WESTAR ENERGY INC /KS - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2015



[ ]	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		132,236,503 shares
(Class)		(Outstanding at April 30, 2015)

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TABLE OF CONTENTS




PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Cash Flows	8
	Condensed Consolidated Statements of Changes in Equity	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	37

PART II. Other Information
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	39
Signature		40

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GLOSSARY OF TERMS

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



Abbreviation or Acronym		Definition
2014 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2014
AFUDC		Allowance for funds used during construction
BACT		Best Available Control Technology
CAA		Clean Air Act
CCB		Coal combustion byproducts
CO		Carbon monoxide
CO₂		Carbon dioxide
CSAPR		Cross-State Air Pollution Rule
EPA		Environmental Protection Agency
EPS		Earnings per share
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
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
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
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.
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

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FORWARD-LOOKING STATEMENTS

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


-	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,

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-	reduced demand for coal-based energy because of actual or potential climate impacts and 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.

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PART I. FINANCIAL INFORMATION

ITEM I. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)



	As of		As of
	March 31, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,074	$	4,556
Accounts receivable, net of allowance for doubtful accounts of $7,072 and $5,309, respectively	236,285		267,327
Fuel inventory and supplies	265,967		247,406
Deferred tax assets	19,747		29,636
Prepaid expenses	18,842		15,793
Regulatory assets	103,925		105,549
Other	23,725		30,655
Total Current Assets	674,565		700,922
PROPERTY, PLANT AND EQUIPMENT, NET	8,232,333		8,162,908
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	275,989		278,573
OTHER ASSETS:
Regulatory assets	756,382		754,229
Nuclear decommissioning trust	190,354		185,016
Other	280,112		265,353
Total Other Assets	1,226,848		1,204,598
TOTAL ASSETS	$	10,409,735	$	10,347,001
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	28,315	$	27,933
Short-term debt	425,400		257,600
Accounts payable	203,138		219,351
Accrued dividends	46,425		44,971
Accrued taxes	110,957		74,356
Accrued interest	89,821		79,707
Regulatory liabilities	57,185		55,142
Other	75,461		90,571
Total Current Liabilities	1,036,702		849,631
LONG-TERM LIABILITIES:
Long-term debt, net	3,090,722		3,215,539
Long-term debt of variable interest entities, net	138,209		166,565
Deferred income taxes	1,488,721		1,475,487
Unamortized investment tax credits	210,280		211,040
Regulatory liabilities	289,468		288,343
Accrued employee benefits	529,229		532,622
Asset retirement obligations	233,659		230,668
Other	77,397		75,799
Total Long-Term Liabilities	6,057,685		6,196,063
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 132,166,154 shares and 131,687,454 shares, respective to each date	660,831		658,437
Paid-in capital	1,788,787		1,781,120
Retained earnings	858,172		855,299
Total Westar Energy, Inc. Shareholders’ Equity	3,307,790		3,294,856
Noncontrolling Interests	7,558		6,451
Total Equity	3,315,348		3,301,307
TOTAL LIABILITIES AND EQUITY	$	10,409,735	$	10,347,001

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Three Months Ended March 31,
	2015			2014
REVENUES	$	590,807		$	628,556
OPERATING EXPENSES:
Fuel and purchased power	155,482			173,839
SPP network transmission costs	56,812			51,958
Operating and maintenance	85,080			91,790
Depreciation and amortization	74,586			70,110
Selling, general and administrative	55,418			56,486
Taxes other than income tax	37,871			34,832
Total Operating Expenses	465,249			479,015
INCOME FROM OPERATIONS	125,558			149,541
OTHER INCOME (EXPENSE):
Investment earnings	2,480			2,378
Other income	2,814			5,917
Other expense	(5,713		)	(5,664		)
Total Other (Expense) Income	(419		)	2,631
Interest expense	44,298			46,241
INCOME BEFORE INCOME TAXES	80,841			105,931
Income tax expense	27,678			34,961
NET INCOME	53,163			70,970
Less: Net income attributable to noncontrolling interests	2,183			2,015
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	50,980		$	68,955
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share	$	0.38		$	0.53
Diluted earnings per common share	$	0.38		$	0.52
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic	132,395,497			129,004,112
Diluted	135,539,631			131,269,363
DIVIDENDS DECLARED PER COMMON SHARE	$	0.36		$	0.35

