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Table of Contents

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, 2011

OR

 

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

For the transition period from              to             

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Kansas

 

48-0290150

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300

(Address, including Zip Code and telephone number, including area code, of registrant’s principal executive offices)

 

 

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

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

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

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

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

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

 

Common Stock, par value $5.00 per share

  

113,690,101 shares

(Class)    (Outstanding at April 27, 2011)


Table of Contents

TABLE OF CONTENTS

 

     Page  

PART I. Financial Information

  

Item 1.

   Condensed Consolidated Financial Statements (Unaudited)   
   Consolidated Balance Sheets      6   
   Consolidated Statements of Income      7   
   Consolidated Statements of Cash Flows      8   
   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      30   

Item 3.

   Quantitative and Qualitative Disclosures About Market Risk      39   

Item 4.

   Controls and Procedures      39   

PART II. Other Information

  

Item 1.

   Legal Proceedings      39   

Item 1A.

   Risk Factors      39   

Item 2.

   Unregistered Sales of Equity Securities and Use of Proceeds      40   

Item 3.

   Defaults Upon Senior Securities      40   

Item 4.

   Removed and Reserved      40   

Item 5.

   Other Information      40   

Item 6.

   Exhibits      40   

Signature

     41   

 

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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

2010 Form 10-K

   Annual Report on Form 10-K for the year ended December 31, 2010

AFUDC

   Allowance for Funds Used During Construction

BACT

   Best available control technology

ECRR

   Environmental Cost Recovery Rider

EPA

   Environmental Protection Agency

EPS

   Earnings per share

FERC

   Federal Energy Regulatory Commission

Fitch

   Fitch Investors Service

GAAP

   Generally Accepted Accounting Principles

GHG

   Greenhouse gas

JEC

   Jeffrey Energy Center

KCC

   Kansas Corporation Commission

KDHE

   Kansas Department of Health and Environment

KGE

   Kansas Gas and Electric Company

La Cygne

   La Cygne Generating Station

MMBtu

   Millions of British Thermal Units

Moody’s

   Moody’s Investors Service

MWh

   Megawatt hours

NAAQS

   National Ambient Air Quality Standards

NDT

   Nuclear Decommissioning Trust

NOx

   Nitrogen Oxide

NRC

   Nuclear Regulatory Commission

ONEOK

   ONEOK, Inc.

OTC

   Over-the-counter

PSD

   Prevention of Significant Deterioration program

RSUs

   Restricted share units

S&P

   Standard & Poor’s Ratings Group

SCR

   Selective catalytic reduction

SO2

   Sulfur dioxide

SPP

   Southwest Power Pool

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:

 

   

the risk of operating in a heavily regulated industry subject to frequent and uncertain political, legislative, judicial and regulatory developments at any level of government that can affect our revenues and costs,

 

   

weather conditions and their effect on sales of electricity as well as on 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, 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 ability of our counterparties to make payments as and when due and to perform as required,

 

   

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

 

   

the impact of frequently changing laws and regulations relating to air 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 (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek’s performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,

 

   

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

 

   

homeland and information security considerations,

 

   

wholesale electricity prices,

 

   

changes in accounting requirements and other accounting matters,

 

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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 and independent system operators,

 

   

reduced demand for coal-based energy because of potential climate impacts and development of alternate energy sources,

 

   

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

 

   

other circumstances affecting anticipated operations, electricity sales and costs, and

 

   

other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2010 (2010 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 2010 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 2010 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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Table of Contents

PART I. FINANCIAL INFORMATION

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

 

     March 31,
2011
     December 31,
2010
 
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 3,343       $ 928   

Accounts receivable, net of allowance for doubtful accounts of $7,260 and $5,729, respectively

     204,434         227,700   

Inventories and supplies, net

     220,642         206,867   

Energy marketing contracts

     5,996         13,005   

Taxes receivable

     22,459         16,679   

Deferred tax assets

     20,135         30,248   

Prepaid expenses

     16,068         12,413   

Regulatory assets

     67,379         73,480   

Other

     15,442         20,289   
                 

Total Current Assets

     575,898         601,609   
                 

PROPERTY, PLANT AND EQUIPMENT, NET

     6,038,935         5,964,439   
                 

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET

     342,157         345,037   
                 

OTHER ASSETS:

     

Regulatory assets

     800,514         787,585   

Nuclear decommissioning trust

     133,102         126,990   

Energy marketing contracts

     9,064         9,472   

Other

     263,086         244,506   
                 

Total Other Assets

     1,205,766         1,168,553   
                 

TOTAL ASSETS

   $ 8,162,756       $ 8,079,638   
                 
LIABILITIES AND EQUITY      

CURRENT LIABILITIES:

     

Current maturities of long-term debt

   $ —         $ 61   

Current maturities of long-term debt of variable interest entities

     26,858         30,155   

Short-term debt

     305,340         226,700   

Accounts payable

     178,870         187,954   

Accrued taxes

     68,261         45,534   

Energy marketing contracts

     2,845         9,670   

Accrued interest

     95,050         77,771   

Regulatory liabilities

     29,539         28,284   

Other

     157,297         176,717   
                 

Total Current Liabilities

     864,060         782,846   
                 

LONG-TERM LIABILITIES:

     

Long-term debt, net

     2,490,878         2,490,871   

Long-term debt of variable interest entities, net

     272,866         278,162   

Deferred income taxes

     1,114,611         1,102,625   

Unamortized investment tax credits

     100,670         101,345   

Regulatory liabilities

     142,899         135,754   

Deferred regulatory gain from sale-leaseback

     96,167         97,541   

Accrued employee benefits

     454,885         483,769   

Asset retirement obligations

     127,777         125,999   

Energy marketing contracts

     —           10   

Other

     61,933         66,878   
                 

Total Long-Term Liabilities

     4,862,686         4,882,954   
                 

COMMITMENTS AND CONTINGENCIES (See Notes 8 and 9)

     

TEMPORARY EQUITY

     —           3,465   
                 

EQUITY:

     

Westar Energy Shareholders’ Equity:

     

Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares

     21,436         21,436   

Common stock, par value $5 per share; authorized 150,000,000 shares; issued and outstanding 113,587,852 shares and 112,128,068 shares, respectively

     567,939         560,640   

Paid-in capital

     1,422,842         1,398,580   

Retained earnings

     418,230         423,647   
                 

Total Westar Energy Shareholders’ Equity

     2,430,447         2,404,303   
                 

Noncontrolling Interests

     5,563         6,070   
                 

Total Equity

     2,436,010         2,410,373   
                 

TOTAL LIABILITIES AND EQUITY

   $ 8,162,756       $ 8,079,638   
                 

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

    Three Months Ended
March 31,
 
    2011     2010  

REVENUES

  $ 481,720      $ 459,830   
               

OPERATING EXPENSES:

   

Fuel and purchased power

    134,184        133,800   

Operating and maintenance

    137,351        121,172   

Depreciation and amortization

    70,259        66,930   

Selling, general and administrative

    48,767        45,927   
               

Total Operating Expenses

    390,561        367,829   
               

INCOME FROM OPERATIONS

    91,159        92,001   
               

OTHER INCOME (EXPENSE):

   

Investment earnings

    1,968        1,757   

Other income

    2,249        854   

Other expense

    (5,368     (4,494
               

Total Other Expense

    (1,151     (1,883
               

Interest expense

    43,538        44,616   
               

INCOME BEFORE INCOME TAXES

    46,470        45,502   

Income tax expense

    13,513        13,820   
               

NET INCOME

    32,957        31,682   

Less: Net income attributable to noncontrolling interests

    1,373        1,002   
               

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY

    31,584        30,680   

Preferred dividends

    242        242   
               

NET INCOME ATTRIBUTABLE TO COMMON STOCK

  $ 31,342      $ 30,438   
               

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2)

