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Form 8-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

Current Report

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):

September 27, 2016

 

 

 

Commission

File Number

 

Exact Name of Registrant as Specified in its Charter,

State of Incorporation,

Address of Principal Executive Offices and

Telephone Number

 

I.R.S. Employer
Identification No.

001-32206   GREAT PLAINS ENERGY INCORPORATED   43-1916803

(A Missouri Corporation)

1200 Main Street

Kansas City, Missouri 64105

(816) 556-2200

 

 

NOT APPLICABLE

(Former name or former address,

if changed since last report)

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 


Item 9.01. Financial Statements and Exhibits.

(a) Financial Statements of Businesses Acquired.

The audited consolidated financial statements and related financial statement schedule as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013, of Westar Energy, Inc. and the related Report of Independent Registered Public Accounting Firm included in its Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 24, 2016, are attached hereto as Exhibit 99.1.

The unaudited condensed consolidated financial statements as of March 31, 2016 and 2015, and for the three-month period ended March 31, 2016 and 2015, of Westar Energy, Inc. included in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed on May 3, 2016, are attached hereto as Exhibits 99.2.

The unaudited condensed consolidated financial statements as of June 30, 2016 and 2015, and for the three-month and six-month periods ended June 30, 2016 and 2015, of Westar Energy, Inc. included in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, filed on August 2, 2016, are attached hereto as Exhibits 99.3.

(b) Pro Forma Financial Information.

Unaudited pro forma condensed combined financial information as of June 30, 2016 and for the six-month period ended June 30, 2016 and the year ended December 31, 2015 giving effect to certain pro forma events relating to Great Plains Energy Incorporated’s pending acquisition of Westar Energy, Inc., is attached hereto as Exhibit 99.4.

(d) Exhibits.

 

Exhibit No.

  

Description

23.1    Consent of Deloitte & Touche LLP.
99.1   

Audited consolidated financial statements and related financial statement schedule as of

December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013, of Westar Energy, Inc. and the related Report of Independent Registered Public Accounting Firm.

99.2    Unaudited condensed consolidated financial statements as of March 31, 2016, and for the three months ended March 31, 2016 and 2015, of Westar Energy, Inc.
99.3    Unaudited condensed consolidated financial statements as of June 30, 2016, and for the three months and six months ended June 30, 2016 and 2015, of Westar Energy, Inc.
99.4    Unaudited pro forma condensed combined financial information.


SIGNATURES

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 hereunto duly authorized.

 

      GREAT PLAINS ENERGY INCORPORATED
Date: September 27, 2016      

/s/ Lori A. Wright

      Lori A. Wright
      Vice President – Corporate Planning, Investor Relations and Treasurer


EXHIBIT INDEX

 

Exhibit No.

  

Description

23.1    Consent of Deloitte & Touche LLP.
99.1   

Audited consolidated financial statements and related financial statement schedule as of

December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 of Westar Energy, Inc. and the related Report of Independent Registered Public Accounting Firm.

99.2    Unaudited condensed consolidated financial statements as of March 31, 2016 and for the three months ended March 31, 2016 and 2015 of Westar Energy, Inc.
99.3    Unaudited condensed consolidated financial statements as of June 30, 2016 and 2015, and for the three months ended June 30, 2016 and 2015 of Westar Energy, Inc.
99.4    Unaudited pro forma condensed combined consolidated financial information.
EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-202692 on Form S-3 of our report dated February 24, 2016 relating to the consolidated financial statements and financial statement schedule of Westar Energy, Inc. and subsidiaries, appearing in this Current Report on Form 8-K of Great Plains Energy Incorporated dated September 27, 2016.

/s/ DELOITTE & TOUCHE LLP

Kansas City, Missouri

September 27, 2016

EX-99.1

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Westar Energy, Inc.

Topeka, Kansas

We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Kansas City, Missouri

February 24, 2016

 

1


WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

 

     As of December 31,  
     2015      2014  
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 3,231       $ 4,556   

Accounts receivable, net of allowance for doubtful accounts of $5,294 and $5,309, respectively

     258,286         267,327   

Fuel inventory and supplies

     301,294         247,406   

Prepaid expenses

     16,864         15,793   

Regulatory assets

     109,606         105,549   

Other

     27,860         28,772   
  

 

 

    

 

 

 

Total Current Assets

     717,141         669,403   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT, NET

     8,524,902         8,162,908   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET

     268,239         278,573   
  

 

 

    

 

 

 

OTHER ASSETS:

     

Regulatory assets

     751,312         754,229   

Nuclear decommissioning trust

     184,057         185,016   

Other

     260,015         238,777   
  

 

 

    

 

 

 

Total Other Assets

     1,195,384         1,178,022   
  

 

 

    

 

 

 

TOTAL ASSETS

   $ 10,705,666       $ 10,288,906   
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

CURRENT LIABILITIES:

     

Current maturities of long-term debt of variable interest entities

   $ 28,309       $ 27,933   

Short-term debt

     250,300         257,600   

Accounts payable

     220,969         219,351   

Accrued dividends

     49,829         44,971   

Accrued taxes

     83,773         74,356   

Accrued interest

     71,426         79,707   

Regulatory liabilities

     25,697         55,142   

Other

     106,632         90,571   
  

 

 

    

 

 

 

Total Current Liabilities

     836,935         849,631   
  

 

 

    

 

 

 

LONG-TERM LIABILITIES:

     

Long-term debt, net

     3,163,950         3,187,080   

Long-term debt of variable interest entities, net

     138,097         166,565   

Deferred income taxes

     1,591,430         1,445,851   

Unamortized investment tax credits

     209,763         211,040   

Regulatory liabilities

     267,114         288,343   

Accrued employee benefits

     462,304         532,622   

Asset retirement obligations

     275,285         230,668   

Other

     88,825         75,799   
  

 

 

    

 

 

 

Total Long-Term Liabilities

     6,196,768         6,137,968   
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (See Notes 3, 13 and 15)

     

EQUITY:

     

Westar Energy, Inc. Shareholders’ Equity:

     

Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,353,426 shares and 131,687,454 shares, respective to each date

     706,767         658,437   

Paid-in capital

     2,004,124         1,781,120   

Retained earnings

     945,830         855,299   
  

 

 

    

 

 

 

Total Westar Energy, Inc. Shareholders’ Equity

     3,656,721         3,294,856   

Noncontrolling Interests

     15,242         6,451   
  

 

 

    

 

 

 

Total Equity

     3,671,963         3,301,307   
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 10,705,666       $ 10,288,906   
  

 

 

    

 

 

 

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

 

2


WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

 

     Year Ended December 31,  
     2015     2014     2013  

REVENUES

   $ 2,459,164      $ 2,601,703      $ 2,370,654   
  

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

      

Fuel and purchased power

     561,065        705,450        634,797   

SPP network transmission costs

     229,043        218,924        178,604   

Operating and maintenance

     330,289        367,188        359,060   

Depreciation and amortization

     310,591        286,442        272,593   

Selling, general and administrative

     250,278        250,439        224,133   

Taxes other than income tax

     156,901        140,302        122,282   
  

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     1,838,167        1,968,745        1,791,469   
  

 

 

   

 

 

   

 

 

 

INCOME FROM OPERATIONS

     620,997        632,958        579,185   
  

 

 

   

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

      

Investment earnings

     7,799        10,622        10,056   

Other income

     19,438        31,522        35,609   

Other expense

     (17,636     (18,389     (18,099
  

 

 

   

 

 

   

 

 

 

Total Other Income

     9,601        23,755        27,566   
  

 

 

   

 

 

   

 

 

 

Interest expense

     176,802        183,118        182,167   
  

 

 

   

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     453,796        473,595        424,584   

Income tax expense

     152,000        151,270        123,721   
  

 

 

   

 

 

   

 

 

 

NET INCOME

     301,796        322,325        300,863   

Less: Net income attributable to noncontrolling interests

     9,867        9,066        8,343   
  

 

 

   

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.

   $ 291,929      $ 313,259      $ 292,520   
  

 

 

   

 

 

   

 

 

 

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

      

Basic earnings per common share

   $ 2.11      $ 2.40      $ 2.29   

Diluted earnings per common share

   $ 2.09      $ 2.35      $ 2.27   

AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING

     137,957,515        130,014,941        127,462,994   

DIVIDENDS DECLARED PER COMMON SHARE

   $ 1.44      $ 1.40      $ 1.36   

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

 

3


WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

 

     Year Ended December 31,  
     2015     2014     2013  

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

      

Net income

   $ 301,796      $ 322,325      $ 300,863   

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

      

Depreciation and amortization

     310,591        286,442        272,593   

Amortization of nuclear fuel

     26,974        26,051        22,690   

Amortization of deferred regulatory gain from sale leaseback

     (5,495     (5,495     (5,495

Amortization of corporate-owned life insurance

     19,850        20,202        15,149   

Non-cash compensation

     8,345        7,280        8,188   

Net deferred income taxes and credits

     151,332        151,451        123,307   

Stock-based compensation excess tax benefits

     (1,307     (875     (576

Allowance for equity funds used during construction

     (2,075     (17,029     (14,143

Changes in working capital items:

      

Accounts receivable

     9,042        (17,291     (24,649

Fuel inventory and supplies

     (53,263     (8,773     10,124   

Prepaid expenses and other

     (23,145     36,717        (12,316

Accounts payable

     6,636        6,189        7,856   

Accrued taxes

     13,073        6,596        14,218   

Other current liabilities

     (80,396     (31,624     (52,829

Changes in other assets

     2,199        6,378        (4,167

Changes in other liabilities

     30,386        35,811        41,990   
  

 

 

   

 

 

   

 

 

 

Cash Flows from Operating Activities

     714,543        824,355        702,803   
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

      

Additions to property, plant and equipment

     (700,228     (852,052     (780,098

Purchase of securities - trusts

     (37,557     (9,075     (66,668

Sale of securities - trusts

     37,930        11,125        81,994   

Investment in corporate-owned life insurance

     (14,845     (16,250     (17,724

Proceeds from investment in corporate-owned life insurance

     66,794        43,234        147,658   

Proceeds from federal grant

     —          —          876   

Investment in affiliated company

     (575     (8,000     (4,947

Other investing activities

     (1,223     (7,730     (2,992
  

 

 

   

 

 

   

 

 

 

Cash Flows used in Investing Activities

     (649,704     (838,748     (641,901
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

      

Short-term debt, net

     (7,300     122,406        (205,241

Proceeds from long-term debt

     543,881        417,943        492,347   

Retirements of long-term debt

     (635,891     (427,500     (100,000

Retirements of long-term debt of variable interest entities

     (27,933     (27,479     (25,942

Repayment of capital leases

     (2,591     (3,340     (2,995

Borrowings against cash surrender value of corporate-owned life insurance

     59,431        59,766        59,565   

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

     (64,593     (41,249     (145,418

Stock-based compensation excess tax benefits

     1,307        875        576   

Issuance of common stock

     257,998        87,669        32,906   

Distributions to shareholders of noncontrolling interests

     (1,076     (1,030     (2,419

Cash dividends paid

     (186,120     (171,507     (162,904

Other financing activities

     (3,277     (2,092     (2,719
  

 

 

   

 

 

   

 

 

 

Cash Flows (used in) from Financing Activities

     (66,164     14,462        (62,244
  

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     (1,325     69        (1,342

CASH AND CASH EQUIVALENTS:

      

Beginning of period

     4,556        4,487        5,829   
  

 

 

   

 

 

   

 

 

 

End of period

   $ 3,231      $ 4,556      $ 4,487   
  

 

 

   

 

 

   

 

 

 

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

 

4


WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

 

     Westar Energy, Inc. Shareholders              
     Common stock
shares
     Common
stock
     Paid-in
capital
    Retained
earnings
    Non-controlling
interests
    Total
equity
 

Balance as of December 31, 2012

     126,503,748       $ 632,519       $ 1,656,972      $ 606,649      $ 14,115      $ 2,910,255   

Net income

     —           —           —          292,520        8,343        300,863   

Issuance of stock

     1,256,391         6,282         26,624        —          —          32,906   

Issuance of stock for compensation and reinvested dividends

     494,090         2,470         7,171        —          —          9,641   

Tax withholding related to stock compensation

     —           —           (2,719     —          —          (2,719

Dividends declared on common stock ($1.36 per share)

     —           —           —          (174,393     —          (174,393

Stock compensation expense

     —           —           8,103        —          —          8,103   

Tax benefit on stock compensation

     —           —           576        —          —          576   

Deconsolidation of noncontrolling interests

     —           —           —          —          (14,282     (14,282

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (2,419     (2,419
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2013

     128,254,229         641,271         1,696,727        724,776        5,757        3,068,531   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     —           —           —          313,259        9,066        322,325   

Issuance of stock

     3,026,239         15,131         72,538        —          —          87,669   

Issuance of stock for compensation and reinvested dividends

     406,986         2,035         7,120        —          —          9,155   

Tax withholding related to stock compensation

     —           —           (2,092     —          —          (2,092

Dividends declared on common stock ($1.40 per share)

     —           —           —          (182,736     —          (182,736

Stock compensation expense

     —           —           7,193        —          —          7,193   

Tax benefit on stock compensation

     —           —           875        —          —          875   

Deconsolidation of noncontrolling interests

     —           —           —          —          (7,342     (7,342

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (1,030     (1,030

Other

     —           —           (1,241     —          —          (1,241
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2014

     131,687,454         658,437         1,781,120        855,299        6,451        3,301,307   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     —           —           —          291,929        9,867        301,796   

Issuance of stock

     9,249,986         46,250         211,748        —          —          257,998   

Issuance of stock for compensation and reinvested dividends

     415,986         2,080         8,373        —          —          10,453   

Tax withholding related to stock compensation

     —           —           (3,277     —          —          (3,277

Dividends declared on common stock ($1.44 per share)

     —           —           —          (201,398     —          (201,398

Stock compensation expense

     —           —           8,250        —          —          8,250   

Tax benefit on stock compensation

     —           —           1,307        —          —          1,307   

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (1,076     (1,076

Other

     —           —           (3,397     —          —          (3,397
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2015

     141,353,426       $ 706,767       $ 2,004,124      $ 945,830      $ 15,242      $ 3,671,963   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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

 

5


WESTAR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K 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 700,000 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 consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.

Use of Management’s Estimates

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

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 3, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

 

6


Fuel Inventory and Supplies

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

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Fuel inventory

   $ 113,438       $ 70,416   

Supplies

     187,856         176,990   
  

 

 

    

 

 

 

Fuel inventory and supplies

   $ 301,294       $ 247,406   
  

 

 

    

 

 

 

Property, Plant and Equipment

We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). 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:

 

     Year Ended December 31,  
     2015     2014     2013  
     (Dollars In Thousands)  

Borrowed funds

   $ 3,505        12,044        11,706   

Equity funds

     2,075        17,029        14,143   
  

 

 

   

 

 

   

 

 

 

Total

   $ 5,580      $ 29,073      $ 25,849   
  

 

 

   

 

 

   

 

 

 

Average AFUDC Rates

     2.7     6.7     4.8

We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.

Depreciation

We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.5% in 2015, 2.4% in 2014 and 2.5% in 2013.

Depreciable lives of property, plant and equipment are as follows.

 

     Years  

Fossil fuel generating facilities

     6       to      78   

Nuclear fuel generating facility

     55       to      71   

Wind generating facilities

     19       to      20   

Transmission facilities

     15       to      75   

Distribution facilities

     22       to      68   

Other

     5       to      30   

 

7


Nuclear Fuel

We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $59.1 million as of December 31, 2015, and $72.3 million as of December 31, 2014. The cost of nuclear fuel charged to fuel and purchased power expense was $27.3 million in 2015, $27.3 million in 2014 and $26.5 million in 2013.

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Cash surrender value of policies

   $ 1,299,408       $ 1,306,777   

Borrowings against policies

     (1,168,794      (1,173,956
  

 

 

    

 

 

 

Corporate-owned life insurance, net

   $ 130,614       $ 132,821   
  

 

 

    

 

 

 

We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.

Revenue Recognition

We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $66.0 million as of December 31, 2015, and $61.0 million as of December 31, 2014.

Allowance for Doubtful Accounts

We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management’s judgment.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.

We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.

 

8


The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, “Taxes,” for additional detail on our accounting for income taxes.

Sales Tax

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.

Earnings Per Share

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

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

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

 

     Year Ended December 31,  
     2015      2014      2013  
     (Dollars In Thousands, Except Per Share Amounts)  

Net income

   $ 301,796       $ 322,325       $ 300,863   

Less: Net income attributable to noncontrolling interests

     9,867         9,066         8,343   
  

 

 

    

 

 

    

 

 

 

Net income attributable to Westar Energy, Inc.

     291,929         313,259         292,520   

Less: Net income allocated to RSUs

     646         790         810   
  

 

 

    

 

 

    

 

 

 

Net income allocated to common stock

   $ 291,283       $ 312,469       $ 291,710   
  

 

 

    

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – basic

     137,957,515         130,014,941         127,462,994   

Effect of dilutive securities:

        

RSUs

     299,198         181,397         17,195   

Forward sale agreements

     1,021,510         2,628,187         818,505   
  

 

 

    

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – diluted (a)

     139,278,223         132,824,525         128,298,694   
  

 

 

    

 

 

    

 

 

 

Earnings per common share, basic

   $ 2.11       $ 2.40       $ 2.29   

Earnings per common share, diluted

   $ 2.09       $ 2.35       $ 2.27   

 

(a) For the years ended December 31, 2015, 2014 and 2013, we had no antidilutive securities.

 

9


Supplemental Cash Flow Information

 

     Year Ended December 31,  
     2015      2014      2013  
     (In Thousands)  

CASH PAID FOR (RECEIVED FROM):

        

Interest on financing activities, net of amount capitalized

   $ 161,484       $ 160,292       $ 148,691   

Interest on financing activities of VIEs

     10,430         12,183         13,892   

Income taxes, net of refunds

     (410      458         (11

NON-CASH INVESTING TRANSACTIONS:

        

Property, plant and equipment additions

     105,169         143,192         127,544   

Property, plant and equipment of VIEs

     —           (7,342      (14,282

NON-CASH FINANCING TRANSACTIONS:

        

Issuance of stock for compensation and reinvested dividends

     10,453         9,155         9,641   

Deconsolidation of VIEs

     —           (7,342      (14,282

Assets acquired through capital leases

     3,130         8,717         334   

New Accounting Pronouncements

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

Presentation of Financial Statements

In November 2015, the FASB issued Accounting Standard Update (ASU) No. 2015-17 to simplify the presentation of deferred income taxes. This guidance requires that deferred tax liabilities and assets be classified as long-term in a classified statement of position. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to retrospectively adopt effective December 31, 2015, resulting in reducing long-term deferred income tax liabilities as of December 31, 2014, by $29.6 million previously presented as current deferred tax assets.

In April 2015, the FASB issued ASU No. 2015-03 to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, resulting in reducing long-term debt as of December 31, 2014, by $1.9 million previously presented in other current assets and $26.6 million previously presented in other long-term assets.

Extraordinary and Unusual Items

In January 2015, the FASB issued ASU No. 2015-01, which eliminates the accounting concept of extraordinary items. The objective of the new guidance is to reduce complexity in accounting standards while maintaining or improving the usefulness of information provided. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We elected to adopt effective January 1, 2015, without an impact to our financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

 

10


3. RATE MATTERS AND REGULATION

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Regulatory Assets:

     

Deferred employee benefit costs

   $ 353,785       $ 435,590   

Amounts due from customers for future income taxes, net

     144,120         153,984   

Debt reacquisition costs

     121,631         61,079   

Depreciation

     65,797         68,422   

Ad valorem tax

     44,455         39,428   

Asset retirement obligations

     31,996         26,106   

Treasury yield hedges

     25,634         26,614   

Wolf Creek outage

     16,561         11,165   

Disallowed plant costs

     15,639         15,809   

La Cygne environmental costs

     15,446         —     

Energy efficiency program costs

     7,922         8,933   

Other regulatory assets

     17,932         12,648   
  

 

 

    

 

 

 

Total regulatory assets

   $ 860,918       $ 859,778   
  

 

 

    

 

 

 

Regulatory Liabilities:

     

Deferred regulatory gain from sale leaseback

   $ 75,560       $ 81,055   

Removal costs

     53,834         88,242   

Jurisdictional allowance for funds used during construction

     32,673         33,103   

Pension and other post-retirement benefits costs

     32,181         15,473   

Nuclear decommissioning

     30,659         43,641   

La Cygne leasehold dismantling costs

     25,330         22,918   

Kansas tax credits

     12,857         12,725   

Retail energy cost adjustment

     12,686         33,274   

Purchase power agreement

     9,972         4,377   

Other regulatory liabilities

     7,059         8,677   
  

 

 

    

 

 

 

Total regulatory liabilities

   $ 292,811       $ 343,485   
  

 

 

    

 

 

 

Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

 

    Deferred employee benefit costs: Includes $319.7 million for pension and post-retirement benefit obligations and $34.1 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. The decrease from 2014 to 2015 is attributable primarily to an increase in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations and the adoption of updated mortality tables. During 2016, we will amortize to expense approximately $26.0 million of the benefit obligations and approximately $6.8 million of the excess pension expense. We are amortizing the excess pension expense over a five-year period. We do not earn a return on this asset.

