the Extension Date, both immediately before and after giving effect to this Agreement.

IV.ACKNOWLEDGMENT AND CONFIRMATION OF THE BORROWER AND GUARANTOR

Each of the Borrower and Guarantor hereby confirms and agrees that after giving effect to this Agreement, the Credit Agreement and the other Loan Documents remain in full force and effect and enforceable against each Loan Party in accordance with their respective terms and shall not be discharged, diminished, limited or otherwise affected in any respect. Each of the Borrower and Guarantor represents and warrants to the Lenders that it has no knowledge of any claims, counterclaims, offsets, or defenses to or with respect to its obligations under the Loan Documents, or if the Borrower or Guarantor has any such claims, counterclaims, offsets, or defenses to the Loan Documents or any transaction related to the Loan Documents, the same are hereby waived, relinquished, and released in consideration of the execution of this Agreement. This acknowledgment and confirmation by the Borrower and Guarantor is made and delivered to induce the Administrative Agent and the Lenders to enter into this Agreement. Each of the Borrower and Guarantor acknowledges that the Administrative Agent and the Lenders would not enter into this Agreement in the absence of the acknowledgment and confirmation contained herein.

V.MISCELLANEOUS

(i)GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK (INCLUDING SECTIONS 5‑1401 AND 5‑1402 OF THE NEW YORK GENERAL OBLIGATIONS LAW, BUT EXCLUDING ALL OTHER CHOICE OF LAW AND CONFLICTS OF LAW RULES).

(ii)Full Force and Effect. Except as expressly modified hereby, the Credit Agreement and the other Loan Documents shall continue in full force and effect in accordance with the provisions thereof on the date hereof. As used in the Credit Agreement, “hereinafter,” “hereto,” “hereof,” and words of similar import shall, unless the context otherwise requires, mean the Credit Agreement after giving effect to this Agreement. Any reference to the Credit Agreement or any of the other Loan Documents herein or in any such documents shall refer to the Credit Agreement and Loan Documents as modified hereby. This Agreement is limited as specified and shall not constitute or be deemed to constitute an amendment, modification or waiver of any provision of the Credit Agreement except as expressly set forth herein. This Agreement shall constitute a Loan Document under the terms of the Credit Agreement.

(iii)Expenses. The Borrower agrees on demand (i) to pay all reasonable fees and expenses of counsel to the Administrative Agent, and (ii) to reimburse the Administrative Agent for all

3

reasonable out-of-pocket costs and expenses, in each case, in connection with the preparation, negotiation, execution and delivery of this Agreement and the other Loan Documents delivered in connection herewith.

(iv)Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

(v)Successors and Assigns. This Agreement shall be binding upon, inure to the benefit of and be enforceable by the respective successors and permitted assigns of the parties hereto.

(vi)Construction. The headings of the various sections and subsections of this Agreement have been inserted for convenience only and shall not in any way affect the meaning or construction of any of the provisions hereof. The provisions of Section 1.2 of the Credit Agreement are hereby incorporated by reference as if fully set forth herein.

(vii)Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission or by email shall be effective as delivery of a manually executed counterpart hereof. A set of the copies of this Agreement signed by all the parties shall be lodged with the Borrower and the Administrative Agent.

[signature pages follow]

4

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

WESTAR ENERGY, INC., as Borrower

By:    /s/ Anthony D. Somma    

Anthony D. Somma

Senior Vice President, Chief Financial Officer and Treasurer    

KANSAS GAS AND ELECTRIC COMPANY, as Guarantor

By:    /s/ Anthony D. Somma    

Anthony D. Somma

Vice President and Treasurer

[Signature Page to Third Extension Agreement]

JPMORGAN CHASE BANK, N.A., as Administrative Agent, as an Issuing Lender and as a Lender

By:    /s/ Bridget Killackey    

Name:    Bridget Killackey

Title: Vice President

[Signature Page to Third Extension Agreement]

BANK OF AMERICA, N.A., as a Documentation Agent and as a Lender

By:    /s/ Geoffrey D. Steinbrenner    

Name:    Geoffrey D. Steinbrenner

Title: Vice President

[Signature Page to Third Extension Agreement]

THE BANK OF NEW YORK MELLON

By:    /s/ Mark W. Rogers    

Name:    Mark W. Rogers

Title:    Vice President

[Signature Page to Third Extension Agreement]

CITIBANK, N.A.,

as a Lender

By:    /s/ D.A. Lipke    

Name:    D.A. Lipke

Title:    Vice President

[Signature Page to Third Extension Agreement]

The Bank of Tokyo-Mitsubishi UFJ, Ltd.

By:    /s/ Maria Ferradas    

Name:    Maria Ferradas

Title:    Vice President

[Signature Page to Third Extension Agreement]

Wells Fargo Bank, National Association

By:    /s/Allison Newman    

Name:    Allison Newman

Title:    Director

[Signature Page to Third Extension Agreement]

                        BARCLAYS BANK PLC

By:    /s/ Marguerite Sutton    

Name:    Marguerite Sutton

Title:    Vice President

[Signature Page to Third Extension Agreement]

CoBank, ACB

By:    /s/ John H. Kemper    

Name:    John H. Kemper

Title:    Vice President

[Signature Page to Third Extension Agreement]

BNP PARIBAS

By:    /s/ Denis O’Meara    

Name:    Denis O’Meara

Title:    Managing Director

By:    /s/ Karima Omar    

Name:    Karima Omar

Title:    Vice President

[Signature Page to Third Extension Agreement]

                        Regions Bank

By:    /s/ D. Mitch Wilson    

Name:    D. Mitch Wilson

Title:    Director

[Signature Page to Third Extension Agreement]

U.S. BANK, NATIONAL ASSOCIATION, as an

Issuing Lender and as a Lender

By:    /s/ Andrew N. Taylor    

Name:    Andrew Taylor

Title:    Senior Vice President

[Signature Page to Third Extension Agreement]

TD BANK, N.A.

By:    /s/ Shannon Batchman    

Name:    Shannon Batchman

Title:    Senior Vice President

[Signature Page to Third Extension Agreement]

Northern Trust Company, as a Lender

By:    /s/ John Canty    

Name:    John Canty

Title:    Senior Vice President

[Signature Page to Third Extension Agreement]

UMB Bank, n.a.

By:    /s/ David A. Proffitt    

Name:    David A. Proffitt

Title:    Senior Vice President

[Signature Page to Third Extension Agreement]

EX-31.A

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended September 30, 2015, of Westar Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	November 3, 2015	By:	/s/    Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer
			Westar Energy, Inc.
			(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the period ended September 30, 2015, of Westar Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	November 3, 2015	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer
			Westar Energy, Inc.
			(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Westar Energy, Inc. (the Company) on Form 10-Q for the quarter ended September 30, 2015 (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 3, 2015	By:	/s/    Mark A. Ruelle
			Mark A. Ruelle
			Director, President and Chief Executive Officer

Date:	November 3, 2015	By:	/s/   Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

XML

Financial Instruments and Risk Management (Unrealized Gains And Losses On Financial Statements) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Available-for-sale Securities, Security Type Allocation Percentage	100.00%		100.00%		100.00%
Unrealized gain (loss) included in regulatory liabilities	$ 240	$ 518	$ 755	$ 2,014
Domestic Equity [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Available-for-sale Securities, Security Type Allocation Percentage	30.00%		30.00%		33.00%
Unrealized gain (loss) included in regulatory liabilities	$ (132)	13	$ (368)	362
Alternative Funds [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Available-for-sale Securities, Security Type Allocation Percentage	10.00%		10.00%		9.00%
Unrealized gain (loss) included in regulatory liabilities	$ 113	(377)	$ 567	1,149
Real Estate Securities [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Available-for-sale Securities, Security Type Allocation Percentage	6.00%		6.00%		5.00%
Unrealized gain (loss) included in regulatory liabilities	$ 259	$ (154)	$ 556	$ 503

XML

Commitments And Contingencies (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015 USD ($)
Commitments And Contingencies [Line Items]
Asset Retirement Obligation, Liabilities Incurred	$ 48,767

XML

Pension and Post-Retirement Benefit Plans (Net Periodic Costs And Pension Contributions) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Components of Net Periodic Cost (Benefit):
Pension Contributions							$ 26,400
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	$ 5,348		$ 4,055		$ 16,044		12,164
Interest cost	10,753		10,400		32,261		31,200
Expected return on plan assets	(10,059)		(9,109)		(31,177)		(27,328)
Prior service costs	130		131		390		394
Actuarial loss, net	8,033		5,690		23,746		15,371
Net periodic cost before regulatory adjustment	14,205		11,167		41,264		31,801
Regulatory adjustment	1,548	[1]	4,002	[1]	4,880	[2]	12,005	[2]
Net periodic cost	15,753		15,169		46,144		43,806
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	361		345		1,082		1,036
Interest cost	1,422		1,588		4,268		4,763
Expected return on plan assets	(1,654)		(1,644)		(4,961)		(4,932)
Prior service costs	114		631		342		1,893
Actuarial loss, net	95		(185)		284		(556)
Net periodic cost before regulatory adjustment	338		735		1,015		2,204
Regulatory adjustment	1,013	[1]	1,124	[1]	3,038	[2]	3,371	[2]
Net periodic cost	$ 1,351		$ 1,859		$ 4,053		$ 5,575

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

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

XML

Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic	$ 304	$ 395	$ 563	$ 721
Net income allocated to common stock	$ 137,699	$ 146,987	$ 252,130	$ 269,089
Weighted Average Number of Shares Outstanding , Basic	141,622,697	130,196,193	136,686,263	129,525,618
RSUs	215,481	198,583	197,373	139,058
Forward sale agreements	0	2,634,011	1,297,949	2,534,907
Weighted average equivalent common shares outstanding - diluted	141,838,178	133,028,787	138,181,585	132,199,583
Earnings Per Share, Basic	$ 0.97	$ 1.13	$ 1.84	$ 2.08
Earnings Per Share, Diluted	$ 0.97	$ 1.10	$ 1.82	$ 2.04
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities			0	0