  $ 0.27      $ 0.27   

Average equivalent common shares outstanding

    113,875,389        110,925,146   

DIVIDENDS DECLARED PER COMMON SHARE

  $ 0.32      $ 0.31   

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

     Three Months Ended
March 31,
 
     2011     2010  

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

    

Net income

   $ 32,957      $ 31,682   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

     70,259        66,930   

Amortization of nuclear fuel

     5,787        6,084   

Amortization of deferred regulatory gain from sale-leaseback

     (1,374     (1,374

Amortization of corporate-owned life insurance

     6,308        5,840   

Non-cash compensation

     2,201        2,130   

Net changes in energy marketing assets and liabilities

     455        (181

Accrued liability to certain former officers

     647        504   

Net deferred income taxes and credits

     16,286        20,518   

Stock-based compensation excess tax benefits

     (629     (277

Allowance for equity funds used during construction

     (1,752     (455

Changes in working capital items:

    

Accounts receivable

     20,344        21,068   

Inventories and supplies

     (13,584     (1,673

Prepaid expenses and other

     5,640        (3,260

Accounts payable

     (2,164     10,001   

Accrued taxes

     17,123        11,382   

Other current liabilities

     (19,493     (15,267

Changes in other assets

     (20,327     7,758   

Changes in other liabilities

     (23,308     (9,442
                

Cash Flows from Operating Activities

     95,376        151,968   
                

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

    

Additions to property, plant and equipment

     (155,945     (103,272

Purchase of securities within trust funds

     (28,152     (8,319

Sale of securities within trust funds

     27,582        7,628   

Proceeds from investment in corporate-owned life insurance

     512        448   

Proceeds from federal grant

     2,113        —     

Investment in affiliated company

     (381     5   

Other investing activities

     2,198        690   
                

Cash Flows used in Investing Activities

     (152,073     (102,820
                

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

    

Short-term debt, net

     78,640        (33,600

Retirements of long-term debt

     (191     (646

Retirements of long-term debt of variable interest entities

     (8,386     (7,954

Repayment of capital leases

     (444     (610

Borrowings against cash surrender value of corporate-owned life insurance

     1,062        965   

Repayment of borrowings against cash surrender value of corporate-owned life insurance

     (2,897     (1,981

Stock-based compensation excess tax benefits

     629        277   

Issuance of common stock, net

     25,787        25,904   

Distributions to shareholders of noncontrolling interests

     (1,880     (1,466

Cash dividends paid

     (33,208     (31,054
                

Cash Flows from (used in) Financing Activities

     59,112        (50,165
                

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     2,415        (1,017

CASH AND CASH EQUIVALENTS:

    

Beginning of period

     928        3,860   
                

End of period

   $ 3,343      $ 2,843   
                

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

 

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)

 

    Westar Energy Shareholders              
    Cumulative
preferred
stock
    Common
stock
    Paid-in
capital
    Retained
earnings
    Noncontrolling
interests
    Total equity  

Balance at December 31, 2009

  $ 21,436      $ 545,360      $ 1,339,790      $ 360,199      $ —        $ 2,266,785   
                                               

Net income

    —          —          —          30,680        1,002        31,682   

Issuance of common stock, net

    —          6,976        22,760        —          —          29,736   

Preferred dividends

    —          —          —          (242     —          (242

Dividends on common stock

    —          —          —          (34,728     —          (34,728

Transfer to temporary equity

    —          —          (6     —          —          (6

Amortization of restricted stock

    —          —          1,653        —          —          1,653   

Stock compensation and tax benefit

    —          —          (1,667     —          —          (1,667

Consolidation of noncontrolling interests

    —          —          —          —          3,435        3,435   

Distributions to shareholders of noncontrolling interests

    —          —          —          —          (1,466     (1,466
                                               

Balance at March 31, 2010

  $ 21,436      $ 552,336      $ 1,362,530      $ 355,909      $ 2,971      $ 2,295,182   
                                               

Balance at December 31, 2010

  $ 21,436      $ 560,640      $ 1,398,580      $ 423,647      $ 6,070      $ 2,410,373   
                                               

Net income

    —          —          —          31,584        1,373        32,957   

Issuance of common stock, net

    —          7,299        26,056        —          —          33,355   

Preferred dividends

    —          —          —          (242     —          (242

Dividends on common stock

    —          —          —          (36,759     —          (36,759

Transfer from temporary equity

    —          —          3,465        —          —          3,465   

Amortization of restricted stock

    —          —          1,653        —          —          1,653   

Stock compensation and tax benefit

    —          —          (6,912     —          —          (6,912

Distributions to shareholders of noncontrolling interests

    —          —          —          —          (1,880     (1,880
                                               

Balance at March 31, 2011

  $ 21,436      $ 567,939      $ 1,422,842      $ 418,230      $ 5,563      $ 2,436,010   
                                               

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 687,000 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) 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 operating segment. 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 2010 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 on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, valuation of investments, valuation of our energy marketing portfolio, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and other 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, 2011, are not necessarily indicative of the results to be expected for the full year.

 

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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,
 
     2011     2010  
     (Dollars in Thousands)  

Borrowed funds

   $ 1,500      $ 744   

Equity funds

     1,752        455   
                

Total

   $ 3,252      $ 1,199   
                

Average AFUDC Rates

     4.6     2.3

Earnings Per Share

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

Under the two-class method, we reduce net income attributable to common stock by the amount of dividends declared in the current period. We allocate the remaining earnings to common stock and RSUs to the extent that each security may share in earnings as if all of the earnings for the period had been distributed. We determine the total earnings allocated to each security by adding together the amount allocated for dividends and the amount allocated for a participation feature. To compute basic EPS, we divide the earnings allocated to common stock by the weighted average equivalent common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements, RSUs that do not have nonforfeitable rights to dividend equivalents and stock options. 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,
 
     2011      2010  
    

(Dollars In Thousands, Except

Per Share Amounts)

 

Net income

   $ 32,957       $ 31,682   

Less: Net income attributable to noncontrolling interests

     1,373         1,002   
                 

Net income attributable to Westar Energy

     31,584         30,680   

Less: Preferred dividends

     242         242   

Net income allocated to RSUs

     147         126   
                 

Net income allocated to common stock

   $ 31,195       $ 30,312   
                 

Weighted average equivalent common shares outstanding – basic

     113,875,389         110,925,146   

Effect of dilutive securities:

     

Restricted share units

     186,312         27,427   

Forward sale agreements

     1,688,752         —     

Employee stock options

     —           207   
                 

Weighted average equivalent common shares outstanding – diluted (a)

     115,750,453         110,952,780   
                 

Earnings per common share, basic and diluted

   $ 0.27       $ 0.27   

 

(a) We did not have any antidilutive shares for the three months ended March 31, 2011 and 2010.