 

11


    Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices. We do not earn a return on this net asset.

 

    Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.

 

    Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.

 

    Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.

 

    Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 14, “Asset Retirement Obligations.” We recover these amounts over the life of the related plant. We do not earn a return on this asset.

 

    Treasury yield hedges: Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.

 

    Wolf Creek outage: We defer the expenses associated with Wolf Creek’s scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.

 

    Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the Kansas Corporation Commission (KCC) revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.

 

    La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.

 

    Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.

 

    Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.

 

12


Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.

 

    Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne unit 2. We amortize the gain over the lease term.

 

    Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.

 

    Jurisdictional allowance for funds used during construction: This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our rates and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.

 

    Pension and other post-retirement benefits costs: Represents amount of pension and other post-retirement benefits expense recognized in setting our prices in excess of actual pension and other post-retirement benefits expense. We amortize the amount over a five-year period.

 

    Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 4, 5 and 14, “Financial Instruments and Trading Securities,” “Financial Investments” and “Asset Retirement Obligations,” respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.

 

    La Cygne leasehold dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.

 

    Kansas tax credits: This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.

 

    Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.

 

    Purchase power agreement: This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a three-year period.

 

    Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.

 

13


KCC Proceedings

General and Abbreviated Rate Reviews

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

In November 2013, the KCC issued an order in our state abbreviated rate review allowing us to adjust our prices to include additional investment in La Cygne environmental upgrades and to reflect cost reductions elsewhere. The new prices were expected to increase our annual retail revenues by approximately $30.7 million.

Environmental Costs

In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

 

    $10.8 million effective in June 2015;

 

    $11.0 million effective in June 2014; and

 

    $27.3 million effective in June 2013.

Transmission Costs

We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

 

    $7.2 million effective in April 2015;

 

    $41.0 million effective in April 2014; and

 

    $11.8 million effective in March 2013.

Property Tax Surcharge

We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

 

    $5.0 million effective in January 2016;

 

    $4.9 million effective in January 2015;

 

    $12.7 million effective in January 2014; and

 

    $15.2 million effective in January 2013.

 

14


FERC Proceedings

In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years, we posted our TFR which was expected to adjust our annual transmission revenues by approximately:

 

    $21.6 million increase effective in January 2016;

 

    $4.6 million decrease effective in January 2015;

 

    $44.3 million increase effective in January 2014; and

 

    $12.2 million increase effective in January 2013.

In August 2014, the KCC filed a complaint against us with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA). The complaint sought to lower our base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, we filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, for the year ended December 31, 2015, we recorded a liability of $13.8 million for our estimated refund obligation from the refund effective date of August 20, 2014 through December 31, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately $11.0 million on an annualized basis as a result of the reduced ROE.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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

 

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

 

    Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs.

 

    Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

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

 

15


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

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

 

     As of December 31, 2015      As of December 31, 2014  
     Carrying Value      Fair Value      Carrying Value      Fair Value  
     (In Thousands)  

Fixed-rate debt

   $ 3,080,000       $ 3,259,533       $ 3,105,000       $ 3,488,410   

Fixed-rate debt of VIEs

     166,271         179,030         194,204         213,579   

 

16


Recurring Fair Value Measurements

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

 

As of December 31, 2015

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

           

Domestic equity funds

   $ —         $ 50,872       $ 6,050       $ 56,922   

International equity funds

     —           33,595         —           33,595   

Core bond fund

     —           25,976         —           25,976   

High-yield bond fund

     —           15,288         —           15,288   

Emerging market bond fund

     —           13,584         —           13,584   

Combination debt/equity/other funds

     —           11,343         —           11,343   

Alternative investment fund

     —           —           16,439         16,439   

Real estate securities fund

     —           —           10,823         10,823   

Cash equivalents

     87         —           —           87   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     87         150,658         33,312         184,057   
  

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

           

Domestic equity funds

     —           17,876         —           17,876   

International equity fund

     —           4,430         —           4,430   

Core bond fund

     —           11,423         —           11,423   

Cash equivalents

     159         —           —           159   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     159         33,729         —           33,888   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 246       $ 184,387       $ 33,312       $ 217,945   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2014

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

           

Domestic equity funds

   $  —         $ 54,925       $ 6,047       $ 60,972   

International equity funds

     —           30,791         —           30,791   

Core bond fund

     —           19,289         —           19,289   

High-yield bond fund

     —           13,198         —           13,198   

Emerging market bond fund

     —           10,988         —           10,988   

Other fixed income fund

     —           4,779         —           4,779   

Combination debt/equity/other funds

     —           18,141         —           18,141   

Alternative investment fund

     —           —           16,970         16,970   

Real estate securities fund

     —           —           9,548         9,548   

Cash equivalents

     340         —           —           340   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     340         152,111         32,565         185,016   
  

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

           

Domestic equity funds

     —           18,698         —           18,698   

International equity fund

     —           4,252         —           4,252   

Core bond fund

     —           12,379         —           12,379   

Cash equivalents

     168         —           —           168   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     168         35,329         —           35,497   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 508       $ 187,440       $ 32,565       $ 220,513   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

17


The following table provides reconciliations of assets held in the NDT measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.

 

     Domestic
Equity
Funds
    Alternative
Investment
Fund
    Real Estate
Securities
Fund
    Net
Balance
 
     (In Thousands)  

Balance as of December 31, 2014

   $ 6,047      $ 16,970      $ 9,548      $ 32,565   

Total realized and unrealized gains and (losses) included in:

        

Regulatory liabilities

     899        (531     1,275        1,643   

Purchases

     400        —          406        806   

Sales

     (1,296     —          (406     (1,702
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2015

   $ 6,050      $ 16,439      $ 10,823      $ 33,312   
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2013

   $ 5,817      $ 15,675      $ 8,511      $ 30,003   

Total realized and unrealized gains and (losses) included in:

        

Regulatory liabilities

     391        1,295        1,037        2,723   

Purchases

     335        —          351        686   

Sales

     (496     —          (351     (847
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2014

   $ 6,047      $ 16,970      $ 9,548      $ 32,565   
  

 

 

   

 

 

   

 

 

   

 

 

 

Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the years ended December 31, 2015 and 2014, attributed to level 3 assets. See Note 3, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.

 

     Domestic
Equity
Funds
     Alternative
Investment
Fund
     Real Estate
Securities
Fund
     Net
Balance
 
     (In Thousands)  

Total unrealized gains (losses):

           

Year ended December 31, 2015

   $ (397    $ (531    $ 869       $ (59

Year ended December 31, 2014

     (105      1,296         685         1,876   

 

18


Some of our investments in the NDT and our trading securities portfolio are measured at net asset value and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.

 

     As of December 31, 2015      As of December 31, 2014     

As of December 31, 2015

     Fair Value      Unfunded
Commitments
     Fair Value      Unfunded
Commitments
    

Redemption

Frequency

  

Length of

Settlement

     (In Thousands)            

Nuclear Decommissioning Trust:

                 

Domestic equity funds

   $ 6,050       $ 1,948       $ 6,047       $ 2,348       (a)    (a)

Alternative investment fund (b)

     16,439         —           16,970         —         Quarterly    65 days

Real estate securities fund (c)

     10,823         —           9,548         —         Quarterly    80 days
  

 

 

    

 

 

    

 

 

    

 

 

       

Total Nuclear Decommissioning Trust

   $ 33,312       $ 1,948       $ 32,565       $ 2,348         
  

 

 

    

 

 

    

 

 

    

 

 

       

Trading Securities:

                 

Domestic equity funds

   $ 17,876       $ —         $ 18,698       $ —         Upon Notice    1 day

International equity funds

     4,430         —           4,252         —         Upon Notice    1 day

Core bond fund

     11,423         —           12,379         —         Upon Notice    1 day
  

 

 

    

 

 

    

 

 

    

 

 

       

Total Trading Securities

     33,729         —           35,329         —           
  

 

 

    

 

 

    

 

 

    

 

 

       

Total

   $ 67,041       $ 1,948       $ 67,894       $ 2,348         
  

 

 

    

 

 

    

 

 

    

 

 

       

 

(a) This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. This fund’s term is expected to be 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.
(b) There is a holdback on final redemptions.
(c) In January 2016, we initiated a plan to sell this investment. We expect to receive proceeds in the amount of the investment’s fair value, determined as of March 31, 2016.

Derivative Instruments

Price Risk

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

Interest Rate Risk

We have entered into numerous fixed and variable rate debt obligations. For details, see Note 9, “Long-Term Debt.” 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.

 

19


5. FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. These obligations totaled $27.4 million and $29.8 million as of December 31, 2015 and 2014, respectively. For additional information on our benefit obligations, see Note 11, “Employee Benefit Plans.”

As of December 31, 2015 and 2014, we measured the fair value of trust assets at $33.9 million and $35.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the years ended December 31, 2015, 2014 and 2013, we recorded unrealized gains of $0.4 million, $2.6 million and $6.7 million, respectively, on assets still held.

Available-for-Sale Securities

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

Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of $0.9 million in 2015. In 2014 and 2013, we realized gains on our available-for-sale securities of $0.1 million and $5.3 million, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

 

20


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

 

            Gross Unrealized               

Security Type

   Cost      Gain      Loss     Fair Value      Allocation  
            (Dollars In Thousands)               

As of December 31, 2015:

             

Domestic equity funds

   $ 49,488       $ 7,436       $ (2   $ 56,922         32

International equity funds

     33,458         1,372         (1,235     33,595         18

Core bond fund

     26,397         —           (421     25,976         14

High-yield bond fund

     17,047         —           (1,759     15,288         8

Emerging market bond fund

     16,306         —           (2,722     13,584         7

Combination debt/equity/other funds

     8,239         3,104         —          11,343         6

Alternative investment fund

     15,000         1,439         —          16,439         9

Real estate securities fund

     11,026         —           (203     10,823         6

Cash equivalents

     87         —           —          87         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 177,048       $ 13,351       $ (6,342   $ 184,057         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2014:

             

Domestic equity funds

   $ 46,126       $ 14,853       $ (7   $ 60,972         33

International equity funds

     27,521         3,683         (413     30,791         17

Core bond fund

     18,811         478         —          19,289         10

High-yield bond fund

     13,342         —           (144     13,198         7

Emerging market bond fund

     12,556         —           (1,568     10,988         6

Other fixed income fund

     4,798         —           (19     4,779         3

Combination debt/equity/other funds

     14,975         3,786         (620     18,141         10

Alternative investment fund

     15,000         1,970         —          16,970         9

Real estate securities fund

     10,619         —           (1,071     9,548         5

Cash equivalents

     340         —           —          340         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 164,088       $ 24,770       $ (3,842   $ 185,016         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

21


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

 

     Less than 12 Months     12 Months or Greater     Total  
     Fair Value      Gross
Unrealized
Losses
    Fair Value      Gross
Unrealized
Losses
    Fair Value      Gross
Unrealized
Losses
 
     (In Thousands)  

As of December 31, 2015:

               

Domestic equity funds

   $ —         $ —        $ 668       $ (2   $ 668       $ (2

International equity funds

     —           —          6,717         (1,235     6,717         (1,235

Core bond funds

     25,976         (421     —           —          25,976         (421

High-yield bond fund

     15,288         (1,759     —           —          15,288         (1,759

Emerging market bond fund

     —           —          13,584         (2,722     13,584         (2,722

Real estate securities fund

     —           —          10,823         (203     10,823         (203
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 41,264       $ (2,180   $ 31,792       $ (4,162   $ 73,056       $ (6,342
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2014:

               

Domestic equity funds

   $ —         $ —        $ 263       $ (7   $ 263       $ (7

International equity funds

     5,905         (413     —           —          5,905         (413

High-yield bond fund

     13,198         (144     —           —          13,198         (144

Emerging market bond fund

     —           —          10,988         (1,568     10,988         (1,568

Other fixed income fund

     4,779         (19     —           —          4,779         (19

Combination debt/equity/other funds

     —           —          5,892         (620     5,892         (620

Real estate securities fund

     —           —          9,548         (1,071     9,548         (1,071
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 23,882       $ (576   $ 26,691       $ (3,266   $ 50,573       $ (3,842
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

6. PROPERTY, PLANT AND EQUIPMENT

The following is a summary of our property, plant and equipment balance.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Electric plant in service

   $ 11,449,933       $ 10,620,292   

Electric plant acquisition adjustment

     802,318         802,318   

Accumulated depreciation

     (4,178,885      (4,112,483
  

 

 

    

 

 

 
     8,073,366         7,310,127   

Construction work in progress

     349,402         773,144   

Nuclear fuel, net

     68,349         79,637   

Plant to be retired, net (a)

     33,785         —     
  

 

 

    

 

 

 

Net property, plant and equipment

   $ 8,524,902       $ 8,162,908   
  

 

 

    

 

 

 

 

(a) Represents the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.

 

22


     As of December 31,  
     2015      2014  
     (In Thousands)  

Electric plant of VIEs

   $ 497,999       $ 497,999   

Accumulated depreciation of VIEs

     (229,760      (219,426
  

 

 

    

 

 

 

Net property, plant and equipment of VIEs

   $ 268,239       $ 278,573   
  

 

 

    

 

 

 

We recorded depreciation expense on property, plant and equipment of $287.9 million in 2015, $263.8 million in 2014 and $249.9 million in 2013. Approximately $9.6 million, $9.7 million and $9.7 million of depreciation expense in 2015, 2014 and 2013, respectively, was attributable to property, plant and equipment of VIEs.

7. JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of December 31, 2015, is shown in the table below.

 

Plant

   In-Service
Dates
     Investment      Accumulated
Depreciation
     Construction
Work in Progress
     Net
MW
     Ownership
Percentage
 
            (Dollars in Thousands)                

La Cygne unit 1 (a)

     June 1973       $ 602,599       $ 152,737       $ 22,461         368         50   

JEC unit 1 (a)

     July 1978         816,051         188,649         800         670         92   

JEC unit 2 (a)

     May 1980         546,955         200,286         10,112         651         92   

JEC unit 3 (a)

     May 1983         715,624         325,599         18,959         654         92   

Wolf Creek (b)

     Sept. 1985         1,880,243         817,353         72,864         551         47   

State Line (c)

     June 2001         111,451         57,828         263         196         40   
     

 

 

    

 

 

    

 

 

    

 

 

    

Total

      $ 4,672,923       $ 1,742,452       $ 125,459         3,090      
     

 

 

    

 

 

    

 

 

    

 

 

    

 

(a) Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.
(b) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
(c) Jointly owned with Empire District Electric Company.

We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 331 MW of net capacity. The VIE’s investment in the 50% interest was $392.1 million and accumulated depreciation was $201.6 million as of December 31, 2015. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 17, “Variable Interest Entities,” for additional information about VIEs.

 

23


8. SHORT-TERM DEBT

In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20.7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2014, no amounts had been borrowed and $15.6 million of letters of credit had been issued under this revolving credit facility.

In February 2014, Westar Energy extended the term of the $270.0 million revolving credit facility to February 2017, of which $20.0 million of this facility was scheduled to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. So long as there is no default under the facility, Westar Energy may increase the aggregate amount of borrowings under the facility to $400.0 million, subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2015 and 2014, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy’s revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. Westar Energy had $250.3 million and $257.6 million of commercial paper issued and outstanding as of December 31, 2015 and 2014, respectively.

In addition, total combined borrowings under Westar Energy’s commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as of December 31, 2015 and 2014, was 0.77% and 0.52%, respectively. Additional information regarding our short-term debt is as follows.

 

     Year Ended December 31,  
     2015     2014  
     (Dollars in Thousands)  

Weighted average short-term debt outstanding

   $ 350,380      $ 232,336   

Weighted daily average interest rates, excluding fees

     0.48     0.30

Our interest expense on short-term debt was $3.0 million in 2015, $2.0 million in 2014 and $2.4 million in 2013.

 

24


9. LONG-TERM DEBT

Outstanding Debt

The following table summarizes our long-term debt outstanding.

 

     As of December 31,  
     2015     2014  
     (In Thousands)  

Westar Energy

    

First mortgage bond series:

    

5.15% due 2017

   $ 125,000      $ 125,000   

8.625% due 2018

     —          300,000   

5.10% due 2020

     250,000        250,000   

3.25% due 2025

     250,000        —     

5.95% due 2035

     —          125,000   

5.875% due 2036

     —          150,000   

4.125% due 2042

     550,000        550,000   

4.10% due 2043

     430,000        430,000   

4.625% due 2043

     250,000        250,000   

4.25% due 2045

     300,000        —     
  

 

 

   

 

 

 
     2,155,000        2,180,000   
  

 

 

   

 

 

 

Pollution control bond series:

    

Variable due 2032, 0.02% as of December 31, 2015; 0.06% as of December 31, 2014

     45,000        45,000   

Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014

     30,500        30,500   
  

 

 

   

 

 

 
     75,500        75,500   
  

 

 

   

 

 

 

KGE

    

First mortgage bond series:

    

6.70% due 2019

     300,000        300,000   

6.15% due 2023

     50,000        50,000   

6.53% due 2037

     175,000        175,000   

6.64% due 2038

     100,000        100,000   

4.30% due 2044

     250,000        250,000   
  

 

 

   

 

 

 
     875,000        875,000   
  

 

 

   

 

 

 

Pollution control bond series:

    

Variable due 2027, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014

     21,940        21,940   

4.85% due 2031 (c)

     50,000        50,000   

Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014

     14,500        14,500   

Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014

     10,000        10,000   
  

 

 

   

 

 

 
     96,440        96,440   
  

 

 

   

 

 

 

Total long-term debt

     3,201,940        3,226,940   

Unamortized debt discount (a)

     (10,374     (11,401

Unamortized debt issuance expense (a)

     (27,616     (28,459
  

 

 

   

 

 

 

Long-term debt, net

   $ 3,163,950      $ 3,187,080   
  

 

 

   

 

 

 

Variable Interest Entities

    

5.92% due 2019 (b)

   $ 4,223      $ 8,413   

5.647% due 2021 (b)

     162,048        185,791   
  

 

 

   

 

 

 

Total long-term debt of variable interest entities

     166,271        194,204   

Unamortized debt premium (a)

     135        294   

Long-term debt of variable interest entities due within one year

     (28,309     (27,933
  

 

 

   

 

 

 

Long-term debt of variable interest entities, net

   $ 138,097      $ 166,565   
  

 

 

   

 

 

 

 

(a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.
(c) KGE has entered into an agreement to refund this debt in June 2016.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

 

25


The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGE first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended, is limited to a maximum of $3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2015, approximately $851.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. As of December 31, 2015, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in KGE’s mortgage.

As of December 31, 2015, we had $121.9 million of variable rate, tax-exempt bonds outstanding. While the interest rates for these bonds have been extremely low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.

In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of $162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 17, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

In November 2015, Westar Energy issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 3.25% and maturing December 2025. Concurrently, Westar Energy issued $300.0 million in principal amount of first mortgage bonds bearing stated interest at 4.25% and maturing December 2045.

Also in November 2015, Westar Energy redeemed $300.0 million in principal amount of first mortgage bonds bearing stated interest at 8.625% maturing in December 2018 for $360.9 million which included a call premium. The call premium was recorded as a regulatory asset and is being amortized over the term of the new bonds.

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

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

In July 2014, KGE issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 4.30% and maturing July 2044, the proceeds of which were used to retire Westar Energy first mortgage bonds in a principal amount of $250.0 million with a stated interest of 6.00% maturing in July 2014.

In June 2014, KGE redeemed $177.5 million in principal amount of pollution control bonds bearing stated interest rates between 5.00% and 5.30%.

In May 2014, Westar Energy issued $180.0 million in principal amount of first mortgage bonds bearing stated interest at 4.10% and maturing April 2043. These bonds constitute a further issuance of a series of bonds initially issued in March 2013 in a principal amount of $250.0 million.

Proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.

 

26


Maturities

The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.

 

Year

   Long-term debt      Long-term
debt of VIEs
 
     (In Thousands)  

2016

   $ —         $ 28,309   

2017

     125,000         26,842   

2018

     —           28,538   

2019

     300,000         31,485   

2020

     250,000         32,254   

Thereafter

     2,526,940         18,843   
  

 

 

    

 

 

 

Total maturities

   $ 3,201,940       $ 166,271   
  

 

 

    

 

 

 

Interest expense on long-term debt, net of debt AFUDC, was $152.7 million in 2015, $158.8 million in 2014 and $154.9 million in 2013. Interest expense on long-term debt of VIEs was $9.8 million in 2015, $11.4 million in 2014 and $13.0 million in 2013.

10. TAXES

Income tax expense is comprised of the following components.