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	53,163		$	70,970
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	74,586			70,110
Amortization of nuclear fuel	4,960			5,966
Amortization of deferred regulatory gain from sale leaseback	(1,374		)	(1,374		)
Amortization of corporate-owned life insurance	5,747			5,884
Non-cash compensation	2,226			1,796
Net deferred income taxes and credits	26,573			34,787
Stock-based compensation excess tax benefits	(1,073		)	636
Allowance for equity funds used during construction	(1,950		)	(5,006		)
Changes in working capital items:
Accounts receivable	31,042			16,892
Fuel inventory and supplies	(18,404		)	(9,956		)
Prepaid expenses and other	4,638			(2,255		)
Accounts payable	17,321			1,422
Accrued taxes	40,007			33,428
Other current liabilities	(20,327		)	2,838
Changes in other assets	(17,034		)	3,650
Changes in other liabilities	12,394			8,524
Cash Flows from Operating Activities	212,495			238,312
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(187,223		)	(218,329		)
Purchase of securities - trusts	(7,345		)	(2,707		)
Sale of securities - trusts	7,847			3,745
Proceeds from investment in corporate-owned life insurance	1,144			1,121
Investment in affiliated company	—			1,362
Other investing activities	(717		)	(1,230		)
Cash Flows used in Investing Activities	(186,294		)	(216,038		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	167,800			44,139
Retirements of long-term debt	(125,000		)	—
Retirements of long-term debt of variable interest entities	(27,925		)	(27,148		)
Repayment of capital leases	(886		)	(755		)
Borrowings against cash surrender value of corporate-owned life insurance	1,045			861
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(899		)	(1,040		)
Stock-based compensation excess tax benefits	1,073			(636		)
Issuance of common stock	8,206			10,317
Distributions to shareholders of noncontrolling interests	(1,076		)	—
Cash dividends paid	(43,787		)	(41,591		)
Other financing activities	(3,234		)	(1,843		)
Cash Flows used in Financing Activities	(24,683		)	(17,696		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	1,518			4,578
CASH AND CASH EQUIVALENTS:
Beginning of period	4,556			4,487
End of period	$	6,074		$	9,065

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

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(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	—	—		—			68,955			2,015			70,970
Issuance of stock	369,159	1,846		8,471			—			—			10,317
Issuance of stock for compensation and reinvested dividends	190,282	951		759			—			—			1,710
Tax withholding related to stock compensation	—	—		(1,843		)	—			—			(1,843		)
Dividends on common stock ($0.35 per share)	—	—		—			(45,320		)	—			(45,320		)
Stock compensation expense	—	—		1,776			—			—			1,776
Tax benefit on stock compensation	—	—		(636		)	—			—			(636		)
Other	—	—		—			—			(1		)	(1		)
Balance as of March 31, 2014	128,813,670	$	644,068	$	1,705,254		$	748,411		$	7,771		$	3,105,504

Balance as of December 31, 2014	131,687,454	$	658,437	$	1,781,120		$	855,299		$	6,451		$	3,301,307
Net income	—	—		—			50,980			2,183			53,163
Issuance of stock	262,827	1,314		6,892			—			—			8,206
Issuance of stock for compensation and reinvested dividends	215,873	1,080		1,948			—			—			3,028
Tax withholding related to stock compensation	—	—		(3,234		)	—			—			(3,234		)
Dividends on common stock ($0.36 per share)	—	—		—			(48,107		)	—			(48,107		)
Stock compensation expense	—	—		2,205			—			—			2,205
Tax benefit on stock compensation	—	—		1,073			—			—			1,073
Distributions to shareholders of noncontrolling interests	—	—		—			—			(1,076		)	(1,076		)
Other	—	—		(1,217		)	—			—			(1,217		)
Balance as of March 31, 2015	132,166,154	$	660,831	$	1,788,787		$	858,172		$	7,558		$	3,315,348

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

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 698,000 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 including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months ended March 31, 2015, are not necessarily indicative of the results to be expected for the full year.

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Fuel Inventory and Supplies

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



	As of		As of
	March 31, 2015		December 31, 2014
	(In Thousands)
Fuel inventory	$	86,401	$	70,416
Supplies	179,566		176,990
Fuel inventory and supplies	$	265,967	$	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 March 31,
	2015			2014
	(Dollars In Thousands)
Borrowed funds	$	2,029		$	3,731
Equity funds	1,950			5,006
Total	$	3,979		$	8,737
Average AFUDC Rates	4.0		%	7.3		%

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 potential issuances of common shares resulting from our forward sale agreements 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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The following table reconciles our basic and diluted EPS from net income.