Supplemental Cash Flow Information

 

     Three Months Ended
March 31,
 
     2011      2010  
     (In Thousands)  

CASH PAID FOR (RECEIVED FROM):

     

Interest on financing activities, net of amount capitalized

   $ 28,413       $ 29,065   

Interest on financing activities of VIEs

     9,024         9,891   

Income taxes, net of refunds

     753         2,013   

NON-CASH INVESTING TRANSACTIONS:

     

Property, plant and equipment additions

     55,448         23,332   

Property, plant and equipment additions of VIEs

     —           356,964   

Jeffrey Energy Center (JEC) 8% leasehold interest

     —           (108,706

NON-CASH FINANCING TRANSACTIONS:

     

Issuance of common stock for reinvested dividends and compensation plans

     5,146         3,536   

Debt of VIEs

     —           337,951   

Capital lease for JEC 8% leasehold interest

     —           (106,423

Assets acquired through capital leases

     208         —     

 

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3. FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING SECURITIES, ENERGY MARKETING AND RISK MANAGEMENT

Values of Financial and Derivative Instruments

GAAP establishes a hierarchal 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 fair value assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:

 

   

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

 

   

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, such as commodity options priced using observable forward prices and volatilities.

 

   

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, such as the complex and subjective models and forecasts used to determine the fair value of options, real estate investments and long-term electricity supply contracts.

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 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, whether in the nuclear decommissioning trust (NDT) or our trading securities portfolio, are held in investment funds that are measured using daily net asset values as reported by the fund managers. In addition, we maintain certain level 3 investments in private equity and real estate securities that require significant unobservable market information to measure the fair value of the investments. The fair value of private equity investments is measured by utilizing both market- and income-based models, public company comparables, at cost or at 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. To measure the fair value of real estate securities we use a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

Energy marketing contracts can be exchange-traded or traded over-the-counter (OTC). Fair value measurements of exchange-traded contracts typically utilize quoted prices in active markets. OTC contracts are valued using market transactions and other market evidence whenever possible, including market-based inputs to models, model calibration to market clearing transactions or alternative pricing sources with reasonable levels of price transparency. Valuation models require a variety of inputs, including contractual terms, market prices, yield curves, credit curves, nonperformance risk, measures of volatility and correlations of such inputs. Certain OTC contracts trade in less liquid markets with limited pricing information and the determination of fair value for these derivatives is inherently more subjective. In these situations, estimates by management are a significant input. See “—Recurring Fair Value Measurements” and “—Derivative Instruments” below for additional information.

 

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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 financial instruments as of March 31, 2011, and December 31, 2010.

 

       As of March 31, 2011        As of December 31, 2010  
       Carrying Value        Fair Value        Carrying Value        Fair Value  
       (In Thousands)  

Fixed-rate debt

     $ 2,373,243         $ 2,552,207         $ 2,373,373         $ 2,570,648   

Fixed-rate debt of VIEs

       297,511           308,501           308,317           341,328   

 

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Recurring Fair Value Measurements

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

 

      Level 1      Level 2      Level 3      Total  
     (In Thousands)  

As of March 31, 2011

           

Assets:

           

Energy Marketing Contracts

   $ —         $ 1,849       $ 13,211       $ 15,060   

Nuclear Decommissioning Trust:

           

Domestic equity

     —           54,063         3,058         57,121   

International equity

     —           27,355         —           27,355   

Core bonds

     —           22,240         —           22,240   

High-yield bonds

     —           9,573         —           9,573   

Emerging market bonds

     —           5,755         —           5,755   

Combination debt/equity fund

     —           7,952         —           7,952   

Real estate securities

     —           —           3,049         3,049   

Cash equivalents

     57         —           —           57   
                                   

Total Nuclear Decommissioning Trust

     57         126,938         6,107         133,102   
                                   

Trading Securities:

           

Domestic equity

     —           21,808         —           21,808   

International equity

     —           5,284         —           5,284   

Core bonds

     —           14,266         —           14,266   
                                   

Total Trading Securities

     —           41,358         —           41,358   
                                   

Treasury Yield Hedges

     —           10,334         —           10,334   
                                   

Total Assets Measured at Fair Value

   $ 57       $ 180,479       $ 19,318       $ 199,854   
                                   

Liabilities:

           

Energy Marketing Contracts

   $ —         $ 1,640       $ 1,205       $ 2,845   

As of December 31, 2010

           

Assets:

           

Energy Marketing Contracts

   $ 2,432       $ 6,258       $ 13,787       $ 22,477   

Nuclear Decommissioning Trust:

           

Domestic equity

     —           60,586         2,867         63,453   

International equity

     —           18,966         —           18,966   

Core bonds

     —           31,906         —           31,906   

High-yield bonds

     —           9,267         305         9,572   

Real estate securities

     —           —           3,049         3,049   

Cash equivalents

     44         —           —           44   
                                   

Total Nuclear Decommissioning Trust

     44         120,725         6,221         126,990   
                                   

Trading Securities:

           

Domestic equity

     —           21,207         —           21,207   

International equity

     —           5,128         —           5,128   

Core bonds

     —           13,077         —           13,077   
                                   

Total Trading Securities

     —           39,412         —           39,412   
                                   

Treasury Yield Hedges

     —           7,711         —           7,711   
                                   

Total Assets Measured at Fair Value

   $ 2,476       $ 174,106       $ 20,008       $ 196,590   
                                   

Liabilities:

           

Energy Marketing Contracts

   $ 1,888       $ 5,820       $ 1,972       $ 9,680   

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of March 31, 2011, we had no right to reclaim cash collateral and had recorded $1.4 million for our obligation to return cash collateral. As of December 31, 2010, we had no right to reclaim cash collateral and had recorded $0.7 million for our obligation to return cash collateral.

 

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The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three months ended March 31, 2011 and 2010.

 

     Energy
Marketing
Contracts, net
    Nuclear Decommissioning Trust     Net
Balance
 
       Domestic
Equity
    High-yield
Bonds
    Real  Estate
Securities
   
     (In Thousands)  

Balance as of December 31, 2010

   $ 11,815      $ 2,867      $ 305      $ 3,049      $ 18,036   

Total realized and unrealized gains (losses) included in:

          

Earnings (a)

     (197     —          —          —          (197

Regulatory assets

     (18 )(b)      —          —          —          (18

Regulatory liabilities

     599  (b)      31        —          —          630   

Purchases

     (742     173        —          —          (569

Sales

     894        (13     (305     —          576   

Settlements

     (345     —          —          —          (345
                                        

Balance as of March 31, 2011

   $ 12,006      $ 3,058      $ —        $ 3,049      $ 18,113   
                                        

Balance as of December 31, 2009

   $ 4,310      $ 2,262      $ 5,741      $ 3,635      $ 15,948   

Total realized and unrealized gains (losses) included in:

          

Earnings (a)

     4        —          —          —          4   

Regulatory assets

     4,468 (b)      —          —          —          4,468   

Regulatory liabilities

     3,286 (b)      82        238        (856     2,750   

Purchases, issuances and settlements

     2,384        40        —          —          2,424   
                                        

Balance as of March 31, 2010

   $ 14,452      $ 2,384      $ 5,979      $ 2,779      $ 25,594   
                                        

 

(a) Unrealized and realized gains and losses included in earnings resulting from energy marketing activities are reported in revenues.
(b) Includes changes in the fair value of certain fuel supply and electricity contracts.

 

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A portion of the gains and losses contributing to changes in net assets in the above table is unrealized. The following table summarizes the unrealized gains and losses we recorded on our consolidated financial statements during the three months ended March 31, 2011 and 2010, attributed to level 3 assets and liabilities.

