FORM U-3A-2
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.
Statement by Holding Company Claiming
Exemption Under Rule 2 from the
Provisions of the Public Utility Holding
Company Act of 1935
Kansas Gas and Electric Company
Kansas Gas and Electric Company ("KG&E") hereby files with
the Securities and Exchange Commission, pursuant to Rule 2, its
statement claiming exemption as a holding company from the
provisions of the Public Utility Holding Company Act of 1935 (the
"Act") by reason of the provisions of Section 3(a)(2) of the Act.
In support of such claim for exemption the following information
is submitted:
1. KG&E is a Kansas corporation whose principal executive
offices are located at 120 East First, Wichita, Kansas 67202.
KG&E's mailing address is P.O. Box 208, Wichita, Kansas 67201.
KG&E's principal business consists of the generation,
transmission, distribution and sale of electricity. KG&E is a
wholly-owned subsidiary of Western Resources, Inc., formerly The
Kansas Power and Light Company. KG&E's subsidiaries are as
follows: Wolf Creek Nuclear Operating Corporation ("WCNOC"), a
Delaware corporation, was incorporated on April 14, 1986, to
operate and maintain Unit No. 1 of the Wolf Creek Generating
Station ("Wolf Creek"). WCNOC does not own, and is not expected
to own, any utility assets as defined in the Act. Wolf Creek and
WCNOC are each owned by KG&E and two non-affiliated electric
utilities, Kansas City Power & Light Company ("KCPL") and Kansas
Electric Power Cooperative, Inc. ("KEPCo") (collectively, the
"Wolf Creek Owners"), in the following percentages: KG&E, 47%;
KCPL, 47%; and KEPCo, 6%.
KG&E provides electric services to customers in the
southeastern portion of Kansas, including the Wichita
metropolitan area. At December 31, 1993, it rendered electric
services at retail to 269,446 residential, commercial and
industrial customers and at wholesale to 27 communities and 12
other electric utilities. Neither KG&E nor any subsidiary of
KG&E owns or operates any gas properties.
2. The principal electric generating stations of KG&E, all
of which are located in Kansas, are as follows:
Accredited
Capability - MW
Name and Location (KG&E's Share)
Nuclear
Wolf Creek, near Burlington .................... 533
Coal
LaCygne Unit 1, near LaCygne .......... 342
LaCygne Unit 2, near LaCygne .......... 335
JEC Unit 1, near St. Mary's ........... 140
JEC Unit 2, near St. Mary's ........... 135
JEC Unit 3, near St. Mary's ........... 140
Subtotal .................... 1,092
Gas/Oil
Gordon Evans, Wichita ................. 517
Murray Gill, Wichita .................. 327
Subtotal .................... 844
Diesel
Wichita, Wichita ...................... 3
Total Active Capability 2,472 MW
KG&E maintains fifteen interconnections with other public
utilities to permit direct extra-high voltage interchange. It is
a member of the MOKAN Power Pool consisting of eleven utilities
in Kansas and western Missouri which have agreed to coordinate
the planning of electric generation and transmission facilities,
the sharing of reserve capacity and electric interchange
transactions, including economy and emergency service. KG&E is
also a member of the Southwest Power Pool, the regional
coordinating council for electric utilities throughout the south-
central United States.
KG&E owns a transmission and distribution system which
enables it to supply its service area. Transmission and
distribution lines, in general, are located by permit or easement
on public roads and streets or the lands of others. All such
transmission and distribution systems are located within the
State of Kansas.
3(a). For the year ended December 31, 1993, KG&E sold
7,744,969 Kwh of electric energy at retail and 796,367 Kwh of
electric energy at wholesale, all of which was sold within the
State of Kansas. WCNOC operates and maintains Wolf Creek on
behalf of the Wolf Creek Owners and does not engage in the sale
of electricity. During 1993 neither KG&E or its subsidiaries
distributed or sold any natural or manufactured gas at retail.
(b) and (c). During 1993 KG&E sold, at wholesale, 1,207,740
Kwh of electric energy to adjoining public utilities through
interconnections at the Kansas state line. During 1993, neither
KG&E or its subsidiaries distributed or sold electric energy at
retail outside the State of Kansas. During 1993, neither KG&E or
its subsidiaries distributed or sold natural gas outside the
State of Kansas or at the Kansas state line.
(d) During 1993, KG&E purchased 386,887,000 Kwh of electric
energy from outside the State of Kansas or at the Kansas state
line. During 1993, neither KG&E or any of its subsidiaries
engaged in the purchase for resale of natural or manufactured gas
inside or outside the State of Kansas.
KG&E hereby reserves the right to assert that WCNOC is not a
Public Utility for purposes of the Act, and that KG&E is not, by
virtue of its ownership interest in WCNOC, required to seek or
file an exemption under the Act as a public utility holding
Company. KG&E makes this filing at this time in order to
preserve all rights it may have under the Act.