	Three Months Ended March 31,
	2015		2014
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	53,163	$	70,970
Less: Net income attributable to noncontrolling interests	2,183		2,015
Net income attributable to Westar Energy, Inc.	50,980		68,955
Less: Net income allocated to RSUs	118		183
Net income allocated to common stock	$	50,862	$	68,772

Weighted average equivalent common shares outstanding – basic	132,395,497		129,004,112
Effect of dilutive securities:
RSUs	175,876		66,427
Forward sale agreements	2,968,258		2,198,824
Weighted average equivalent common shares outstanding – diluted (a)	135,539,631		131,269,363

Earnings per common share, basic	$	0.38	$	0.53
Earnings per common share, diluted	$	0.38	$	0.52

_______________

(a)We had no antidilutive securities for the three months ended March 31, 2015 and 2014.

Supplemental Cash Flow Information



	Three Months Ended March 31,
	2015		2014
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	38,927	$	39,028
Interest on financing activities of VIEs	5,651		6,515
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	63,265		79,844
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	3,028		1,710
Assets acquired through capital leases	294		446

New Accounting Pronouncements

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

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Presentation of Financial Statements

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs. The amendments in this guidance require 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 March 2015, the Kansas Corporation Commission (KCC) issued an order allowing us to adjust our prices to include updated transmission costs as reflected in the transmission formula rate discussed below. The new prices were effective in April 2015 and are expected to increase our annual retail revenues by approximately $7.2 million.

In March 2015, we filed an application with the KCC to adjust our prices to include costs associated with investments in environmental projects during 2014. We expect to implement the new prices in June 2015 and estimate that this will increase our annual retail revenues by approximately $10.8 million.

In March 2015, we filed an application with the KCC to increase our prices by $152.0 million to include, among other things, the additional investment in La Cygne Generating Station (La Cygne) environmental upgrades, the investment to extend the life of Wolf Creek and programs to improve reliability. We expect the KCC to issue an order on our request by late October 2015.

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.

FERC Proceedings

Our transmission formula rate 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 with 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 seeks to lower our 10.8% base return on equity (ROE) used in determining our transmission formula rate to approximately 8.9%, which would result in a refund obligation of approximately $19.0 million on an annualized basis, and based on our current rate base would reduce our future transmission revenues by approximately $19.0 million on an annualized basis. We filed a response to the complaint opposing any change to the ROE and subsequently on December 18, 2014, the FERC ordered that this matter be set for hearing and settlement judge procedures. Based on settlement discussions between the parties, we have recorded a liability of $6.0 million for our estimated refund obligation from the refund effective date of August 20, 2014, through March 31, 2015. Our estimated refund obligation is based on a base ROE of 9.8%. In addition, we estimate our future transmission revenues would be reduced by approximately $10.0 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:

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•	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 March 31, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,980,000	$	3,413,513	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs	166,278		183,356		194,204		213,579

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Recurring Fair Value Measurements

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



As of March 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	52,013	$	6,061	$	58,074
International equity funds	—		34,860		—		34,860
Core bond fund	—		19,627		—		19,627
High-yield bond fund	—		13,556		—		13,556
Emerging market bond fund	—		12,465		—		12,465
Other fixed income fund	—		4,862		—		4,862
Combination debt/equity/other funds	—		19,867		—		19,867
Alternative investment fund	—		—		16,784		16,784
Real estate securities fund	—		—		9,758		9,758
Cash equivalents	501		—		—		501
Total Nuclear Decommissioning Trust	501		157,250		32,603		190,354
Trading Securities:
Domestic equity funds	—		18,649		—		18,649
International equity fund	—		4,450		—		4,450
Core bond fund	—		12,466		—		12,466
Cash equivalents	169		—		—		169
Total Trading Securities	169		35,565		—		35,734
Total Assets Measured at Fair Value	$	670	$	192,815	$	32,603	$	226,088

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

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The following table provides reconciliations of assets held in the Nuclear Decommissioning Trust (NDT) measured at fair value using significant level 3 inputs for the three months ended March 31, 2015 and 2014.