 

     Three Months Ended March 31, 2011  
     Energy
Marketing
Contracts,
net
    Nuclear Decommissioning Trust     Net
Balance
 
       Domestic
Equity
     High-yield
Bonds
     Real Estate
Securities
   
     (In Thousands)  

Total unrealized gains (losses) included in:

            

Earnings (a)

   $ (273   $ —         $ —         $ —        $ (273

Regulatory assets

     (10 )(b)      —           —           —          (10

Regulatory liabilities

     601  (b)      19         —           —          620   
                                          

Total

   $ 318      $ 19       $ —         $ —        $ 337   
                                          
     Three Months Ended March 31, 2010  

Total unrealized gains (losses) included in:

            

Earnings (a)

   $ (197   $ —         $ —         $ —        $ (197

Regulatory assets

     4,540 (b)      —           —           —          4,540   

Regulatory liabilities

     3,251 (b)      82         238         (856     2,715   
                                          

Total

   $ 7,594      $ 82       $ 238       $ (856   $ 7,058   
                                          

 

(a) Unrealized gains and losses included in earnings resulting from energy marketing activities are reported in revenues.
(b) Includes changes in the fair value of certain fuel supply and electricity contracts.

 

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Some of our investments in the NDT and all of our trading securities do not have readily determinable fair values and 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 further information on these investments.

 

     As of March 31, 2011      As of December 31, 2010      As of March 31, 2011  
     Fair
Value
     Unfunded
Commitments
     Fair
Value
     Unfunded
Commitments
     Redemption
Frequency
    Length of
Settlement
 
     (In thousands)               

Nuclear Decommissioning Trust:

                

Domestic equity

   $ 3,058       $ 2,350       $ 2,867       $ 2,523         (a)        (a)   

High-yield bonds

     —           —           305         —           (b)        (b)   

Real estate securities

     3,049         —           3,049         —           (c)        (c)   
                                        

Total Nuclear Decommissioning Trust

   $ 6,107       $ 2,350       $ 6,221       $ 2,523        
                                        

Trading Securities:

                

Domestic equity

   $ 21,808       $ —         $ 21,207       $ —           Upon Notice        1 day   

International equity

     5,284         —           5,128         —           Upon Notice        1 day   

Core bonds

     14,266         —           13,077         —           Upon Notice        1 day   
                                        

Total Trading Securities

     41,358         —           39,412         —          
                                        

Total

   $ 47,465       $ 2,350       $ 45,633       $ 2,523        
                                        

 

(a) This investment is in 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. One fund has begun to make distributions and we expect the other to begin in 2013.
(b) We completely settled this fund in the first quarter of 2011.
(c) The nature of this investment requires relatively long holding periods which do not necessarily accommodate ready liquidity. In addition, adverse financial conditions affecting residential and commercial real estate markets have further limited liquidity associated with this investment.

Derivative Instruments

Cash Flow Hedges

In 2010, we entered into treasury yield hedge transactions for a total notional amount of $100.0 million in order to manage our interest rate risk associated with a future anticipated issuance of fixed-rate debt, which is probable to occur within 18 months of the initial treasury yield hedge transaction date. Such transactions are designated and qualify as cash flow hedges and are measured at fair value by estimating the net present value of a series of payments using market-based models with observable inputs, such as the spread between the 30-year U.S. Treasury bill yield and the contracted, fixed yield. As a result of regulatory accounting treatment, we report the effective portion of the gain or loss on these derivative instruments as a regulatory liability or regulatory asset and will amortize such amounts to interest expense over the life of the related debt. We record hedge ineffectiveness gains in other income and hedge ineffectiveness losses in other expense on our consolidated statements of income. As of March 31, 2011, and December 31, 2010, the fair value of the treasury yield hedge transactions was $10.3 million and $7.7 million, respectively, which we recorded in other assets on our consolidated balance sheets. We also recorded these same amounts in long-term regulatory liabilities on our consolidated balance sheets to reflect the effective portion of the gains on these transactions as of March 31, 2011, and December 31, 2010.

Commodity Contracts

We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We trade electricity and other energy-related products using a variety of financial instruments, including futures contracts, options, swaps and physical commodity contracts.

 

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We classify these commodity derivative instruments as energy marketing contracts on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities. With the exception of certain fuel supply and electricity contracts, which we record as regulatory assets or regulatory liabilities, we include the change in the fair value of energy marketing contracts in revenues on our consolidated statements of income.

The following table presents the fair value of commodity derivative instruments reflected on our consolidated balance sheets.

Commodity Derivatives Not Designated as Hedging Instruments as of March 31, 2011

 

Asset Derivatives

    

Liability Derivatives

 

Balance Sheet Location

   Fair Value     

Balance Sheet Location

   Fair Value  
     (In thousands)           (In thousands)  

Current assets:

      Current liabilities:   

Energy marketing contracts

   $ 5,996      

Energy marketing contracts

   $ 2,845   

Other assets:

        

Energy marketing contracts

     9,064         
              

Total

   $ 15,060         
              

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 2010

 

Asset Derivatives

    

Liability Derivatives

 

Balance Sheet Location

   Fair Value     

Balance Sheet Location

   Fair Value  
     (In thousands)           (In thousands)  

Current assets:

      Current liabilities:   

Energy marketing contracts

   $ 13,005      

Energy marketing contracts

   $ 9,670   

Other assets:

      Long-term liabilities:   

Energy marketing contracts

     9,472      

Energy marketing contracts

     10   
                    

Total

   $ 22,477       Total    $ 9,680   
                    

The following table presents how changes in the fair value of commodity derivative instruments affected our consolidated financial statements for the three months ended March 31, 2011 and 2010.

 

     Three Months Ended
March 31, 2011
    Three Months Ended
March  31, 2010
 

Location

   Net Loss
Recognized
    Net Gain
Recognized
    Net Loss
Recognized
 
     (In thousands)  

Revenues decrease

   $ (1,555   $ —        $ (565

Regulatory assets decrease

     —          (7,193     —     

Regulatory liabilities (decrease) increase

     (213     3,380        —     

As of March 31, 2011, and December 31, 2010, we had under contract the following energy-related products.

 

     Unit of
Measure
     Net Quantity as of  
        March 31, 2011      December 31, 2010  

Electricity

     MWh         2,913,347         2,791,966   

Natural Gas

     MMBtu         1,515,000         1,150,000   

Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have net open positions, we are exposed to the risk that changing market prices could have a material adverse impact on our consolidated financial results.

 

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Energy Marketing Activities

Within our energy trading portfolio, we may establish certain positions intended to economically hedge a portion of physical sale or purchase contracts and we may enter into certain positions attempting to take advantage of market trends and conditions. We use the term economic hedge to mean a strategy intended to manage risks of volatility in prices or rate movements on selected assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to offset the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks.

Price Risk

We use various types of fuel, including coal, natural gas, uranium, diesel and oil, to operate our plants and purchase power to meet customer demand. Our prices, consolidated financial results and cash flows are exposed to market risks from commodity price changes for electricity and other energy-related products and 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 these 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 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.

Credit Risk

In addition to commodity price risk, we are exposed to credit risks associated with the financial condition of counterparties, product location (basis) pricing differentials, physical liquidity constraint and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties intended to reduce our overall credit risk exposure to a level we deem acceptable and include the right to offset derivative assets and liabilities by counterparty.

We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of March 31, 2011, and December 31, 2010, was $0.8 million and $1.6 million, respectively, for which we had posted $0.5 million of collateral, including independent amounts, as of March 31, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of March 31, 2011, and December 31, 2010, we would have been required to provide to our counterparties $0.7 million and $1.6 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

 

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4. FINANCIAL INVESTMENTS

We report some of our investments in debt and equity securities at fair value. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We have equity and debt investments in a trust used to fund retirement benefits that we classify as trading securities. We include any unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. We recorded unrealized gains of $1.5 million and $1.6 million, respectively, during the three months ended March 31, 2011 and 2010.