The above-named claimant has caused this statement to be
duly executed on its behalf by its authorized officer on this
28th day of February, 1994.
KANSAS GAS AND ELECTRIC COMPANY
By:__________________________
Richard D. Terrill
Secretary, Treasurer and
General Counsel
Corporate Seal
Name, title and address of officer to whom notices and
correspondence concerning this statement should be addressed:
Richard D. Terrill
Secretary, Treasurer and General Counsel
Kansas Gas and Electric Company
c/o Western Resources, Inc.
P.O. Box 889
818 Kansas Avenue
Topeka, Kansas 66601
EXHIBIT A
A consolidating statement of income and surplus of the
claimant and its subsidiary companies for the last calendar year,
together with a consolidating balance sheet of claimant and its
subsidiary companies as of the close of such calendar year:
Statements of income and surplus and balance sheets of KG&E
are attached.
In conformance with prior discussions with the Commission's
staff these financial statements are not consolidating financial
statements and financial statements of WCNOC are omitted because:
WCNOC is the operating agent for the Wolf Creek
Generating Station and is owned 47% by KG&E. KG&E's
$47 investment in WCNOC is carried in Other Property
and Investment - Other on the balance sheet. All
assets of the Wolf Creek Generating Station are owned
by KG&E, KCPL and KEPCo, the "Owners". WCNOC operates
solely as an agent of the Owners, and therefore, KG&E
classifies, in its financial statements, the payables,
expenses and receipts (if any) incurred by WCNOC as if
such items had been incurred by KG&E. WCNOC has no
revenue or income. Payment for expenses are made from
checking accounts owned and funded by the Owners.
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of Dollars)
December 31,
1993 1992
ASSETS
UTILITY PLANT:
Electric plant in service (Notes 1, 6, and 12). . . . . . $3,339,832 $3,293,365
Less - Accumulated depreciation . . . . . . . . . . . . . 790,843 724,188
2,548,989 2,569,177
Construction work in progress . . . . . . . . . . . . . . 28,436 29,634
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 29,271 33,312
Net utility plant . . . . . . . . . . . . . . . . . . . 2,606,696 2,632,123
OTHER PROPERTY AND INVESTMENTS:
Decommissioning trust (Note 3). . . . . . . . . . . . . . 13,204 9,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 10,941 13,855
24,145 23,127
CURRENT ASSETS:
Cash and cash equivalents (Note 2). . . . . . . . . . . . 63 892
Accounts receivable and unbilled revenues (net)(Note 6) . 11,112 10,543
Advances to parent company (Note 14). . . . . . . . . . . 192,792 74,289
Fossil fuel, at average cost, . . . . . . . . . . . . . . 7,594 16,101
Materials and supplies, at average cost . . . . . . . . . 29,933 31,453
Prepayments and other current assets. . . . . . . . . . . 14,995 7,820
256,489 141,098
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 9) . . . . . . . . . . 113,479 138,361
Deferred coal contract settlement costs (Note 4). . . . . 21,247 24,520
Phase-in revenues (Note 4). . . . . . . . . . . . . . . . 78,950 96,495
Other deferred plant costs. . . . . . . . . . . . . . . . 32,008 32,212
Corporate-owned life insurance (net) (Note 2) . . . . . . 45 144,547
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 54,420 46,749
300,149 482,884
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,187,479 $3,279,232
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statement). . . . . . . . . . . . . . . $1,899,221 $2,009,227
CURRENT LIABILITIES:
Short-term debt (Note 5). . . . . . . . . . . . . . . . . 155,800 93,500
Long-term debt due within one year (Note 6) . . . . . . . 238 228
Accounts payable. . . . . . . . . . . . . . . . . . . . . 51,095 60,908
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 12,185 17,684
Accrued interest. . . . . . . . . . . . . . . . . . . . . 7,381 10,935
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 9,427 5,963
236,126 189,218
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Notes 1 and 9) . . . . . . . . . . 646,159 671,196
Deferred investment tax credits (Note 9). . . . . . . . . 78,048 73,939
Deferred gain from sale-leaseback (Note 7). . . . . . . . 261,981 271,621
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 65,944 64,031
1,052,132 1,080,787
COMMITMENTS AND CONTINGENCIES (Notes 3 and 10)
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,187,479 $3,279,232
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Thousands of Dollars)
Year Ended December 31,
1992
Pro Forma April 1 | January 1
1993 1992 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
|
OPERATING REVENUES (Notes 2 and 4). . . . $ 616,997 $ 554,251 $ 423,538 | $ 130,713 $ 594,968
|