 

     Year Ended December 31,  
     2015      2014      2013  
     (In Thousands)  

Income Tax Expense (Benefit):

        

Current income taxes:

        

Federal

   $ 327       $ 416       $ 135   

State

     341         (597      279   

Deferred income taxes:

        

Federal

     124,891         124,923         102,030   

State

     29,484         29,657         24,443   

Investment tax credit amortization

     (3,043      (3,129      (3,166
  

 

 

    

 

 

    

 

 

 

Income tax expense

   $ 152,000       $ 151,270       $ 123,721   
  

 

 

    

 

 

    

 

 

 

 

27


The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Deferred tax assets:

     

Tax credit carryforward (a)

   $ 266,963       $ 257,827   

Net operating loss carryforward (b)

     129,232         179,285   

Deferred employee benefit costs

     122,757         158,102   

Deferred state income taxes

     67,307         66,557   

Deferred regulatory gain on sale-leaseback

     33,287         35,706   

Deferred compensation

     27,266         29,315   

Alternative minimum tax carryforward (c)

     26,725         24,114   

Accrued liabilities

     21,115         23,048   

Disallowed costs

     10,211         10,829   

LaCygne dismantling cost

     10,018         9,064   

Capital loss carryforward (d)

     1,668         1,981   

Other

     41,319         27,689   
  

 

 

    

 

 

 

Total gross deferred tax assets

     757,868         823,517   
  

 

 

    

 

 

 

Less: Valuation allowance (e)

     1,668         1,981   
  

 

 

    

 

 

 

Deferred tax assets

   $ 756,200       $ 821,536   
  

 

 

    

 

 

 

Deferred tax liabilities:

     

Accelerated depreciation

   $ 1,787,457       $ 1,664,367   

Acquisition premium

     155,881         163,894   

Amounts due from customers for future income taxes, net

     144,120         153,984   

Deferred employee benefit costs

     122,757         158,102   

Deferred state income taxes

     59,787         59,170   

Debt reacquisition costs

     42,314         20,102   

Pension expense tracker

     12,051         14,187   

Storm costs

     —           15,713   

Other

     23,263         17,868   
  

 

 

    

 

 

 

Total deferred tax liabilities

   $ 2,347,630       $ 2,267,387   
  

 

 

    

 

 

 

Net deferred income tax liabilities

   $ 1,591,430       $ 1,445,851   
  

 

 

    

 

 

 

 

(a) Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2015), we had available federal general business tax credits of $80.9 million and state investment tax credits of $186.1 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2035. The state investment tax credits expire beginning in 2017 and ending in 2031.
(b) As of December 31, 2015, we had a federal net operating loss carryforward of $326.5 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2031 and ending in 2034.
(c) As of December 31, 2015, we had available an alternative minimum tax credit carryforward of $26.7 million, which has an unlimited carryforward period.
(d) As of December 31, 2015, we had an unused capital loss carryforward of $4.2 million that is available to offset future capital gains. The capital losses will expire in 2016.
(e) As we do not expect to realize any significant capital gains in the future, we have established a valuation allowance of $1.7 million. The total valuation allowance related to the deferred tax assets was $1.7 million as of December 31, 2015, and $2.0 million as of December 31, 2014.

 

28


In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.

Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.

 

     Year Ended December 31,  
     2015     2014     2013  

Statutory federal income tax rate

     35.0     35.0     35.0

Effect of:

      

COLI policies

     (4.4     (4.0     (5.4

State income taxes

     4.3        4.0        3.8   

Flow through depreciation for plant-related differences

     2.6        2.0        2.2   

Production tax credits

     (2.1     (2.1     (2.3

Amortization of federal investment tax credits

     (0.7     (0.7     (0.7

AFUDC equity

     (0.2     (1.3     (1.2

Capital loss utilization carryforward

     (0.1     (0.3     (1.1

Liability for unrecognized income tax benefits

     —          (0.2     0.1   

Other

     (0.9     (0.5     (1.3
  

 

 

   

 

 

   

 

 

 

Effective income tax rate

     33.5     31.9     29.1
  

 

 

   

 

 

   

 

 

 

We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2012 and forward.

The unrecognized income tax benefits decreased from $3.2 million at December 31, 2014, to $2.9 million at December 31, 2015. The decrease for unrecognized income tax benefits was largely attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement in a tax period for which the statute of limitations has closed. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:

 

     2015      2014      2013  
     (In Thousands)  

Unrecognized income tax benefits as of January 1

   $ 3,188       $ 1,703       $ 1,219   

Additions based on tax positions related to the current year

     410         872         224   

Additions for tax positions of prior years

     —           813         325   

Reductions for tax positions of prior years

     (86      (200      (65

Lapse of statute of limitations

     (611      —           —     

Settlements

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Unrecognized income tax benefits as of December 31

   $ 2,901       $ 3,188       $ 1,703   
  

 

 

    

 

 

    

 

 

 

The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $2.9 million, $3.2 million and $2.4 million (net of tax) as of December 31, 2015, 2014 and 2013, respectively.

 

29


Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2015 and 2014, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2015 or 2014.

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

11. EMPLOYEE BENEFIT PLANS

Pension and Post-Retirement Benefit Plans

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, and union employees hired after December 31, 2011, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.

The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee’s years of service. In 2014 and prior years, our retirees were covered under a health insurance policy. In January 2015, we began giving our retirees a fixed annual allowance, which provides them the flexibility to obtain health coverage in the marketplace that is tailored to their needs.

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. See Note 12, “Wolf Creek Employee Benefit Plans,” for information about Wolf Creek’s benefit plans.

 

30


The following tables summarize the status of our pension and post-retirement benefit plans.

 

     Pension Benefits     Post-retirement Benefits  

As of December 31,

   2015     2014     2015     2014  
     (In Thousands)  

Change in Benefit Obligation:

        

Benefit obligation, beginning of year

   $ 1,030,645      $ 823,780      $ 141,516      $ 133,061   

Service cost

     21,392        16,218        1,443        1,381   

Interest cost

     43,014        41,600        5,691        6,351   

Plan participants’ contributions

     —          —          582        4,232   

Benefits paid

     (44,945     (39,225     (6,549     (12,184

Actuarial (gains) losses

     (90,644     188,272        (16,399     16,509   

Amendments

     5,731        —          —          (7,834
  

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation, end of year (a)

   $ 965,193      $ 1,030,645      $ 126,284      $ 141,516   
  

 

 

   

 

 

   

 

 

   

 

 

 

Change in Plan Assets:

        

Fair value of plan assets, beginning of year

   $ 661,141      $ 609,817      $ 121,349      $ 121,766   

Actual return on plan assets

     (6,948     61,291        (208     7,189   

Employer contributions

     41,000        26,400        —          —     

Plan participants’ contributions

     —          —          534        4,074   

Benefits paid

     (41,248     (36,367     (6,259     (11,680
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets, end of year

   $ 653,945      $ 661,141      $ 115,416      $ 121,349   
  

 

 

   

 

 

   

 

 

   

 

 

 

Funded status, end of year

   $ (311,248   $ (369,504   $ (10,868   $ (20,167
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts Recognized in the Balance Sheets Consist of:

        

Current liability

   $ (2,745   $ (2,716   $ (344   $ (246

Noncurrent liability

     (308,503     (366,788     (10,524     (19,921
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount recognized

   $ (311,248   $ (369,504   $ (10,868   $ (20,167
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts Recognized in Regulatory Assets Consist of:

        

Net actuarial loss (gain)

   $ 254,085      $ 329,572      $ (12,208   $ (2,253

Prior service cost

     8,078        2,867        3,130        3,585   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount recognized

   $ 262,163      $ 332,439      $ (9,078   $ 1,332   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) As of December 31, 2015 and 2014, pension benefits include non-qualified benefit obligations of $27.4 million and $29.8 million, respectively, which are funded by a trust containing assets of $33.9 million and $35.5 million, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 4 and 5, “Financial Instruments and Trading Securities” and “Financial Investments,” respectively, for additional information regarding these amounts.

 

     Pension Benefits     Post-retirement Benefits  

As of December 31,

   2015     2014     2015     2014  
     (Dollars in Thousands)  

Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:

        

Projected benefit obligation

   $ 965,193      $ 1,030,645      $ —        $ —     

Fair value of plan assets

     653,945        661,141        —          —     

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:

        

Accumulated benefit obligation

   $ 864,263      $ 914,800        —          —     

Fair value of plan assets

     653,945        661,141        —          —     

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:

        

Accumulated post-retirement benefit obligation

     —          —        $ 126,284      $ 141,516   

Fair value of plan assets

     —          —          115,416        121,349   

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:

        

Discount rate

     4.60     4.17     4.51     4.10

Compensation rate increase

     4.00     4.00     —          —     

 

31


We use a measurement date of December 31 for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased the pension and post-retirement benefit obligations by approximately $59.6 million and $5.8 million, respectively.

We utilize actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections of life expectancies based on additional years of actual mortality experience. We adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension and post-retirement benefit obligations by approximately $27.3 million and $1.8 million, respectively.

We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.

 

     Pension Benefits     Post-retirement Benefits  

Year Ended December 31,

   2015     2014     2013     2015     2014     2013  
     (Dollars in Thousands)  

Components of Net Periodic Cost (Benefit):

            

Service cost

   $ 21,392      $ 16,218      $ 21,420      $ 1,443      $ 1,381      $ 2,028   

Interest cost

     43,014        41,600        38,520        5,691        6,351        6,007   

Expected return on plan assets

     (40,236     (36,438     (33,405     (6,614     (6,576     (6,691

Amortization of unrecognized:

            

Transition obligation, net

     —          —          —          —          —          325   

Prior service costs

     520        526        601        455        2,524        2,524   

Actuarial loss (gain), net

     32,131        19,362        33,914        379        (742     1,125   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost before regulatory adjustment

     56,821        41,268        61,050        1,354        2,938        5,318   

Regulatory adjustment (a)

     6,886        15,479        3,693        4,096        4,499        2,922   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost

   $ 63,707      $ 56,747      $ 64,743      $ 5,450      $ 7,437      $ 8,240   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

            

Current year actuarial (gain) loss

   $ (43,459   $ 162,569      $ (163,086   $ (9,576   $ 15,896      $ (30,201

Amortization of actuarial (loss) gain

     (32,379     (19,362     (33,914     (379     742        (1,125

Current year prior service cost

     5,730        —          —          —          (7,834     —     

Amortization of prior service costs

     (520     (526     (601     (455     (2,524     (2,525

Amortization of transition obligation

     —          —          —          —          —          (325

Other adjustments

     352        —          —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in regulatory assets

   $ (70,276   $ 142,681      $ (197,601   $ (10,410   $ 6,280      $ (34,176
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in net periodic cost and regulatory assets

   $ (6,569   $ 199,428      $ (132,858   $ (4,960   $ 13,717      $ (25,936
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):

            

Discount rate

     4.17     5.07     4.13     4.10     4.88     3.99

Expected long-term return on plan assets

     6.50     6.50     6.50     6.00     6.00     6.00

Compensation rate increase

     4.00     4.00     4.00     4.00     4.00     4.00

 

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

 

32


We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.

 

     Pension
Benefits
     Post-retirement
Benefits
 
     (In Thousands)  

Actuarial loss (gain)

   $ 20,559       $ (1,118

Prior service cost

     987         455   
  

 

 

    

 

 

 

Total

   $ 21,546       $ (663
  

 

 

    

 

 

 

We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

Plan Assets

We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company’s debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.

Target allocations for our pension plan assets are approximately 39% to debt securities, 39% to equity securities, 12% to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining 10% to a fund which provides tactical portfolio overlay by investing in debt and equity securities. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.

 

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Target allocations for our post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities. Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy. See Note 4, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

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

 

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The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.

 

As of December 31, 2015

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

  

Domestic equity funds

   $  —         $ 165,506       $ 25,277       $ 190,783   

International equity fund

     —           75,453         —           75,453   

Emerging market equity fund

     —           20,798         —           20,798   

Domestic bond fund

     —           105,279         —           105,279   

Core bond funds

     —           99,726         —           99,726   

High-yield bond fund

     —           28,288         —           28,288   

Emerging market bond fund

     —           23,019         —           23,019   

Combination debt/equity/other fund

     —           36,151         —           36,151   

Alternative investment funds

     —           —           39,557         39,557   

Real estate securities fund

     —           —           30,173         30,173   

Cash equivalents

     —           4,718         —           4,718   
  

 

 

       

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 558,938       $ 95,007       $ 653,945   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2014

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

  

Domestic equity funds

   $  —         $ 160,574       $ 23,996       $ 184,570   

International equity fund

     —           82,604         —           82,604   

Core bond funds

     —           224,740         —           224,740   

High-yield bond fund

     —           20,412         —           20,412   

Emerging market bond fund

     —           14,685         —           14,685   

Combination debt/equity/other fund

     —           61,632         —           61,632   

Alternative investment funds

     —           —           41,141         41,141   

Real estate securities fund

     —           —           26,439         26,439   

Cash equivalents

     —           4,918         —           4,918   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 569,565       $ 91,576       $ 661,141   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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The following table provides a reconciliation of pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.

 

     Domestic
Equity Funds
     Alternative
Investment
Funds
     Real Estate
Securities
Fund
     Total  
     (In Thousands)  

Balance as of December 31, 2014

   $ 23,996       $ 41,141       $ 26,439       $ 91,576   

Actual gain (loss) on plan assets:

           

Relating to assets still held at the reporting date

     934         (1,584      3,944         3,294   

Relating to assets sold during the period

     2,755         —           60         2,815   

Purchases, issuances and settlements, net

     (2,408      —           (270      (2,678
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2015

   $ 25,277       $ 39,557       $ 30,173       $ 95,007   
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2013

   $ 22,488       $ 39,171       $ 24,022       $ 85,681   

Actual gain (loss) on plan assets:

           

Relating to assets still held at the reporting date

     (154      1,970         2,630         4,446   

Relating to assets sold during the period

     1,365         —           29         1,394   

Purchases, issuances and settlements, net

     297         —           (242      55   
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2014

   $ 23,996       $ 41,141       $ 26,439       $ 91,576   
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.

 

As of December 31, 2015

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

     

Domestic equity funds

   $  —        $ 59,946       $  —         $ 59,946   

International equity fund

     —           14,419         —           14,419   

Core bond funds

     —           40,475         —           40,475   

Cash equivalents

     —           576         —           576   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 115,416       $ —         $ 115,416   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2014

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

     

Domestic equity funds

   $ —         $ 63,600       $ —         $ 63,600   

International equity fund

     —           14,783         —           14,783   

Core bond funds

     —           42,390         —           42,390   

Cash equivalents

     —           576         —           576   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 121,349       $ —         $ 121,349   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.

 

     Pension Benefits      Post-retirement Benefits  
     To/(From) Trust      (From)
Company Assets
     To/(From) Trust      (From)
Company Assets
 
     (In Millions)  

Expected contributions:

           

2016

   $ 28.0          $ —        

Expected benefit payments:

           

2016

   $ (54.0    $ (2.8    $ (7.4    $ (0.4

2017

     (55.0      (2.8      (7.7      (0.3

2018

     (57.4      (2.7      (7.9      (0.3

2019

     (59.3      (2.7      (8.1      (0.3

2020

     (61.4      (2.7      (8.3      (0.3

2021-2025

     (318.3      (12.6      (41.2      (1.1

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $7.7 million in 2015, $7.0 million in 2014 and $6.9 million in 2013.

Stock-Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to 8.25 million shares of common stock may be granted under the LTISA Plan. As of December 31, 2015, awards of approximately 5.0 million shares of common stock had been made under the plan.

All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to ten years. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.

 

     Year Ended December 31,  
     2015      2014      2013  
     (In Thousands)  

Compensation expense

   $ 8,250       $ 7,193       $ 8,121   

Income tax benefits related to stock-based compensation arrangements

     3,263         2,845         3,212   

We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.

 

37


RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy’s common stock, are paid on these RSUs during the vesting period.

RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2015 valuation, inputs for expected volatility ranged from 14.6% to 19.1% and the risk-free interest rate was approximately 1.0%. For the 2014 valuation, inputs for expected volatility ranged from 15.2% to 23.3% and the risk-free interest rate was approximately 0.3%. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with only service requirements was as follows.

 

     As of December 31,  
     2015      2014      2013  
     Shares     Weighted-
Average
Grant Date
Fair Value
     Shares     Weighted-
Average
Grant Date
Fair Value
     Shares     Weighted-
Average
Grant Date
Fair Value
 
     (Shares In Thousands)  

Nonvested balance, beginning of year

     342.2      $ 31.38         352.5      $ 28.38         351.1      $ 25.47   

Granted

     115.7        39.50         131.5        34.53         139.6        31.06   

Vested

     (115.4     28.77         (118.2     26.19         (125.5     23.22   

Forfeited

     (32.6     33.07         (23.6     30.00         (12.7     28.35   
  

 

 

      

 

 

      

 

 

   

Nonvested balance, end of year

     309.9        35.21         342.2        31.38         352.5        28.38   
  

 

 

      

 

 

      

 

 

   

Total unrecognized compensation cost related to RSU awards with only service requirements was $4.5 million and $4.4 million as of December 31, 2015 and 2014, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with only service requirements that vested during the years ended December 31, 2015, 2014 and 2013, was $4.7 million, $3.9 million and $3.7 million, respectively.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with performance measures was as follows.

 

     As of December 31,  
     2015      2014      2013  
     Shares     Weighted-
Average
Grant Date
Fair Value
     Shares     Weighted-
Average
Grant Date
Fair Value
     Shares     Weighted-
Average
Grant Date
Fair Value
 
     (Shares In Thousands)  

Nonvested balance, beginning of year

     345.1      $ 32.31         350.1      $ 30.35         340.1      $ 29.20   

Granted

     94.8        40.26         126.1        35.97         134.4        31.54   

Vested

     (109.0     28.99         (108.2     30.56         (112.5     28.29   

Forfeited

     (31.8     34.03         (22.9     30.70         (11.9     30.45   
  

 

 

      

 

 

      

 

 

   

Nonvested balance, end of year

     299.1        36.00         345.1        32.31         350.1        30.35   
  

 

 

      

 

 

      

 

 

   

 

38


As of December 31, 2015 and 2014, total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million and $3.8 million, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with performance measures that vested during the years ended December 31, 2015, 2014 and 2013, was $3.1 million, $0.5 million and $2.3 million, respectively.

Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 296 shares of common stock for dividends in 2015, 403 shares in 2014 and 551 shares in 2013. Participants received common stock distributions of 2,024 shares in 2015, 1,944 shares in 2014 and 3,456 shares in 2013.

Income tax benefits resulting from income tax deductions in excess of the related compensation cost recognized in the financial statements is classified as cash flows from financing activities in the consolidated statements of cash flows.

12. WOLF CREEK EMPLOYEE BENEFIT PLANS

Pension and Post-retirement Benefit Plans

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. KGE accrues its 47% share of Wolf Creek’s cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status of KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans.

 

     Pension Benefits     Post-retirement Benefits  

As of December 31,

   2015     2014     2015     2014  
     (In Thousands)  

Change in Benefit Obligation:

        

Benefit obligation, beginning of year

   $ 210,320      $ 162,820      $ 8,240      $ 10,010   

Service cost

     7,595        5,695        138        173   

Interest cost

     9,016        8,469        314        464   

Plan participants’ contributions

     —          —          934        766   

Benefits paid

     (6,217     (5,039     (1,622     (1,292

Actuarial (gains) losses

     (14,296     38,375        (211     (1,881
  

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation, end of year

   $ 206,418      $ 210,320      $ 7,793      $ 8,240   
  

 

 

   

 

 

   

 

 

   

 

 

 

Change in Plan Assets:

        

Fair value of plan assets, beginning of year

   $ 124,660      $ 114,734      $ 6      $ 17   

Actual return on plan assets

     (2,879     7,626        —          —     

Employer contributions

     5,805        7,089        787        515   

Plan participants’ contributions

     —          —          934        766   

Benefits paid

     (5,964     (4,789     (1,622     (1,292
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets, end of year

   $ 121,622      $ 124,660      $ 105      $ 6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Funded status, end of year

   $ (84,796   $ (85,660   $ (7,688   $ (8,234
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts Recognized in the Balance Sheets Consist of:

        

Current liability

   $ (247   $ (247   $ (597   $ (575

Noncurrent liability

     (84,549     (85,413     (7,091     (7,659
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount recognized

   $ (84,796   $ (85,660   $ (7,688   $ (8,234
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts Recognized in Regulatory Assets Consist of:

        

Net actuarial loss (gain)

   $ 56,747      $ 65,049      $ (184   $ 29   

Prior service cost

     501        559        —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount recognized

   $ 57,248      $ 65,608      $ (184   $ 29   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Pension Benefits     Post-retirement Benefits  

As of December 31,

   2015     2014     2015     2014  
     (Dollars in Thousands)  

Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:

        

Projected benefit obligation

   $ 206,418      $ 210,320      $ —        $ —     

Fair value of plan assets

     121,622        124,660        —          —     

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:

        

Accumulated benefit obligation

   $ 180,718      $ 179,228      $ —        $ —     

Fair value of plan assets

     121,622        124,660        —          —     

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:

        

Accumulated post-retirement benefit obligation

   $ —        $ —        $ 7,793      $ 8,240   

Fair value of plan assets

     —          —          105        6   

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:

        

Discount rate

     4.61     4.20     4.27     3.89

Compensation rate increase

     4.00     4.00     —          —     

Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased Wolf Creek’s pension and post-retirement benefit obligations by approximately $12.4 million and $0.3 million, respectively.