XML

Financial Investments (Tables)

9 Months Ended

Sep. 30, 2015

Investments [Abstract]

Cost And Fair Value Of Investments

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of September 30, 2015, and December 31, 2014.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2015
Domestic equity funds	$	42,418	$	12,218	$	(6	)	$	54,630	30	%
International equity funds	30,685		1,218		(1,214		)	30,689		17	%
Core bond fund	19,397		310		—			19,707		11	%
High-yield bond fund	14,106		—		(923		)	13,183		7	%
Emerging market bond fund	14,295		—		(2,667		)	11,628		6	%
Other fixed income fund	4,948		—		(25		)	4,923		3	%
Combination debt/equity/other funds	16,213		3,474		(749		)	18,938		10	%
Alternative investment fund	15,000		2,538		—			17,538		10	%
Real estate securities fund	10,918		—		(515		)	10,403		6	%
Cash equivalents	117		—		—			117		<1%
Total	$	168,097	$	19,758	$	(6,099	)	$	181,756	100	%
As of December 31, 2014
Domestic equity funds	$	46,126	$	14,853	$	(7	)	$	60,972	33	%
International equity funds	27,521		3,683		(413		)	30,791		17	%
Core bond fund	18,811		478		—			19,289		10	%
High-yield bond fund	13,342		—		(144		)	13,198		7	%
Emerging market bond fund	12,556		—		(1,568		)	10,988		6	%
Other fixed income fund	4,798		—		(19		)	4,779		3	%
Combination debt/equity/other funds	14,975		3,786		(620		)	18,141		10	%
Alternative investment fund	15,000		1,970		—			16,970		9	%
Real estate securities fund	10,619		—		(1,071		)	9,548		5	%
Cash equivalents	340		—		—			340		<1%
Total	$	164,088	$	24,770	$	(3,842	)	$	185,016	100	%

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

September 30, 2015, and December 31, 2014.

	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2015
Domestic equity funds	$	—	$	—		$	564	$	(6	)	$	564	$	(6	)
International equity funds	—		—			6,236		(1,214		)	6,236		(1,214		)
High-yield bond fund	13,183		(923		)	—		—			13,183		(923		)
Emerging market bond fund	—		—			11,628		(2,667		)	11,628		(2,667		)
Other fixed income fund	4,923		(25		)	—		—			4,923		(25		)
Combination debt/equity/other funds	—		—			6,289		(749		)	6,289		(749		)
Real estate securities fund	—		—			10,403		(515		)	10,403		(515		)
Total	$	18,106	$	(948	)	$	35,120	$	(5,151	)	$	53,226	$	(6,099	)
As of December 31, 2014
Domestic equity funds	$	—	$	—		$	263	$	(7	)	$	263	$	(7	)
International equity funds	5,905		(413		)	—		—			5,905		(413		)
High-yield bond fund	13,198		(144		)	—		—			13,198		(144		)
Emerging market bond fund	—		—			10,988		(1,568		)	10,988		(1,568		)
Other fixed income funds	4,779		(19		)	—		—			4,779		(19		)
Combination debt/equity/other funds	—		—			5,892		(620		)	5,892		(620		)
Real estate securities fund	—		—			9,548		(1,071		)	9,548		(1,071		)
Total	$	23,882	$	(576	)	$	26,691	$	(3,266	)	$	50,573	$	(3,842	)

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Common Stock Common Stock (Details) shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($) shares
Forward Contract Indexed To Issuers Equity, Indexed Shares For Period	9.2
Forward Contract Indexed to Issuer's Equity, Actual Proceeds | $	$ 254.6

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Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,500	$ 100	$ 800	$ 1,500
Trading securities	33,222		33,222		$ 35,497
Cost	168,097		168,097		164,088
Available-for-sale Securities, Gross Unrealized Gain	19,758		19,758		24,770
Available-for-sale Securities, Gross Unrealized Loss	(6,099)		(6,099)		(3,842)
Available-for-sale Securities	$ 181,756		$ 181,756		$ 185,016
Allocation	100.00%		100.00%		100.00%
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 17,250		$ 17,250		$ 18,698
Cost	42,418		42,418		46,126
Available-for-sale Securities, Gross Unrealized Gain	12,218		12,218		14,853
Available-for-sale Securities, Gross Unrealized Loss	(6)		(6)		(7)
Available-for-sale Securities	$ 54,630		$ 54,630		$ 60,972
Allocation	30.00%		30.00%		33.00%
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 4,308		$ 4,308		$ 4,252
Cost	30,685		30,685		27,521
Available-for-sale Securities, Gross Unrealized Gain	1,218		1,218		3,683
Available-for-sale Securities, Gross Unrealized Loss	(1,214)		(1,214)		(413)
Available-for-sale Securities	$ 30,689		$ 30,689		$ 30,791
Allocation	17.00%		17.00%		17.00%
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 11,505		$ 11,505		$ 12,379
Cost	19,397		19,397		18,811
Available-for-sale Securities, Gross Unrealized Gain	310		310		478
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 19,707		$ 19,707		$ 19,289
Allocation	11.00%		11.00%		10.00%
High-Yield Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 14,106		$ 14,106		$ 13,342
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(923)		(923)		(144)
Available-for-sale Securities	$ 13,183		$ 13,183		$ 13,198
Allocation	7.00%		7.00%		7.00%
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 14,295		$ 14,295		$ 12,556
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(2,667)		(2,667)		(1,568)
Available-for-sale Securities	$ 11,628		$ 11,628		$ 10,988
Allocation	6.00%		6.00%		6.00%
Other Fixed Income [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 4,948		$ 4,948		$ 4,798
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(25)		(25)		(19)
Available-for-sale Securities	$ 4,923		$ 4,923		$ 4,779
Allocation	3.00%		3.00%		3.00%
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 16,213		$ 16,213
Available-for-sale Securities, Gross Unrealized Gain	3,474		3,474
Available-for-sale Securities, Gross Unrealized Loss	(749)		(749)
Available-for-sale Securities	$ 18,938		$ 18,938
Allocation	10.00%		10.00%
Combination Debt and Equity Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost					$ 14,975
Available-for-sale Securities, Gross Unrealized Gain					3,786
Available-for-sale Securities, Gross Unrealized Loss					(620)
Available-for-sale Securities					$ 18,141
Allocation					10.00%
Alternative Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 15,000		$ 15,000		$ 15,000
Available-for-sale Securities, Gross Unrealized Gain	2,538		2,538		1,970
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 17,538		$ 17,538		$ 16,970
Allocation	10.00%		10.00%		9.00%
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 10,918		$ 10,918		$ 10,619
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	(515)		(515)		(1,071)
Available-for-sale Securities	$ 10,403		$ 10,403		$ 9,548
Allocation	6.00%		6.00%		5.00%
Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 159		$ 159		$ 168
Cost	117		117		340
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
Available-for-sale Securities, Gross Unrealized Loss	0		0		0
Available-for-sale Securities	$ 117		$ 117		$ 340

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Financial Instruments and Risk Management (Fair Value Of Assets And Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	$ 181,756	$ 185,016
Trading securities	33,222	35,497
Total assets measured at fair value	214,978	220,513
Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	117	340
Trading securities	159	168
Total assets measured at fair value	276	508
Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	147,719	152,111
Trading securities	33,063	35,329
Total assets measured at fair value	180,782	187,440
Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	33,920	32,565
Trading securities	0	0
Total assets measured at fair value	33,920	32,565
Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	54,630	60,972
Trading securities	17,250	18,698
Domestic Equity [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Domestic Equity [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	48,651	54,925
Trading securities	17,250	18,698
Domestic Equity [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	5,979	6,047
Trading securities	0	0
International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	30,689	30,791
Trading securities	4,308	4,252
International Equity [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
International Equity [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	30,689	30,791
Trading securities	4,308	4,252
International Equity [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	19,707	19,289
Trading securities	11,505	12,379
Core Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Core Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	19,707	19,289
Trading securities	11,505	12,379
Core Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
High-Yield Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	13,183	13,198
High-Yield Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
High-Yield Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	13,183	13,198
High-Yield Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Emerging Market Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	11,628	10,988
Emerging Market Bonds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Emerging Market Bonds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	11,628	10,988
Emerging Market Bonds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Other Fixed Income [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	4,923	4,779
Other Fixed Income [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Other Fixed Income [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	4,923	4,779
Other Fixed Income [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Combination Debt Equity And Other Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	18,938
Combination Debt Equity And Other Fund [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0
Combination Debt Equity And Other Fund [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	18,938
Combination Debt Equity And Other Fund [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0
Combination Debt and Equity Fund [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		18,141
Combination Debt and Equity Fund [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0
Combination Debt and Equity Fund [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		18,141
Combination Debt and Equity Fund [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		0
Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	17,538	16,970
Alternative Funds [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Alternative Funds [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Alternative Funds [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	17,538	16,970
Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	10,403	9,548
Real Estate Securities [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Real Estate Securities [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Real Estate Securities [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	10,403	9,548
Cash Equivalents [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	117	340
Trading securities	159	168
Cash Equivalents [Member] | Level 1 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	117	340
Trading securities	159	168
Cash Equivalents [Member] | Level 2 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	0	0
Cash Equivalents [Member] | Level 3 [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	0	0
Trading securities	$ 0	$ 0

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Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Variable Interest Entity [Line Items]
Property, plant and equipment, net		$ 8,379,029	$ 8,162,908
Accrued interest	[1]	60,844	79,707
Long-term debt, net		2,941,889	3,215,539
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Property, plant and equipment, net		270,822	278,573
Regulatory assets	[2]	8,777	7,882
Current maturities of long-term debt		28,309	27,933
Accrued interest	[1]	68	2,961
Long-term debt, net		$ 138,134	$ 166,565

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

[2] Included in long-term regulatory assets on our consolidated balance sheets.