Available-for-Sale Securities

We hold investments in equity, debt and real estate securities in a trust fund 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, 2011, and December 31, 2010. At March 31, 2011, investments in the NDT fund were allocated 43% to domestic equity, 21% to international equity, 17% to core bonds, 7% to high-yield bonds, 4% to emerging market bonds, 6% to combined debt/equity funds, 2% to real estate securities and less than 1% to cash and cash equivalents. The core bond fund is limited to ensure that at least 80% of funds are invested in investment grade U.S. corporate and government fixed income securities, including mortgage-backed securities. As of March 31, 2011, the fair value of the debt securities in the NDT fund was $37.6 million, held entirely in bond funds.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $0.9 million during the three months ended March 31, 2011 and 2010. 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 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.

 

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The following table presents the costs and fair values of investments in the NDT fund as of March 31, 2011, and December 31, 2010.

 

      Cost      Gross Unrealized     Fair Value  

Security Type

      Gain      Loss    
     (In Thousands)  

As of March 31, 2011:

          

Domestic equity

   $ 50,213       $ 7,000       $ (92   $ 57,121   

International equity

     24,774         2,581         —          27,355   

Core bonds

     22,235         5         —          22,240   

High-yield bonds

     9,170         403         —          9,573   

Emerging market bonds

     5,501         254         —          5,755   

Combination debt/equity fund

     7,737         215         —          7,952   

Real estate securities

     6,207         —           (3,158     3,049   

Cash equivalents

     57         —           —          57   
                                  

Total

   $ 125,894       $ 10,458       $ (3,250   $ 133,102   
                                  

As of December 31, 2010:

          

Domestic equity

   $ 58,592       $ 4,972       $ (111   $ 63,453   

International equity

     17,249         1,717         —          18,966   

Core bonds

     32,054         —           (148     31,906   

High-yield bonds

     9,086         486         —          9,572   

Real estate securities

     6,207         —           (3,158     3,049   

Cash equivalents

     44         —           —          44   
                                  

Total

   $ 123,232       $ 7,175       $ (3,417   $ 126,990   
                                  

The following table presents the fair value and 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, 2011, and December 31, 2010.

 

     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, 2011:

               

Domestic equity

   $ 3,058       $ (92   $ —         $ —        $ 3,058       $ (92

Real estate securities

     —           —          3,049         (3,158     3,049         (3,158
                                                   

Total

   $ 3,058       $ (92   $ 3,049       $ (3,158   $ 6,107       $ (3,250
                                                   

As of December 31, 2010:

               

Domestic equity

   $ 2,867       $ (111   $ —         $ —        $ 2,867       $ (111

Core bonds

     31,906         (148     —           —          31,906         (148

Real estate securities

     —           —          3,049         (3,158     3,049         (3,158
                                                   

Total

   $ 34,773       $ (259   $ 3,049       $ (3,158   $ 37,822       $ (3,417
                                                   

 

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5. RATE MATTERS AND REGULATION

FERC Proceedings

Our transmission formula rate that includes projected 2011 transmission capital expenditures and operating costs became effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million. This updated rate provides the basis for our request with the Kansas Corporation Commission (KCC) to adjust our retail prices to include updated transmission costs.

6. SHORT-TERM DEBT

Westar Energy has a $730.0 million revolving credit facility with a syndicate of banks that terminates on March 17, 2012. As of March 31, 2011, $305.3 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2010, $226.7 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility.

In February 2011, Westar Energy entered into a new revolving credit facility with a similar syndicate of banks for an additional $270.0 million. The commitments under this facility terminate in February 2015. As of March 31, 2011, Westar Energy had neither borrowed monies nor issued letters of credit under this revolving credit facility.

7. TAXES

We recorded income tax expense of $13.5 million with an effective income tax rate of 29% for the three months ended March 31, 2011. We recorded income tax expense of $13.8 million with an effective income tax rate of 30% for the same period of 2010. The decrease in the effective income tax rate for the three months ended March 31, 2011, was due primarily to increases in the tax benefits from AFUDC equity and increases in production tax credits.

At March 31, 2011, and December 31, 2010, our liability for unrecognized income tax benefits was $3.8 million and $1.9 million, respectively. The net increase in the liability for unrecognized income tax benefits was largely attributable to tax positions taken with respect to the capitalization of plant related expenditures. We do not expect any significant changes in this liability in the next 12 months.

As of March 31, 2011, and December 31, 2010, we had $0.4 million accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either March 31, 2011, or December 31, 2010.

As of March 31, 2011, and December 31, 2010, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

8. COMMITMENTS AND CONTINGENCIES

Federal Clean Air Act

We must comply with the Federal Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on pollutants generated during our operations, including sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx) and mercury. In addition, we must comply with the provisions of the Federal Clean Air Act Amendments of 1990 that require reductions in SO2 and NOx.

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

 

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Under the Federal Clean Air Act, the Environmental Protection Agency (EPA) sets National Ambient Air Quality Standards (NAAQS) for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. 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 2010, the EPA strengthened the NAAQS for both NOx and SO2. We are currently evaluating what impact this could have on our operations. 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.

Environmental Projects

We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could change materially depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce the net production, reliability and availability of the plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments.

The environmental cost recovery rider (ECRR) allows for the more timely inclusion in retail prices of the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our prices to recognize increased operating and maintenance costs, however, we must file a general rate case with the KCC. The KCC has indicated that it believes environmental costs at La Cygne Generating Station (La Cygne) may be more appropriate to recover through the filing of a general rate case as opposed to the ECRR. This could increase the time between making these investments and having them reflected in the prices we charge our customers, as well as the amount we charge our customers, and could affect our capital expenditure plans. This matter has not yet been resolved.

Greenhouse Gases

Under EPA regulations finalized in May 2010, known as the tailoring rule, the EPA began regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two Federal Clear Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, 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), will be required to implement best available control technology (BACT). 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 new regulations on our operations and consolidated financial results, but we believe the cost of compliance with new regulations could be material.

 

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Renewable Energy Standard

In May 2009, Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. In years 2011 through 2015 net renewable generation capacity must be 10% of the average peak 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. We have worked with third parties to develop approximately 300 MW of qualifying wind generation facilities, which together with the use of renewable energy credits, we expect to meet the 2011 requirement. On December 14, 2010, we announced that we reached two separate agreements with third parties, subject to regulatory approval, to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of wind generation beginning in late 2012. We expect these agreements, along with our prior development of wind generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in 2016.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and KDHE entered into a consent agreement governing all future work at these sites. Under terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK Inc. (ONEOK), ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million.

EPA Lawsuit

In March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement that we entered into with the parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at JEC violated certain requirements of the EPA’s New Source Review program, which requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions. As part of the settlement agreement, in 2009 we recorded $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and a $3.0 million civil penalty. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In addition, we will install a selective catalytic reduction (SCR) on one of the three JEC coal units by the end of 2014. We estimate the cost of this to be approximately $240.0 million. This amount could change materially depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, we may have to install an SCR on another JEC unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge customers.

FERC Investigation

A non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008 remains pending. In May 2009, FERC staff advised us that it had preliminarily concluded that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. In March 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and could potentially alter the manner in which we are permitted to buy and sell energy and use transmission service.

 

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9. LEGAL PROCEEDINGS

In late 2002, one of our former executive officers resigned from his position and another executive officer was placed on administrative leave from his position. Following the completion of an investigation and the publication of a report prepared by a special committee of our board of directors, our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment and the publication of the report of the special committee. As of March 31, 2011, we had accrued liabilities of $81.4 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. As of December 31, 2010, we had accrued liabilities of $80.6 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. The arbitration was stayed in August 2004 pending final resolution of criminal charges filed by the United States Attorney’s Office against them in U.S. District Court in the District of Kansas. In August 2010, these criminal charges were dismissed and subsequently the stay of the arbitration was lifted. We expect arbitration proceedings to conclude in 2011. While we intend to vigorously defend against the counterclaims they filed in the arbitration, we are exploring alternatives to settle all claims related to these executives. We are unable to predict the ultimate amount of the compensation, legal fees or related amounts we may be required to pay them, or the ultimate impact of these matters on our consolidated financial results.