OPERATING EXPENSES: |
Fuel used for generation: |
Fossil fuel . . . . . . . . . . . . . 93,388 73,785 53,701 | 20,084 97,159
Nuclear fuel. . . . . . . . . . . . . 13,275 12,558 10,126 | 2,432 8,593
Power purchased . . . . . . . . . . . . 9,864 8,746 3,207 | 5,539 7,811
Other operations. . . . . . . . . . . . 118,948 129,083 91,436 | 37,647 148,312
Maintenance . . . . . . . . . . . . . . 46,740 46,702 35,956 | 10,746 52,934
Depreciation and amortization . . . . . 75,530 74,696 55,547 | 19,149 75,115
Amortization of phase-in revenues . . . 17,545 17,544 13,158 | 4,386 17,545
Taxes (see statement): |
Federal income. . . . . . . . . . . . 39,553 16,305 17,523 | (1,218) 17,569
State income . . . . . . . . . . . . 9,570 4,264 4,732 | (468) 5,307
General . . . . . . . . . . . . . . . 45,203 40,406 30,155 | 10,251 38,540
Total operating expenses. . . . . . 469,616 424,089 315,541 | 108,548 468,885
|
OPERATING INCOME. . . . . . . . . . . . . 147,381 130,162 107,997 | 22,165 126,083
|
OTHER INCOME AND DEDUCTIONS: |
Investment income . . . . . . . . . . . 629 1,367 953 | 414 3,147
Corporate-owned life insurance (net). . 7,841 10,724 9,308 | 1,416 4,615
Miscellaneous (net) (Note 3). . . . . . 8,642 6,506 8,464 | (1,958) (12,844)
Income taxes (net) (see statement). . . 2,227 191 (1,296) | 1,487 6,921
Total other income and deductions . 19,339 18,788 17,429 | 1,359 1,839
|
INCOME BEFORE INTEREST CHARGES. . . . . . 166,720 148,950 125,426 | 23,524 127,922
|
INTEREST CHARGES: |
Long-term debt. . . . . . . . . . . . . 53,908 57,862 42,889 | 14,973 59,668
Other . . . . . . . . . . . . . . . . . 6,075 15,121 11,777 | 3,344 17,838
Allowance for borrowed funds used during |
construction (credit) . . . . . . . . (1,366) (2,014) (1,181) | (833) (3,186)
Total interest charges. . . . . . . 58,617 70,969 53,485 | 17,484 74,320
|
NET INCOME. . . . . . . . . . . . . . . . 108,103 77,981 71,941 | 6,040 53,602
|
PREFERRED DIVIDENDS . . . . . . . . . . . - - - | 205 821
|
EARNINGS APPLICABLE TO COMMON STOCK . . . $ 108,103 $ 77,981 $ 71,941 | $ 5,835 $ 52,781
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year Ended December 31,
1992
March 31 | January 1
1993 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net income. . . . . . . . . . . . . . . . . . . . . . $ 108,103 $ 71,941 | $ 6,040 $ 53,602
Depreciation and amortization . . . . . . . . . . . . 75,530 55,547 | 19,149 75,115
Other amortization (incl. nuclear fuel) . . . . . . . 11,254 8,929 | 1,352 6,014
Deferred taxes and investment tax credits (net) . . . 22,572 9,326 | (2,851) 3,525
Amortization of phase-in revenues . . . . . . . . . . 17,545 13,158 | 4,386 17,545
Corporate-owned life insurance. . . . . . . . . . . . (21,650) (14,704) | (3,295) (11,986)
Coal contract settlements (Note 4). . . . . . . . . . - - | - (8,500)
Amortization of gain from sale-leaseback. . . . . . . (9,640) (7,231) | (2,409) (9,641)
Changes in working capital items: |
Accounts receivable and unbilled |
revenues (net) (Note 2) . . . . . . . . . . . . . (569) 1,079 | 1,272 346
Fossil fuel . . . . . . . . . . . . . . . . . . . . 8,507 4,425 | (1,858) 3,631
Accounts payable. . . . . . . . . . . . . . . . . . (9,813) (7,216) | (6,100) 15,421
Interest and taxes accrued. . . . . . . . . . . . . (9,053) (14,345) | 10,598 1,296
Other . . . . . . . . . . . . . . . . . . . . . . . (2,191) (8,456) | 1,689 (5,832)
Changes in other assets and liabilities . . . . . . . (16,530) (41,401) | (5,479) 3,947
Net cash flows from operating activities. . . . . . 174,065 71,052 | 22,494 144,483
|
CASH FLOWS USED IN INVESTING ACTIVITIES: |
Additions to utility plant. . . . . . . . . . . . . . 66,886 53,138 | 11,496 74,348
Corporate-owned life insurance policies . . . . . . . 27,268 20,233 | 6,802 27,349
Death proceeds of corporate-owned life insurance. . . (10,160) (6,789) | - -
Purchase of short-term investments . . . . . . . . . - - | - 742
Proceeds from short-term investments. . . . . . . . . - - | - (22,097)
Other investments . . . . . . . . . . . . . . . . . . - - | (552) 1,142
Merger: |
Purchase of KG&E common stock-net of cash received. - 432,043 | - -
Purchase of KG&E preferred stock. . . . . . . . . . - 19,665 | - -
Net cash flows used in investing activities . . . 83,994 518,290 | 17,746 81,484
|
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: |
Short-term debt (net) . . . . . . . . . . . . . . . . 62,300 49,900 | 5,800 7,800
Advances to parent company (net). . . . . . . . . . . (118,503) (74,289) | - -
First mortgage bonds issued . . . . . . . . . . . . . 65,000 135,000 | - 323,406
First mortgage bonds retired. . . . . . . . . . . . . (140,000) (125,000) | - (57,000)
Other long-term debt (net). . . . . . . . . . . . . . 7,043 14,498 | (3,810) (377,031)