	Domestic Equity Funds			Alternative Investment Fund			Real Estate Securities Fund			Net Balance
	(In Thousands)
Balance as of December 31, 2014	$	6,047		$	16,970		$	9,548		$	32,565
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	338			(186		)	210			362
Purchases	100			—			97			197
Sales	(424		)	—			(97		)	(521		)
Balance as of March 31, 2015	$	6,061		$	16,784		$	9,758		$	32,603

Balance as of December 31, 2013	$	5,817		$	15,675		$	8,511		$	30,003
Total realized and unrealized gains (losses) included in:
Regulatory liabilities	162			427			301			890
Purchases	50			—			76			126
Sales	(45		)	—			(76		)	(121		)
Balance as of March 31, 2014	$	5,984		$	16,102		$	8,812		$	30,898

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 months ended March 31, 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)
Three Months Ended March 31, 2015	$	(86	)	$	(186	)	$	112	$	(160	)
Three Months Ended March 31, 2014	117			427			224		768

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Some of our investments in the 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 March 31, 2015				As of December 31, 2014				As of March 31, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	6,061	$	2,248	$	6,047	$	2,348	(a)	(a)
Alternative investment fund	16,784		—		16,970		—		(b)	(b)
Real estate securities fund	9,758		—		9,548		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	32,603		2,248		32,565		2,348

Trading Securities:
Domestic equity funds	18,649		—		18,698		—		Upon Notice	1 day
International equity funds	4,450		—		4,252		—		Upon Notice	1 day
Core bond fund	12,466		—		12,379		—		Upon Notice	1 day
Total Trading Securities	35,565		—		35,329		—
Total	$	68,168	$	2,248	$	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 will be 15 years, subject to the general partner's right to extend the term for up to three additional one-year periods.


(b)	This fund had an initial lock-up period of 24 months, which expired in April 2015. Redemptions are allowed, on a quarterly basis, after 24 months at the sole discretion of the fund's board of directors. A 65-day notice of redemption is required. 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.

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.

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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 March 31, 2015, and December 31, 2014, we measured the fair value of trust assets at $35.7 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 ended March 31, 2015 and 2014, we recorded unrealized gains of $0.7 million and $0.5 million, respectively, on the assets still held.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of March 31, 2015, and December 31, 2014.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $0.2 million and $0.1 million during the three months ended March 31, 2015 and 2014, respectively. 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 March 31, 2015, and December 31, 2014.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of March 31, 2015
Domestic equity funds	$	42,167	$	15,914	$	(7	)	$	58,074	31	%
International equity funds	30,608		4,689		(437		)	34,860		18	%
Core bond fund	18,911		716		—			19,627		10	%
High-yield bond fund	13,517		39		—			13,556		7	%
Emerging market bond fund	14,062		—		(1,597		)	12,465		7	%
Other fixed income fund	4,827		35		—			4,862		3	%
Combination debt/equity/other funds	16,010		4,419		(562		)	19,867		10	%
Alternative investment fund	15,000		1,784		—			16,784		9	%
Real estate securities fund	10,717		—		(959		)	9,758		5	%
Cash equivalents	501		—		—			501		<1%
Total	$	166,320	$	27,596	$	(3,562	)	$	190,354	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 of March 31, 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 March 31, 2015
Domestic equity funds	$	—	$	—		$	363	$	(7	)	$	363	$	(7	)
International equity funds	7,233		(437		)	—		—			7,233		(437		)
Emerging market bond fund	—		—			12,465		(1,597		)	12,465		(1,597		)
Combination debt/equity/other funds	—		—			6,397		(562		)	6,397		(562		)
Real estate securities fund	—		—			9,758		(959		)	9,758		(959		)
Total	$	7,233	$	(437	)	$	28,983	$	(3,125	)	$	36,216	$	(3,562	)

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 February 2014, Westar Energy had 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.

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.

7. TAXES

We recorded income tax expense of $27.7 million with an effective income tax rate of 34% for the three months ended March 31, 2015, and income tax expense of $35.0 million with an effective income tax rate of 33% for the same period of 2014.

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

As of March 31, 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 March 31, 2015, or December 31, 2014.

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

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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.

8. PENSION AND POST-RETIREMENT BENEFIT PLANS

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



	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	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	7,661			4,840			95			(185		)
Net periodic cost before regulatory adjustment	13,833			10,317			338			735
Regulatory adjustment (a)	1,797			4,002			1,013			1,124
Net periodic cost	$	15,630		$	14,319		$	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.

During the three months ended March 31, 2015 and 2014, we contributed $8.5 million and $10.4 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 table summarizes the net periodic costs for KGE's 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization.