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Wolf Creek Pension and Post-Retirement Benefit Plans Wolf Creek Pension and Post-Retirement Benefit Plans (Net Periodic Costs and Pension Contributions) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Components of Net Periodic Cost (Benefit):
Pension Contributions							$ 26,400
Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Pension Contributions							2,400
KGE [Member]
Subsidiary Interest in Defined Benefit Plans					47.00%
Pension Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	$ 5,348		$ 4,055		$ 16,044		12,164
Interest cost	10,753		10,400		32,261		31,200
Expected return on plan assets	(10,059)		(9,109)		(31,177)		(27,328)
Prior service costs	130		131		390		394
Actuarial loss, net	8,033		5,690		23,746		15,371
Net periodic cost before regulatory adjustment	14,205		11,167		41,264		31,801
Regulatory adjustment	1,548	[1]	4,002	[1]	4,880	[2]	12,005	[2]
Net periodic cost	15,753		15,169		46,144		43,806
Pension Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	1,899		1,424		5,696		4,271
Interest cost	2,254		2,117		6,761		6,352
Expected return on plan assets	(2,261)		(2,021)		(6,783)		(6,063)
Prior service costs	14		14		43		43
Actuarial loss, net	1,482		747		4,448		2,240
Net periodic cost before regulatory adjustment	3,388		2,281		10,165		6,843
Regulatory adjustment	(304)	[3]	501	[3]	(912)	[4]	1,502	[4]
Net periodic cost	3,084		2,782		9,253		8,345
Post-Retirement Benefits [Member]
Components of Net Periodic Cost (Benefit):
Service cost	361		345		1,082		1,036
Interest cost	1,422		1,588		4,268		4,763
Expected return on plan assets	(1,654)		(1,644)		(4,961)		(4,932)
Prior service costs	114		631		342		1,893
Actuarial loss, net	95		(185)		284		(556)
Net periodic cost before regulatory adjustment	338		735		1,015		2,204
Regulatory adjustment	1,013	[1]	1,124	[1]	3,038	[2]	3,371	[2]
Net periodic cost	1,351		1,859		4,053		5,575
Post-Retirement Benefits [Member] | Wolf Creek [Member]
Components of Net Periodic Cost (Benefit):
Service cost	34		43		103		130
Interest cost	79		116		236		347
Expected return on plan assets	0		0		0		0
Prior service costs	0		0		0		0
Actuarial loss, net	1		41		2		124
Net periodic cost before regulatory adjustment	114		200		341		601
Regulatory adjustment	0	[3]	0	[3]	0	[4]	0	[4]
Net periodic cost	$ 114		$ 200		$ 341		$ 601

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

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

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

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

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Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the 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 2014 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 endedSeptember 30, 2015, are not necessarily indicative of the results to be expected for the full year.

Fuel Inventory and Supplies

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

	As of		As of
	September 30, 2015		December 31, 2014
	(In Thousands)
Fuel inventory	$	89,144	$	70,416
Supplies	187,545		176,990
Fuel inventory and supplies	$	276,689	$	247,406

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 consolidated statements of income as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	466		$	2,504		$	3,047		$	9,448
Equity funds	—			3,627			2,034			13,345
Total	$	466		$	6,131		$	5,081		$	22,793
Average AFUDC Rates	1.0		%	6.4		%	2.8		%	6.9		%

Earnings Per Share

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

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	140,564	$	149,760	$	259,970	$	276,552
Less: Net income attributable to noncontrolling interests	2,561		2,378		7,277		6,742
Net income attributable to Westar Energy, Inc.	138,003		147,382		252,693		269,810
Less: Net income allocated to RSUs	304		395		563		721
Net income allocated to common stock	$	137,699	$	146,987	$	252,130	$	269,089
Weighted average equivalent common shares outstanding – basic	141,622,697		130,196,193		136,686,263		129,525,618
Effect of dilutive securities:
RSUs	215,481		198,583		197,373		139,058
Forward sale agreements	—		2,634,011		1,297,949		2,534,907
Weighted average equivalent common shares outstanding – diluted (a)	141,838,178		133,028,787		138,181,585		132,199,583
Earnings per common share, basic	$	0.97	$	1.13	$	1.84	$	2.08
Earnings per common share, diluted	$	0.97	$	1.10	$	1.82	$	2.04

_______________

(a) We had no antidilutive securities for the three and nine months endedSeptember 30, 2015 and 2014.

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2015		2014
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	119,173	$	119,275
Interest on financing activities of VIEs	10,430		12,178
Income taxes, net of refunds	126		361
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	60,155		111,494
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	8,008		6,697
Assets acquired through capital leases	2,246		1,454

New Accounting Pronouncements

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

Revenue Recognition

In May 2014, the FASB issued guidance that addresses revenue from contracts with customers. 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. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

Presentation of Financial Statements

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, and do not expect this to have a material impact to our financial statements.

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Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 1,500	$ 100	$ 800	$ 1,500
Fair Value, Less than 12 Months	18,106		18,106		$ 23,882
Gross Unrealized Losses, Less than 12 Months	(948)		(948)		(576)
Fair Value, 12 Months or Greater	35,120		35,120		26,691
Gross Unrealized Losses, 12 Months or Greater	(5,151)		(5,151)		(3,266)
Fair Value, Total	53,226		53,226		50,573
Gross Unrealized Losses, Total	(6,099)		(6,099)		(3,842)
Domestic Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	564		564		263
Gross Unrealized Losses, 12 Months or Greater	(6)		(6)		(7)
Fair Value, Total	564		564		263
Gross Unrealized Losses, Total	(6)		(6)		(7)
International Equity [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		5,905
Gross Unrealized Losses, Less than 12 Months	0		0		(413)
Fair Value, 12 Months or Greater	6,236		6,236		0
Gross Unrealized Losses, 12 Months or Greater	(1,214)		(1,214)		0
Fair Value, Total	6,236		6,236		5,905
Gross Unrealized Losses, Total	(1,214)		(1,214)		(413)
Core Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	13,183		13,183		13,198
Gross Unrealized Losses, Less than 12 Months	(923)		(923)		(144)
Fair Value, 12 Months or Greater	0		0		0
Gross Unrealized Losses, 12 Months or Greater	0		0		0
Fair Value, Total	13,183		13,183		13,198
Gross Unrealized Losses, Total	(923)		(923)		(144)
Emerging Market Bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	11,628		11,628		10,988
Gross Unrealized Losses, 12 Months or Greater	(2,667)		(2,667)		(1,568)
Fair Value, Total	11,628		11,628		10,988
Gross Unrealized Losses, Total	(2,667)		(2,667)		(1,568)
Other Fixed Income [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	4,923		4,923		4,779
Gross Unrealized Losses, Less than 12 Months	(25)		(25)		(19)
Fair Value, 12 Months or Greater	0		0		0
Gross Unrealized Losses, 12 Months or Greater	0		0		0
Fair Value, Total	4,923		4,923		4,779
Gross Unrealized Losses, Total	(25)		(25)		(19)
Combination Debt Equity And Other Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	6,289		6,289		5,892
Gross Unrealized Losses, 12 Months or Greater	(749)		(749)		(620)
Fair Value, Total	6,289		6,289		5,892
Gross Unrealized Losses, Total	(749)		(749)		(620)
Real Estate Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value, Less than 12 Months	0		0		0
Gross Unrealized Losses, Less than 12 Months	0		0		0
Fair Value, 12 Months or Greater	10,403		10,403		9,548
Gross Unrealized Losses, 12 Months or Greater	(515)		(515)		(1,071)
Fair Value, Total	10,403		10,403		9,548
Gross Unrealized Losses, Total	$ (515)		$ (515)		$ (1,071)

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2015

Variable Interest Entities [Abstract]

Assets And Liabilities of VIEs

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

	As of		As of
	September 30, 2015		December 31, 2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	270,822	$	278,573
Regulatory assets (a)	8,777		7,882
Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Accrued interest (b)	68		2,961
Long-term debt of variable interest entities, net	138,134		166,565

_______________

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

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

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The change in the balance of our ARO liability from December 31, 2014, through September 30, 2015, is summarized in the following table.