Borrowings against life insurance policies (net). . . 183,260 (5,649) | 6,398 3,590
Revolving credit agreement (net). . . . . . . . . . . (150,000) - | - 80,000
Special deposits (net). . . . . . . . . . . . . . . . - - | - 13,263
Other (net) . . . . . . . . . . . . . . . . . . . . . - - | (17) 31
Dividends on preferred and common stock . . . . . . . - - | (13,535) (54,143)
Financing expenses. . . . . . . . . . . . . . . . . . - - | - (8,508)
Issuance of KCA common stock. . . . . . . . . . . . . - 453,670 | - -
Net cash flows from (used in) financing activities (90,900) 448,130 | (5,164) (68,592)
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . (829) 892 | (416) (5,593)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . 892 - | 2,378 7,971
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . $ 63 $ 892 | $ 1,962 $ 2,378
|
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION |
CASH PAID FOR: |
Interest on financing activities (net of amount |
capitalized) . . . . . . . . . . . . . . . . . . $ 77,653 $ 63,451 | $ 11,635 $ 89,901
Income taxes . . . . . . . . . . . . . . . . . . . . 29,354 14,225 | - 11,350
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF TAXES
(Thousands of Dollars)
Year Ended December 31,
1992
April 1 | January 1
1993 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
FEDERAL INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . $ 19,220 $ 11,356 | $ (322) $ 11,023
Deferred (net). . . . . . . . . . . . . . . . . . . 16,691 8,633 | (1,785) 64
Investment tax credit-Deferral. . . . . . . . . . . 4,900 946 | - 3,622
-Amortization. . . . . . . . . (3,114) (2,400) | (777) (2,913)
Total Federal income taxes . . . . . . . . . . . 37,697 18,535 | (2,884) 11,796
Income taxes applicable to non-operating items. . . . 1,856 (1,012) | 1,666 5,773
Total Federal income taxes charged to operations 39,553 17,523 | (1,218) 17,569
|
STATE INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . 5,104 2,869 | - 1,407
Deferred (net). . . . . . . . . . . . . . . . . . . 4,095 2,147 | (289) 2,752
Total state income taxes . . . . . . . . . . . . 9,199 5,016 | (289) 4,159
Income taxes applicable to non-operating items. . . 371 (284) | (179) 1,148
Total state income taxes charged to operations . 9,570 4,732 | (468) 5,307
|
GENERAL TAXES: |
Property. . . . . . . . . . . . . . . . . . . . . . 38,432 26,380 | 8,622 32,755
Payroll and other taxes . . . . . . . . . . . . . . 6,771 3,775 | 1,629 5,785
Total general taxes charged to operations. . . . 45,203 30,155 | 10,251 38,540
|
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 94,326 $ 52,410 | $ 8,565 $ 61,416
Year Ended December 31,
Pro Forma
1993 1992 1991
(Successor) (Predecessor)
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 30% 21% 23%
Effect of:
Additional depreciation . . . . . . . . . . . . . . (2) (4) (8)
Accelerated amortization of deferred income
tax credits. . . . . . . . . . . . . . . . . . 7 11 15
State income taxes, net of Federal benefit. . . . . (4) (2) (4)
Amortization of investment tax credits. . . . . . . 2 2 4
Corporate-owned life insurance. . . . . . . . . . . 5 6 6
Other items (net) . . . . . . . . . . . . . . . . . (3) - (2)
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 34% 34%
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)
December 31,
1993 1992
COMMON STOCK EQUITY (Note 1):
(see statement)
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 56.1% $1,065,634 53.0%
Retained earnings . . . . . . . . . . . . . . . . . . . . . 180,044 9.5 71,941 3.6
Total common stock equity . . . . . . . . . . . . . . . . 1,245,678 65.6 1,137,575 56.6
LONG-TERM DEBT (Note 6):
First Mortgage Bonds:
Series Due 1993 1992
5-5/8% 1996 $ 16,000 $ 16,000
8-1/8% 2001 - 35,000
7-3/8% 2002 - 25,000
7.6% 2003 135,000 135,000
6.5% 2005 65,000 -
8-3/8% 2006 - 25,000
8-1/2% 2007 - 25,000
8-7/8% 2008 - 30,000
216,000 291,000
Pollution Control Bonds:
5-7/8% 2007 21,940 21,940
6% 2007 10,000 10,000
6.8% 2004 14,500 14,500
7% 2031 327,500 327,500
373,940 373,940
Total bonds. . . . . . . . . . . . . . . . . . . . . . 589,940 664,940
Other Long-Term Debt:
Pollution control obligations:
5-3/4% series 2003 13,980 14,205
Revolving credit agreement 1993 - 150,000
Other long-term agreement 1995 53,913 46,640
Total other long-term debt . . . . . . . . . . . . . . 67,893 210,845
Unamortized premium and discount (net). . . . . . . . . . . (4,052) (3,905)
Long-term debt due within one year. . . . . . . . . . . . . (238) (228)
Total long-term debt . . . . . . . . . . . . . . . . . 653,543 34.4 871,652 43.4
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,899,221 100.0% $2,009,227 100.0%
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON STOCK EQUITY