	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	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.

During the three months ended March 31, 2015, we funded $1.3 million of Wolf Creek's pension plan contributions. During the three months ended March 31, 2014, we did not fund Wolf Creek's pension plan.

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 (NO_x), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO₂ and NO_x, 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 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 NO_x. 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. A decision is expected later this year. 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 of CSAPR until the U.S. Court of Appeals and the EPA take further action, however, we are prepared to comply with CSAPR in its current form.

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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, NO_x (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 December 2014, the EPA published a proposed rule revising NAAQS for ozone and to make certain other changes, including extending the ozone monitoring season by at least one month. The EPA intends to issue a final rule regarding the ozone NAAQS by October 2015 and make attainment/nonattainment designations for any revised standards by October 2017. We are currently reviewing this proposed new standard and cannot at this time predict the impact it may have on our operations, but it could be material. Nonattainment designations on areas that impact our 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 strengthened the NAAQS for both NO_x and SO₂. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations and consolidated financial results. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS 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. The EPA is currently, and has further proposed, using the federal CAA to 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 January 2014, the EPA re-proposed a New Source Performance Standard that would limit CO₂emissions for new coal and natural gas fueled electric generating units. The re-proposal would limit CO₂ emissions to 1,000 lbs per Megawatt hour (MWh) generated for larger natural gas units and 1,100 lbs per MWh generated for smaller natural gas units and coal units. The EPA issued proposed standards addressing CO₂ emissions for modified, reconstructed and existing power plants in June 2014. The standards for existing plants is known as the Clean Power Plan. The EPA anticipates issuing final rules for new, modified, reconstructed and existing power plants by summer 2015 and requiring states to submit their state plans to the EPA by summer 2016. The EPA is expected to propose in summer 2015 a federal plan that will implement the Clean Power Plan for states that fail to submit adequate state plans, with such federal plan expected to be finalized by summer 2016. While the Clean Power Plan is not yet final, various legal and judicial challenges to it have been filed. We cannot at this time determine the impact of such proposals 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.

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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 are expected to be issued by the EPA by the end of September 2015. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations or consolidated financial results.

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 Technology Available 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 LaCygne 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 April 2014, the EPA along with the U.S. Army Corps of Engineers issued a proposed rule defining the Waters of the United States for purposes of the CWA. The related public comment period closed in November 2014. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the proposal, which could impact several permitting programs. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations 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 impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material.

Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015, net renewable generation capacity must be 10% of the average peak retail demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. With our existing wind generation facilities, purchased power contracts and renewable energy credits, we are able to satisfy the net renewable generation requirement through 2015. With our agreements to purchase an additional 400 megawatts of installed design capacity from wind generation facilities, which will begin later in 2015 through 2016, we expect to meet the increased requirements for 2020 and thereafter. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

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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 has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025 and believes it will be able to expand on-site storage as needed past 2025. We cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.

FERC Proceedings

In August 2014, the KCC filed a complaint against us with the FERC under Section 206 of the FPA. See Note 3, "Rate Matters and Regulation," for additional information.

11. LEGAL PROCEEDINGS

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

12. COMMON STOCK

During the three months ended March 31, 2015, Westar Energy issued 0.2 million shares of common stock with a physical settlement amount of $7.5 million to completely settle certain forward sale transactions under the March 2013 master forward sale agreement. Under that agreement Westar Energy had been required to settle any forward transaction within 18 months of the date of the transaction. Assuming physical share settlement of the approximately 8.9 million shares associated with all outstanding forward sale transactions as of March 31, 2015, Westar Energy would have received aggregate proceeds of approximately $247.2 million based on a weighted-average forward price of $27.73 per share.

13. 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
	March 31, 2015		December 31, 2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	275,989	$	278,573
Regulatory assets (a)	8,213		7,882

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,315	$	27,933
Accrued interest (b)	68		2,961
Long-term debt of variable interest entities, net	138,209		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.

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 United States under the regulation of the KCC and FERC.

In Management's Discussion and Analysis, we discuss our operating results for the three months ended March 31, 2015, compared to the same period 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 March 31,
	2015		2014		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	50,980	$	68,955	$	(17,975	)
Earnings per common share, basic	0.38		0.53		(0.15		)

Net income and basic EPS decreased for the three months ended March 31, 2015, compared to the same period in 2014, due primarily to decreased energy marketing margins of $12.2 million and lower retail electricity sales. The decreased energy marketing margins were due primarily to greater volatility of power prices in 2014 in some of the wholesale markets in which we buy and sell power. The lower retail electricity sales were attributable principally to warmer weather, which particularly impacts residential and commercial electricity sales. As measured by heating degree days, the weather during the three months ended March 31, 2015, was 13% warmer than the same period of 2014. Also contributing to the decrease was our having recorded a $6.0 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.