We and our subsidiaries are involved in various other 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 adverse affect on our consolidated financial results. See Note 5, “Rate Matters and Regulation,” and Note 8, “Commitments and Contingencies,” for additional information.

10. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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,

   2011     2010     2011     2010  
     (In Thousands)  

Components of Net Periodic Cost:

        

Service cost

   $ 4,017      $ 3,518      $ 452      $ 433   

Interest cost

     9,955        9,842        1,692        1,788   

Expected return on plan assets

     (7,772     (9,597     (1,200     (1,360

Amortization of unrecognized:

        

Transition obligation, net

     —          —          978        978   

Prior service costs

     303        667        539        544   

Actuarial loss, net

     5,915        4,245        254        101   
                                

Net periodic cost before regulatory adjustment

     12,418        8,675        2,715        2,484   

Regulatory adjustment

     (5,625     (3,121     297        430   
                                

Net periodic cost

   $ 6,793      $ 5,554      $ 3,012      $ 2,914   
                                

During the three months ended March 31, 2011 and 2010, we contributed $29.0 million and $8.4 million, respectively, to the Westar Energy pension trust.

 

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11. WOLF CREEK INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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

 

     Pension Benefits     Post-retirement Benefits  

Three Months Ended March 31,

   2011     2010     2011      2010  
     (In Thousands)  

Components of Net Periodic Cost:

         

Service cost

   $ 1,260      $ 1,024      $ 54       $ 54   

Interest cost

     1,864        1,724        126         130   

Expected return on plan assets

     (1,525     (1,380     —           —     

Amortization of unrecognized:

         

Transition obligation, net

     13        14        14         14   

Prior service costs

     4        7        8         —     

Actuarial loss, net

     995        606        76         69   
                                 

Net periodic cost before regulatory adjustment

     2,611        1,995        278         267   

Regulatory adjustment

     (657     (322     —           —     
                                 

Net periodic cost

   $ 1,954      $ 1,673      $ 278       $ 267   
                                 

During the three months ended March 31, 2011 and 2010, we funded $5.7 million and $0.9 million, respectively, of Wolf Creek’s pension plan contribution.

12. COMMON STOCK ISSUANCE

On February 15, 2011, Westar Energy delivered approximately 1.1 million shares of common stock and received proceeds of $25.8 million as partial settlement of the forward sale agreement entered into with a bank in April 2010. Assuming physical share settlement of the approximately 3.1 million remaining shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $68.5 million, net of commission, based on an average forward price of $21.86 per share.

During the three months ended March 31, 2011, Westar Energy did not deliver any shares of common stock under the forward sale agreement entered into with a bank in November 2010. Assuming physical share settlement of the approximately 8.5 million shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $203.4 million, net of commission, based on an average forward price of $23.98 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 JEC, our 50% interest in La Cygne unit 2 and railcars we use to transport coal to some of our plants 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 such 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.

Railcars

Under two separate agreements that expire in May 2013 and November 2014, we lease railcars from trusts to transport coal to some of our power plants. The trusts were financed with equity contributions from owner participants and debt issued by the trusts. The trusts were created specifically to purchase the railcars and lease them to us, and do not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trusts. In determining the primary beneficiary of the trusts, we concluded that the activities of the trusts that most significantly impact their economic performance and that we have the power to direct include the operation, maintenance and repair of the railcars and our ability to exercise a purchase option at the end of the agreements at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trusts that could potentially be significant if the fair value of the railcars at the end of the agreements is greater than the fixed amounts. Our agreements with these trusts also include renewal options during which time we would pay a fixed amount of rent. We have the potential to receive benefits from the trusts during the renewal periods if the fixed amount of rent is less than the amount we would be required to pay under a new agreement.

 

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Financial Statement Impact

We have recorded the following assets and liabilities on our consolidated balance sheets as a result of consolidating the VIEs described above.

 

     As of
March 31, 2011
     As of
December 31, 2010
 
     (In Thousands)  

Assets:

     

Property, plant and equipment of variable interest entities, net

   $ 342,157       $ 345,037   

Regulatory asset (a)

     4,278         3,963   

Liabilities:

     

Current maturities of long-term debt of variable interest entities

   $ 26,858       $ 30,155   

Accrued interest (b)

     573         5,064   

Long-term debt of variable interest entities, net

     272,866         278,162   

 

(a)        Included in other 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 VIEs’ ownership of the reported 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,” “pro forma,” “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 general financial condition, significant changes that occurred during 2011 and our operating results for the three months ended March 31, 2011 and 2010. 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 EPS.

 

     Three Months Ended March 31,  
         2011              2010              Change      
     (Thousands of Dollars, Except per Share Amounts)  

Net income attributable to common stock

   $ 31,342       $ 30,438       $ 904   

Earnings per common share, basic

     0.27         0.27         —     

Current Trends

From time to time we update current trends discussed in our 2010 Form 10-K. The following is to be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Form 10-K.

Regulation of Nuclear Generating Station

Additional regulation of Wolf Creek resulting from NRC oversight of the plant’s performance or from changing regulations generally, including those that could potentially result from events surrounding the Fukushima Daiichi nuclear power plant in Japan, or any event that might occur at any nuclear plant anywhere in the world, may result in increased operating and capital expenditures. We cannot estimate the cost associated with such increases, but they could be material to our operations and consolidated financial results.

In March 2011, the NRC established a task force to conduct a review of U.S. nuclear power plant safety in the aftermath of a March 11, 2011, earthquake and tsunami that eventually resulted in station blackout and a level 7 event on the International Nuclear and Radiological Event Scale (the highest level event on the scale) at Japan’s Fukushima Daiichi nuclear power plant. The task force expects to develop recommendations for the NRC on whether it should require immediate enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures, and licensing processes. The timing and effects of any NRC action cannot be determined at this time.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our 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 estimates and assumptions by management. The policies highlighted in our 2010 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.

 

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From December 31, 2010, through March 31, 2011, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2010 Form 10-K.

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 for lighting public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. This category also includes changes in valuations of contracts for the sale of such electricity that have yet to settle. Margins realized from sales based on prevailing market prices generally serve to offset our retail prices and the cost-based prices charged to certain wholesale customers.