(Thousands of Dollars, Except Shares)
Years Ended December 31,
Other
Common Stock Paid-in Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total
BALANCE DECEMBER 31, 1990. . 40,996,185 636,986 270 171,139 (9,996,426) (199,255) 609,140
(Predecessor)
Net income . . . . . . . . 53,602 53,602
Cash dividends:
Common stock . . . . . . (53,322) (53,322)
Preferred stock. . . . . (821) (821)
Employee stock plans . . . 1,560 17 14 31
BALANCE DECEMBER 31, 1991. . 40,997,745 637,003 284 170,598 (9,996,426) (199,255) 608,630
(Predecessor)
Net income . . . . . . . . 6,040 6,040
Cash dividends:
Common stock . . . . . . (13,330) (13,330)
Preferred stock. . . . . (205) (205)
Employee stock plans . . . (12) (966) (12)
Merger of KG&E with KCA. . (40,997,745) (636,991) (284) (163,103) 9,997,392 199,255 (601,123)
BALANCE MARCH 31, 1992
(Predecessor). . . . . . . -0- -0- -0- -0- -0- -0- -0-
KCA common stock issued. . 1,000 $1,065,634 - - - - $1,065,634
Net income . . . . . . . . $ 71,941 71,941
BALANCE DECEMBER 31, 1992. . 1,000 1,065,634 - 71,941 - - 1,137,575
(Successor)
Net income . . . . . . . . 108,103 108,103
BALANCE DECEMBER 31, 1993. . 1,000 $1,065,634 $ - $ 180,044 - $ - $1,245,678
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ACQUISITION AND MERGER
On March 31, 1992, Western Resources, Inc. (formerly The Kansas Power and
Light Company) (Western Resources) through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company (KG&E) for $454 million in cash and
23,479,380 shares of Western Resources common stock (the Merger). Western
Resources also paid $20 million in costs to complete the Merger. The total
cost of the acquisition to Western Resources was $1.066 billion.
Simultaneously, KCA and KG&E merged and adopted the name of Kansas Gas and
Electric Company. The Merger was accounted for as a purchase. For income tax
purposes the tax basis of the Company's assets was not changed by the Merger.
In the accompanying statements, KG&E prior to the Merger is labeled as the
"Predecessor" and after the Merger as the "Successor". Throughout the notes
to financial statements, the "Company, KG&E" refers to both Predecessor and
Successor.
As Western Resources acquired 100% of the common and preferred stock of
KG&E, the Company has recorded an acquisition premium of $490 million on the
balance sheet for the difference in purchase price and book value and
increased common stock equity to reflect the new cost basis of Western
Resources' investment in the Company. This acquisition premium and related
income tax requirement of $294 million under Statement of Financial Accounting
Standards No. 109 (SFAS 109) have been classified as plant acquisition
adjustment in electric plant in service on the balance sheet. For income tax
purposes the tax basis of KG&E assets was not changed as the result of the
Merger. Under the provisions of the order of the Kansas Corporation
Commission (KCC), the acquisition premium is recorded as an acquisition
adjustment and not allocated to the other assets and liabilities of the
Company.
The pro forma information for the year ended December 31, 1992 in the
accompanying financial statements gives effect to the Merger as if it occurred
on January 1, 1992, and was derived by combining the historical information
for the three month period ended March 31, 1992 and the nine month period
ended December 31, 1992. No purchase accounting adjustments were made for
periods prior to the Merger in determining pro forma amounts, other than the
elimination of preferred dividends, because such adjustments would be
immaterial. This pro forma information is not necessarily indicative of the
results of operations that would have occurred had the Merger been consummated
on January 1, 1992, nor is it necessarily indicative of future operating
results or financial position. The pro forma effects on the Company's net
income for 1991 presented giving effect to the Merger as if it had occurred at
the beginning of the earliest period presented would not be materially
different from that shown in the income statements included herein.
In the November 1991 KCC order approving the Merger, a mechanism was
approved to share equally between the shareholders and ratepayers the cost
savings generated by the Merger in excess of the revenue requirement needed to
allow recovery of the amortization of a portion of the acquisition adjustment,
including income tax, calculated on the basis of a purchase price of KG&E's
common stock at $29.50 per share. The order provides an amortization period
for the acquisition adjustment of 40 years commencing in August 1995, at which
time the full amount of cost savings is expected to have been implemented.