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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 pursuant to the Clean Power Plan, 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, NO_x, ozone, CO and SO₂) and the CSAPR;


•	our water discharges, including under Section 316(b) of the federal Clean Water Act (CWA) and the definition of Waters of the United States for purposes of the CWA;


•	the regulation of CCB; and


•	applicable renewable energy standards.

See Note 3, “Rate Matters and Regulation” and Note 10, “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 March 31, 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 Months Ended March 31, 2015, Compared to Three Months Ended March 31, 2014

Below we discuss our operating results for the three months ended March 31, 2015, compared to the results for the three months ended March 31, 2014. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.



	Three Months Ended March 31,
	2015			2014			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	181,294		$	192,287		$	(10,993	)	(5.7	)
Commercial	161,305			161,100			205			0.1
Industrial	96,479			94,495			1,984			2.1
Other retail	539			(8,523		)	9,062			106.3
Total Retail Revenues	439,617			439,359			258			0.1
Wholesale	86,755			110,613			(23,858		)	(21.6	)
Transmission (a)	58,585			61,466			(2,881		)	(4.7	)
Other	5,850			17,118			(11,268		)	(65.8	)
Total Revenues	590,807			628,556			(37,749		)	(6.0	)
OPERATING EXPENSES:
Fuel and purchased power	155,482			173,839			(18,357		)	(10.6	)
SPP network transmission costs	56,812			51,958			4,854			9.3
Operating and maintenance	85,080			91,790			(6,710		)	(7.3	)
Depreciation and amortization	74,586			70,110			4,476			6.4
Selling, general and administrative	55,418			56,486			(1,068		)	(1.9	)
Taxes other than income tax	37,871			34,832			3,039			8.7
Total Operating Expenses	465,249			479,015			(13,766		)	(2.9	)
INCOME FROM OPERATIONS	125,558			149,541			(23,983		)	(16.0	)
OTHER INCOME (EXPENSE):
Investment earnings	2,480			2,378			102			4.3
Other income	2,814			5,917			(3,103		)	(52.4	)
Other expense	(5,713		)	(5,664		)	(49		)	(0.9	)
Total Other (Expense) Income	(419		)	2,631			(3,050		)	(115.9	)
Interest expense	44,298			46,241			(1,943		)	(4.2	)
INCOME BEFORE INCOME TAXES	80,841			105,931			(25,090		)	(23.7	)
Income tax expense	27,678			34,961			(7,283		)	(20.8	)
NET INCOME	53,163			70,970			(17,807		)	(25.1	)
Less: Net income attributable to noncontrolling interests	2,183			2,015			168			8.3
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	50,980		$	68,955		$	(17,975	)	(26.1	)
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.38		$	0.53		$	(0.15	)	(28.3	)
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	0.38		$	0.52		$	(0.14	)	(26.9	)

_______________

(a) Includes revenue from an SPP network transmission tariff corresponding to our SPP network transmission costs. For the three months ended March 31, 2015 and 2014, these costs, less administration fees of $14.3 million and $12.0 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 months ended March 31, 2015 and 2014.



	Three Months Ended March 31,
	2015		2014		Change			% Change
	(Dollars In Thousands)
Revenues	$	590,807	$	628,556	$	(37,749	)	(6.0	)
Less: Fuel and purchased power expense	155,482		173,839		(18,357		)	(10.6	)
SPP network transmission costs	56,812		51,958		4,854			9.3
Gross Margin	$	378,513	$	402,759	$	(24,246	)	(6.0	)

The following table reflects changes in electricity sales for the three months ended March 31, 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 March 31,
	2015	2014	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,554	1,709	(155	)	(9.1	)
Commercial	1,731	1,760	(29	)	(1.6	)
Industrial	1,324	1,339	(15	)	(1.1	)
Other retail	20	21	(1	)	(4.8	)
Total Retail	4,629	4,829	(200	)	(4.1	)
Wholesale	2,571	2,476	95		3.8
Total	7,200	7,305	(105	)	(1.4	)