Wolf Creek utilizes actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections of life expectancies based on additional years of actual mortality experience. Wolf Creek adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension benefit obligation by approximately $4.8 million.

 

40


The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans.

 

     Pension Benefits     Post-retirement Benefits  

Year Ended December 31,

   2015     2014     2013     2015     2014     2013  
     (Dollars in Thousands)  

Components of Net Periodic Cost (Benefit):

            

Service cost

   $ 7,595      $ 5,695      $ 6,835      $ 138      $ 173      $ 206   

Interest cost

     9,016        8,469        7,562        314        464        413   

Expected return on plan assets

     (9,044     (8,084     (7,373     —          —          —     

Amortization of unrecognized:

            

Prior service costs

     57        58        58        —          —          —     

Actuarial loss, net

     5,930        2,987        5,421        3        165        265   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost before regulatory adjustment

     13,554        9,125        12,503        455        802        884   

Regulatory adjustment (a)

     (1,485     2,328        (641     —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost

   $ 12,069      $ 11,453      $ 11,862      $ 455      $ 802      $ 884   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

            

Current year actuarial (gain) loss

   $ (2,373   $ 38,833      $ (29,911   $ (211   $ (1,881   $ (1,303

Amortization of actuarial gain

     (5,930     (2,987     (5,421     (3     (165     (265

Amortization of prior service cost

     (57     (58     (58     —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in regulatory assets

   $ (8,360   $ 35,788      $ (35,390   $ (214   $ (2,046   $ (1,568
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized in net periodic cost and regulatory assets

   $ 3,709      $ 47,241      $ (23,528   $ 241      $ (1,244   $ (684
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

            

Discount rate

     4.20     5.11     4.16     3.89     4.70     3.78

Expected long-term return on plan assets

     7.50     7.50     7.50     —          —          —     

Compensation rate increase

     4.00     4.00     4.00     —          —          —     

 

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

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.

 

     Pension
Benefits
     Post-retirement
Benefits
 
     (In Thousands)  

Actuarial loss (gain)

   $ 4,357       $ (14

Prior service cost

     55         —     
  

 

 

    

 

 

 

Total

   $ 4,412       $ (14
  

 

 

    

 

 

 

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

 

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For measurement purposes, the assumed annual health care cost growth rates were as follows.

 

     As of December 31,  
     2015     2014  

Health care cost trend rate assumed for next year

     7.0     7.0

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)

     5.0     5.0

Year that the rate reaches the ultimate trend rate

     2020        2019   

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.

 

     One-Percentage-
Point Increase
     One-Percentage-
Point Decrease
 
     (In Thousands)  

Effect on total of service and interest cost

   $ (8    $ 8   

Effect on post-retirement benefit obligation

     (95      97   

Plan Assets

Wolf Creek’s pension and post-retirement plan investment strategy is to manage assets in a prudent manner with regard to preserving principal while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

The target allocations for Wolf Creek’s pension plan assets are 31% to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies, private equity funds and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.

All of Wolf Creek’s pension plan assets are recorded at fair value using daily net asset values as reported by the trustee. However, level 3 investments in real estate funds and alternative funds are invested in underlying investments that are illiquid and require significant judgment when measuring them at fair value using market- and income-based models. Significant unobservable inputs for underlying real estate investments include estimated market discount rates, projected cash flows and estimated value into perpetuity. Alternative funds invest in a wide range of investments typically with low correlations to traditional investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. See Note 4, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

 

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The following table provides the fair value of KGE’s 47% share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.

 

As of December 31, 2015

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

  

Domestic equity funds

   $  —         $ 30,503       $ —         $ 30,503   

International equity funds

     —           37,682         —           37,682   

Core bond funds

     —           30,287         —           30,287   

Real estate securities fund

     —           6,123         6,434         12,557   

Commodities fund

     —           5,811         —           5,811   

Alternative investment fund

     —           —           4,258         4,258   

Cash equivalents

     —           524         —           524   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 110,930       $ 10,692       $ 121,622   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2014

   Level 1      Level 2      Level 3      Total  
     (In Thousands)  

Assets:

  

Domestic equity funds

   $ —         $ 31,580       $ —         $ 31,580   

International equity funds

     —           38,624         —           38,624   

Core bond funds

     —           31,854         —           31,854   

Real estate securities fund

     —           6,313         5,649         11,962   

Commodities fund

     —           5,887         —           5,887   

Alternative investment fund

     —           —           4,309         4,309   

Cash equivalents

     —           444         —           444   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ —         $ 114,702       $ 9,958       $ 124,660   
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table provides a reconciliation of KGE’s 47% share of Wolf Creek’s pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.

 

     Real Estate
Securities
Fund
     Alternative
Investment
Fund
     Total  
     (In Thousands)  

Balance as of December 31, 2014

   $ 5,649       $ 4,309       $ 9,958   

Actual gain (loss) on plan assets:

        

Relating to assets still held at the reporting date

     785         (51      734   
  

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2015

   $ 6,434       $ 4,258       $ 10,692   
  

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2013

   $ 5,094       $ 4,147       $ 9,241   

Actual gain on plan assets:

        

Relating to assets still held at the reporting date

     555         162         717   
  

 

 

    

 

 

    

 

 

 

Balance as of December 31, 2014

   $ 5,649       $ 4,309       $ 9,958   
  

 

 

    

 

 

    

 

 

 

 

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Cash Flows

The following table shows our expected cash flows for KGE’s 47% share of Wolf Creek’s pension and post-retirement benefit plans for future years.

 

Expected Cash Flows

   Pension Benefits      Post-retirement Benefits  
     To/(From) Trust      (From)
Company Assets
     To/(From) Trust      (From)
Company Assets
 
     (In Millions)  

Expected contributions:

           

2016

   $ 8.0          $ 0.6      

Expected benefit payments:

           

2016

   $ (6.0    $ (0.3    $ (1.8    $ —     

2017

     (6.9      (0.3      (2.0      —     

2018

     (7.8      (0.3      (2.3      —     

2019

     (8.7      (0.3      (2.6      —     

2020

     (9.6      (0.3      (2.9      —     

2021 - 2025

     (61.3      (1.3      (18.2      —     

Savings Plan

Wolf Creek maintains a qualified 401(k) savings plan in which most of its employees participate. Wolf Creek matches employees’ contributions in cash up to specified maximum limits. Wolf Creek’s contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. KGE’s portion of the expense associated with Wolf Creek’s matching contributions was $1.6 million in 2015, $1.4 million in 2014 and $1.4 million in 2013.

13. COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel, Purchased Power and Transmission Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2015, was as follows.

 

     Committed
Amount
 
     (In Thousands)  

2016 (a)

   $ 757,250   

2017

     13,199   

2018

     48,744   

Thereafter

     31,720   
  

 

 

 

Total amount committed

   $ 850,913   
  

 

 

 

 

(a) Significant portion related to construction commitments.

Environmental Matters

Federal Clean Air Act

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

 

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

Sulfur Dioxide and Nitrogen Oxide

Through the combustion of fossil fuels at our generating facilities, we emit SO2 and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet SO2 and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.

We are subject to the SO2 allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO2 emissions for that year. In 2015, we had adequate SO2 allowances to meet generation and we expect to have enough to cover emissions under this program in 2016.

Cross-State Air Pollution Rule

In November 2015, the EPA proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of NOx emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

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

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

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

In 2010, the EPA revised the NAAQS for SO2. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO2 emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

 

45


Greenhouse Gases

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

In October 2015, the EPA published a rule establishing new source performance standards that limit CO2 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. However, the U.S. Court of Appeals for the D.C. Circuit placed the case on an expedited review schedule with oral arguments scheduled for June 2016. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

Mercury and Air Toxics Standards

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

In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. In December 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order leaving MATS in effect while EPA develops a final cost determination. The Court anticipates this final determination to be completed prior to the MATS compliance deadline in April 2016. Based on the final MATS rule, we do not expect there to be a material impact on our operations or consolidated financial results.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

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

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

 

46


Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $34.4 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 14, “Asset Retirement Obligations,” for additional information.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization, which coordinates the operation of a multistate interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results.

Renewable Energy Standard

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

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately $360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

 

47


We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $2.8 million in 2015, $2.8 million in 2014 and $2.9 million in 2013. We record our investment in the NDT fund at fair value, which approximated $184.1 million and $185.0 million as of December 31, 2015 and 2014, respectively.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek paid into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. In November 2013, a federal court of appeals ruled that the DOE must stop collecting this fee effective May 2014. Our share of the fee, calculated as one tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014 and $3.0 million in 2013. We included these costs in fuel and purchased power expense on our consolidated statements of income.

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

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Nuclear Insurance

We maintain nuclear liability, property and business interruption insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of $3.2 billion plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and business interruption insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within 12 months from the date of the first act. In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which has been reauthorized through December 2025 by the Energy Policy Act of 2005, we are required to insure against public liability claims resulting from nuclear incidents to the current limit of public liability, which is approximately $13.5 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.1 billion is provided through mandatory participation in an industry-wide retrospective assessment program. In addition, Congress could impose additional revenue-raising measures to pay claims. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (our share is $59.8 million), payable at no more than $19.0 million (our share is $8.9 million) per incident per year per reactor. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018.

 

48


Nuclear Property and Business Interruption Insurance

The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $42.0 million (our share is $19.7 million).

Accidental Nuclear Outage Insurance

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.

Fuel, Purchased Power and Transmission Commitments

To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2015, our share of Wolf Creek’s nuclear fuel commitments was approximately $16.7 million for uranium concentrates expiring in 2017, $2.5 million for conversion expiring in 2017, $94.6 million for enrichment expiring in 2027 and $33.2 million for fabrication expiring in 2025.

As of December 31, 2015, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $827.8 million. The contracts are for plants that we operate and expire at various times through 2020.

As of December 31, 2015, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately $109.6 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,314 MW expiring in 2028 through 2036. Of the approximately 1,314 MW under contract, approximately 400 MW are associated with agreements pursuant to which generation providers are scheduled to deliver power beginning by early 2017. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $104.8 million in 2016 and approximately $145.0 million for the next several years thereafter.

We have acquired rights to transmit a total of 206 MW. These agreements providing transmission capacity for 206 MW expire in 2016. As of December 31, 2015, we are committed to spend approximately $7.1 million over the remaining terms of these agreements.

FERC Proceedings

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

14. ASSET RETIREMENT OBLIGATIONS

Legal Liability

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.

 

49


We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (KGE’s 47% share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.

The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Beginning ARO

   $ 230,668       $ 160,682   

Increase in nuclear decommissioning ARO liability

     —           50,683   

Increase in other ARO liabilities

     34,440         9,580   

Liabilities settled

     (1,553      (593

Accretion expense

     12,964         10,316   

Revisions in estimated cash flows

     (1,234      —     
  

 

 

    

 

 

 

Ending ARO

   $ 275,285       $ 230,668   
  

 

 

    

 

 

 

In 2015, we recorded an approximately $34.4 million increase in our ARO in response to the EPA’s published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant. See Note 13, “Commitments and Contingencies - Regulation of Coal Combustion Byproducts,” for additional information.

Wolf Creek filed a nuclear decommissioning cost study with the KCC in 2014. As a result of the study, we recorded in 2014 a $50.7 million increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek.

Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We determined that our conditional AROs include the retirement of our wind generation facilities, disposal of asbestos insulating material at our power plants, the remediation of ash disposal ponds and the disposal of PCB-contaminated oil.

We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was placed into service.

The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.”

We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. The retirement obligation for the ash landfills was determined based upon the date each landfill was originally placed in service.

PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.

Non-Legal Liability - Cost of Removal

We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2015 and 2014, we had $53.8 million and $88.2 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

 

50


15. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 3 and 13, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.

16. COMMON STOCK

General

Westar Energy’s Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2015 and 2014, Westar Energy had issued 141.4 million shares and 131.7 million shares, respectively.

Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2015 and 2014, Westar Energy issued 0.5 million shares and 0.5 million shares, respectively, through the DSPP and other stock-based plans operated under the LTISA Plan. As of December 31, 2015 and 2014, a total of 1.2 million shares and 1.6 million shares, respectively, were available under the DSPP registration statement.

Issuances

In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy’s common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013 an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under each agreement.

In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. The maximum amount that Westar Energy may offer and sell under the March 2013 master agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the sales agency financing agreement and master forward sale confirmation, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser and the bank will borrow shares of Westar Energy’s common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements.

In April 2010, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank that was terminated in March 2013. The maximum amount that Westar Energy could offer and sell under the agreements was the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Terms under these agreements were generally similar to the March 2013 agreements described above.

 

51


The following table summarizes our common stock activity pursuant to the three forward sale agreements.

 

     Year Ended December 31,  
     2015      2014      2013  

Shares that could be settled at beginning of year

     9,160,500         12,052,976         1,753,415   

Transactions entered

     —           —           11,367,673   

Transactions settled (a)

     9,160,500         2,892,476         1,068,112   
  

 

 

    

 

 

    

 

 

 

Shares that could be settled at end of year

     —           9,160,500         12,052,976   
  

 

 

    

 

 

    

 

 

 

 

(a) The shares settled during the years ended December 31, 2015, 2014 and 2013, were settled with a physical settlement amount of approximately $254.6 million, $82.9 million and $27.0 million, respectively.

The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.

Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

17. 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 and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

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

8% Interest in Jeffrey Energy Center

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

 

52


50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 9, “Long-term Debt,” for additional information.

Railcars

Under two separate agreements, we leased railcars from unrelated trusts to transport coal to some of our power plants. We consolidated the trusts as VIEs until the agreements expired in November 2014 and May 2013. As a result of deconsolidating the trusts, property, plant and equipment of VIEs, net and noncontrolling interests decreased $7.3 million in 2014 and $14.3 million in 2013.

Financial Statement Impact

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

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Assets:

     

Property, plant and equipment of variable interest entities, net

   $ 268,239       $ 278,573   

Regulatory assets (a)

     9,088         7,882   

Liabilities:

     

Current maturities of long-term debt of variable interest entities

   $ 28,309       $ 27,933   

Accrued interest (b)

     2,457         2,961   

Long-term debt of variable interest entities, net

     138,097         166,565   

 

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

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

18. LEASES

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.

 

53


Rental expense and estimated future commitments under operating leases are as follows.

 

Year Ended December 31,

   Total
Operating
Leases
 
     (In Thousands)  

Rental expense:

  

2013

   $ 16,484   

2014

     14,143   

2015

     14,035   

Future commitments:

  

2016

   $ 13,550   

2017

     11,646   

2018

     10,216   

2019

     8,815   

2020

     5,988   

Thereafter

     8,917   
  

 

 

 

Total future commitments

   $ 59,132   
  

 

 

 

Capital Leases

We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.

Assets recorded under capital leases are listed below.

 

     As of December 31,  
     2015      2014  
     (In Thousands)  

Vehicles

   $ 17,345       $ 18,820   

Computer equipment

     1,204         1,504   

Generation plant

     40,048         40,048   

Accumulated amortization

     (13,477      (11,741
  

 

 

    

 

 

 

Total capital leases

   $ 45,120       $ 48,631   
  

 

 

    

 

 

 

 

54


Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.

 

Year Ended December 31,

   Total Capital
Leases
 
     (In Thousands)  

2016

   $ 5,812   

2017

     5,386   

2018

     5,233   

2019

     4,645   

2020

     4,007   

Thereafter

     56,050   
  

 

 

 
     81,133   

Amounts representing imputed interest

     (32,271
  

 

 

 

Present value of net minimum lease payments under capital leases

     48,862   

Less: Current portion

     3,815   
  

 

 

 

Total long-term obligation under capital leases

   $ 45,047   
  

 

 

 

19. QUARTERLY RESULTS (UNAUDITED)

Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.

 

2015    First      Second      Third      Fourth  
     (In Thousands, Except Per Share Amounts)  

Revenues (a)

   $ 590,807       $ 589,563       $ 732,829       $ 545,965   

Net income (a)

     53,163         66,243         140,564         41,826   

Net income attributable to Westar Energy, Inc. (a)

     50,980         63,710         138,003         39,235   

Per Share Data (a):

           

Basic:

           

Earnings available

   $ 0.38       $ 0.47       $ 0.97       $ 0.28   

Diluted:

           

Earnings available

   $ 0.38       $ 0.46       $ 0.97       $ 0.28   

Cash dividend declared per common share

   $ 0.36       $ 0.36       $ 0.36       $ 0.36   

Market price per common share:

           

High

   $ 44.03       $ 39.65       $ 40.22       $ 43.56   

Low

   $ 36.58       $ 33.88       $ 34.17       $ 37.55   

 

(a) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

 

55


2014    First      Second      Third      Fourth  
     (In Thousands, Except Per Share Amounts)  

Revenues (a)

   $ 628,556       $ 612,668       $ 764,040       $ 596,439   

Net income (a)

     70,970         55,822         149,760         45,773   

Net income attributable to Westar Energy, Inc. (a)

     68,955         53,473         147,382         43,449   

Per Share Data (a):

           

Basic:

           

Earnings available

   $ 0.53       $ 0.41       $ 1.13       $ 0.33   

Diluted:

           

Earnings available

   $ 0.52       $ 0.40       $ 1.10       $ 0.32   

Cash dividend declared per common share

   $ 0.35       $ 0.35       $ 0.35       $ 0.35   

Market price per common share:

           

High

   $ 35.33       $ 38.24       $ 38.23       $ 43.15   

Low

   $ 31.67       $ 34.51       $ 33.76       $ 33.73   

 

(a) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

 

56


WESTAR ENERGY, INC.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

Description

   Balance at
Beginning
of Period
     Charged to
Costs and
Expenses
     Deductions (a)     Balance
at End
of Period
 
     (In Thousands)  

Year ended December 31, 2013

          

Allowances deducted from assets for doubtful accounts

   $ 4,916       $ 7,039       $ (7,359   $ 4,596   

Year ended December 31, 2014

          

Allowances deducted from assets for doubtful accounts

   $ 4,596       $ 9,752       $ (9,039   $ 5,309   

Year ended December 31, 2015

          

Allowances deducted from assets for doubtful accounts

   $ 5,309       $ 8,614       $ (8,629   $ 5,294   

 

(a) Result from write-offs of accounts receivable.

 

57

EX-99.2

Exhibit 99.2

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

 

     As of      As of  
     March 31, 2016      December 31, 2015  
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 3,471       $ 3,231   

Accounts receivable, net of allowance for doubtful accounts of $6,790 and $5,294, respectively

     225,090         258,286   

Fuel inventory and supplies

     301,340         301,294   

Prepaid expenses

     20,271         16,864   

Regulatory assets

     98,368         109,606   

Other

     27,039         27,860   
  

 

 

    

 

 

 

Total Current Assets

     675,579         717,141   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT, NET

     8,675,925         8,524,902   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET

     265,655         268,239   
  

 

 

    

 

 

 

OTHER ASSETS:

     

Regulatory assets

     746,741         751,312   

Nuclear decommissioning trust

     183,455         184,057   

Other

     258,242         260,015   
  

 

 

    

 

 

 

Total Other Assets

     1,188,438         1,195,384   
  

 

 

    

 

 

 

TOTAL ASSETS

   $ 10,805,597       $ 10,705,666   
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

CURRENT LIABILITIES:

     

Current maturities of long-term debt

   $ 125,000       $   

Current maturities of long-term debt of variable interest entities

     26,842         28,309   

Short-term debt

     316,800         250,300   

Accounts payable

     230,307         220,969   

Accrued dividends

     52,695         49,829   

Accrued taxes

     128,152         83,773   

Accrued interest

     86,222         71,426   

Regulatory liabilities

     31,461         25,697   

Other

     76,454         106,632   
  

 

 

    

 

 

 

Total Current Liabilities

     1,073,933         836,935   
  

 

 

    

 

 

 

LONG-TERM LIABILITIES:

     

Long-term debt, net

     3,039,239         3,163,950   

Long-term debt of variable interest entities, net

     111,239         138,097   

Deferred income taxes

     1,619,112         1,591,430   

Unamortized investment tax credits

     209,040         209,763   

Regulatory liabilities

     250,545         267,114   

Accrued employee benefits

     456,541         462,304   

Asset retirement obligations

     276,718         275,285   

Other

     82,025         88,825   
  

 

 

    

 

 

 

Total Long-Term Liabilities

     6,044,459         6,196,768   
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (See Notes 3, 10 and 11)

     

EQUITY:

     

Westar Energy, Inc. Shareholders’ Equity:

     

Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,628,562 shares and 141,353,426 shares, respective to each date

     708,143         706,767   

Paid-in capital

     2,003,311         2,004,124   

Retained earnings

     959,936         945,830   
  

 

 

    

 

 

 

Total Westar Energy, Inc. Shareholders’ Equity

     3,671,390         3,656,721   

Noncontrolling Interests

     15,815         15,242   
  

 

 

    

 

 

 

Total Equity

     3,687,205         3,671,963   
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 10,805,597       $ 10,705,666   
  

 

 

    

 

 

 

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

 

1


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

     Three Months Ended March 31,  
     2016     2015  

REVENUES

   $ 569,450      $ 590,807   
  

 

 

   

 

 

 

OPERATING EXPENSES:

    

Fuel and purchased power

     100,058        155,482   

SPP network transmission costs

     60,760        56,812   

Operating and maintenance

     77,757        85,080   

Depreciation and amortization

     83,640        74,586   

Selling, general and administrative

     56,456        55,418   

Taxes other than income tax

     48,968        37,871   
  

 

 

   

 

 

 

Total Operating Expenses

     427,639        465,249   
  

 

 

   

 

 

 

INCOME FROM OPERATIONS

     141,811        125,558   
  

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

    

Investment earnings

     2,016        2,480   

Other income

     9,477        2,814   

Other expense

     (5,543     (5,713
  

 

 

   

 

 

 

Total Other Income (Expense)

     5,950        (419
  

 

 

   

 

 

 

Interest expense

     40,431        44,298   
  

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     107,330        80,841   

Income tax expense

     38,622        27,678   
  

 

 

   

 

 

 

NET INCOME

     68,708        53,163   

Less: Net income attributable to noncontrolling interests

     3,123        2,183   
  

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.