Merger savings will be measured by application of an inflation index to
certain pre-merger operating and maintenance costs at the time of the next
Kansas rate case. While the Company has achieved savings from the Merger,
there is no assurance that the savings achieved will be sufficient to, or the
cost savings sharing mechanism will operate as to fully offset the
amortization of the acquisition adjustment. The order further provides a
moratorium on increases, with certain exceptions, in the Company's Kansas
electric rates until August 1995. The KCC ordered refunds totalling $32
million to the combined companies' (Western Resources and the Company)
customers to share with customers the Merger-related cost savings achieved
during the moratorium period. The first refund was made in April 1992 and
amounted to approximately $4.9 million for the Company. A refund of
approximately $4.9 million was made in December 1993 and an additional refund
of approximately $8.7 million will be made in September 1994.
The KCC order approving the Merger requires the legal reorganization of
the Company so that it is no longer held as a separate subsidiary after
January 1, 1995, unless good cause is shown why such separate existence should
be maintained. The Securities and Exchange Commission order relating to the
Merger granted Western Resources an exemption under the Public Utilities
Holding Company Act until January 1, 1995. In connection with a requested
ruling that a merger of the Company into Western Resources would not adversely
affect the tax structure of the merger, the Company received a response from
the Internal Revenue Service that the IRS would not issue the requested
ruling. In light of the IRS response, the Company withdrew its request for a
ruling. The Company will consider alternative forms of combination or seek
regulatory approvals to waive the requirements for a combination. There is no
certainty as to whether a combination will occur or as to the form or timing
thereof.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The financial statements of KG&E include, through March 31,
1992, its 80% owned subsidiary, CIC Systems, Inc. (CIC). In April 1992, the
Company disposed of its 80% interest in CIC. KG&E owns 47 percent of Wolf
Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf
Creek Generating Station (Wolf Creek). The Company records its proportionate
share of all transactions of WCNOC as it does other jointly-owned facilities.
The accounting policies of the Company are in accordance with generally
accepted accounting principles as applied to regulated public utilities. The
accounting and rates of the Company are subject to requirements of the KCC and
the Federal Energy Regulatory Commission (FERC).
Utility Plant: Utility plant (including plant acquisition adjustment) is
stated at cost. For constructed plant, cost includes contracted services,
direct labor and materials, indirect charges for engineering, supervision,
general and administrative costs, and an allowance for funds used during
construction (AFUDC). The AFUDC rate was 5.5% for 1993, 6.51% for the nine
months ended December 31, 1992, 6.70% for the three months ended March 31,
1992, and 7.74% for 1991. The cost of additions to utility plant and
replacement units of property is capitalized. Maintenance costs and
replacement of minor items of property are charged to expense as incurred.
When units of depreciable property are retired, they are removed from the
plant accounts and the original cost plus removal charges less salvage are
charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.9% during 1993, 2.9% during the nine months ended
December 31, 1992, 3.0% during the three months ended March 31, 1992, and 3.0%
during 1991 of the average original cost of depreciable property.
Cash and Cash Equivalents: For purposes of the Statements of Cash Flows,
cash and cash equivalents include cash on hand and highly liquid
collateralized debt instruments purchased with maturities of three months or
less.
Income Taxes: Income tax expense includes provisions for income taxes
currently payable and deferred income taxes calculated in conformance with
income tax laws, regulatory orders and SFAS 109 (see Note 9).
Investment tax credits are deferred as realized and amortized to income
over the life of the property which gave rise to the credits.
Revenues: Operating revenues include amounts actually billed for
services rendered and an accrual of estimated unbilled revenues. Unbilled
revenues represent the estimated amount customers will be billed for service
provided from the time meters were last read to the end of the accounting
period. Unbilled revenues of $22.3 and $16.6 million at December 31, 1993 and
1992, respectively, are recorded as a component of accounts receivable on the
balance sheets. Certain amounts of unbilled revenues have been sold (see Note
6).
The Company had reserves for doubtful accounts receivable of $3.0 and
$2.4 million at December 31, 1993 and 1992, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement,
conversion, enrichment and fabrication is recorded as an asset at original
cost and is amortized to expense based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel
in the reactor at December 31, 1993 and 1992 was $17.4 and $26.0 million,
respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts
related to corporate-owned life insurance contracts (COLI), primarily with one
highly rated major insurance company, are recorded on the balance sheets
(millions of dollars):
1993 1992
Cash surrender value of contracts. . . $269.1 $230.3
Prepaid COLI . . . . . . . . . . . . . 9.5 4.8
Borrowings against contracts . . . . . (269.0) (85.8)
COLI net . . . . . . . . . . . . . $ 9.6 $149.3
The decrease in COLI (net) is a result of increased borrowings against
the accumulated cash surrender value of the COLI policies. The COLI
borrowings will be repaid with proceeds from death benefits. Management
expects to realize increases in cash surrender value of contracts resulting
from premiums and investment earnings on a tax free basis upon receipt of net
proceeds from death benefits under the contracts. Interest expense included
in corporate-owned life insurance (net) on the statements of income was $11.9
million for 1993, $5.3 million for the nine months ended December 31, 1992,
$1.9 million for the three months ended March 31, 1992, and $7.3 for 1991.