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

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

Electric utility revenues are impacted by things such as rate regulation, fuel costs, customer conservation efforts, 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 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, 2011, Compared to Three Months Ended March 31, 2010

Below we discuss our operating results for the three months ended March 31, 2011, compared to the results for the three months ended March 31, 2010. 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,  
     2011     2010     Change     % Change  
     (In Thousands, Except Per Share Amounts)  

REVENUES:

        

Residential

   $ 152,908      $ 144,742      $ 8,166        5.6   

Commercial

     128,827        117,470        11,357        9.7   

Industrial

     79,196        69,040        10,156        14.7   

Other retail

     (3,014     1,993        (5,007     (251.2
                          

Total Retail Revenues

     357,917        333,245        24,672        7.4   

Wholesale

     78,594        82,748        (4,154     (5.0

Transmission (a)

     37,176        36,629        547        1.5   

Other

     8,033        7,208        825        11.4   
                          

Total Revenues

     481,720        459,830        21,890        4.8   
                          

OPERATING EXPENSES:

        

Fuel and purchased power

     134,184        133,800        384        0.3   

Operating and maintenance

     137,351        121,172        16,179        13.4   

Depreciation and amortization

     70,259        66,930        3,329        5.0   

Selling, general and administrative

     48,767        45,927        2,840        6.2   
                          

Total Operating Expenses

     390,561        367,829        22,732        6.2   
                          

INCOME FROM OPERATIONS

     91,159        92,001        (842     (0.9
                          

OTHER INCOME (EXPENSE):

        

Investment earnings

     1,968        1,757        211        12.0   

Other income

     2,249        854        1,395        163.3   

Other expense

     (5,368     (4,494     (874     (19.4
                          

Total Other Expense

     (1,151     (1,883     732        38.9   
                          

Interest expense

     43,538        44,616        (1,078     (2.4
                          

INCOME BEFORE INCOME TAXES

     46,470        45,502        968        2.1   

Income tax expense

     13,513        13,820        (307     (2.2
                          

NET INCOME

     32,957        31,682        1,275        4.0   

Less: Net income attributable to noncontrolling interests

     1,373        1,002        371        37.0   
                          

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY

     31,584        30,680        904        2.9   

Preferred dividends

     242        242        —          —     
                          

NET INCOME ATTRIBUTABLE TO COMMON STOCK

   $ 31,342      $ 30,438      $ 904        3.0   
                          

BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY

   $ 0.27      $ 0.27      $ —          —     

 

(a) Transmission: Reflects revenue derived from an SPP network transmission tariff. For the three months ended March 31, 2011, our SPP network transmission costs were $32.1 million. This amount, less $4.2 million retained by the SPP as administration cost, was returned to us as revenue. For the three months ended March 31, 2010, our SPP network transmission costs were $27.2 million. This amount, less an administration cost of $3.1 million retained by the SPP, was 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. For this reason, 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 less the sum of fuel and purchased power costs and SPP network transmission costs. Transmission costs reflect the costs of providing network transmission service. Accordingly, in calculating gross margin, we recognize the net value of this transmission activity as shown in the table immediately following. However, we record transmission costs as operating and maintenance expense on our consolidated statements of income. The following table summarizes our gross margin for the three months ended March 31, 2011 and 2010.

 

       Three Months Ended March 31,  
       2011      2010        Change      % Change  
       (Dollars In Thousands)  

REVENUES:

               

Residential

     $ 152,908       $ 144,742         $ 8,166         5.6   

Commercial

       128,827         117,470           11,357         9.7   

Industrial

       79,196         69,040           10,156         14.7   

Other retail

       (3,014      1,993           (5,007      (251.2
                                 

Total Retail Revenues

       357,917         333,245           24,672         7.4   

Wholesale

       78,594         82,748           (4,154      (5.0

Transmission

       37,176         36,629           547         1.5   

Other

       8,033         7,208           825         11.4   
                                 

Total Revenues

       481,720         459,830           21,890         4.8   

Less: Fuel and purchased power expense

       134,184         133,800           384         0.3   

SPP network transmission costs

       32,051         27,154           4,897         18.0   
                                 

Gross Margin

     $ 315,485       $ 298,876         $ 16,609         5.6   
                                 

The following table reflects changes in electricity sales for the three months ended March 31, 2011 and 2010. 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,  
       2011        2010        Change      % Change  
       (Thousands of MWh)  

ELECTRICITY SALES:

                 

Residential

       1,658           1,682           (24      (1.4

Commercial

       1,704           1,666           38         2.3   

Industrial

       1,337           1,277           60         4.7   

Other retail

       22           22           —           —     
                                   

Total Retail

       4,721           4,647           74         1.6   

Wholesale

       1,910           2,298           (388      (16.9
                                   

Total

       6,631           6,945           (314      (4.5
                                   

Gross margin increased due primarily to higher total retail revenues. Of the $24.7 million increase in total retail revenues, 78% was attributable to higher prices and 22% was due to higher electricity sales. Higher retail electricity sales were the result of increased industrial and commercial electricity sales. Although economic conditions have not recovered to levels experienced prior to the economic downturn, we believe improving economic conditions are why some of our industrial and commercial customers experienced increased production, which resulted in more electricity sales to them.

 

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Income from operations is the most directly comparable measure to 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, 2011 and 2010.

 

     Three Months Ended March 31,  
     2011      2010      Change     % Change  
     (Dollars In Thousands)  

Gross margin

   $ 315,485       $ 298,876       $ 16,609        5.6   

Add: SPP network transmission costs

     32,051         27,154         4,897        18.0   

Less: Operating and maintenance expense

     137,351         121,172         16,179        13.4   

Depreciation and amortization expense

     70,259         66,930         3,329        5.0   

Selling, general and administrative expense

     48,767         45,927         2,840        6.2   
                            

Income from operations

   $ 91,159       $ 92,001       $ (842     (0.9
                            

Operating Expenses

 

     Three Months Ended March 31,  
     2011      2010      Change      % Change  
     (Dollars in Thousands)  

Operating and maintenance expense

   $ 137,351       $ 121,172       $ 16,179         13.4   

Operating and maintenance expense increased due primarily to higher SPP network transmission costs of $4.9 million, which were offset by higher SPP network transmission revenues of $3.8 million, higher power plant maintenance costs of $4.2 million and higher maintenance costs of $1.6 million for our electrical distribution system. Also contributing to the increase was a $1.4 million increase in operating costs at Wolf Creek related primarily to higher regulatory compliance costs and a $0.8 million increase in property taxes, which is offset in retail revenues. The increase in power plant maintenance costs was due primarily to planned maintenance outages at two of our power plants during the three months ended March 31, 2011, as well as higher maintenance costs at Wolf Creek. Additional tree trimming and other line clearance activities during the three months ended March 31, 2011, were the primary contributors to the higher maintenance costs for our electrical distribution system.

 

     Three Months Ended March 31,  
     2011      2010      Change      % Change  
     (Dollars in Thousands)  

Depreciation and amortization expense

   $ 70,259       $ 66,930       $ 3,329         5.0   

Depreciation and amortization expense increased due primarily to the addition of transmission facilities and additions to our power plants.

 

     Three Months Ended March 31,  
     2011      2010      Change      % Change  
     (Dollars in Thousands)  

Selling, general and administrative expense

   $ 48,767       $ 45,927       $ 2,840         6.2   

Selling, general and administrative expense increased due principally to higher legal fees of $1.7 million related primarily to the arbitration proceedings discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings,” and the amortization of $0.9 million of previously deferred amounts associated with various energy efficiency programs.

 

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FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of March 31, 2011, compared to December 31, 2010.

Inventory and supplies increased $13.8 million due primarily to a 12% increase in the volume of coal resulting from outages at our power plants and a 10% increase in the delivered cost of coal.

Current deferred tax assets decreased $10.1 million and other current liabilities decreased $19.4 million due primarily to the payment of non-union, non-executive, at-risk employee compensation related to 2010 compensation metrics. This compensation is payable only in the event we meet pre-established operating and financial objectives.

Short-term debt increased $78.6 million due principally to increased borrowings under Westar Energy’s revolving credit facility. We used borrowings under the revolving credit facility to fund our capital and on-going operating needs.

Non-current deferred income taxes increased $12.0 million due primarily to plant-related deferred taxes.