   $ 65,585      $ 50,980   
  

 

 

   

 

 

 

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

    

Basic earnings per common share

   $ 0.46      $ 0.38   

Diluted earnings per common share

   $ 0.46      $ 0.38   

AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:

    

Basic

     141,992,846        132,395,497   

Diluted

     142,311,228        135,539,631   

DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.38      $ 0.36   

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

 

2


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

     Three Months Ended March 31,  
     2016     2015  

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

    

Net income

   $ 68,708      $ 53,163   

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

    

Depreciation and amortization

     83,640        74,586   

Amortization of nuclear fuel

     8,329        4,960   

Amortization of deferred regulatory gain from sale leaseback

     (1,374     (1,374

Amortization of corporate-owned life insurance

     5,261        5,747   

Non-cash compensation

     2,491        2,226   

Net deferred income taxes and credits

     33,984        26,573   

Allowance for equity funds used during construction

     (2,464     (1,950

Changes in working capital items:

    

Accounts receivable

     33,196        31,042   

Fuel inventory and supplies

     109        (18,404

Prepaid expenses and other

     7,712        4,638   

Accounts payable

     (31,158     17,321   

Accrued taxes

     49,339        40,007   

Other current liabilities

     (28,984     (20,327

Changes in other assets

     21,933        (17,034

Changes in other liabilities

     (11,846     12,394   
  

 

 

   

 

 

 

Cash Flows from Operating Activities

     238,876        213,568   
  

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

    

Additions to property, plant and equipment

     (220,849     (187,223

Purchase of securities - trusts

     (13,712     (7,345

Sale of securities - trusts

     16,332        7,847   

Proceeds from investment in corporate-owned life insurance

     23,963        1,144   

Investment in affiliated company

     (655     —     

Other investing activities

     (2,840     (717
  

 

 

   

 

 

 

Cash Flows used in Investing Activities

     (197,761     (186,294
  

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

    

Short-term debt, net

     66,500        167,800   

Proceeds from long-term debt of variable interest entities

     162,048        —     

Retirements of long-term debt

     —          (125,000

Retirements of long-term debt of variable interest entities

     (190,355     (27,925

Repayment of capital leases

     (675     (886

Borrowings against cash surrender value of corporate-owned life insurance

     963        1,045   

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

     (22,837     (899

Issuance of common stock

     657        8,206   

Distributions to shareholders of noncontrolling interests

     (2,550     (1,076

Cash dividends paid

     (49,665     (43,787

Other financing activities

     (4,961     (3,234
  

 

 

   

 

 

 

Cash Flows used in Financing Activities

     (40,875     (25,756
  

 

 

   

 

 

 

NET CHANGE IN CASH AND CASH EQUIVALENTS

     240        1,518   

CASH AND CASH EQUIVALENTS:

    

Beginning of period

     3,231        4,556   
  

 

 

   

 

 

 

End of period

   $ 3,471      $ 6,074   
  

 

 

   

 

 

 

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

 

3


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)

 

     Westar Energy, Inc. Shareholders              
     Common
stock shares
     Common
stock
     Paid-in
capital
    Retained
earnings
    Non-
controlling
interests
    Total
equity
 

Balance as of December 31, 2014

     131,687,454       $ 658,437       $ 1,781,120      $ 855,299      $ 6,451      $ 3,301,307   

Net income

     —           —           —          50,980        2,183        53,163   

Issuance of stock

     262,827         1,314         6,892        —          —          8,206   

Issuance of stock for compensation and reinvested dividends

     215,873         1,080         1,948        —          —          3,028   

Tax withholding related to stock compensation

     —           —           (3,234     —          —          (3,234

Dividends declared on common stock

($0.36 per share)

     —           —           —          (48,107     —          (48,107

Stock compensation expense

     —           —           2,205        —          —          2,205   

Tax benefit on stock compensation

     —           —           1,073        —          —          1,073   

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (1,076     (1,076

Other

     —           —           (1,217     —          —          (1,217
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of March 31, 2015

     132,166,154       $ 660,831       $ 1,788,787      $ 858,172      $ 7,558      $ 3,315,348   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2015

     141,353,426       $ 706,767       $ 2,004,124      $ 945,830      $ 15,242      $ 3,671,963   

Net income

     —           —           —          65,585        3,123        68,708   

Issuance of stock

     14,907         75         582        —          —          657   

Issuance of stock for compensation and reinvested dividends

     260,229         1,301         1,104        —          —          2,405   

Tax withholding related to stock compensation

     —           —           (4,961     —          —          (4,961

Dividends declared on common stock

($0.38 per share)

     —           —           —          (54,805     —          (54,805

Stock compensation expense

     —           —           2,462        —          —          2,462   

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (2,550     (2,550

Cumulative effect of accounting change - stock compensation

     —           —           —          3,326        —          3,326   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of March 31, 2016

     141,628,562       $ 708,143       $ 2,003,311      $ 959,936      $ 15,815      $ 3,687,205   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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

 

4


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 702,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2015 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months ended March 31, 2016, are not necessarily indicative of the results to be expected for the full year.

 

5


Fuel Inventory and Supplies

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

 

     As of      As of  
     March 31, 2016      December 31, 2015  
     (In Thousands)  

Fuel inventory

   $ 113,965       $ 113,438   

Supplies

     187,375         187,856   
  

 

 

    

 

 

 

Fuel inventory and supplies

   $ 301,340       $ 301,294   
  

 

 

    

 

 

 

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,  
     2016     2015  
     (Dollars In Thousands)  

Borrowed funds

   $ 2,008      $ 2,029   

Equity funds

     2,464        1,950   
  

 

 

   

 

 

 

Total

   $ 4,472      $ 3,979   
  

 

 

   

 

 

 

Average AFUDC Rates

     5.2     4.0

Earnings Per Share

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

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

 

6


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

 

     Three Months Ended March 31,  
     2016      2015  
    

(Dollars In Thousands, Except

Per Share Amounts)

 

Net income

   $ 68,708       $ 53,163   

Less: Net income attributable to noncontrolling interests

     3,123         2,183   
  

 

 

    

 

 

 

Net income attributable to Westar Energy, Inc.

     65,585         50,980   

Less: Net income allocated to RSUs

     135         118   
  

 

 

    

 

 

 

Net income allocated to common stock

   $ 65,450       $ 50,862   
  

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – basic

     141,992,846         132,395,497   

Effect of dilutive securities:

     

RSUs

     318,382         175,876   

Forward sale agreements

     —           2,968,258   
  

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – diluted (a)

     142,311,228         135,539,631   
  

 

 

    

 

 

 

Earnings per common share, basic

   $ 0.46       $ 0.38   

Earnings per common share, diluted

   $ 0.46       $ 0.38   

 

(a) We had no antidilutive securities for the three months ended March 31, 2016 and 2015.

Supplemental Cash Flow Information

 

     Three Months Ended March 31,  
     2016      2015  
     (In Thousands)  

CASH PAID FOR (RECEIVED FROM):

     

Interest on financing activities, net of amount capitalized

   $ 30,415       $ 38,927   

Interest on financing activities of VIEs

     4,150         5,651   

Income taxes, net of refunds

     (383      —     

NON-CASH INVESTING TRANSACTIONS:

     

Property, plant and equipment additions

     130,532         63,265   

NON-CASH FINANCING TRANSACTIONS:

     

Issuance of stock for compensation and reinvested dividends

     2,405         3,028   

Assets acquired through capital leases

     180         294   

New Accounting Pronouncements

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

 

7


Leases

In February 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-02 which requires lessees to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.

Stock-based Compensation

In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.

Under current GAAP, if the tax deduction for a stock-based payment award exceeds the compensation cost recorded for financial reporting, the additional tax benefit is recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits and expense. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities and cash flows used in financing activities on the accompanying condensed consolidated statements of cash flows for the three months ended March 31, 2015, as $1.1 million higher than as previously reported.

Financial Instruments

In May 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 4 “Financial Instruments and Trading Securities.”

3. RATE MATTERS AND REGULATION

KCC Proceedings

In December 2015, the Kansas Corporation Commission (KCC) approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million.

In March 2016, the KCC issued an order allowing us to adjust our retail prices, subject to refund, to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2016 and are expected to increase our annual retail revenues by approximately $25.3 million.

We will update our retail prices with the KCC later this year to reflect the TFR with the reduced return on equity (ROE) as described below. We estimate the annualized impact of this update on our retail revenues will be a decrease of approximately $20.0 million.

 

8


FERC Proceedings

In March 2016, the Federal Energy Regulatory Commission (FERC) approved a settlement reducing our base return on equity (ROE) used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. As of March 31, 2016, we have recorded a regulatory liability of $16.7 million for our estimated refund obligation from the refund effective date of August 20, 2014, through March 31, 2016.

In May 2016, our TFR that includes projected 2016 transmission capital expenditures and operating costs was revised to reflect the reduced ROE. The estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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

 

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

 

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

 

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

 

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

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

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

 

     As of March 31, 2016      As of December 31, 2015  
     Carrying Value      Fair Value      Carrying Value      Fair Value  
     (In Thousands)  

Fixed-rate debt

   $ 3,080,000       $ 3,386,212       $ 3,080,000       $ 3,259,533   

Fixed-rate debt of VIEs

     137,963         152,155         166,271         179,030   

 

9


Recurring Fair Value Measurements

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

 

As of March 31, 2016

   Level 1      Level 2      Level 3      NAV      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

        

Domestic equity funds

   $ —         $ 46,313       $ —         $ 5,830       $ 52,143   

International equity funds

     —           31,846         —           —           31,846   

Core bond fund

     —           24,650         —           —           24,650   

High-yield bond fund

     —           14,493         —           —           14,493   

Emerging market bond fund

     —           13,715         —           —           13,715   

Combination debt/equity/other funds

     —           11,071         —           —           11,071   

Alternative investment fund

     —           —           —           14,862         14,862   

Real estate securities fund

     —           —           —           20,649         20,649   

Cash equivalents

     26         —           —           —           26   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     26         142,088         —           41,341         183,455   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

        

Domestic equity funds

     —           17,776         —           —           17,776   

International equity fund

     —           4,321         —           —           4,321   

Core bond fund

     —           11,657         —           —           11,657   

Cash equivalents

     156         —           —           —           156   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     156         33,754         —           —           33,910   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 182       $ 175,842       $ —         $ 41,341       $ 217,365   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2015

   Level 1      Level 2      Level 3      NAV      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

        

Domestic equity funds

   $ —         $ 50,872       $ —         $ 6,050       $ 56,922   

International equity funds

     —           33,595         —           —           33,595   

Core bond fund

     —           25,976         —           —           25,976   

High-yield bond fund

     —           15,288         —           —           15,288   

Emerging market bond fund

     —           13,584         —           —           13,584   

Combination debt/equity/other funds

     —           11,343         —           —           11,343   

Alternative investment fund

     —           —           —           16,439         16,439   

Real estate securities fund

     —           —           —           10,823         10,823   

Cash equivalents

     87         —           —           —           87   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     87         150,658         —           33,312         184,057   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

        

Domestic equity funds

     —           17,876         —           —           17,876   

International equity fund

     —           4,430         —           —           4,430   

Core bond fund

     —           11,423         —           —           11,423   

Cash equivalents

     159         —           —           —           159   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     159         33,729         —           —           33,888   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 246       $ 184,387       $ —         $ 33,312       $ 217,945   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

10


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

 

     As of March 31, 2016      As of December 31, 2015      As of March 31, 2016  
     Fair Value      Unfunded
Commitments
     Fair Value      Unfunded
Commitments
     Redemption
Frequency
    Length of
Settlement
 
     (In Thousands)               

Nuclear Decommissioning Trust:

                

Domestic equity funds

   $ 5,830       $ 3,829       $ 6,050       $ 1,948         (a)        (a)   

Alternative investment fund (b)

     14,862         —           16,439         —           Quarterly        65 days   

Real estate securities fund

     20,649         —           10,823         —           Quarterly        (c)   
  

 

 

    

 

 

    

 

 

    

 

 

      

Total Nuclear Decommissioning Trust

   $ 41,341       $ 3,829       $ 33,312       $ 1,948        
  

 

 

    

 

 

    

 

 

    

 

 

      

 

(a) This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. In the first quarter of 2016, we committed to investing in a fourth fund. The terms are expected to be 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods for both the third and fourth fund.
(b) There is a holdback on final redemptions.
(c) This investment is in two real estate funds. In April 2016, we received proceeds for the first investment in the amount of the investment’s fair value as of March 31, 2016. Redemptions of the second fund are allowed on the last business day of the calendar quarter, or such other day or days as the investment manager may determine, and redemptions are granted as soon as reasonably possible with notice of at least 65 days. There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

5. FINANCIAL INVESTMENTS

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

 

11


Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of March 31, 2016, and December 31, 2015, we measured the fair value of trust assets at $33.9 million. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months ended March 31, 2016 and 2015, we recorded unrealized gains of $0.5 million and $0.7 million, respectively, on the assets still held.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of March 31, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of $1.6 million during the three months ended March 31, 2016, and a gain of $0.2 million during the three months ended March 31, 2015. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of March 31, 2016, and December 31, 2015.

 

            Gross Unrealized               

Security Type

   Cost      Gain      Loss     Fair Value      Allocation  
            (Dollars In Thousands)               

As of March 31, 2016:

             

Domestic equity funds

   $ 45,147       $ 7,099       $ (103   $ 52,143         28

International equity funds

     31,101         1,553         (808     31,846         17

Core bond fund

     24,459         191         —          24,650         13

High-yield bond fund

     15,941         —           (1,448     14,493         9

Emerging market bond fund

     15,106         —           (1,391     13,715         7

Combination debt/equity/other funds

     8,113         2,958         —          11,071         6

Alternative investment fund

     15,000         —           (138     14,862         9

Real estate securities fund

     20,636         13         —          20,649         11

Cash equivalents

     26         —           —          26         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 175,529       $ 11,814       $ (3,888   $ 183,455         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2015:

             

Domestic equity funds

   $ 49,488       $ 7,436       $ (2   $ 56,922         32

International equity funds

     33,458         1,372         (1,235     33,595         18

Core bond fund

     26,397         —           (421     25,976         14

High-yield bond fund

     17,047         —           (1,759     15,288         8

Emerging market bond fund

     16,306         —           (2,722     13,584         7

Combination debt/equity/other funds

     8,239         3,104         —          11,343         6

Alternative investment fund

     15,000         1,439         —          16,439         9

Real estate securities fund

     11,026         —           (203     10,823         6

Cash equivalents

     87         —           —          87         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 177,048       $ 13,351       $ (6,342   $ 184,057         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

12


The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of March 31, 2016, and December 31, 2015.

 

     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, 2016:

               

Domestic equity funds

   $  —         $ —        $ 668       $ (103   $ 668       $ (103

International equity funds

     —           —          6,591         (808     6,591         (808

High-yield bond fund

     14,493         (1,448     —           —          14,493         (1,448

Emerging market bond fund

     —           —          13,715         (1,391     13,715         (1,391

Alternative investments

     14,862         (138     —           —          14,862         (138
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 29,355       $ (1,586   $ 20,974       $ (2,302   $ 50,329       $ (3,888
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2015:

               

Domestic equity funds

   $ —         $ —        $ 668       $ (2   $ 668       $ (2

International equity funds

     —           —          6,717         (1,235     6,717         (1,235

Core bond funds

     25,976         (421     —           —          25,976         (421

High-yield bond fund

     15,288         (1,759     —           —          15,288         (1,759

Emerging market bond fund

     —           —          13,584         (2,722     13,584         (2,722

Real estate securities fund

     —           —          10,823         (203     10,823         (203
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 41,264       $ (2,180   $ 31,792       $ (4,162   $ 73,056       $ (6,342
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

6. DEBT FINANCING

In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of $162.1 million in outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 12, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

7. TAXES

We recorded income tax expense of $38.6 million with an effective income tax rate of 36% for the three months ended March 31, 2016, and income tax expense of $27.7 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three months ended March 31, 2016, was due primarily to an increase in income before income taxes.

As of March 31, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $2.9 million. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

As of March 31, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either March 31, 2016, or December 31, 2015.

As of March 31, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

 

13


8. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

 

     Pension Benefits      Post-retirement Benefits  

Three Months Ended March 31,

   2016      2015      2016      2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

           

Service cost

   $ 4,664       $ 5,348       $ 271       $ 361   

Interest cost

     10,959         10,753         1,393         1,422   

Expected return on plan assets

     (10,663      (10,059      (1,709      (1,654

Amortization of unrecognized:

           

Prior service costs

     246         130         114         114   

Actuarial loss (gain), net

     5,388         7,661         (280      95   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit) before regulatory adjustment

     10,594         13,833         (211      338   

Regulatory adjustment (a)

     3,306         1,797         (486      1,013   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit)

   $ 13,900       $ 15,630       $ (697    $ 1,351   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

During the three months ended March 31, 2016 and 2015, we contributed $6.8 million and $8.5 million, respectively, to the Westar Energy pension trust.

9. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

 

     Pension Benefits     Post-retirement Benefits  

Three Months Ended March 31,

   2016     2015     2016     2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

        

Service cost

   $ 1,687      $ 1,899      $ 32      $ 34   

Interest cost

     2,414        2,254        81        79   

Expected return on plan assets

     (2,431     (2,261     —          —     

Amortization of unrecognized:

        

Prior service costs

     14        14        —          —     

Actuarial loss (gain), net

     1,089        1,482        (4     1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost before regulatory adjustment

     2,773        3,388        109        114   

Regulatory adjustment (a)

     483        (304     —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic cost

   $ 3,256      $ 3,084      $ 109      $ 114   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

During the three months ended March 31, 2016 and 2015, we funded $1.6 million and $1.3 million of Wolf Creek’s pension plan contributions, respectively.

 

14


10. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Rule

In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (NOx) emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

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

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

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

In 2010, the EPA revised the NAAQS for SO2. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO2 emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. In February 2016, the EPA proposed to accept the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable. We are working with Kansas Department of Health and Environment to determine the impact of this proposed designation. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

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

 

15


In October 2015, the EPA published a rule establishing new source performance standards that limit CO2 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. However, the U.S. Court of Appeals for the D.C. Circuit placed the case on an expedited review schedule with oral arguments scheduled for June 2016. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

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

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

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

 

16


We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results. We believe any amounts we may owe would be recovered in our future prices.

Storage of Spent Nuclear Fuel

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

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

FERC Proceedings

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

11. LEGAL PROCEEDINGS

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

12. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

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

 

17


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 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 6, “Debt Financing,” for additional information.