	(In Thousands)
Balance as of December 31, 2014	$	230,668
Liabilities incurred	48,767
Liabilities settled	(1,312		)
Accretion expense	9,500
Revisions in estimated cash flows	(1,234		)
Balance as of September 30, 2015	$	286,389

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Debt Financing (Narrative) (Details) - USD ($)	1 Months Ended		9 Months Ended
	Aug. 31, 2015	Jan. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Feb. 01, 2015	Dec. 31, 2014	Sep. 29, 2011	Feb. 18, 2011
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 275,000,000	$ 427,500,000
Revolving Credit Facility Lender One [Member]
Debt Instrument [Line Items]
Long-term Line of Credit			0			$ 0
Line of Credit Facility, Maximum Borrowing Capacity							$ 730,000,000
Line of Credit Facility, Increase(Decrease) in Maximum Borrowing Capacity			20,700,000
Letters of Credit Outstanding, Amount			19,200,000			15,600,000
Revolving Credit Facility Lender Two [Member]
Debt Instrument [Line Items]
Long-term Line of Credit			$ 0			$ 0
Line of Credit Facility, Maximum Borrowing Capacity								$ 270,000,000
Line of Credit Facility, Increase(Decrease) in Maximum Borrowing Capacity					$ 20,000,000
Letters of Credit Outstanding, Amount		$ 0
Westar Energy [Member] | Debt Instrument Three [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.875%	5.95%
Repayments of Long-term Debt	$ 150,000,000	$ 125,000,000

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Description Of Business (Details)	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of customers in Kansas	699,000

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Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Total	$ 276,689	$ 247,406
Fuel Inventory [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	89,144	70,416
Supplies [Member]
Public Utilities, Inventory [Line Items]
Public Utility Inventory	$ 187,545	$ 176,990

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Description Of Business

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description Of Business

DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 699,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

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Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Borrowed funds	$ (466)	$ (2,504)	$ (3,047)	$ (9,448)
Equity funds	0	3,627	2,034	13,345
Total	$ 466	$ 6,131	$ 5,081	$ 22,793
Average AFUDC rates	1.00%	6.40%	2.80%	6.90%

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Financial Instruments and Risk Management (Investments In Financial Instruments) (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Dec. 31, 2014
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		$ 181,756	$ 185,016
Trading securities		33,222	35,497
Total		214,978	220,513
Asset Retirement Obligation, Revision of Estimate		(1,234)
Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		54,630	60,972
Trading securities		17,250	18,698
Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		17,538	16,970
Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		10,403	9,548
International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		30,689	30,791
Trading securities		4,308	4,252
Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		19,707	19,289
Trading securities		11,505	12,379
Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		33,920	32,565
Trading securities		33,063	35,329
Total		66,983	67,894
Unfunded commitments		2,048	2,348
Fair Value [Member] | Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets	[1]	5,979	6,047
Trading securities		17,250	18,698
Fair Value [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		17,538	16,970
Fair Value [Member] | Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Nuclear decommissioning trust assets		10,403	9,548
Fair Value [Member] | International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Trading securities		4,308	4,252
Fair Value [Member] | Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Trading securities		11,505	12,379
Decommissioning Trust Assets [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		2,048	2,348
Decommissioning Trust Assets [Member] | Fair Value [Member] | Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 2,048	2,348
Investment redemption frequency		This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. This fund’s term is expected to be 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.
Decommissioning Trust Assets [Member] | Fair Value [Member] | Alternative Funds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	0
Investment redemption frequency		Quarterly
Investment redemption length of settlement	[2]	65 days
Decommissioning Trust Assets [Member] | Fair Value [Member] | Real Estate Securities [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	0
Investment redemption frequency		Quarterly
Investment redemption length of settlement		80 days
Trading Securities [Member] | Fair Value [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	0
Trading Securities [Member] | Fair Value [Member] | Domestic Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	0
Investment redemption frequency		Upon Notice
Investment redemption length of settlement		1 day
Trading Securities [Member] | Fair Value [Member] | International Equity [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	0
Investment redemption frequency		Upon Notice
Investment redemption length of settlement		1 day
Trading Securities [Member] | Fair Value [Member] | Core Bonds [Member]
Financial and Derivative Instruments and Trading Securities [Line Items]
Unfunded commitments		$ 0	$ 0
Investment redemption frequency		Upon Notice
Investment redemption length of settlement		1 day

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

[2] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjZhNTkzNDgwMzdlMTQ1Mjc4YzhmOTJlOGZlZWIyMmNifFRleHRTZWxlY3Rpb246QzVGOTg4QTFCODdENTM2RDlCQzExMkZENzFBMjMxOTkM}

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Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents		$ 3,829	$ 4,556
Accounts receivable, net of allowance for doubtful accounts of $4,503 and $4,596, respectively		288,764	267,327
Fuel inventory and supplies		276,689	247,406
Deferred Tax Assets, Net of Valuation Allowance, Current		22,861	29,636
Prepaid expenses		16,380	15,793
Regulatory assets		125,562	105,549
Other		23,598	30,655
Total Current Assets		757,683	700,922
Property, plant and equipment, net		8,379,029	8,162,908
OTHER ASSETS:
Regulatory assets		735,474	754,229
Nuclear decommissioning trust		181,756	185,016
Other		259,315	265,353
Total Other Assets		1,176,545	1,204,598
TOTAL ASSETS		10,584,079	10,347,001
CURRENT LIABILITIES:
Short-term debt		303,600	257,600
Accounts payable		175,309	219,351
Accrued dividends		49,781	44,971
Accrued taxes		122,791	74,356
Accrued interest	[1]	60,844	79,707
Regulatory liabilities		47,432	55,142
Other		90,627	90,571
Total Current Liabilities		878,693	849,631
LONG-TERM LIABILITIES:
Long-term debt, net		2,941,889	3,215,539
Deferred income taxes		1,601,511	1,475,487
Unamortized investment tax credits		208,760	211,040
Regulatory liabilities		259,545	288,343
Accrued employee benefits		518,307	532,622
Asset retirement obligations		286,389	230,668
Other		74,930	75,799
Total Long-Term Liabilities		$ 6,029,465	$ 6,196,063
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 129,272,835 shares and 128,254,229 shares, respective to each date		$ 706,344	$ 658,437
Paid-in capital		1,999,204	1,781,120
Retained earnings		957,721	855,299
Total Westar Energy, Inc. Shareholders' Equity		3,663,269	3,294,856
Noncontrolling Interests		12,652	6,451
Total Equity		3,675,921	3,301,307
TOTAL LIABILITIES AND EQUITY		10,584,079	10,347,001
Variable Interest Entity [Member]
CURRENT ASSETS:
Property, plant and equipment, net		270,822	278,573
CURRENT LIABILITIES:
Current maturities of long-term debt		28,309	27,933
Accrued interest	[1]	68	2,961
LONG-TERM LIABILITIES:
Long-term debt, net		$ 138,134	$ 166,565

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

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Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Income Tax Contingency [Line Items]
Income tax expense	$ 66,293	$ 71,532	$ 127,810	$ 132,643
Effective income tax rate	32.00%	32.00%	33.00%	32.00%
Liability for unrecognized income tax benefits	$ 2,700		$ 2,700		$ 3,200
Interest on liability related to unrecognized income tax benefits	0		0		0
Penalties accrued for unrecognized income tax benefits	0		0		0
Accrual for taxes other than income taxes	$ 1,500		$ 1,500		$ 1,500

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Consolidated Statements Of Changes In Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2013	$ 3,068,531	$ 641,271	$ 1,696,727	$ 724,776	$ 5,757
Beginning Balance (Shares) at Dec. 31, 2013		128,254,229
Net income	276,552	$ 0	0	269,810	6,742
Issuance of stock	58,560	$ 10,343	48,217	0	0
Issuance of stock (shares)		2,068,510
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		335,202
Issuance Of Stock For Compensation And Reinvested Dividends	6,697	$ 1,676	5,021
Tax withholding related to stock compensation	(2,050)		(2,050)
Dividends on common stock	(136,458)	0	0	(136,458)	0
Stock compensation expense	5,970		5,970
Tax Benefit on stock compensation	790	0	790	0	0
Distributions to shareholders of noncontrolling interests	0
Ending Balance at Sep. 30, 2014	3,277,377	$ 653,290	1,753,460	858,128	12,499
Ending Balance (Shares) at Sep. 30, 2014		130,657,941
Stockholders' Equity, Other	(1,215)				0
Beginning Balance at Dec. 31, 2014	3,301,307	$ 658,437	1,781,120	855,299	6,451
Beginning Balance (Shares) at Dec. 31, 2014		131,687,454
Net income	259,970	$ 0	0	252,693	7,277
Issuance of stock	257,169	$ 46,147	211,022	0	0
Issuance of stock (shares)		9,229,357
Issuance Of Stock For Compensation And Reinvested Dividends, Shares		352,078
Issuance Of Stock For Compensation And Reinvested Dividends	8,008	$ 1,760	6,248
Tax withholding related to stock compensation	(3,234)		(3,234)
Dividends on common stock	(150,271)	0	0	(150,271)	0
Stock compensation expense	6,212		6,212
Tax Benefit on stock compensation	1,231	0	1,231	0	0
Deconsolidation of variable interest entity	1,076				1,076
Distributions to shareholders of noncontrolling interests	1,076
Ending Balance at Sep. 30, 2015	3,675,921	$ 706,344	1,999,204	$ 957,721	12,652
Ending Balance (Shares) at Sep. 30, 2015		141,268,889
Stockholders' Equity, Other	$ (3,395)		$ (3,395)		$ 0

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Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Oct. 31, 2015	Sep. 30, 2015	Sep. 30, 2015
FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 11.0
Loss Contingency Accrual		11.2	$ 11.2
Loss Contingency Accrual, Period Increase (Decrease)			$ 2.5
Kansas Corporation Commission [Member] | Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		7.2
Kansas Corporation Commission [Member] | Environmental Cost Recovery Rider [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		10.8
Kansas Corporation Commission [Member] | Ad Valorem Tax [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		4.9
Federal Energy Regulatory Commission [Member] | Electric Transmission [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 21.6	4.6
Westar Energy [Member] | Kansas Corporation Commission [Member] | General Rate Case [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 78.3
Total Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Return on Equity, Percentage		10.30%
Base Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Requested Return on Equity, Percentage		9.80%
Incentive Return on Equity [Member] | FERC 206 [Member]
Regulatory Proceedings [Line Items]
Public Utilities, Approved Return on Equity, Percentage		0.50%

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Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation

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

Use Of Management's Estimates

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

Fuel Inventory And Supplies

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost.