As approved by the Kansas Corporation Commission (KCC), the Company is
using a portion of the net income stream generated by COLI policies purchased
in 1993 and 1992 (see Note 8) to offset Statement of Financial Accounting
Standards No. 106 (SFAS 106) expenses.
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
3. COMMITMENTS AND CONTINGENCIES
Environmental: The Company and the Kansas Department of Health and
Environment entered into a consent agreement to perform preliminary
assessments of six former manufactured gas sites. The preliminary assessments
of these sites have been completed at minimal cost. Until such time that risk
assessments are completed at these sites, it will be impossible to predict the
cost of remediation. However, the Company is aware of other utilities in
Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have
incurred remediation costs for such sites ranging between $500,000 and $10
million, depending on the site. The Company is also aware that the KCC has
permitted another Kansas utility to recover a portion of the remediation costs
through rates. To the extent that such remediation costs are not recovered
through rates, the costs could be material to the Company's financial position
or results of operations depending on the degree of remediation and number of
years over which the remediation must be completed.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982,
the U.S. Department of Energy (DOE) is responsible for the ultimate storage
and disposal of spent nuclear fuel removed from nuclear reactors. Under a
contract with the DOE for disposal of spent nuclear fuel, the Company pays a
quarterly fee to DOE of one mill per kilowatthour of net nuclear generation.
These fees are included as part of nuclear fuel expense and amounted to $3.5
million for 1993, $1.6 million for the nine months ended December 31, 1992,
$.5 million for the three months ended March 31, 1992, and $2.8 million for
1991.
Decommissioning: The Company's share of Wolf Creek decommissioning
costs, currently authorized in rates, was estimated to be approximately $97
million in 1988 dollars. Decommissioning costs are being charged to operating
expenses. Amounts so expensed are deposited in an external trust fund and
will be used solely for the physical decommissioning of the plant. Electric
rates charged to customers provide for recovery of these decommissioning costs
over the estimated life of Wolf Creek. At December 31, 1993 and 1992, $13.2
and $9.3 million respectively, were on deposit in the decommissioning fund.
On September 1, 1993, WCNOC filed an application with the KCC for an order
approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the
Company's share of Wolf Creek decommissioning costs at approximately $174
million in 1993 dollars. If approved by the KCC, management expects
substantially all such cost increases to be recovered through the ratemaking
process.
The Company carries $164 million in premature decommissioning insurance
in the event of a shortfall in the trust fund. The insurance coverage has
several restrictions. One of these is that it can only be used if Wolf Creek
incurs an accident exceeding $500 million in expenses to safely stabilize the
reactor, to decontaminate the reactor and reactor station site in accordance
with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay
for on-site property damages. If the amount designated as decommissioning
insurance is needed to implement the NRC-approved plan for stabilization and
decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.4 billion for a single
nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum
available private insurance of $200 million and the balance is provided by an
assessment plan mandated by the NRC. Under this plan, the Owners are jointly
and severally subject to a retrospective assessment of up to $79.3 million
($37.3 million, Company's share) in the event there is a nuclear incident
involving any of the nation's licensed reactors. This assessment is subject
to an inflation adjustment based on the Consumer Price Index. There is a
limitation of $10 million ($4.7 million, Company's share) in retrospective
assessments per incident per year.
The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totalling
approximately $2.8 billion ($1.3 billion, Company's share). This insurance is
provided by a combination of "nuclear insurance pools" ($1.3 billion) and
Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The remaining proceeds from the $2.8 billion insurance
coverage ($1.3 billion, Company's share), if any, can be used for property
damage up to $1.1 billion (Company's share) and premature decommissioning
costs up to $117.5 million (Company's share) in excess of funds previously
collected for decommissioning (as discussed under "Decommissioning"), with the
remaining $47 million (Company's share) available for either property damage
or premature decommissioning costs.
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 losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves, and other NEIL resources, the Company may be subject to
retrospective assessments of approximately $9 million per year.
There can be no assurance that all potential losses or liabilities will
be insurable or that the amount of insurance will be sufficient to cover them.
Any substantial losses not covered by insurance, to the extent not recoverable
through rates, could have a material adverse effect on the Company's financial
condition and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in sulfur dioxide and nitrous oxide emissions effective in
1995 and 2000 and a probable reduction in toxic emissions. To meet the
monitoring and reporting requirements under the acid rain program, the Company
is installing continuous monitoring and reporting equipment at a total cost of
approximately $2.3 million. At December 31, 1993, the Company had completed
approximately $850 thousand of these capital expenditures with the remaining
$1.4 million of capital expenditures to be completed in 1994 and 1995. The
Company does not expect additional equipment to reduce sulfur emissions to be
necessary under Phase II. The Company currently has no Phase I affected
units.