Financial Statement Impact

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

 

     As of      As of  
     March 31, 2016      December 31, 2015  
     (In Thousands)  

Assets:

     

Property, plant and equipment of variable interest entities, net

   $ 265,655       $ 268,239   

Regulatory assets (a)

     9,428         9,088   

Liabilities:

     

Current maturities of long-term debt of variable interest entities

   $ 26,842       $ 28,309   

Accrued interest (b)

     19         2,457   

Long-term debt of variable interest entities, net

     111,239         138,097   

 

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

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

 

18

EX-99.3

Exhibit 99.3

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

 

     As of
June 30, 2016
     As of
December 31, 2015
 
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 5,213       $ 3,231   

Accounts receivable, net of allowance for doubtful accounts of $5,093 and $5,294, respectively

     298,841         258,286   

Fuel inventory and supplies

     299,465         301,294   

Prepaid expenses

     17,994         16,864   

Regulatory assets

     87,256         109,606   

Other

     33,099         27,860   
  

 

 

    

 

 

 

Total Current Assets

     741,868         717,141   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT, NET

     8,800,698         8,524,902   
  

 

 

    

 

 

 

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET

     263,072         268,239   
  

 

 

    

 

 

 

OTHER ASSETS:

     

Regulatory assets

     734,844         751,312   

Nuclear decommissioning trust

     189,179         184,057   

Other

     241,081         260,015   
  

 

 

    

 

 

 

Total Other Assets

     1,165,104         1,195,384   
  

 

 

    

 

 

 

TOTAL ASSETS

   $ 10,970,742       $ 10,705,666   
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

CURRENT LIABILITIES:

     

Current maturities of long-term debt

   $ 125,000       $ —     

Current maturities of long-term debt of variable interest entities

     26,842         28,309   

Short-term debt

     177,000         250,300   

Accounts payable

     178,374         220,969   

Accrued dividends

     52,767         49,829   

Accrued taxes

     95,084         83,773   

Accrued interest

     41,969         71,426   

Regulatory liabilities

     33,634         25,697   

Other

     90,841         106,632   
  

 

 

    

 

 

 

Total Current Liabilities

     821,511         836,935   
  

 

 

    

 

 

 

LONG-TERM LIABILITIES:

     

Long-term debt, net

     3,387,696         3,163,950   

Long-term debt of variable interest entities, net

     111,230         138,097   

Deferred income taxes

     1,655,825         1,591,430   

Unamortized investment tax credits

     208,318         209,763   

Regulatory liabilities

     247,916         267,114   

Accrued employee benefits

     455,923         462,304   

Asset retirement obligations

     280,507         275,285   

Other

     87,065         88,825   
  

 

 

    

 

 

 

Total Long-Term Liabilities

     6,434,480         6,196,768   
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (See Notes 4, 11 and 12)

     

EQUITY:

     

Westar Energy, Inc. Shareholders’ Equity:

     

Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,691,017 shares and 141,353,426 shares, respective to each date

     708,455         706,767   

Paid-in capital

     2,008,491         2,004,124   

Retained earnings

     978,187         945,830   
  

 

 

    

 

 

 

Total Westar Energy, Inc. Shareholders’ Equity

     3,695,133         3,656,721   

Noncontrolling Interests

     19,618         15,242   
  

 

 

    

 

 

 

Total Equity

     3,714,751         3,671,963   
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 10,970,742       $ 10,705,666   
  

 

 

    

 

 

 

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

 

1


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

     Three Months Ended June 30,  
     2016     2015  

REVENUES

   $ 621,448      $ 589,563   
  

 

 

   

 

 

 

OPERATING EXPENSES:

    

Fuel and purchased power

     118,630        140,080   

SPP network transmission costs

     55,227        57,352   

Operating and maintenance

     85,619        82,739   

Depreciation and amortization

     84,226        76,759   

Selling, general and administrative

     75,724        63,663   

Taxes other than income tax

     48,407        37,494   
  

 

 

   

 

 

 

Total Operating Expenses

     467,833        458,087   
  

 

 

   

 

 

 

INCOME FROM OPERATIONS

     153,615        131,476   
  

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

    

Investment earnings

     2,280        1,634   

Other income

     3,382        15,121   

Other expense

     (2,908     (2,633
  

 

 

   

 

 

 

Total Other Income

     2,754        14,122   
  

 

 

   

 

 

 

Interest expense

     39,683        45,516   
  

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     116,686        100,082   

Income tax expense

     40,542        33,839   
  

 

 

   

 

 

 

NET INCOME

     76,144        66,243   

Less: Net income attributable to noncontrolling interests

     3,804        2,533   
  

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.

   $ 72,340      $ 63,710   
  

 

 

   

 

 

 

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

    

Basic earnings per common share

   $ 0.51      $ 0.47   

Diluted earnings per common share

   $ 0.51      $ 0.46   

AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:

    

Basic

     142,033,842        135,939,197   

Diluted

     142,497,335        137,412,152   

DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.38      $ 0.36   

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

 

2


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

     Six Months Ended June 30,  
     2016     2015  

REVENUES

   $ 1,190,898      $ 1,180,370   
  

 

 

   

 

 

 

OPERATING EXPENSES:

    

Fuel and purchased power

     218,688        295,561   

SPP network transmission costs

     115,987        114,164   

Operating and maintenance

     163,377        167,819   

Depreciation and amortization

     167,866        151,345   

Selling, general and administrative

     132,179        119,082   

Taxes other than income tax

     97,375        75,365   
  

 

 

   

 

 

 

Total Operating Expenses

     895,472        923,336   
  

 

 

   

 

 

 

INCOME FROM OPERATIONS

     295,426        257,034   
  

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

    

Investment earnings

     4,296        4,113   

Other income

     12,860        17,935   

Other expense

     (8,451     (8,345
  

 

 

   

 

 

 

Total Other Income

     8,705        13,703   
  

 

 

   

 

 

 

Interest expense

     80,114        89,814   
  

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     224,017        180,923   

Income tax expense

     79,165        61,517   
  

 

 

   

 

 

 

NET INCOME

     144,852        119,406   

Less: Net income attributable to noncontrolling interests

     6,927        4,716   
  

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.

   $ 137,925      $ 114,690   
  

 

 

   

 

 

 

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

    

Basic earnings per common share

   $ 0.97      $ 0.85   

Diluted earnings per common share

   $ 0.97      $ 0.84   

AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:

    

Basic

     142,013,344        134,177,136   

Diluted

     142,361,347        136,329,603   

DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.76      $ 0.72   

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

 

3


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

     Six Months Ended June 30,  
     2016     2015  

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

    

Net income

   $ 144,852      $ 119,406   

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

    

Depreciation and amortization

     167,866        151,345   

Amortization of nuclear fuel

     16,831        10,085   

Amortization of deferred regulatory gain from sale leaseback

     (2,748     (2,748

Amortization of corporate-owned life insurance

     8,819        9,042   

Non-cash compensation

     4,778        4,241   

Net deferred income taxes and credits

     75,334        54,740   

Allowance for equity funds used during construction

     (5,247     (2,041

Changes in working capital items:

    

Accounts receivable

     (40,555     998   

Fuel inventory and supplies

     2,140        (31,307

Prepaid expenses and other

     7,126        (40,195

Accounts payable

     (21,364     (2,873

Accrued taxes

     16,272        16,893   

Other current liabilities

     (62,434     (65,908

Changes in other assets

     1,848        (9,712

Changes in other liabilities

     15,163        21,046   
  

 

 

   

 

 

 

Cash Flows from Operating Activities

     328,681        233,012   
  

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

    

Additions to property, plant and equipment

     (503,631     (334,905

Purchase of securities - trusts

     (39,603     (9,980

Sale of securities - trusts

     41,201        10,263   

Investment in corporate-owned life insurance

     (14,648     (14,845

Proceeds from investment in corporate-owned life insurance

     24,171        1,192   

Investment in affiliated company

     (655     —     

Other investing activities

     (2,798     (653
  

 

 

   

 

 

 

Cash Flows used in Investing Activities

     (495,963     (348,928
  

 

 

   

 

 

 

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

    

Short-term debt, net

     (73,300     49,500   

Proceeds from long-term debt

     396,577        —     

Proceeds from long-term debt of variable interest entities

     162,048        —     

Retirements of long-term debt

     (50,000     (125,000

Retirements of long-term debt of variable interest entities

     (190,355     (27,925

Repayment of capital leases

     (401     (1,721

Borrowings against cash surrender value of corporate-owned life insurance

     54,910        56,622   

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

     (22,921     (899

Issuance of common stock

     1,354        256,394   

Distributions to shareholders of noncontrolling interests

     (2,551     (1,076

Cash dividends paid

     (101,137     (89,035

Other financing activities

     (4,960     (3,234
  

 

 

   

 

 

 

Cash Flows from Financing Activities

     169,264        113,626   
  

 

 

   

 

 

 

NET CHANGE IN CASH AND CASH EQUIVALENTS

     1,982        (2,290

CASH AND CASH EQUIVALENTS:

    

Beginning of period

     3,231        4,556   
  

 

 

   

 

 

 

End of period

   $ 5,213      $ 2,266   
  

 

 

   

 

 

 

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

 

4


WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

     Westar Energy, Inc. Shareholders              
     Common
stock shares
     Common
stock
     Paid-in
capital
    Retained
earnings
    Non-controlling
interests
    Total
equity
 

Balance as of December 31, 2014

     131,687,454       $ 658,437       $ 1,781,120      $ 855,299      $ 6,451      $ 3,301,307   

Net income

     —           —           —          114,690        4,716        119,406   

Issuance of stock

     9,208,267         46,041         210,353        —          —          256,394   

Issuance of stock for compensation and reinvested dividends

     282,897         1,415         4,117        —          —          5,532   

Tax withholding related to stock compensation

     —           —           (3,234     —          —          (3,234

Dividends declared on common stock ($0.72 per share)

     —           —           —          (99,169     —          (99,169

Stock compensation expense

     —           —           4,196        —          —          4,196   

Tax benefit on stock compensation

     —           —           1,178        —          —          1,178   

Distributions to shareholders of noncontrolling interests

     —           —           —          —          (1,076     (1,076

Other

     —           —           (69     —          (1     (70
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of June 30, 2015

     141,178,618       $ 705,893       $ 1,997,661      $ 870,820      $ 10,090      $ 3,584,464   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2015

     141,353,426       $ 706,767       $ 2,004,124      $ 945,830      $ 15,242      $ 3,671,963   

Net income

     —           —           —          137,925        6,927        144,852   

Issuance of stock

     28,674         143         1,211        —          —          1,354   

Issuance of stock for compensation and reinvested dividends

     308,917         1,545         3,396        —          —          4,941   

Tax withholding related to stock compensation

     —           —           (4,960     —          —          (4,960

Dividends declared on common stock ($0.76 per share)

     —           —           —          (108,894     —          (108,894

Stock compensation expense

     —           —           4,720        —          —          4,720   

Distribution to shareholders of noncontrolling interests

     —           —           —          —          (2,551     (2,551

Cumulative effect of accounting change - stock compensation

     —           —           —          3,326        —          3,326   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of June 30, 2016

     141,691,017       $ 708,455       $ 2,008,491      $ 978,187      $ 19,618      $ 3,714,751   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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

 

5


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 704,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2015 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of the results to be expected for the full year.

 

6


Fuel Inventory and Supplies

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

 

     As of
June 30, 2016
     As of
December 31, 2015
 
     (In Thousands)  

Fuel inventory

   $ 107,397       $ 113,438   

Supplies

     192,068         187,856   
  

 

 

    

 

 

 

Fuel inventory and supplies

   $ 299,465       $ 301,294   
  

 

 

    

 

 

 

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 June 30,     Six Months Ended June 30,  
     2016     2015     2016     2015  
     (Dollars In Thousands)  

Borrowed funds

   $ 2,338      $ 552      $ 4,347      $ 2,581   

Equity funds

     2,783        90        5,247        2,041   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 5,121      $ 642      $ 9,594      $ 4,622   
  

 

 

   

 

 

   

 

 

   

 

 

 

Average AFUDC Rates

     4.2     1.2     4.6     3.2

Earnings Per Share

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

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

 

7


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

 

     Three Months Ended June 30,      Six Months Ended June 30,  
     2016      2015      2016      2015  
     (Dollars In Thousands, Except Per Share Amounts)  

Net income

   $ 76,144       $ 66,243       $ 144,852       $ 119,406   

Less: Net income attributable to noncontrolling interests

     3,804         2,533         6,927         4,716   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income attributable to Westar Energy, Inc.

     72,340         63,710         137,925         114,690   

Less: Net income allocated to RSUs

     156         141         290         257   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income allocated to common stock

   $ 72,184       $ 63,569       $ 137,635       $ 114,433   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – basic

     142,033,842         135,939,197         142,013,344         134,177,136   

Effect of dilutive securities:

           

RSUs

     463,493         121,234         348,003         127,999   

Forward sale agreements

     —           1,351,721         —           2,024,468   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average equivalent common shares outstanding – diluted (a)

     142,497,335         137,412,152         142,361,347         136,329,603   
  

 

 

    

 

 

    

 

 

    

 

 

 

Earnings per common share, basic

   $ 0.51       $ 0.47       $ 0.97       $ 0.85   

Earnings per common share, diluted

   $ 0.51       $ 0.46       $ 0.97       $ 0.84   

 

(a) We had no antidilutive securities for the three and six months ended June 30, 2016 and 2015.

Supplemental Cash Flow Information

 

     Six Months Ended June 30,  
     2016      2015  
     (In Thousands)  

CASH PAID FOR (RECEIVED FROM):

     

Interest on financing activities, net of amount capitalized

   $ 70,697       $ 82,297   

Interest on financing activities of VIEs

     4,150         5,651   

Income taxes, net of refunds

     (77      126   

NON-CASH INVESTING TRANSACTIONS:

     

Property, plant and equipment additions

     71,830         66,861   

NON-CASH FINANCING TRANSACTIONS:

     

Issuance of stock for compensation and reinvested dividends

     4,941         5,532   

Assets acquired through capital leases

     392         1,102   

 

8


New Accounting Pronouncements

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

Leases

In February 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-02 which requires lessees to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. We are evaluating the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated financial statements.

Stock-based Compensation

In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.

Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits and expense. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying condensed consolidated statements of cash flows for the six months ended June 30, 2015, as $1.2 million higher than as previously reported, and cash flows from financing activities as $1.2 million lower than as previously reported.

Financial Instruments

In May 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 5, “Financial Instruments and Trading Securities.”

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We are continuing to analyze the new standard and have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

 

9


3. PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock.

The closing of the merger is subject to customary conditions including, among others, approval by our shareholders and the shareholders of Great Plains Energy and receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger.

On July 14, 2016, Great Plains Energy filed a registration statement on Form S-4 with the SEC. The registration statement includes a preliminary proxy statement that, once finalized, will be sent to our shareholders in connection with the special meeting of our shareholders to be held to vote to approve the merger.

The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If Great Plains Energy terminates the merger agreement because our board of directors changes its recommendation, if we terminate the merger agreement to enter into an acquisition agreement with a superior proposal, or if our shareholders vote and do not give approval and we enter into an acquisition proposal within 12 months of termination of the merger agreement, we must pay Great Plains Energy a termination fee of $280.0 million.

If the merger agreement is terminated under other circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. If we terminate the merger agreement because the Great Plains Energy board of directors changes its recommendation, Great Plains Energy must pay us a termination fee of $180.0 million. If either party terminates the merger agreement because the end date occurred or Great Plains Energy shareholders’ approval was not acquired, and it has either been publicly disclosed that Great Plains Energy has entered into an alternative acquisition proposal, or an acquisition proposal was entered into within 12 months after the termination of the merger agreement, Great Plains Energy must pay us a termination fee of $180.0 million. If Great Plains Energy shareholders’ meeting was held and completed, but approval was not obtained, and the termination fee described above is not payable by Great Plains Energy, Great Plains Energy must pay us a termination fee of $80.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three months ended June 30, 2016, we incurred approximately $7.8 million of merger-related expenses, which is included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to coincide with the closing of the merger.

We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies,” and Note 12, “Legal Proceedings,” for more information on legal matters.

4. RATE MATTERS AND REGULATION

KCC Proceedings

In December 2015, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million.

In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR), along with the reduced return on equity (ROE) as described below. The

 

10


updated prices were retroactively effective April 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $7.0 million. As of June 30, 2016, we have recorded a regulatory liability of $4.0 million for our estimated refund obligation from the refund effective date of April 2016 through June 2016.

FERC Proceedings

In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO.

The updated prices were retroactively effective January 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million. This increase also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation during the three months ended June 30, 2016. As of June 30, 2016, we have a remaining refund obligation of $8.1 million which is included in current regulatory liabilities on our balance sheet.

5. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

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

 

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

 

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

 

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

 

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

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

 

11


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

 

     As of June 30, 2016      As of December 31, 2015  
     Carrying Value      Fair Value      Carrying Value      Fair Value  
     (In Thousands)  

Fixed-rate debt

   $ 3,430,000       $ 3,865,914       $ 3,080,000       $ 3,259,533   

Fixed-rate debt of VIEs

     137,963         154,097         166,271         179,030   

 

12


Recurring Fair Value Measurements

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

 

As of June 30, 2016

   Level 1      Level 2      Level 3      NAV      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

        

Domestic equity funds

     —         $ 50,856       $  —         $ 5,944       $ 56,800   

International equity funds

     —           34,560         —           —           34,560   

Core bond fund

     —           27,509         —           —           27,509   

High-yield bond fund

     —           16,557         —           —           16,557   

Emerging markets bond fund

     —           15,342         —           —           15,342   

Combination debt/equity/other funds

     —           12,277         —           —           12,277   

Alternative investments fund

     —           —           —           16,386         16,386   

Real estate securities fund

     —           —           —           9,500         9,500   

Cash equivalents

     248         —           —           —           248   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     248         157,101         —           31,830         189,179   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

        

Domestic equity funds

     —           17,782         —           —           17,782   

International equity fund

     —           4,220         —           —           4,220   

Core bond fund

     —           11,935         —           —           11,935   

Cash equivalents

     156         —           —           —           156   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     156         33,937         —           —           34,093   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 404       $ 191,038       $ —         $ 31,830       $ 223,272   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2015

   Level 1      Level 2      Level 3      NAV      Total  
     (In Thousands)  

Nuclear Decommissioning Trust:

        

Domestic equity funds

   $ —         $ 50,872       $ —         $ 6,050       $ 56,922   

International equity funds

     —           33,595         —           —           33,595   

Core bond fund

     —           25,976         —           —           25,976   

High-yield bond fund

     —           15,288         —           —           15,288   

Emerging markets bond fund

     —           13,584         —           —           13,584   

Combination debt/equity/other funds

     —           11,343         —           —           11,343   

Alternative investments fund

     —           —           —           16,439         16,439   

Real estate securities fund

     —           —           —           10,823         10,823   

Cash equivalents

     87         —           —           —           87   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

     87         150,658         —           33,312         184,057   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Trading Securities:

        

Domestic equity funds

     —           17,876         —           —           17,876   

International equity fund

     —           4,430         —           —           4,430   

Core bond fund

     —           11,423         —           —           11,423   

Cash equivalents

     159         —           —           —           159   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Trading Securities

     159         33,729         —           —           33,888   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Assets Measured at Fair Value

   $ 246       $ 184,387       $ —         $ 33,312       $ 217,945   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

13


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

 

     As of June 30, 2016      As of December 31, 2015      As of June 30, 2016  
     Fair Value      Unfunded
Commitments
     Fair Value      Unfunded
Commitments
     Redemption
Frequency
    Length of
Settlement
 
            (In Thousands)                      

Nuclear Decommissioning Trust:

                

Domestic equity funds

   $ 5,944       $ 3,689       $ 6,050       $ 1,948         (a)        (a)   

Alternative investments fund (b)

     16,386         —           16,439         —           Quarterly        65 days   

Real estate securities fund (b)

     9,500         —           10,823         —           Quarterly        65 days   
  

 

 

    

 

 

    

 

 

    

 

 

      

Total

   $ 31,830       $ 3,689       $ 33,312       $ 1,948        
  

 

 

    

 

 

    

 

 

    

 

 

      

 

(a) This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.
(b) There is a holdback on final redemptions.

Price Risk

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

Interest Rate Risk

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

6. FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.1 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months ended June 30, 2016, we recorded an unrealized gain of $0.6 million on assets still held. For the six months ended June 30, 2016, we recorded an unrealized gain of $1.1 million on assets still held. For the three months ended June 30, 2015, we recorded no unrealized gain or loss on assets still held. For the six months ended June 30, 2015, we recorded an unrealized gain of $0.7 million on assets still held.

 

14


Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a gain of $0.1 million during the three months ended June 30, 2016, and a loss of $1.4 million during the six months ended June 30, 2016. We realized a loss of $0.6 million for the three months ended June 30, 2015, and a loss of $0.5 million for the six months ended June 30, 2015. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2016, and December 31, 2015.

 

            Gross Unrealized               

Security Type

   Cost      Gain      Loss     Fair Value      Allocation  
            (Dollars In Thousands)               

As of June 30, 2016:

             

Domestic equity funds

   $ 49,844       $ 6,965       $ (9   $ 56,800         30

International equity funds

     33,935         1,201         (576     34,560         18

Core bond fund

     26,882         627         —          27,509         15

High-yield bond fund

     17,405         —           (848     16,557         9

Emerging market bond fund

     16,145         —           (803     15,342         8

Combination debt/equity/other funds

     9,003         3,274         —          12,277         6

Alternative investment fund

     15,000         1,386         —          16,386         9

Real estate securities fund

     9,500         —           —          9,500         5

Cash equivalents

     248         —           —          248         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 177,962       $ 13,453       $ (2,236   $ 189,179         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2015:

             

Domestic equity funds

   $ 49,488       $ 7,436       $ (2   $ 56,922         32

International equity funds

     33,458         1,372         (1,235     33,595         18

Core bond fund

     26,397         —           (421     25,976         14

High-yield bond fund

     17,047         —           (1,759     15,288         8

Emerging market bond fund

     16,306         —           (2,722     13,584         7

Combination debt/equity/other funds

     8,239         3,104         —          11,343         6

Alternative investment fund

     15,000         1,439         —          16,439         9

Real estate securities fund

     11,026         —           (203     10,823         6

Cash equivalents

     87         —           —          87         <1
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 177,048       $ 13,351       $ (6,342   $ 184,057         100
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

15


The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2016, and December 31, 2015.