Allowance For Funds Used During Construction

Allowance for Funds Used During Construction

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

Earnings Per Share

Earnings Per Share

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

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

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Financial Instruments and Risk Management (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fixed Rate Debt Member
Debt Instrument [Line Items]
Carrying Value	$ 2,830,000	$ 3,105,000
Fair Value	3,071,423	3,488,410
Fixed Rate Debt Of Variable Interest Entities Member
Debt Instrument [Line Items]
Carrying Value	166,271	194,204
Fair Value	$ 178,586	$ 213,579

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Financial Instruments and Risk Management (Tables)

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Financial And Derivative Instruments and Trading Securities [Abstract]

Carrying Values And Fair Values Of Financial Instruments

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

	As of September 30, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,830,000	$	3,071,423	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs	166,271		178,586		194,204		213,579

Fair Value Of Assets And Liabilities

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

As of September 30, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	48,651	$	5,979	$	54,630
International equity funds	—		30,689		—		30,689
Core bond fund	—		19,707		—		19,707
High-yield bond fund	—		13,183		—		13,183
Emerging market bond fund	—		11,628		—		11,628
Other fixed income fund	—		4,923		—		4,923
Combination debt/equity/other funds	—		18,938		—		18,938
Alternative investment fund	—		—		17,538		17,538
Real estate securities fund	—		—		10,403		10,403
Cash equivalents	117		—		—		117
Total Nuclear Decommissioning Trust	117		147,719		33,920		181,756
Trading Securities:
Domestic equity funds	—		17,250		—		17,250
International equity fund	—		4,308		—		4,308
Core bond fund	—		11,505		—		11,505
Cash equivalents	159		—		—		159
Total Trading Securities	159		33,063		—		33,222
Total Assets Measured at Fair Value	$	276	$	180,782	$	33,920	$	214,978
As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	54,925	$	6,047	$	60,972
International equity funds	—		30,791		—		30,791
Core bond fund	—		19,289		—		19,289
High-yield bond fund	—		13,198		—		13,198
Emerging market bond fund	—		10,988		—		10,988
Other fixed income fund	—		4,779		—		4,779
Combination debt/equity/other funds	—		18,141		—		18,141
Alternative investment fund	—		—		16,970		16,970
Real estate securities fund	—		—		9,548		9,548
Cash equivalents	340		—		—		340
Total Nuclear Decommissioning Trust	340		152,111		32,565		185,016
Trading Securities:
Domestic equity funds	—		18,698		—		18,698
International equity fund	—		4,252		—		4,252
Core bond fund	—		12,379		—		12,379
Cash equivalents	168		—		—		168
Total Trading Securities	168		35,329		—		35,497
Total Assets Measured at Fair Value	$	508	$	187,440	$	32,565	$	220,513

Reconciliations Of Assets And Liabilities At Fair Value

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2015.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities  Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2015	$	5,910		$	17,425	$	10,042		$	33,377
Total realized and unrealized gains included in:
Regulatory liabilities	273			113		361			747
Purchases	200			—		103			303
Sales	(404		)	—		(103		)	(507		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920
Balance as of December 31, 2014	$	6,047		$	16,970	$	9,548		$	32,565
Total realized and unrealized gains included in:
Regulatory liabilities	836			568		855			2,259
Purchases	300			—		299			599
Sales	(1,204		)	—		(299		)	(1,503		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2014.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2014	$	6,288		$	16,446	$	9,026		$	31,760
Total realized and unrealized gains included in:
Regulatory liabilities	113			377		245			735
Purchases	95			—		92			187
Sales	(126		)	—		(92		)	(218		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464
Balance as of December 31, 2013	$	5,817		$	15,675	$	8,511		$	30,003
Total realized and unrealized gains included in:
Regulatory liabilities	722			1,148		760			2,630
Purchases	191			—		257			448
Sales	(360		)	—		(257		)	(617		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464

Unrealized Gains And Losses On Fair Value Assets And Liabilities

The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the three and nine months endedSeptember 30, 2015 and 2014, attributed to level 3 assets and liabilities. See Note 3, “Rate Matters and Regulation,” in the 2014 Form 10-K for additional information regarding our regulatory assets and liabilities.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund		Net Balance
	(In Thousands)
Total unrealized gains (losses):
Three months ended September 30, 2015	$	(132	)	$	113	$	259	$	240
Three months ended September 30, 2014	(13		)	377		154		518
Nine months ended September 30, 2015	(368		)	567		556		755
Nine months ended September 30, 2014	362			1,149		503		2,014

Investments In Financial Instruments

The following table provides additional information on these investments.

	As of September 30, 2015				As of December 31, 2014				As of September 30, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,979	$	2,048	$	6,047	$	2,348	(a)	(a)
Alternative investment fund (b)	17,538		—		16,970		—		Quarterly	65 days
Real estate securities fund	10,403		—		9,548		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	33,920		2,048		32,565		2,348
Trading Securities:
Domestic equity funds	17,250		—		18,698		—		Upon Notice	1 day
International equity funds	4,308		—		4,252		—		Upon Notice	1 day
Core bond fund	11,505		—		12,379		—		Upon Notice	1 day
Total Trading Securities	33,063		—		35,329		—
Total	$	66,983	$	2,048	$	67,894	$	2,348

_______________

(a) This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. This fund’s term is expected to be 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.

XML

Consolidated Statements Of Changes in Equity Parenthetical (Parentheticals) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.36	$ 0.35	$ 1.08	$ 1.05

XML

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Allowance for doubtful accounts	$ 3,519	$ 5,309
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	141,687,454	131,687,454
Common stock, shares outstanding	141,268,889	131,687,454

XML

Commitments And Contingencies

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Federal Clean Air Act

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

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

Cross-State Air Pollution Rule

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce emissions of SO₂ and NOx. In April 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia Circuit that had vacated CSAPR and remanded CSAPR back to the U.S. Court of Appeals for further proceedings consistent with the U.S. Supreme Court decision.

In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion to lift the CSAPR stay. In October 2014, the U.S. Court of Appeals granted the motion to lift the CSAPR stay and established a schedule to hear arguments on the remaining outstanding issues, which began in March 2015. In July 2015, the U.S. Court of Appeals found the EPA erred in certain SO₂ and ozone season NOx emissions budgets for several states and sent these back to the EPA for reconsideration, but upheld the remainder of the rule. During the CSAPR stay, we installed various emission controls at our generation facilities that we expect reduces the impact of CSAPR. We are unable to determine the full impact of reinstatement, and any possible revisions, of CSAPR. However, we are prepared to comply with CSAPR in its current form.

National Ambient Air Quality Standards

Under the federal CAA, the EPA sets National Ambient Air Quality Standards (NAAQS) for certain emissions considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015 the EPA strengthened the ozone NAAQS by lowering the standards from the current 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations, but it could be material. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.

In 2010, the EPA revised the NAAQS for both NOx and 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, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016.  Tecumseh Energy Center (TEC) is our only generating station that meets this criteria. We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Byproducts of burning coal and other fossil fuels include carbon dioxide (CO₂) and other gases referred to as GHGs, which are believed by many to contribute to climate change. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. In October 2015, the EPA also 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 in the U.S. Court of Appeals for D.C. Circuit in October 2015, and more challenges are expected. We are evaluating the CPP and cannot at this time determine the impact of the CPP on our operations or consolidated financial results, but we believe the costs to comply could be material.

Under regulations formerly known as the Tailoring Rule, the EPA regulates GHG emissions from certain stationary sources. The regulations are implemented pursuant to two federal CAA programs, the Prevention of Significant Deterioration (PSD) and Title V Operating Permit Programs, that impose recordkeeping and monitoring requirements and also mandate the implementation of best available control technology (BACT) for projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for other pollutants. Therefore, if future modifications to our sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our future operations or consolidated financial results as we would not be required to implement BACT until we construct a new major source or make a major modification of an existing major source. The cost of compliance, however, could be material.

Mercury and Air Toxics Standards

In 2012, the Mercury and Air Toxics Standards (MATS) rule became effective. Under the MATS rule the EPA regulates the emissions of mercury, non-mercury metals, acid gases and organics. MATS required compliance to begin in April 2015, three years after the effective date. Sources could petition their state air regulatory agency to ask for an additional year to prepare for compliance. We petitioned the KDHE and our petition request was granted. Our current compliance date is April 2016 for all of our MATS affected units.

In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. On remand, the court could instruct the EPA on the cost benefit analysis needed to support the rule, vacate the rule in its entirety or take other action. MATS will remain in effect during the remand proceedings unless a stay is requested and granted. There will not be a material impact on our operations or consolidated financial results if MATS in its current form becomes a final rule. We are unable to predict the impact on our operations or consolidated financial results if MATS is vacated and the EPA proposes a replacement rule.

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 released in final, pre-publication form in September 2015. We are evaluating the final, pre-publication rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but it may be material.

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

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. We are currently evaluating the final rule. The resulting impact of the rule could have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), 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 CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and potential closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $48.8 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 11, “Asset Retirement Obligations,” for additional information.

Renewable Energy Standard

In May 2015, Kansas repealed a state mandate to maintain a minimum amount of renewable energy sources, effective January 1, 2016.

Storage of Spent Nuclear Fuel

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

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. 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.

FERC Proceedings

See Note 3, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2015	Oct. 27, 2015
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Trading Symbol	WR
Entity Registrant Name	WESTAR ENERGY INC /KS
Entity Central Index Key	0000054507
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		141,337,536

XML

Asset Retirement Obligations (Notes)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

In June 2015, we recorded an approximately $48.8 million increase in our ARO in response to the EPA’s published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant. See Note 10, “Commitments and Contingencies - Regulation of Coal Combustion Byproducts,” for additional information.

The change in the balance of our ARO liability from December 31, 2014, through September 30, 2015, is summarized in the following table.