Gross margin decreased for the three months ended March 31, 2015, compared to the same period in 2014, due primarily to decreased energy marketing margins of $12.2 million due to greater volatility in 2014 of power prices in some of the wholesale markets in which we buy and sell power. Also contributing to the decrease in gross margin was lower retail electricity sales, offset by higher prices. The lower retail electricity sales were attributable principally to warmer weather, which particularly impacts residential and commercial electricity sales. As measured by heating degree days, the weather during the three months ended March 31, 2015, was 13% warmer than the same period of 2014. The higher prices were primarily due to investments we made in our transmission infrastructure and air quality controls at our power plants. Further contributing to the decrease in gross margin was our having recorded a $6.0 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.

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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 months ended March 31, 2015 and 2014.



	Three Months Ended March 31,
	2015		2014		Change			% Change
	(Dollars In Thousands)
Gross margin	$	378,513	$	402,759	$	(24,246	)	(6.0	)
Less: Operating and maintenance expense	85,080		91,790		(6,710		)	(7.3	)
Depreciation and amortization expense	74,586		70,110		4,476			6.4
Selling, general and administrative expense	55,418		56,486		(1,068		)	(1.9	)
Taxes other than income tax	37,871		34,832		3,039			8.7
Income from operations	$	125,558	$	149,541	$	(23,983	)	(16.0	)

Operating Expenses and Other Income and Expense Items



	Three Months Ended March 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	85,080	$	91,790	$	(6,710	)	(7.3	)

Operating and maintenance expense decreased due principally to $5.6 million lower costs at Wolf Creek, which were the result principally of higher operating and maintenance costs incurred during a 2014 scheduled outage.



	Three Months Ended March 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	74,586	$	70,110	$	4,476	6.4

Depreciation and amortization expense increased during the three months ended March 31, 2015, compared to the same period of 2014 due to additions at our power plants, including air quality controls and the addition of transmission facilities.



	Three Months Ended March 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	55,418	$	56,486	$	(1,068	)	(1.9	)

Selling, general and administrative expense for the three months ended March 31, 2015, decreased due primarily to amortizing $1.2 million less for previously deferred amounts associated with various energy efficiency programs.

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	Three Months Ended March 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	37,871	$	34,832	$	3,039	8.7

Taxes other than income tax increased due primarily to a $2.9 million increase in property tax expense, which is offset in retail revenues.



	Three Months Ended March 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Income tax expense	$	27,678	$	34,961	$	(7,283	)	(20.8	)

Income tax expense decreased for the three month period 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 March 31, 2015, compared to December 31, 2014.



	As of		As of
	March 31, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	265,967	$	247,406	$	18,561	7.5

Inventory increased due principally to a $17.1 million increase in coal inventory due mostly to improved rail performance.



	As of	As of
	March 31, 2015	December 31, 2014	Change			% Change
	(Dollars in Thousands)
Deferred tax assets	19,747	29,636	$	(9,889	)	(33.4	)

Deferred tax assets decreased due primarily to the reversal of $6.5 million of accumulated deferred income taxes related to our having paid non-union, non-executive employee compensation that is at-risk to employees and payable only upon meeting pre-established operating and financial objectives. In addition, deferred tax assets decreased $5.4 million due to an increase in deferred expenses for Wolf Creek's refueling and maintenance outages.



	As of		As of
	March 31, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	860,307	$	859,778	$	529		0.1
Regulatory liabilities	346,653		343,485		3,168			0.9
Net regulatory assets	$	513,654	$	516,293	$	(2,639	)	(0.5	)

Total regulatory assets increased due primarily to a $13.6 million increase in amounts deferred for Wolf Creek's refueling and maintenance outages; however, partially offsetting this increase was a $11.7 million decrease in deferred employee benefit costs.

Total regulatory liabilities increased due primarily to the following reasons:

•a $5.3 million increase in the fair value of the NDT;


•	$3.0 million increase in refund obligations related to amounts we have collected from our customers in excess of our actual cost of fuel and purchased power;


•	$2.3 million increase in jurisdictional AFUDC, which is AFUDC that is accrued subsequent to the time costs are included in our prices and prior to the time associated costs are placed into service; however,


•	partially offsetting these increases was a $4.8 million decrease in amounts collected but not yet spent to dispose of plant assets.



	As of		As of
	March 31, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Long-term debt	$	3,090,722	$	3,215,539	$	(124,817	)	(3.9	)

Total long-term debt decreased due to Westar Energy redeeming $125.0 million in principal amount of first mortgage bonds in January 2015.