Accrued employee benefits decreased $28.9 million due principally to our having made a $29.0 million payment to our pension trust.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy’s 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 borrowings under the revolving credit facilities. To meet the cash requirements for our capital investments, we expect to use internally generated cash, borrowings under the revolving credit facilities and the issuance of debt and equity securities in the capital markets. We also use proceeds from the issuance of securities to repay borrowings under the revolving credit facilities, with such borrowed amounts principally related to investments in capital equipment, and for working capital and general corporate purposes. The aforementioned sources and uses of cash are similar to our historical activities. 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.

Capital Resources

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million, respectively. As of April 27, 2011, $346.0 million had been borrowed and an additional $23.1 million of 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. We anticipate refinancing the $730.0 million revolving credit facility later this year.

Common Stock Issuance

On February 15, 2011, Westar Energy delivered approximately 1.1 million shares of common stock and received proceeds of $25.8 million as partial settlement of the forward sale agreement entered into with a bank in April 2010. Assuming physical share settlement of the approximately 3.1 million remaining shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $68.5 million, net of commission, based on an average forward price of $21.86 per share.

 

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During the three months ended March 31, 2011, Westar Energy did not deliver any shares of common stock under the forward sale agreement entered into with a bank in November 2010. Assuming physical share settlement of the approximately 8.5 million shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $203.4 million, net of commission, based on an average forward price of $23.98 per share.

Cash Flows from Operating Activities

Operating activities provided $95.4 million of cash in the three months ended March 31, 2011, compared to cash provided of $152.0 million during the same period of 2010. Principal contributors to the decrease include our having contributed $24.8 million more to the Westar Energy pension trust, Westar Energy post-retirement benefit plan and Wolf Creek pension trust, and our having paid $40.4 million more for fuel and purchased power, which was the result of our having purchased significantly more power during the three months ended March 31, 2011, due primarily to planned maintenance outages at some of our power plants.

Cash Flows used in Investing Activities

Investing activities used $152.1 million of cash in the three months ended March 31, 2011, compared to $102.8 million during the same period of 2010. We spent $155.9 million in the three months ended March 31, 2011, and $103.3 million in the same period of 2010 on additions to property, plant and equipment.

Cash Flows from (used in) Financing Activities

Financing activities provided $59.1 million of cash in the three months ended March 31, 2011, compared to $50.2 million of cash used in financing activities in the same period of 2010. The increase in cash provided from financing activities was due primarily to our having borrowed $78.6 million under Westar Energy’s revolving credit facility during the three months ended March 31, 2011, compared to our having repaid $33.6 million of borrowings under the credit facility during the same period last year. We used borrowings under the revolving credit facility to fund our capital and on-going operating needs.

Debt Covenants

We remain in compliance with the debt covenants described in our 2010 Form 10-K.

Credit Ratings

Moody’s Investors Service (Moody’s), Standard & Poor’s Ratings Group (S&P) and Fitch Investors Service (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, less favorable credit ratings make borrowing more difficult and costly. Under Westar Energy’s revolving credit facilities our cost of borrowing is determined in part by credit ratings. However, Westar Energy’s ability to borrow under the revolving credit facilities is 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.

 

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As of April 27, 2011, 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
Unsecured
Debt
   Rating
Outlook

Moody’s

   Baa1    Baa1    Baa3    Positive

S&P

     BBB+      BBB+    BBB    Stable

Fitch

     BBB+      BBB+    BBB    Positive

Certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of March 31, 2011, and December 31, 2010, was $0.8 million and $1.6 million, respectively, for which we had posted $0.5 million of collateral, including independent amounts, as of March 31, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of March 31, 2011, and December 31, 2010, we would have been required to provide to our counterparties $0.7 million and $1.6 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Pension Contribution

During the three months ended March 31, 2011, we contributed $29.0 million to the Westar Energy pension trust and funded $5.7 million of Wolf Creek’s pension plan contribution.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2010, through March 31, 2011, our off-balance sheet arrangements did not change materially. For additional information, see our 2010 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2010, through March 31, 2011, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2010 Form 10-K.

 

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OTHER INFORMATION

Proposed Environmental Regulations

In March 2011, the EPA proposed air toxic standards, including mercury standards, under the Clean Air Act for coal and oil-fired electric generating units. The EPA is required to issue a final rule by November 2011 and the proposal provides up to four years for facilities to meet the standards. We are currently evaluating the proposal. Until the final rule is issued, we cannot determine its impact on our operations or consolidated financial results, but it could be material.

Changes in Prices

KCC Proceedings

On April 11, 2011, the KCC issued an order allowing us to adjust our prices, subject to final KCC review, to include updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective April 14, 2011, and are expected to increase our annual retail revenues by $17.4 million. We expect the KCC to issue a final order on our request in the second quarter of 2011.

On March 29, 2011, we filed an application with the KCC to adjust our prices to include costs associated with environmental investments made in 2010. We expect the KCC to issue an order on our request in May 2011 and estimate that this will increase our annual retail revenues by approximately $11.0 million.

FERC Proceedings

Our transmission formula rate that includes projected 2011 transmission capital expenditures and operating costs became effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

Fair Value of Energy Marketing Contracts

The following table shows the fair value of energy marketing contracts outstanding as of March 31, 2011.

 

     Fair Value of Contracts  
     (In Thousands)  

Net fair value of contracts outstanding as of December 31, 2010 (a)

   $ 12,797   

Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period

     (614

Changes in fair value of contracts outstanding at the beginning and end of the period

     (329

Fair value of new contracts entered into during the period

     361   
        

Fair value of contracts outstanding as of March 31, 2011 (b)

   $ 12,215   
        

 

  

(a)    Approximately $7.8 million of the fair value of energy marketing contracts was recognized as a regulatory liability.

       

(b)    Approximately $7.6 million of the fair value of energy marketing contracts were recognized as a regulatory liability.

       

 

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The sources of the fair values of the financial instruments related to these contracts and the maturity periods of the contracts as of March 31, 2011, are summarized in the following table.

 

     Fair Value of Contracts at End of Period  

Sources of Fair Value

   Total
Fair  Value
    Maturity
Less  Than
1 Year
     Maturity
1-3  Years
    Maturity
4-5  Years
    Maturity
Over 5  Years
 
     (Dollars In Thousands)  

Prices provided by other external sources (swaps and forwards)

   $ 12,494      $ 3,133       $ 7,663      $ 1,698      $ —     

Prices based on option pricing models (options and other) (a)

     (279     18         (211     (86     —     
                                         

Total fair value of contracts outstanding

   $ 12,215      $ 3,151       $ 7,452      $ 1,612      $ —     
                                         

 

(a) Options are priced using a series of techniques, such as the Black option pricing model.

 

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, 2010, to March 31, 2011, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2010 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 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission 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 Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting during the three months ended March 31, 2011, 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 other legal proceedings is set forth in Notes 5, 8 and 9 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

Our risk factors did not change materially from December 31, 2010, through March 31, 2011. For additional information, see our 2010 Form 10-K.

 

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

None

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

 

ITEM 4. REMOVED AND RESERVED

 

ITEM 5. OTHER INFORMATION

None

 

ITEM 6. EXHIBITS

 

4(a)   Fifty-Sixth Supplemental Indenture, dated as of February 18, 2011, by and among Kansas Gas and Electric Company, The Bank of New York Mellon Trust Company, N.A. and Richard Tarnas (filed as Exhibit 4.1 to the Form 8-K filed on February 22, 2011)
10(a)   Credit Agreement dated as of February 18, 2011, among Westar Energy, Inc., and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10.1 to the Form 8-K filed on February 22, 2011)
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, 2011
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, 2011
32   Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended March 31, 2011 (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, 2011

    By:   

/s/ Mark A. Ruelle

         Mark A. Ruelle,
        

Executive Vice President and

Chief Financial Officer

 

41