	(In Thousands)
Balance as of December 31, 2014	$	230,668
Liabilities incurred	48,767
Liabilities settled	(1,312		)
Accretion expense	9,500
Revisions in estimated cash flows	(1,234		)
Balance as of September 30, 2015	$	286,389

XML

Consolidated Statements Of Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES	$ 732,829	$ 764,040	$ 1,913,199	$ 2,005,264
OPERATING EXPENSES:
Fuel and purchased power	163,943	200,755	459,504	539,373
Network Transmission Cost	57,487	55,720	171,651	163,211
Operating and maintenance	80,444	84,213	248,263	277,841
Depreciation and amortization	77,184	72,279	228,529	213,270
Selling, general and administrative	60,485	60,977	179,567	179,633
Taxes, Miscellaneous	37,682	34,677	113,047	104,248
Total Operating Expenses	477,225	508,621	1,400,561	1,477,576
INCOME FROM OPERATIONS	255,604	255,419	512,638	527,688
OTHER INCOME (EXPENSE):
Investment earnings (losses)	314	1,655	4,427	7,208
Other income	637	14,991	18,572	26,566
Other expense	(5,392)	(6,242)	(13,737)	(14,192)
Total Other Income	(4,441)	10,404	9,262	19,582
Interest expense	44,306	44,531	134,120	138,075
INCOME BEFORE INCOME TAXES	206,857	221,292	387,780	409,195
Income tax expense	66,293	71,532	127,810	132,643
NET INCOME	140,564	149,760	259,970	276,552
Less: Net income attributable to noncontrolling interests	2,561	2,378	7,277	6,742
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$ 138,003	$ 147,382	$ 252,693	$ 269,810
Earnings Per Share [Abstract]
Earnings Per Share, Basic	$ 0.97	$ 1.13	$ 1.84	$ 2.08
Earnings Per Share, Diluted	$ 0.97	$ 1.10	$ 1.82	$ 2.04
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING
Weighted Average Number of Shares Outstanding , Basic	141,622,697	130,196,193	136,686,263	129,525,618
Weighted Average Number of Shares Outstanding, Diluted	141,838,178	133,028,787	138,181,585	132,199,583
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.36	$ 0.35	$ 1.08	$ 1.05

XML

Financial Investments

9 Months Ended

Sep. 30, 2015

Investments [Abstract]

Financial Investments

FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of September 30, 2015, and December 31, 2014, we measured the fair value of trust assets at $33.2 million and $35.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months endedSeptember 30, 2015, we recorded an unrealized loss of $1.5 million on assets still held. For the nine months endedSeptember 30, 2015, we recorded an unrealized loss of $0.8 million on assets still held. For the three and nine months endedSeptember 30, 2014, we recorded an unrealized loss of $0.1 million and an unrealized gain of $1.5 million on assets still held, respectively.

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, 2015, and December 31, 2014.

Using the specific identification method to determine cost, we realized a loss of$0.5 million during the three months endedSeptember 30, 2015, and a loss of$1.0 million during the nine months endedSeptember 30, 2015, on our available-for-sale securities. We realized no gains or losses on our available-for-sale securities for the three months endedSeptember 30, 2014, and a gain of $0.2 million for the nine months endedSeptember 30, 2014. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of September 30, 2015, and December 31, 2014.

			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of September 30, 2015
Domestic equity funds	$	42,418	$	12,218	$	(6	)	$	54,630	30	%
International equity funds	30,685		1,218		(1,214		)	30,689		17	%
Core bond fund	19,397		310		—			19,707		11	%
High-yield bond fund	14,106		—		(923		)	13,183		7	%
Emerging market bond fund	14,295		—		(2,667		)	11,628		6	%
Other fixed income fund	4,948		—		(25		)	4,923		3	%
Combination debt/equity/other funds	16,213		3,474		(749		)	18,938		10	%
Alternative investment fund	15,000		2,538		—			17,538		10	%
Real estate securities fund	10,918		—		(515		)	10,403		6	%
Cash equivalents	117		—		—			117		<1%
Total	$	168,097	$	19,758	$	(6,099	)	$	181,756	100	%
As of December 31, 2014
Domestic equity funds	$	46,126	$	14,853	$	(7	)	$	60,972	33	%
International equity funds	27,521		3,683		(413		)	30,791		17	%
Core bond fund	18,811		478		—			19,289		10	%
High-yield bond fund	13,342		—		(144		)	13,198		7	%
Emerging market bond fund	12,556		—		(1,568		)	10,988		6	%
Other fixed income fund	4,798		—		(19		)	4,779		3	%
Combination debt/equity/other funds	14,975		3,786		(620		)	18,141		10	%
Alternative investment fund	15,000		1,970		—			16,970		9	%
Real estate securities fund	10,619		—		(1,071		)	9,548		5	%
Cash equivalents	340		—		—			340		<1%
Total	$	164,088	$	24,770	$	(3,842	)	$	185,016	100	%

The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as ofSeptember 30, 2015, and December 31, 2014.

	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of September 30, 2015
Domestic equity funds	$	—	$	—		$	564	$	(6	)	$	564	$	(6	)
International equity funds	—		—			6,236		(1,214		)	6,236		(1,214		)
High-yield bond fund	13,183		(923		)	—		—			13,183		(923		)
Emerging market bond fund	—		—			11,628		(2,667		)	11,628		(2,667		)
Other fixed income fund	4,923		(25		)	—		—			4,923		(25		)
Combination debt/equity/other funds	—		—			6,289		(749		)	6,289		(749		)
Real estate securities fund	—		—			10,403		(515		)	10,403		(515		)
Total	$	18,106	$	(948	)	$	35,120	$	(5,151	)	$	53,226	$	(6,099	)
As of December 31, 2014
Domestic equity funds	$	—	$	—		$	263	$	(7	)	$	263	$	(7	)
International equity funds	5,905		(413		)	—		—			5,905		(413		)
High-yield bond fund	13,198		(144		)	—		—			13,198		(144		)
Emerging market bond fund	—		—			10,988		(1,568		)	10,988		(1,568		)
Other fixed income funds	4,779		(19		)	—		—			4,779		(19		)
Combination debt/equity/other funds	—		—			5,892		(620		)	5,892		(620		)
Real estate securities fund	—		—			9,548		(1,071		)	9,548		(1,071		)
Total	$	23,882	$	(576	)	$	26,691	$	(3,266	)	$	50,573	$	(3,842	)

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Financial Instruments and Risk Management

9 Months Ended

Sep. 30, 2015

Financial And Derivative Instruments and Trading Securities [Abstract]

Financial And Derivative Instruments And Trading Securities

FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:

• 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 measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or 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. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

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

All of our level 2 investments are held in investment funds that are measured at fair value using daily net asset values. In addition, we maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

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, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,830,000	$	3,071,423	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs	166,271		178,586		194,204		213,579

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, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	48,651	$	5,979	$	54,630
International equity funds	—		30,689		—		30,689
Core bond fund	—		19,707		—		19,707
High-yield bond fund	—		13,183		—		13,183
Emerging market bond fund	—		11,628		—		11,628
Other fixed income fund	—		4,923		—		4,923
Combination debt/equity/other funds	—		18,938		—		18,938
Alternative investment fund	—		—		17,538		17,538
Real estate securities fund	—		—		10,403		10,403
Cash equivalents	117		—		—		117
Total Nuclear Decommissioning Trust	117		147,719		33,920		181,756
Trading Securities:
Domestic equity funds	—		17,250		—		17,250
International equity fund	—		4,308		—		4,308
Core bond fund	—		11,505		—		11,505
Cash equivalents	159		—		—		159
Total Trading Securities	159		33,063		—		33,222
Total Assets Measured at Fair Value	$	276	$	180,782	$	33,920	$	214,978
As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	54,925	$	6,047	$	60,972
International equity funds	—		30,791		—		30,791
Core bond fund	—		19,289		—		19,289
High-yield bond fund	—		13,198		—		13,198
Emerging market bond fund	—		10,988		—		10,988
Other fixed income fund	—		4,779		—		4,779
Combination debt/equity/other funds	—		18,141		—		18,141
Alternative investment fund	—		—		16,970		16,970
Real estate securities fund	—		—		9,548		9,548
Cash equivalents	340		—		—		340
Total Nuclear Decommissioning Trust	340		152,111		32,565		185,016
Trading Securities:
Domestic equity funds	—		18,698		—		18,698
International equity fund	—		4,252		—		4,252
Core bond fund	—		12,379		—		12,379
Cash equivalents	168		—		—		168
Total Trading Securities	168		35,329		—		35,497
Total Assets Measured at Fair Value	$	508	$	187,440	$	32,565	$	220,513

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2015.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities  Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2015	$	5,910		$	17,425	$	10,042		$	33,377
Total realized and unrealized gains included in:
Regulatory liabilities	273			113		361			747
Purchases	200			—		103			303
Sales	(404		)	—		(103		)	(507		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920
Balance as of December 31, 2014	$	6,047		$	16,970	$	9,548		$	32,565
Total realized and unrealized gains included in:
Regulatory liabilities	836			568		855			2,259
Purchases	300			—		299			599
Sales	(1,204		)	—		(299		)	(1,503		)
Balance as of September 30, 2015	$	5,979		$	17,538	$	10,403		$	33,920

The following table provides reconciliations of assets measured at fair value using significant level 3 inputs for the three and nine months endedSeptember 30, 2014.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund			Net Balance
	(In Thousands)
Balance as of June 30, 2014	$	6,288		$	16,446	$	9,026		$	31,760
Total realized and unrealized gains included in:
Regulatory liabilities	113			377		245			735
Purchases	95			—		92			187
Sales	(126		)	—		(92		)	(218		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464
Balance as of December 31, 2013	$	5,817		$	15,675	$	8,511		$	30,003
Total realized and unrealized gains included in:
Regulatory liabilities	722			1,148		760			2,630
Purchases	191			—		257			448
Sales	(360		)	—		(257		)	(617		)
Balance as of September 30, 2014	$	6,370		$	16,823	$	9,271		$	32,464

Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the three and nine months endedSeptember 30, 2015 and 2014, attributed to level 3 assets and liabilities. See Note 3, “Rate Matters and Regulation,” in the 2014 Form 10-K for additional information regarding our regulatory assets and liabilities.