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	As of		As of
	March 31, 2015		December 31, 2014		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	28,315	$	27,933	$	382		1.4
Long-term debt of variable interest entities	138,209		166,565		(28,356		)	(17.0	)
Total long-term debt of variable interest entities	$	166,524	$	194,498	$	(27,974	)	(14.4	)

Total long-term debt of VIEs 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
	March 31, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Short-term debt	$	425,400	$	257,600	$	167,800	65.1

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



	As of		As of
	March 31, 2015		December 31, 2014		Change		% Change
	(Dollars in Thousands)
Accrued taxes	$	110,957	$	74,356	$	36,601	49.2

Accrued taxes increased due mostly to an increase in accrued property taxes.

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 will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. As of April 30, 2015, Westar Energy had $478.0 million of commercial paper issued and outstanding.

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Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. In September 2014, Westar Energy extended the term of the $730.0 million facility by one year to terminate in September 2018, $81.4 million of which will expire in September 2017. In February 2014, Westar Energy had 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 two years 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 April 30, 2015, no amounts were borrowed and $22.6 million in letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date.

Long-Term Debt Financing

In January 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.

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.

As of April 30, 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	Positive

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Common Stock

Summary of Cash Flows



	Three Months Ended March 31,
	2015			2014			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	212,495		$	238,312		$	(25,817	)	(10.8	)
Investing activities	(186,294		)	(216,038		)	29,744			13.8
Financing activities	(24,683		)	(17,696		)	(6,987		)	(39.5	)
Net increase in cash and cash equivalents	$	1,518		$	4,578		$	(3,060	)	(66.8	)

Cash Flows from Operating Activities

Cash flows from operating activities decreased due principally to our having paid approximately $25.5 million more for purchased power and transmission services, our having received $23.6 million less for wholesale power sales and transmission services and our having received $9.1 million less for energy marketing activities. Partially offsetting these decreases was our having paid $40.8 million less for coal and natural gas.

Cash Flows used in Investing Activities

Cash flows used in investing activities decreased due primarily to our having invested $31.1 million less in additions to property, plant and equipment.

Cash Flows used in Financing Activities

Cash flows used in financing activities increased due principally to Westar Energy having redeemed $125.0 million in principal amount of first mortgage bonds in January 2015. Offsetting this increase was our having issued $123.7 million more of commercial paper.

Pension Contribution

During the three months ended March 31, 2015, we contributed $8.5 million to the Westar Energy pension trust. We funded $1.3 million of Wolf Creek's pension plan contributions during the same period.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2014, through March 31, 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 March 31, 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.

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OTHER INFORMATION

Changes in Prices

KCC Proceedings

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 discussed below. The new prices were effective in April 2015 and are expected to increase our annual retail revenues by approximately $7.2 million.

In March 2015, we filed an application with the KCC to increase our prices by $152.0 million to include, among other things, the additional investment in La Cygne environmental upgrades, the investment to extend the life of Wolf Creek and programs to improve reliability. We expect the KCC to issue an order on our request by late October 2015.

FERC Proceedings

In August 2014, the KCC filed a complaint against us with the FERC under Section 206 of the FPA. The complaint seeks to lower our 10.8% base ROE used in determining our transmission formula rate to approximately 8.9%, which would result in a refund obligation of approximately $19.0 million on an annualized basis, and based on our current rate base would reduce our future transmission revenues by approximately $19.0 million on an annualized basis. We filed a response to the complaint opposing any change to the ROE and subsequently on December 18, 2014, the FERC ordered that this matter be set for hearing and settlement judge procedures. Based on settlement discussions between the parties, we have recorded a liability of $6.0 million for our estimated refund obligation from the refund effective date of August 20, 2014, through March 31, 2015. Our estimated refund obligation is based on a base ROE of 9.8%. In addition, we estimate our future transmission revenues would be reduced by approximately $10.0 million on an annualized basis as a result of the reduced ROE.

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 March 31, 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 ended March 31, 2015, that have 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 11 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 March 31, 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



31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended March 31, 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 March 31, 2015
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended March 31, 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

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SIGNATURE

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



		WESTAR ENERGY, INC.

Date:	May 5, 2015	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

WESTAR ENERGY INC /KS - FORM 10-Q - May 5, 2015

Attached files

WESTAR ENERGY INC /KS Reports