 

     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 June 30, 2016:

               

Domestic equity funds

   $ 861       $ (9   $ —         $ —        $ 861       $ (9

International equity funds

     —           —          7,426         (576     7,426         (576

High-yield bond fund

     —           —          16,557         (848     16,557         (848

Emerging market bond fund

     —           —          15,342         (803     15,342         (803
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 861       $ (9   $ 39,325       $ (2,227   $ 40,186       $ (2,236
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2015:

               

Domestic equity funds

   $ —         $ —        $ 668       $ (2   $ 668       $ (2

International equity funds

     —           —          6,717         (1,235     6,717         (1,235

Core bond funds

     25,976         (421     —           —          25,976         (421

High-yield bond fund

     15,288         (1,759     —           —          15,288         (1,759

Emerging market bond fund

     —           —          13,584         (2,722     13,584         (2,722

Real estate securities fund

     —           —          10,823         (203     10,823         (203
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 41,264       $ (2,180   $ 31,792       $ (4,162   $ 73,056       $ (6,342
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

7. DEBT FINANCING

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of $162.1 million in outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 13, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

8. TAXES

We recorded income tax expense of $40.5 million with an effective income tax rate of 35% for the three months ended June 30, 2016, and income tax expense of $33.8 million with an effective income tax rate of 34% for the same period of 2015. We recorded income tax expense of $79.2 million with an effective income tax rate of 35% for the six months ended June 30, 2016, and income tax expense of $61.5 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three and six months ended June 30, 2016, was due primarily to an increase in income before income taxes.

As of June 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $3.0 million and $2.9 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

 

16


As of June 30, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2016, or December 31, 2015.

As of June 30, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

9. PENSION AND POST-RETIREMENT BENEFIT PLANS

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

 

     Pension Benefits      Post-retirement Benefits  

Three Months Ended June 30,

   2016      2015      2016      2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

           

Service cost

   $ 4,633       $ 5,348       $ 271       $ 361   

Interest cost

     10,921         10,753         1,393         1,422   

Expected return on plan assets

     (10,663      (10,059      (1,708      (1,654

Amortization of unrecognized:

           

Prior service costs

     174         130         114         114   

Actuarial loss (gain), net

     5,146         8,053         (280      95   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit) before regulatory adjustment

     10,211         14,225         (210      338   

Regulatory adjustment (a)

     3,306         1,534         (486      1,013   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit)

   $ 13,517       $ 15,759       $ (696    $ 1,351   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

 

     Pension Benefits      Post-retirement Benefits  

Six Months Ended June 30,

   2016      2015      2016      2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

           

Service cost

   $ 9,297       $ 10,696       $ 542       $ 722   

Interest cost

     21,880         21,507         2,786         2,845   

Expected return on plan assets

     (21,326      (20,118      (3,417      (3,307

Amortization of unrecognized:

           

Prior service costs

     420         260         228         227   

Actuarial loss (gain), net

     10,534         15,714         (560      190   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit) before regulatory adjustment

     20,805         28,059         (421      677   

Regulatory adjustment (a)

     6,613         3,332         (972      2,026   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost (benefit)

   $ 27,418       $ 31,391       $ (1,393    $ 2,703   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

During the six months ended June 30, 2016 and 2015, we contributed $11.2 million and $19.4 million, respectively, to the Westar Energy pension trust.

 

17


10. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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

 

     Pension Benefits      Post-retirement Benefits  

Three Months Ended June 30,

   2016      2015      2016      2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

           

Service cost

   $ 1,687       $ 1,899       $ 32       $ 34   

Interest cost

     2,414         2,254         82         79   

Expected return on plan assets

     (2,430      (2,261      —           —     

Amortization of unrecognized:

           

Prior service costs

     14         14         —           —     

Actuarial loss (gain), net

     1,089         1,482         (4      1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost before regulatory adjustment

     2,774         3,388         110         114   

Regulatory adjustment (a)

     483         (304      —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost

   $ 3,257       $ 3,084       $ 110       $ 114   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

 

     Pension Benefits      Post-retirement Benefits  

Six Months Ended June 30,

   2016      2015      2016      2015  
     (In Thousands)  

Components of Net Periodic Cost (Benefit):

           

Service cost

   $ 3,374       $ 3,797       $ 64       $ 69   

Interest cost

     4,828         4,508         163         157   

Expected return on plan assets

     (4,861      (4,522      —           —     

Amortization of unrecognized:

           

Prior service costs

     28         28         —           —     

Actuarial loss (gain), net

     2,178         2,965         (8      1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost before regulatory adjustment

     5,547         6,776         219         227   

Regulatory adjustment (a)

     966         (608      —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic cost

   $ 6,513       $ 6,168       $ 219       $ 227   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

During the six months ended June 30, 2016 and 2015, we funded $3.2 million and $2.5 million of Wolf Creek’s pension plan contributions, respectively.

 

18


11. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Rule

In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (NOx) emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

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

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

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

In 2010, the EPA revised the NAAQS for SO2. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO2 emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, Kansas Department of Health and Environment (KDHE) recommended a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO2 Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We are working with KDHE to determine the impact of this proposed designation. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

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

 

19


In October 2015, the EPA published a rule establishing new source performance standards that limit CO2 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. In May 2016, the U.S. Court of Appeals for the D.C. Circuit decided to forego the normal three judge panel to review the CPP and to conduct the review en banc. At the same time, the Court scheduled oral arguments for September 2016. In June 2016, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

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

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we believe the impact on our operations or consolidated financial results could be material.

 

20


SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results, but it could be material.

Storage of Spent Nuclear Fuel

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

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the Federal Power Act.

Department of Justice Proceedings

At any time before or after the merger, the Department of Justice (DOJ) or the Federal Trade Commission could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the merger or seeking divestiture of substantial assets of Great Plains Energy, the Company or their respective subsidiaries. Private parties and state attorneys general may also bring an action under the antitrust laws under certain circumstances. On June 23, 2016, the DOJ sent a letter to us and Great Plains Energy informing the parties that it had opened an investigation into the proposed transaction and requested that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

12. LEGAL PROCEEDINGS

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

 

21


Pending Merger

Following the announcement of the merger agreement, two putative class action complaints and one putative derivative action complaint challenging the merger were filed on behalf of purported Westar Energy shareholders in the District Court of Shawnee County, Kansas.

The first complaint, filed on June 13, 2016, is captioned Smith v. Westar Energy, Inc., et al., Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that we and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration undervalues Westar Energy, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourages third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, our CEO will reap significant personal financial gain. The complaint seeks, among other remedies, a declaration that the action may be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement (to the extent already implemented), a directive to the members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

The second complaint, filed on June 14, 2016, is captioned Miller v. Westar Energy, Inc., et al., Case No. 2016-CV-000458. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration deprives our shareholders of fair consideration for their shares, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, an order to permit the action to be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement, a directive to defendants to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

Counsel for plaintiffs in the Smith matter and the Miller matter have filed an unopposed motion for consolidation and appointment of lead counsel. The defendants believe that the claims asserted against them in both class action lawsuits are without merit and intend to vigorously defend against such claims.

The third complaint, filed on July 5, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action is brought on behalf of our shareholders and names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as the nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals. The complaint seeks, among other remedies, an order to permit the action to be maintained as a derivative action, enjoining direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement (to the extent already implemented), imposing a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The defendants intend to seek dismissal of this complaint at the appropriate time.

 

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13. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

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

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 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 7, “Debt Financing,” for additional information.

 

23


Financial Statement Impact

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

 

     As of
June 30, 2016
     As of
December 31, 2015
 
     (In Thousands)  

Assets:

     

Property, plant and equipment of variable interest entities, net

   $ 263,072       $ 268,239   

Regulatory assets (a)

     9,758         9,088   

Liabilities:

     

Current maturities of long-term debt of variable interest entities

   $ 26,842       $ 28,309   

Accrued interest (b)

     867         2,457   

Long-term debt of variable interest entities, net

     111,230         138,097   

 

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

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

 

24

EX-99.4

Exhibit 99.4

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

The Unaudited Pro Forma Condensed Combined Financial Statements (referred to as the “pro forma financial statements”) have been derived from the historical consolidated financial statements of Great Plains Energy Incorporated (“Great Plains Energy”) and Westar Energy, Inc. (“Westar”). The pro forma financial statements should be read in conjunction with the:

 

    accompanying notes to the Unaudited Pro Forma Condensed Combined Financial Statements;

 

    consolidated financial statements of Great Plains Energy as of and for the year ended December 31, 2015, included in Great Plains Energy’s Annual Report on Form 10-K;

 

    unaudited consolidated financial statements of Great Plains Energy as of and for the six months ended June 30, 2016, included in Great Plains Energy’s Quarterly Report on Form 10-Q;

 

    consolidated financial statements of Westar as of and for the year ended December 31, 2015, included in Westar’s Annual Report on Form 10-K; and

 

    unaudited condensed consolidated financial statements of Westar as of and for the six months ended June 30, 2016, included in Westar’s Quarterly Report on Form 10-Q.

The pro forma financial statements give effect to the merger, Great Plains Energy’s expected equity and debt issuances to finance the cash portion of the merger consideration and the redemption by Great Plains Energy of all of its existing outstanding preferred stock (collectively referred to in this section as the “transactions”). Great Plains Energy has obtained committed financing in the form of a $7.517 billion senior unsecured bridge term loan facility from Goldman Sachs Bank USA and Goldman Sachs Lending Partners LLC. However, Great Plains Energy has prepared its pro forma financial statements assuming the cash portion of the merger consideration will be financed through its expected issuances of equity and debt based on current market conditions, and as a result, these pro forma financial statements assume that Great Plains Energy will not borrow any amounts under the bridge term loan facility. Any borrowings under the bridge term loan facility would be classified as short-term debt in current liabilities.

The Unaudited Pro Forma Condensed Combined Statements of Income (referred to as the “pro forma statements of income”) for the six months ended June 30, 2016 and for the year ended December 31, 2015 give effect to the transactions as if they occurred on January 1, 2015. The Unaudited Pro Forma Condensed Combined Balance Sheet (referred to as the “pro forma balance sheet”) as of June 30, 2016 gives effect to the transactions as if they occurred on June 30, 2016.

The historical consolidated financial information has been adjusted in the pro forma financial statements to give effect to pro forma events that are: (1) directly attributable to the merger; (2) factually supportable; and (3) with respect to the statements of income, expected to have a continuing impact on the combined results of Great Plains Energy and Westar. As such, the impact from merger related expenses is not included in the accompanying pro forma statements of income. However, the impact of these expenses is reflected in the pro forma balance sheet as an increase to other current liabilities and a decrease to retained earnings.

As described in the accompanying notes, the pro forma financial statements have been prepared using the acquisition method of accounting under existing generally accepted accounting principles (“GAAP”), and the regulations of the Securities and Exchange Commission. Great Plains Energy has been treated as the acquirer in the merger for accounting purposes. The purchase price for the pro forma financial statements has been estimated based on (1) the number of outstanding shares of Westar common stock on June 30, 2016, and (2) an assumed exchange ratio of 0.2963 determined using the 20-day volume-weighted average price per share of Great Plains Energy common stock ending on August 1, 2016.

Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in connection with the pro forma financial statements. Since the pro forma financial statements have been prepared based on preliminary estimates, the final amounts recorded at the date of the merger may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed and the final purchase price.


The pro forma financial statements have been presented for illustrative purposes only and are not necessarily indicative of the results of operations and financial position that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations or financial position of the combined company.

GREAT PLAINS ENERGY INCORPORATED

Unaudited Pro Forma Condensed Combined Balance Sheet

June 30, 2016

 

     Great Plains
Energy Historical
(Note 3(a))
     Westar
Historical
(Note3(a))
     Pro Forma
Adjustments
    Note 3     Great Plains
Energy Combined
Pro Forma
 
     (millions)  

ASSETS

            

Current Assets

            

Cash and cash equivalents

   $ 7.2       $ 5.2       $ 59.9        (b   $ 72.3   

Funds on deposit

     6.0         5.8             11.8   

Receivables, net

     211.8         298.8         (35.6     (c     475.0   

Accounts receivable pledged as collateral

     173.7         —               173.7   

Fuel inventories, at average cost

     103.9         107.4             211.3   

Materials and supplies, at average cost

     160.5         192.1             352.6   

Deferred refueling outage costs

     9.7         8.8             18.5   

Refundable income taxes

     1.0         —               1.0   

Prepaid expenses and other assets

     68.0         45.3         (32.2     (i     81.1   
  

 

 

    

 

 

    

 

 

     

 

 

 

Total

     741.8         663.4         (7.9       1,397.3   
  

 

 

    

 

 

    

 

 

     

 

 

 

Utility Plant, at Original Cost

            

Electric

     13,302.4         12,457.7             25,760.1   

Less - accumulated depreciation

     5,015.2         4,297.4             9,312.6   
  

 

 

    

 

 

    

 

 

     

 

 

 

Net utility plant in service

     8,287.2         8,160.3         —            16,447.5   

Construction work in progress

     439.9         568.7             1,008.6   

Nuclear fuel, net of amortization

     71.6         71.7             143.3   
  

 

 

    

 

 

    

 

 

     

 

 

 

Total

     8,798.7         8,800.7         —            17,599.4   
  

 

 

    

 

 

    

 

 

     

 

 

 

Property, Plant and Equipment of Variable Interest Entities

            

Electric

     —           498.0             498.0   

Less - accumulated depreciation

     —           234.9             234.9   
  

 

 

    

 

 

    

 

 

     

 

 

 

Net property, plant and equipment

     —           263.1         —            263.1   
  

 

 

    

 

 

    

 

 

     

 

 

 

Investments and Other Assets

            

Nuclear decommissioning trust fund

     210.3         189.2             399.5   

Regulatory assets

     1,001.2         813.3         464.2        (d     2,278.7   

Goodwill

     169.0         —           4,816.7        (k     4,985.7   

Other

     89.3         241.0         (6.9     (c     308.4   
           (15.0     (e  
  

 

 

    

 

 

    

 

 

     

 

 

 

Total

     1,469.8         1,243.5         5,259.0          7,972.3   
  

 

 

    

 

 

    

 

 

     

 

 

 

Total

   $ 11,010.3       $ 10,970.7       $ 5,251.1        $ 27,232.1   
  

 

 

    

 

 

    

 

 

     

 

 

 

The accompanying Notes to the Unaudited Pro Forma Condensed Combined Financial Statements are an integral part of these statements.


GREAT PLAINS ENERGY INCORPORATED

Unaudited Pro Forma Condensed Combined Balance Sheet

June 30, 2016

 

     Great Plains
Energy Historical
(Note 3(a))
    Westar
Historical
(Note3(a))
     Pro Forma
Adjustments
    Note 3     Great Plains
Energy Combined
Pro Forma
 
     (millions)  

LIABILITIES AND CAPITALIZATION

           

Current Liabilities

           

Notes payable

   $ 74.0      $ —             $ 74.0   

Collateralized note payable

     173.7        —               173.7   

Commercial paper

     340.4        177.0             517.4   

Current maturities of long-term debt

     251.1        125.0         3.1        (d     379.2   

Current maturities of long-term debt of variable interest entities

     —          26.8         3.1        (d     29.9   

Accounts payable

     263.3        178.6         (35.6     (c     406.3   

Accrued taxes

     80.6        95.1             175.7   

Accrued interest

     45.0        42.0             87.0   

Accrued compensation and benefits

     42.1        17.3             59.4   

Pension and post-retirement liability

     3.4        3.3             6.7   

Interest rate derivative instruments

     77.0        —           (77.0     (i     —     

Other

     26.2        122.8         75.0        (g     304.0   
          (0.4     (e  
          80.4        (h  
  

 

 

   

 

 

    

 

 

     

 

 

 

Total

     1,376.8        787.9         48.6          2,213.3   
  

 

 

   

 

 

    

 

 

     

 

 

 

Deferred Credits and Other Liabilities

           

Deferred income taxes

     1,186.6        1,655.8         (73.3     (f     2,769.1   

Deferred tax credits

     126.9        208.3             335.2   

Asset retirement obligations

     293.8        280.5             574.3   

Pension and post-retirement liability

     466.5        402.8             869.3   

Regulatory liabilities

     302.4        281.5             583.9   

Other

     76.9        140.3         (6.9     (c     210.3   
  

 

 

   

 

 

    

 

 

     

 

 

 

Total

     2,453.1        2,969.2         (80.2       5,342.1   
  

 

 

   

 

 

    

 

 

     

 

 

 

Capitalization

           

Common shareholders’ equity

           

Common stock

     2,658.8        2,716.9         (15.0     (j     5,360.7   

Retained earnings

     1,000.4        978.2         (1,070.5     (j     908.1   

Treasury stock, at cost

     (3.8     —               (3.8

Accumulated other comprehensive loss

     (9.0     —               (9.0
  

 

 

   

 

 

    

 

 

     

 

 

 

Total

     3,646.4        3,695.1         (1,085.5       6,256.0   

Noncontrolling interests

     —          19.6             19.6   

Cumulative preferred stock

     39.0        —           (39.0     (e     —     

Mandatory convertible preferred stock

     —          —           1,544.5        (e     1,544.5   

Long-term debt

     3,495.0        3,387.7         4,849.8        (d     11,732.5   

Long-term debt of variable interest entities

     —          111.2         12.9        (d     124.1   
  

 

 

   

 

 

    

 

 

     

 

 

 

Total

     7,180.4        7,213.6         5,282.7          19,676.7   
  

 

 

   

 

 

    

 

 

     

 

 

 

Commitments and Contingencies

           
  

 

 

   

 

 

    

 

 

     

 

 

 

Total

   $ 11,010.3      $ 10,970.7       $ 5,251.1        $ 27,232.1   
  

 

 

   

 

 

    

 

 

     

 

 

 

The accompanying Notes to the Unaudited Pro Forma Condensed Combined Financial Statements are an integral part of these statements.


GREAT PLAINS ENERGY INCORPORATED

Unaudited Pro Forma Condensed Combined Statement of Income

For the Six Months Ended June 30, 2016

 

     Great Plains
Energy Historical
(Note 3(a))
    Westar
Historical
(Note3(a))
    Pro Forma
Adjustments
    Note 3     Great Plains
Energy Combined
Pro Forma
 
     (millions, except per share amounts)  

Operating Revenues

          

Electric revenues

   $ 1,242.9      $ 1,190.9      $ (1.8     (c   $ 2,432.0   
  

 

 

   

 

 

   

 

 

     

 

 

 

Operating Expenses

          

Fuel

     180.0        145.8            325.8   

Purchased power

     98.1        71.0            169.1   

Transmission

     40.7        117.9        (0.6     (c     158.0   

Utility operating and maintenance expenses

     359.8        283.4        (1.2     (c     642.0   

Costs to achieve anticipated acquisition

     5.0        7.8        (12.3     (h     0.5   

Depreciation and amortization

     170.5        167.9            338.4   

General taxes

     110.8        97.4            208.2   

Other

     5.8        2.3            8.1   
  

 

 

   

 

 

   

 

 

     

 

 

 

Total

     970.7        893.5        (14.1       1,850.1   
  

 

 

   

 

 

   

 

 

     

 

 

 

Operating income

     272.2        297.4        12.3          581.9   

Non-operating income (expense)

     (2.3     3.5            1.2   

Interest charges

     (184.1     (80.1     (67.9     (d     (250.5
         81.6        (i  
  

 

 

   

 

 

   

 

 

     

 

 

 

Income before income tax expense and income from equity investments

     85.8        220.8        26.0          332.6   

Income tax expense

     (28.8     (79.2     1.0        (f     (107.0

Income from equity investments, net of income taxes

     1.4        3.3            4.7   
  

 

 

   

 

 

   

 

 

     

 

 

 

Net income

     58.4        144.9        27.0          230.3   

Less: Net income attributable to noncontrolling interests

     —          (7.0         (7.0
  

 

 

   

 

 

   

 

 

     

 

 

 

Net income attributable to controlling interests

     58.4        137.9        27.0          223.3   

Preferred stock dividend requirements

     0.8        —          57.2        (e     58.0   
  

 

 

   

 

 

   

 

 

     

 

 

 

Earnings available for common shareholders

   $ 57.6      $ 137.9      $ (30.2     $ 165.3   
  

 

 

   

 

 

   

 

 

     

 

 

 

Average number of basic common shares outstanding

     154.5        142.0        (49.5     (l     247.0   

Average number of diluted common shares outstanding

     154.9        142.4        (49.9     (l     247.4   

Basic earnings per common share

   $ 0.37      $ 0.97          $ 0.67   

Diluted earnings per common share

   $ 0.37      $ 0.97          $ 0.67   
  

 

 

   

 

 

       

 

 

 

The accompanying Notes to the Unaudited Pro Forma Condensed Combined Financial Statements are an integral part of these statements.