	Domestic Equity Funds			Alternative Investment Fund		Real Estate Securities Fund		Net Balance
	(In Thousands)
Total unrealized gains (losses):
Three months ended September 30, 2015	$	(132	)	$	113	$	259	$	240
Three months ended September 30, 2014	(13		)	377		154		518
Nine months ended September 30, 2015	(368		)	567		556		755
Nine months ended September 30, 2014	362			1,149		503		2,014

Some of our investments in the Nuclear Decommissioning Trust (NDT) and our trading securities portfolio are measured at net asset value 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, 2015				As of December 31, 2014				As of September 30, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	5,979	$	2,048	$	6,047	$	2,348	(a)	(a)
Alternative investment fund (b)	17,538		—		16,970		—		Quarterly	65 days
Real estate securities fund	10,403		—		9,548		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	33,920		2,048		32,565		2,348
Trading Securities:
Domestic equity funds	17,250		—		18,698		—		Upon Notice	1 day
International equity funds	4,308		—		4,252		—		Upon Notice	1 day
Core bond fund	11,505		—		12,379		—		Upon Notice	1 day
Total Trading Securities	33,063		—		35,329		—
Total	$	66,983	$	2,048	$	67,894	$	2,348

_______________

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

(b) There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

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Summary Of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Schedule of Utility Inventory

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

	As of		As of
	September 30, 2015		December 31, 2014
	(In Thousands)
Fuel inventory	$	89,144	$	70,416
Supplies	187,545		176,990
Fuel inventory and supplies	$	276,689	$	247,406

Allowance For Funds Used During Construction

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Dollars In Thousands)
Borrowed funds	$	466		$	2,504		$	3,047		$	9,448
Equity funds	—			3,627			2,034			13,345
Total	$	466		$	6,131		$	5,081		$	22,793
Average AFUDC Rates	1.0		%	6.4		%	2.8		%	6.9		%

Reconciliation Of Basic And Diluted EPS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	140,564	$	149,760	$	259,970	$	276,552
Less: Net income attributable to noncontrolling interests	2,561		2,378		7,277		6,742
Net income attributable to Westar Energy, Inc.	138,003		147,382		252,693		269,810
Less: Net income allocated to RSUs	304		395		563		721
Net income allocated to common stock	$	137,699	$	146,987	$	252,130	$	269,089
Weighted average equivalent common shares outstanding – basic	141,622,697		130,196,193		136,686,263		129,525,618
Effect of dilutive securities:
RSUs	215,481		198,583		197,373		139,058
Forward sale agreements	—		2,634,011		1,297,949		2,534,907
Weighted average equivalent common shares outstanding – diluted (a)	141,838,178		133,028,787		138,181,585		132,199,583
Earnings per common share, basic	$	0.97	$	1.13	$	1.84	$	2.08
Earnings per common share, diluted	$	0.97	$	1.10	$	1.82	$	2.04

_______________

(a) We had no antidilutive securities for the three and nine months endedSeptember 30, 2015 and 2014.

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2015		2014
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	119,173	$	119,275
Interest on financing activities of VIEs	10,430		12,178
Income taxes, net of refunds	126		361
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	60,155		111,494
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	8,008		6,697
Assets acquired through capital leases	2,246		1,454

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Legal Proceedings

9 Months Ended

Sep. 30, 2015

Legal Proceedings [Abstract]

Legal Proceedings

LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Note 3, “Rate Matters and Regulation,” and Note 10, “Commitments and Contingencies,” for additional information.

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Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Pension And Post-Retirement Benefit Plans

PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,348		$	4,055		$	361		$	345
Interest cost	10,753			10,400			1,422			1,588
Expected return on plan assets	(10,059		)	(9,109		)	(1,654		)	(1,644		)
Amortization of unrecognized:
Prior service costs	130			131			114			631
Actuarial loss (gain), net	8,033			5,690			95			(185		)
Net periodic cost before regulatory adjustment	14,205			11,167			338			735
Regulatory adjustment (a)	1,548			4,002			1,013			1,124
Net periodic cost	$	15,753		$	15,169		$	1,351		$	1,859

 _______________

(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,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	16,044		$	12,164		$	1,082		$	1,036
Interest cost	32,261			31,200			4,268			4,763
Expected return on plan assets	(31,177		)	(27,328		)	(4,961		)	(4,932		)
Amortization of unrecognized:
Prior service costs	390			394			342			1,893
Actuarial loss (gain), net	23,746			15,371			284			(556		)
Net periodic cost before regulatory adjustment	41,264			31,801			1,015			2,204
Regulatory adjustment (a)	4,880			12,005			3,038			3,371
Net periodic cost	$	46,144		$	43,806		$	4,053		$	5,575

 _______________

(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 endedSeptember 30, 2015 and 2014, we contributed $29.7 million and $26.4 million, respectively, to the Westar Energy pension trust.

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Debt Financing

9 Months Ended

Sep. 30, 2015

Long-term Debt, Unclassified [Abstract]

Debt Financing

DEBT FINANCING

In September 2015, Westar Energy extended the term of its $730.0 million credit facility to September 2019, $20.7 million of which will expire in September 2017. As of September 30, 2015, Westar Energy had no borrowed amounts and $19.2 million of letters of credit outstanding under this revolving credit facility. As of December 31, 2014, Westar Energy had no borrowed amounts and $15.6 million of letters of credit outstanding under this revolving credit facility.

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

In February 2014, Westar Energy extended the term of its $270.0 million credit facility to February 2017,

$20.0 million of which was set to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. As of September 30, 2015, and December 31, 2014, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

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

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Taxes

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Taxes

TAXES

We recorded income tax expense of $66.3 million with an effective income tax rate of 32% for the three months endedSeptember 30, 2015, and income tax expense of $71.5 million with an effective income tax rate of 32% for the same period of 2014. We recorded income tax expense of $127.8 million with an effective income tax rate of 33% for the nine months endedSeptember 30, 2015, and income tax expense of $132.6 million with an effective income tax rate of 32% for the same period of 2014.

As of September 30, 2015, and December 31, 2014, our unrecognized income tax benefits totaled $2.7 million and $3.2 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of September 30, 2015, and December 31, 2014, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either September 30, 2015, or December 31, 2014.

As of September 30, 2015, and December 31, 2014, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

Effective January 1, 2014, we adopted new regulations released by the Internal Revenue Service and the United States Treasury Department regarding deduction and capitalization of expenditures related to tangible property, including the tax treatment of, among other things, materials and supplies and the determination of whether expenditures with respect to tangible property are a deductible repair or must be capitalized, and regulations regarding dispositions of property under the Modified Accelerated Cost Recovery System. The adoption of these regulations did not have a material impact on our consolidated financial results.

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Wolf Creek Pension and Post-Retirement Benefit Plans

9 Months Ended

Sep. 30, 2015

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

Wolf Creek Pension And Post-Retirement Benefit Plans

WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,899		$	1,424		$	34	$	43
Interest cost	2,254			2,117			79		116
Expected return on plan assets	(2,261		)	(2,021		)	—		—
Amortization of unrecognized:
Prior service costs	14			14			—		—
Actuarial loss, net	1,482			747			1		41
Net periodic cost before regulatory adjustment	3,388			2,281			114		200
Regulatory adjustment (a)	(304		)	501			—		—
Net periodic cost	$	3,084		$	2,782		$	114	$	200

 _______________

(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,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,696		$	4,271		$	103	$	130
Interest cost	6,761			6,352			236		347
Expected return on plan assets	(6,783		)	(6,063		)	—		—
Amortization of unrecognized:
Prior service costs	43			43			—		—
Actuarial loss, net	4,448			2,240			2		124
Net periodic cost before regulatory adjustment	10,165			6,843			341		601
Regulatory adjustment (a)	(912		)	1,502			—		—
Net periodic cost	$	9,253		$	8,345		$	341	$	601

 _______________

(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 endedSeptember 30, 2015 and 2014, we funded $4.5 million and $2.4 million of Wolf Creek’s pension plan contributions, respectively.

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Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash Paid For (Received From)
Interest on financing activities	$ 119,173	$ 119,275
Income taxes, net of refunds	126	361
Noncash Investing and Financing Transactions
Property, plant and equipment	60,155	111,494
Issuance of common stock for reinvested dividends and compensation plans	8,008	6,697
Deconsolidation of VIE	(1,076)
Assets acquired through capital leases	2,246	1,454
Variable Interest Entity, Primary Beneficiary [Member]
Cash Paid For (Received From)
Interest on financing activities	$ 10,430	$ 12,178

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Variable Interest Entities (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Initial Consolidation, Gain (Loss)	$ 0
Jeffrey Energy Center [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	8.00%
Agreement expiration date	Jan. 01, 2019
La Cygne Generating Station [Member]
Variable Interest Entity [Line Items]
Variable interest entity percentage of asset held	50.00%
Agreement expiration date	Sep. 01, 2029

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Variable Interest Entities

9 Months Ended

Sep. 30, 2015

Variable Interest Entities [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne

unit 2 are VIEs of which we are the primary beneficiary.

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

Financial Statement Impact

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

	As of		As of
	September 30, 2015		December 31, 2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	270,822	$	278,573
Regulatory assets (a)	8,777		7,882
Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Accrued interest (b)	68		2,961
Long-term debt of variable interest entities, net	138,134		166,565

_______________

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

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

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

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Pension and Post-Retirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2015

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,348		$	4,055		$	361		$	345
Interest cost	10,753			10,400			1,422			1,588
Expected return on plan assets	(10,059		)	(9,109		)	(1,654		)	(1,644		)
Amortization of unrecognized:
Prior service costs	130			131			114			631
Actuarial loss (gain), net	8,033			5,690			95			(185		)
Net periodic cost before regulatory adjustment	14,205			11,167			338			735
Regulatory adjustment (a)	1,548			4,002			1,013			1,124
Net periodic cost	$	15,753		$	15,169		$	1,351		$	1,859

 _______________

(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,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	16,044		$	12,164		$	1,082		$	1,036
Interest cost	32,261			31,200			4,268			4,763
Expected return on plan assets	(31,177		)	(27,328		)	(4,961		)	(4,932		)
Amortization of unrecognized:
Prior service costs	390			394			342			1,893
Actuarial loss (gain), net	23,746			15,371			284			(556		)
Net periodic cost before regulatory adjustment	41,264			31,801			1,015			2,204
Regulatory adjustment (a)	4,880			12,005			3,038			3,371
Net periodic cost	$	46,144		$	43,806		$	4,053		$	5,575

 _______________

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

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	$ 286,389	$ 230,668
Asset Retirement Obligation, Liabilities Settled	1,312
Asset Retirement Obligation, Accretion Expense	9,500
Asset Retirement Obligation, Liabilities Incurred	48,767
Asset Retirement Obligation, Cash Paid to Settle	$ (1,234)

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Financial Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Trading securities	$ 33,222		$ 33,222		$ 35,497
Unrealized gains losses	1,500	$ 100	800	$ 1,500
Realized gains on available-for-sale-securities	500	$ 0	1,000	$ 200
Revolving Credit Facility Lender One [Member]
Schedule of Available-for-sale Securities [Line Items]
Long-term Line of Credit	0		0		0
Revolving Credit Facility Lender Two [Member]
Schedule of Available-for-sale Securities [Line Items]
Long-term Line of Credit	$ 0		$ 0		$ 0

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Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 259,970	$ 276,552
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	228,529	213,270
Amortization of nuclear fuel	18,528	18,218
Amortization of deferred regulatory gain from sale leaseback	(4,121)	(4,121)
Amortization of corporate-owned life insurance	15,309	15,510
Non-cash compensation	6,280	6,034
Net deferred income taxes and credits	126,602	134,714
Stock-based compensation excess tax benefits	(1,231)	(790)
Allowance for equity funds used during construction	(2,034)	(13,345)
Changes in working capital items:
Accounts receivable	(21,437)	(50,084)
Fuel inventory and supplies	(28,814)	(5,703)
Prepaid expenses and other	(22,742)	8,693
Accounts payable	(4,979)	(4,397)
Accrued taxes	51,867	41,323
Other current liabilities	(66,000)	(19,732)
Changes in other assets	1,394	6,019
Changes in other liabilities	26,512	28,051
Cash Flows from Operating Activities	583,633	650,212
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(486,515)	(648,933)
Purchase of securities - trusts	(20,752)	(6,582)
Sale of securities - trusts	20,957	8,221
Investment in corporate-owned life insurance	14,845	16,250
Proceeds from investment in corporate-owned life insurance	65,962	23,989
Other investing activities	(781)	(2,203)
Cash Flows used in Investing Activities	(435,974)	(641,758)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	46,000	67,206
Proceeds from long-term debt	0	417,943
Retirements of long-term debt	(275,000)	(427,500)
Repayment of capital leases	(1,759)	(2,397)
Borrowings against cash surrender value of corporate-owned life insurance	57,726	57,764
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(63,894)	(22,737)
Stock-based compensation excess tax benefits	1,231	790
Issuance of common stock	257,169	58,560
Distributions to shareholders of noncontrolling interests	1,076	0
Cash dividends paid	(137,616)	(127,364)
Other financing activities	(3,234)	(2,050)
Cash Flows from Financing Activities	(148,386)	(7,106)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(727)	1,348
CASH AND CASH EQUIVALENTS:
Beginning of period	4,556	4,487
End of period	3,829	5,835
Variable Interest Entity [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Retirements of long-term debt	$ (27,933)	$ (27,321)

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Rate Matters And Regulation

9 Months Ended

Sep. 30, 2015

Regulated Operations [Abstract]

Rate Matters And Regulation

RATE MATTERS AND REGULATION

KCC Proceedings

In September 2015, the Kansas Corporation Commission (KCC) issued an order in our state general rate case allowing us to adjust our prices to include, among other things, additional investment in La Cygne Generating Station (La Cygne) environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million. The KCC also approved our request to file an abbreviated rate review within 12 months of the effective date of this order to update our prices to include additional capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in environmental projects during 2015.

In May 2015, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in environmental projects during 2014. The new prices became effective in June 2015 and are expected to increase our annual retail revenues by approximately $10.8 million. In October 2015, in connection with the state general rate case, the existing balance of costs associated with these investments were rolled into our base prices.

In March 2015, the KCC issued an order allowing us to adjust our prices to include updated transmission costs as reflected in the transmission formula rate (TFR) discussed below. The new prices became effective in April 2015 and are expected to increase our annual retail revenues by approximately $7.2 million.

In December 2014, 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 2015 and are expected to increase our annual retail revenues by approximately $4.9 million. In October 2015, in connection with the state general rate case, the existing balance of costs incurred for property taxes were rolled into our base prices.

FERC Proceedings

Our TFR that includes projected 2016 transmission capital expenditures and operating costs will become effective in January 2016 and is expected to increase our annual transmission revenues by approximately $21.6 million.

Our TFR that includes projected 2015 transmission capital expenditures and operating costs was effective in January 2015 and is expected to decrease our annual transmission revenues by approximately $4.6 million. This updated rate provided the basis for our request to the KCC to adjust our retail prices to include updated transmission costs as discussed above.

In August 2014, the KCC filed a complaint against us with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA).  The complaint sought to lower our base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, we filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, during the nine months ended September 30, 2015, we recorded a liability of $11.2 million for our estimated refund obligation from the refund effective date of August 20, 2014 through September 30, 2015, of which $2.5 million was recorded in the three months ended September 30, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately $11.0 million on an annualized basis as a result of the reduced ROE.

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

9 Months Ended

Sep. 30, 2015

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,348		$	4,055		$	361		$	345
Interest cost	10,753			10,400			1,422			1,588
Expected return on plan assets	(10,059		)	(9,109		)	(1,654		)	(1,644		)
Amortization of unrecognized:
Prior service costs	130			131			114			631
Actuarial loss (gain), net	8,033			5,690			95			(185		)
Net periodic cost before regulatory adjustment	14,205			11,167			338			735
Regulatory adjustment (a)	1,548			4,002			1,013			1,124
Net periodic cost	$	15,753		$	15,169		$	1,351		$	1,859

 _______________

(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,	2015			2014			2015			2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	16,044		$	12,164		$	1,082		$	1,036
Interest cost	32,261			31,200			4,268			4,763
Expected return on plan assets	(31,177		)	(27,328		)	(4,961		)	(4,932		)
Amortization of unrecognized:
Prior service costs	390			394			342			1,893
Actuarial loss (gain), net	23,746			15,371			284			(556		)
Net periodic cost before regulatory adjustment	41,264			31,801			1,015			2,204
Regulatory adjustment (a)	4,880			12,005			3,038			3,371
Net periodic cost	$	46,144		$	43,806		$	4,053		$	5,575

 _______________

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

Wolf Creek [Member]

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

Schedule of Net Periodic Benefit Costs [Table Text Block]

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

	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,899		$	1,424		$	34	$	43
Interest cost	2,254			2,117			79		116
Expected return on plan assets	(2,261		)	(2,021		)	—		—
Amortization of unrecognized:
Prior service costs	14			14			—		—
Actuarial loss, net	1,482			747			1		41
Net periodic cost before regulatory adjustment	3,388			2,281			114		200
Regulatory adjustment (a)	(304		)	501			—		—
Net periodic cost	$	3,084		$	2,782		$	114	$	200

 _______________

(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,	2015			2014			2015		2014
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,696		$	4,271		$	103	$	130
Interest cost	6,761			6,352			236		347
Expected return on plan assets	(6,783		)	(6,063		)	—		—
Amortization of unrecognized:
Prior service costs	43			43			—		—
Actuarial loss, net	4,448			2,240			2		124
Net periodic cost before regulatory adjustment	10,165			6,843			341		601
Regulatory adjustment (a)	(912		)	1,502			—		—
Net periodic cost	$	9,253		$	8,345		$	341	$	601

 _______________

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

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Financial Instruments and Risk Management (Reconciliations Of Assets And Liabilities At Fair Value) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Balance at period start	$ 33,377	$ 31,760	$ 32,565	$ 30,003
Regulatory liabilities	747	735	2,259	2,630
Purchases	303	187	599	448
Sales	(507)	(218)	(1,503)	(617)
Balance at period end	33,920	32,464	33,920	32,464
Domestic Equity [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Balance at period start	5,910	6,288	6,047	5,817
Regulatory liabilities	273	113	836	722
Purchases	200	95	300	191
Sales	(404)	(126)	(1,204)	(360)
Balance at period end	5,979	6,370	5,979	6,370
Alternative Funds [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Balance at period start	17,425	16,446	16,970	15,675
Regulatory liabilities	113	377	568	1,148
Purchases	0	0	0	0
Sales	0	0	0	0
Balance at period end	17,538	16,823	17,538	16,823
Real Estate Securities [Member]
Summary of Investments, Other than Investments in Related Parties, Reportable Data [Line Items]
Balance at period start	10,042	9,026	9,548	8,511
Regulatory liabilities	361	245	855	760
Purchases	103	92	299	257
Sales	(103)	(92)	(299)	(257)
Balance at period end	$ 10,403	$ 9,271	$ 10,403	$ 9,271

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Common Stock

9 Months Ended

Sep. 30, 2015

Class of Stock [Line Items]

Common Stock

COMMON STOCK

During the nine months endedSeptember 30, 2015, Westar Energy issued 9.2 million shares of common stock with a

physical settlement amount of $254.6 million to settle all outstanding forward sale transactions. Westar Energy used the proceeds from this transaction to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.