GREAT PLAINS ENERGY INCORPORATED

Unaudited Pro Forma Condensed Combined Statement of Income

For the Year Ended December 31, 2015

 

     Great Plains
Energy Historical
(Note 3(a))
    Westar
Historical
(Note3(a))
    Pro Forma
Adjustments
    Note 3     Great Plains
Energy Combined
Pro Forma
 
     (millions, except per share amounts)  

Operating Revenues

          

Electric revenues

   $ 2,502.2      $ 2,459.2      $ (3.5     (c   $ 4,957.9   
  

 

 

   

 

 

   

 

 

     

 

 

 

Operating Expenses

          

Fuel

     421.4        404.8            826.2   

Purchased power

     187.3        149.1            336.4   

Transmission

     89.1        236.1        (1.2     (c     324.0   

Utility operating and maintenance expenses

     724.8        573.4        (2.3     (c     1,295.9   

Depreciation and amortization

     330.4        310.6            641.0   

General taxes

     213.2        156.9            370.1   

Other

     5.9        5.3            11.2   
  

 

 

   

 

 

   

 

 

     

 

 

 

Total

     1,972.1        1,836.2        (3.5       3,804.8   
  

 

 

   

 

 

   

 

 

     

 

 

 

Operating income

     530.1        623.0                1,153.1   

Non-operating income (expense)

     3.7        0.2            3.9   

Interest charges

     (199.3     (176.8     (135.8     (d     (511.9
  

 

 

   

 

 

   

 

 

     

 

 

 

Income before income tax expense and income from equity investments

     334.5        446.4        (135.8       645.1   

Income tax expense

     (122.7     (152.0     53.3        (f     (221.4

Income from equity investments, net of income taxes

     1.2        7.4            8.6   
  

 

 

   

 

 

   

 

 

     

 

 

 

Net income

     213.0        301.8        (82.5       432.3   

Less: Net income attributable to noncontrolling interests

           (9.9         (9.9
  

 

 

   

 

 

   

 

 

     

 

 

 

Net income attributable to controlling interests

     213.0        291.9        (82.5       422.4   

Preferred stock dividend requirements

     1.6              114.4        (e     116.0   
  

 

 

   

 

 

   

 

 

     

 

 

 

Earnings available for common shareholders

   $ 211.4      $ 291.9      $ (196.9     $ 306.4   
  

 

 

   

 

 

   

 

 

     

 

 

 

Average number of basic common shares outstanding

     154.2        138.0        (45.5     (l     246.7   

Average number of diluted common shares outstanding

     154.8        139.3        (46.8     (l     247.3   

Basic earnings per common share

   $ 1.37      $ 2.11          $ 1.24   

Diluted earnings per common share

   $ 1.37      $ 2.09          $ 1.24   
  

 

 

   

 

 

       

 

 

 

The accompanying Notes to the Unaudited Pro Forma Condensed Combined Financial Statements are an integral part of these statements.


NOTES TO THE UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Note 1. Basis of Pro Forma Presentation

The pro forma statements of income for the six months ended June 30, 2016 and for the year ended December 31, 2015 give effect to the transactions as if they were completed on January 1, 2015. The pro forma balance sheet as of June 30, 2016 gives effect to the transactions as if they were completed on June 30, 2016.

The pro forma financial statements have been derived from the historical consolidated financial statements of Great Plains Energy and Westar. Assumptions and estimates underlying the pro forma adjustments are described in these notes, which should be read in conjunction with the pro forma financial statements. Since the pro forma financial statements have been prepared based upon preliminary estimates, the final amounts recorded at the date of the merger may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed.

The merger is reflected in the pro forma financial statements as an acquisition of Westar by Great Plains Energy, based on the guidance provided by accounting standards for business combinations. Under these accounting standards, the total estimated purchase price is calculated as described in Note 2 to the pro forma financial statements, and the assets acquired and the liabilities assumed have been measured at estimated fair value. For the purpose of measuring the estimated fair value of the assets acquired and liabilities assumed, Great Plains Energy has applied the accounting guidance for fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurements utilize estimates based on key assumptions of the merger, including historical and current market data. The pro forma adjustments included herein are preliminary and will be revised at the time of the merger as additional information becomes available and as additional analyses are performed. The final purchase price allocation will be determined at the time that the merger is completed and the final amounts recorded for the merger may differ materially from the information presented.

Estimated transaction costs have been excluded from the pro forma statements of income as they reflect non-recurring charges directly related to the merger. However, the anticipated transaction costs are reflected in the pro forma balance sheet as an increase in other current liabilities and a decrease in retained earnings.

The pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies that could result from the merger. Further, the pro forma financial statements do not reflect the effect of any regulatory actions that may impact the pro forma financial statements when the merger is completed.

Westar’s regulated operations are comprised of electric generation, transmission and distribution operations. These operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission and the Kansas Corporation Commission and are accounted for pursuant to GAAP, including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for Westar’s regulated operations provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Thus, the fair values of Westar’s tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values, and the pro forma financial statements do not reflect any net adjustments related to these amounts.

Note 2. Preliminary Purchase Price and Preliminary Purchase Price Allocation

The merger agreement provides that each outstanding share of Westar common stock at the effective time of the merger (subject to certain exceptions) will be converted into the right to receive $51 of cash consideration and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the date of the effective time of the merger.


The purchase price for the merger is estimated as follows (shares in thousands):

 

Westar shares outstanding as of June 30, 2016

     141,691   

Cash consideration (per Westar share)

   $ 51.00   
  

 

 

 

Estimated cash portion of purchase price (in millions)

   $ 7,226.2   

Westar shares outstanding as of June 30, 2016

     141,691   

Exchange ratio (per Westar share)

     0.2963   
  

 

 

 

Estimated total Great Plains Energy common shares assumed to be issued

     41,983.0   

Closing price of Great Plains Energy common stock on August 1, 2016

   $ 29.70   
  

 

 

 

Estimated equity portion of purchase price (in millions)

   $ 1,246.9   

Estimated equity compensation (in millions)

     47.8   
  

 

 

 

Total estimated purchase price (in millions)

   $ 8,520.9   
  

 

 

 

The preliminary purchase price was computed using Westar’s outstanding shares as of June 30, 2016, multiplied by the cash consideration portion of the purchase price and adjusted for the exchange ratio for the equity portion of the purchase price. The preliminary purchase price reflects an exchange ratio calculated by dividing $9.00 by $30.3706, the 20-day volume-weighted average price per share of Great Plains Energy common stock ending on August 1, 2016. The preliminary purchase price reflects the market value of Great Plains Energy common stock to be issued in connection with the merger based on the closing price of Great Plains Energy common stock on August 1, 2016. The preliminary purchase price also reflects the total estimated fair value of Westar’s equity compensation awards settled as of June 30, 2016 as required by the merger agreement, excluding the value attributable to post-combination service.

The preliminary purchase price will fluctuate with the market price of Great Plains Energy common stock through the 20-day volume-weighted average price per share used to calculate the exchange ratio and through the value of Great Plains Energy stock issued at the close of the transaction until the purchase price is reflected on an actual basis when the merger is completed. An increase of 20% in the 20-day volume-weighted average price per share from the price used above would decrease the purchase price by approximately $107 million. A decrease of 20% in the 20-day volume-weighted average price per share from the price used above would increase the purchase price by approximately $78 million. These fluctuations assume a closing price of Great Plains Energy common stock at the effective time of the merger of $29.70, the closing price of Great Plains Energy common stock on August 1, 2016.

An increase or decrease of 20% in the Great Plains Energy closing common share price from the price used above would increase or decrease the purchase price by approximately $249 million, assuming an exchange ratio of 0.2963.

The allocation of the preliminary purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments to reflect the fair values of Westar’s assets and liabilities. The allocation of the preliminary purchase price is as follows (in millions):

 

Current Assets

   $ 663.4   

Total Utility Plant, Net

     8,800.7   

Property, Plant and Equipment of Variable Interest Entities, Net

     263.1   

Goodwill

     4,816.7   

Other Long-Term Assets, excluding Goodwill

     1,707.7   
  

 

 

 

Total Assets

   $ 16,251.6   

Current Liabilities, including Current Maturities of Long-Term Debt

     794.1   

Long-Term Liabilities

     2,944.1   

Long-Term Debt

     3,848.8   

Long-Term Debt of Variable Interest Entities

     124.1   

Noncontrolling Interests

     19.6   
  

 

 

 

Total Liabilities and Noncontrolling Interests

     7,730.7   
  

 

 

 

Total Estimated Purchase Price

   $ 8,520.9   
  

 

 

 


Note 3. Adjustments to Pro Forma Financial Statements

The pro forma adjustments included in the pro forma financial statements are as follows:

 

  (a) Great Plains Energy and Westar historical presentation—Based on the amounts reported in the consolidated statements of income and balance sheets of Great Plains Energy and Westar for the year ended December 31, 2015 and for the six months ended and as of June 30, 2016, certain financial statement line items included in Westar’s historical presentation have been reclassified to conform to corresponding financial statement line items included in Great Plains Energy’s historical presentation. These reclassifications have no material impact on the historical operating income, net income attributable to controlling interests, total assets, liabilities or shareholders’ equity reported by Great Plains Energy or Westar.

Additionally, based on Great Plains Energy’s review of Westar’s summary of significant accounting policies disclosed in Westar’s consolidated historical financial statements, which are filed as Exhibit 99.1 to this Current Report on Form 8-K, as well as preliminary discussions with Westar management, the nature and amount of any adjustments to the historical financial statements of Westar to conform its accounting policies to those of Great Plains Energy are not expected to be material. Upon completion of the merger, further review of Westar’s accounting policies and financial statements may result in revisions to Westar’s policies and classifications to conform to those of Great Plains Energy.

 

  (b) Cash and cash equivalents—The pro forma balance sheet reflects the following pro forma adjustments (in millions):

 

     June 30
2016
    

Note 3
FN

Proceeds from long-term debt issuance

   $ 4,415.0       (d)

Proceeds from issuance of mandatory convertible preferred stock

     1,600.0       (e)

Proceeds from issuance of Great Plains Energy common stock

     1,500.0       (j)

Debt and equity issuance fees

     (111.8    (d)(e)(j)

Estimated cash portion of purchase price

     (7,226.2   

Redemption of Great Plains Energy’s cumulative preferred stock

     (40.1    (e)

Settlement of interest rate swaps

     (77.0    (i)
  

 

 

    

Total

   $ 59.9      
  

 

 

    

 

  (c) Intercompany Transactions—Reflects the elimination of jointly-owned electric plant and electric transmission transactions between Great Plains Energy and Westar, as if Great Plains Energy and Westar were consolidated affiliates during the periods presented.

 

  (d) Long-Term Debt—The pro forma balance sheet includes the following pro forma adjustments to the line item of Long-term debt (in millions):

 

     June 30
2016
 

Westar long-term debt fair value adjustment

   $ 461.1   

Issuance of long-term debt (net of issuance costs)

     4,388.7   
  

 

 

 

Total

   $ 4,849.8   
  

 

 

 

The line items of Current maturities of long-term debt, Current maturities of long-term debt of variable interest entities and Long-term debt of variable interest entities also include pro forma adjustments to reflect Westar’s long-term debt at estimated fair value. For purposes of the pro forma adjustments, estimated fair value is based on prevailing market prices for the individual debt securities as of June 30, 2016. The final fair value determination of the debt will be based on prevailing market prices at the completion of the merger. The fair value adjustments to Westar’s regulated company debt of $461.1 million and $3.1 million within the Long-term debt and Current maturities of long-term debt line items, respectively, are offset by an increase to regulatory assets. The fair value adjustment to the long-term debt of Westar’s variable interest entities (if there continues to be a premium to book value) will be amortized as a reduction to interest expense over the remaining life of the debt.

The $4,388.7 million issuance of long-term debt (net of issuance costs of $26.3 million) reflects Great Plains Energy’s anticipated debt financing for a portion of the estimated cash consideration of the merger and other costs directly attributable to the merger.


The pro forma statements of income include the following pro forma adjustments related to long-term debt in the line item of Interest charges (in millions):

 

     Six Months Ended
June 30, 2016
     Year Ended
December 31, 2015
 

Interest expense on $4,388.7 million of long-term debt

   $ (69.6    $ (139.3

Long-term debt fair value adjustment amortization

     1.7         3.5   
  

 

 

    

 

 

 

Total

   $ (67.9    $ (135.8
  

 

 

    

 

 

 

The pro forma adjustment for the incremental interest expense on the estimated $4,388.7 million of long-term debt that Great Plains Energy expects to issue includes the amortization of the estimated issuance costs over the lives of the debt issued. The incremental interest expense reflects an estimated average annual interest cost of 3.16%. A change of 0.125% in the estimated average annual interest rate would cause a change in annual interest expense of approximately $5.5 million.

The amortization of the long-term debt fair value adjustment pertains to Westar’s long-term debt of variable interest entities. The effect of the fair value adjustment is being amortized over the remaining life of the individual debt issuances, with the longest amortization period being approximately five years. The remainder of the fair value adjustments for Westar’s regulated company debt is offset by an increase to regulatory assets, and amortization of these adjustments will offset each other with no effect on earnings.

 

  (e) Preferred Stock—The pro forma balance sheet includes pro forma adjustments to reflect $720.0 million of proceeds (net of $30 million of issuance costs) from the issuance of 7.25% mandatory convertible preferred stock (750,000 shares) to OCM Credit Portfolio LP (“OMERS”) pursuant to a stock purchase agreement and an estimated $824.5 million of proceeds (net of $25.5 million of issuance costs) of additional 7.25% mandatory convertible preferred stock (850,000 shares) that Great Plains Energy anticipates issuing to finance a portion of the estimated cash consideration of the merger. The pro forma adjustment reflecting the $30 million of issuance costs for the preferred stock issued to OMERS includes the reclassification of $15 million of up-front issuance costs deferred in Investments and Other Assets—Other until the issuance of the preferred stock at the time of the merger.

The pro forma statements of income include pro forma adjustments reflecting accumulated dividends from the issuance of these mandatory convertible preferred shares of $58.0 million and $116.0 million for the six months ended June 30, 2016 and year ended December 31, 2015, respectively. A change of 1.0% in the dividend rate of the estimated $824.5 million of mandatory convertible preferred stock would change the annual dividend amount approximately $9 million.

The pro forma balance sheet also includes pro forma adjustments reflecting the $40.1 million redemption (including a redemption premium and accrued dividends of $1.1 million) of all the outstanding shares of Great Plains Energy’s $39.0 million of 3.80%, 4.20%, 4.35% and 4.5% cumulative preferred stock which is required in order to issue the mandatory convertible preferred stock to finance the transaction. The pro forma adjustment reflecting the redemption of the cumulative preferred stock includes the reduction of $0.4 million of other current liabilities related to accrued dividends previously declared. Great Plains Energy redeemed the cumulative preferred stock in August 2016.

The pro forma statements of income also includes pro forma adjustments for the elimination of preferred dividends of $0.8 million and $1.6 million for the six months ended June 30, 2016 and year ended December 31, 2015, respectively, related to the redemption of Great Plains Energy’s 3.80%, 4.20%, 4.35% and 4.5% cumulative preferred stock.

 

  (f) Income Taxes—The pro forma balance sheet includes a pro forma adjustment to estimate the impacts on deferred income taxes of $6.3 million for the allocation of the purchase price, $24.8 million for estimated merger transaction costs, $29.5 million for the estimated settlement of all outstanding Westar equity compensation awards, and $12.7 million to fully amortize deferred financing fees related to the bridge term loan facility, based on the estimated statutory income tax rate of 39.3% for the combined company. The pro forma statements of income include a pro forma adjustment to reflect the income tax effects of the pro forma adjustments calculated using an estimated statutory income tax rate of 39.3% for the combined company. The estimated statutory tax rate of 39.3% could change based on future changes in the applicable tax rates and final determination of the combined company’s tax position.

 

  (g) Equity Compensation Awards—The pro forma balance sheet includes a pro forma adjustment to Other Current Liabilities for the estimated settlement of all outstanding Westar equity compensation awards as required in the merger agreement that will become payable at the time the merger is consummated. The settlement of the equity compensation awards have been excluded from the pro forma statements of income as they reflect non-recurring charges not expected to have a continuing impact on the combined results.


  (h) Merger Transaction Costs—The pro forma balance sheet includes a pro forma adjustment for $80.4 million of estimated merger transaction costs consisting of fees related to advisory, legal, investment banking, and other professional services, all of which are directly attributable to the merger. The pro forma statement of income for the six months ended June 30, 2016 includes a pro forma adjustment to eliminate $12.3 million of merger transaction costs incurred by Great Plains Energy and Westar. Incurred costs related to integration planning not directly attributable to the merger transaction were not eliminated. The merger transaction costs are non-recurring charges and have been excluded from the pro forma statements of income.

 

  (i) Other Financing Costs—The pro forma balance sheet includes a pro forma adjustment to Prepaid expenses and other assets for $32.2 million of deferred financing fees related to the bridge term loan facility that Great Plains Energy expects will be fully amortized at the time of the merger.

The pro forma balance sheet also includes a $77.0 million pro forma adjustment to Interest rate derivative instruments to reflect the settlement of four interest rate swap transactions entered into by Great Plains Energy to manage interest rate risk with regards to the estimated $4,415.0 million principal amount of long-term debt that Great Plains Energy expects to issue to finance a portion of the estimated cash consideration of the merger and other costs directly attributable to the merger.

The pro forma statement of income for the six months ended June 30, 2016 includes the following pro forma adjustments related to other financing costs in the line item of Interest charges (in millions):

 

Mark-to-market impacts of interest rate swaps

   $  77.0   

Eliminate amortization of deferred financing fees for bridge facility

     4.6   
  

 

 

 

Total

   $ 81.6   
  

 

 

 

Both the mark-to-market impacts of interest rate swaps and the amortization of deferred financing fees for the bridge term loan facility (which Great Plains Energy expects to be fully amortized at the time of the merger) were excluded from the pro forma statements of income as they represent non-recurring charges directly attributable to the merger transaction.

 

  (j) Common Shareholders’ Equity—The pro forma balance sheet reflects the following adjustments: (i) the elimination of Westar’s historical equity balances, (ii) the estimated issuance of 50.5 million shares of Great Plains Energy common stock ($1,455.0 million of common stock, net of $45 million of issuance costs, based on Great Plains Energy’s closing stock price of $29.70 on August 1, 2016) to finance a portion of the estimated cash consideration of the merger, (iii) the estimated issuance of 42.0 million shares of Great Plains Energy common stock ($1,246.9 million of common stock see Note 2 for details of the calculation) for the equity portion of the purchase price and (iv) adjustments to decrease retained earnings of $55.6 million (net of tax) for estimated merger transaction costs, $16.5 million (net of tax) to reflect the fair value of settled Westar equity compensation awards attributable to post-combination service, $0.7 million related to the redemption of Great Plains Energy’s 3.80%, 4.20%, 4.35% and 4.5% cumulative preferred stock, and $19.5 million (net of tax) to reflect the full amortization of deferred financing fees related to the bridge term loan facility.

 

  (k) Goodwill—Reflects the preliminary estimate of goodwill created as a result of the merger. See below for a detailed calculation of goodwill created.

 

Total Estimated Purchase Price

   $  8,520.9   

Fair value of Westar’s Noncontrolling Interests

     19.6   
  

 

 

 

Estimated Westar Fair Value

     8,540.5   

Less: Fair Value of Net Assets Acquired

     3,723.8   
  

 

 

 

Pro Forma Goodwill Adjustment

   $ 4,816.7   
  

 

 

 

 

  (l) Shares Outstanding—Reflects the elimination of Westar’s common stock, the issuance of approximately 50.5 million shares of Great Plains Energy common stock to finance a portion of the estimated cash consideration of the merger and the issuance of 42.0 million shares of Great Plains Energy stock per the exchange ratio of 0.2963 (see Note 2 for details of the calculation).


See below for a detailed calculation of the pro forma weighted-average number of basic and diluted shares outstanding.

 

     Six Months Ended
June 30, 2016
     Year Ended
December 31, 2015
 

Basic (millions):

     

Great Plains Energy weighted-average shares outstanding

     154.5         154.2   

Great Plains Energy shares issued to fund cash consideration

     50.5         50.5   

Equivalent Westar common shares after exchange

     42.0         42.0   
  

 

 

    

 

 

 
     247.0         246.7   
  

 

 

    

 

 

 

Diluted (millions):

     

Great Plains Energy weighted-average shares outstanding

     154.9         154.8   

Great Plains Energy shares issued to fund cash consideration

     50.5         50.5   

Equivalent Westar common shares after exchange

     42.0         42.0   
  

 

 

    

 

 

 
     247.4         247.3   
  

 

 

    

 

 

 

The 750,000 shares of 7.25% mandatory convertible preferred stock that will be issued to OMERS pursuant to a stock purchase agreement and the 850,000 of additional shares of 7.25% mandatory convertible preferred stock expected to be issued that are reflected in the pro forma financial statements have not been assumed to be converted in the calculation of pro forma weighted-average diluted shares outstanding for the six months ended June 30, 2016 and year ended December 31, 2015, as the conversion would be anti-dilutive. The conversion features of the 850,000 shares of mandatory convertible preferred stock have been assumed to be identical to those for the 750,000 shares of mandatory convertible preferred stock that will be issued to OMERS.