The nitrous oxide and toxic limits, which were not set in the law, will
be specified in future EPA regulations. The EPA has issued for public comment
preliminary nitrous oxide regulations for Phase I group 1 units. Nitrous
oxide regulations for Phase II units and Phase I group 2 units are mandated in
the Act to be promulgated by January 1, 1997. Although the Company has no
Phase I units, the final nitrous oxide regulations for Phase I group 1 may
allow for early compliance for Phase II group 1 units. Until such time as the
Phase I group 1 nitrous oxide regulations are final, the Company will be
unable to determine its compliance options or related compliance costs.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS)
completed an examination of the Company's federal income tax returns for the
years 1984 through 1988. In April 1992, the Company received the examination
report and upon review filed a written protest in August 1992. In October
1993, the Company received another examination report for the years 1989 and
1990 covering the same issues identified in the previous examination report.
Upon review of this report, the Company filed a written protest in November
1993. The most significant proposed adjustments reduce the depreciable basis
of certain assets and investment tax credits generated. Management believes
there are significant questions regarding the theory, computations, and
sampling techniques used by the IRS to arrive at its proposed adjustments, and
also believes any additional tax expense incurred or loss of investment tax
credits will not be material to the Company's financial position and results
of operations. Additional income tax payments, if any, are expected to be
offset by investment tax credit carryforwards, alternative minimum tax credit
carryforwards, or deferred tax provisions.
Other Investments: In prior years, the Company routinely purchased
short-term investment grade commercial paper for special deposit interest
accounts associated with tax-exempt pollution control bonds. On February 1,
1990, the Company purchased $6.6 million of Drexel Burnham Lambert Group Inc.
(Drexel) commercial paper. On February 13, 1990, Drexel filed for bankruptcy.
In 1990, additional claims being filed and potential lengthy litigation
indicated full recovery would be unlikely; accordingly, the investment was
written off in 1990. The Company recognized the recovery of approximately
$4.2 million during the nine months ended December 31, 1992, of the
investment, which is included in miscellaneous income.
Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the Company has entered into various commitments to obtain
nuclear fuel, coal, and natural gas. Some of these contracts contain
provisions for price escalation and minimum purchase commitments. At
December 31, 1993, WCNOC's nuclear fuel commitments (Company's share) were
approximately $18.0 million for uranium concentrates expiring at various times
through 1997, $123.6 million for enrichment expiring at various times through
2014, and $45.5 million for fabrication through 2012. At December 31, 1993,
the Company's coal and natural gas contract commitments in 1993 dollars under
the remaining term of the contracts are $666 million and $20.4 million,
respectively. The largest coal contract was renegotiated in early 1993 and
expires in 2020 with the remaining coal contracts expiring at various times
through 2013. The majority of natural gas contracts expire in 1995 with
automatic one-year extension provisions. In the normal course of business,
additional commitments and spot market purchases will be made to obtain
adequate fuel supplies.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment
will be collected from utilities for a uranium enrichment decontamination and
decommissioning fund. The Company's portion of the assessment for Wolf Creek
is approximately $7 million, payable over 15 years. Management expects such
costs to be recovered through the ratemaking process.
4. RATE MATTERS AND REGULATION
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26,
1992, in connection with the Merger, the KCC approved the elimination of the
ECA for most retail customers effective April 1, 1992. The provisions for
fuel costs included in base rates were established at a level intended by the
KCC to equal the projected average cost of fuel through August 1995 and to
include recovery of costs provided by previously issued orders relating to
coal contract settlements and storm damage recovery discussed below.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring that
the accrual of phase-in revenues be discontinued effective December 31, 1988.
Effective January 1, 1989, the Company began amortizing the phase-in revenue
asset on a straight-line basis over 9-1/2 years.
Cost of Service Audit Appeal: In September 1991, the KCC ordered the
Company to refund (which the Company has done) $5.6 million of revenues plus
$0.6 million in interest, for the period July 2, 1990 through January 31,
1991. This order concluded the appeal of the February 1990 KCC order to
reduce rates by $8.7 million. The Company had previously recorded reserves
totalling $10.8 million; however, as the order also made rates permanent, the
excess reserves of $3.3 million were reversed in September 1991.
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing the Company to defer its share of a 1989 coal contract settlement
with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million.
This amount is recorded as a deferred charge on the balance sheets. The
settlement resulted in the termination of a long-term coal contract. In June
1991, the KCC permitted the Company to recover this settlement as follows:
76% of the settlement plus a return through its ECA over the remaining term of
the terminated contract (through 2002) and 24% to be amortized to expense with
a deferred return equivalent to the carrying cost of the asset.
In February 1991, the Company paid $8.5 million to settle a coal contract
lawsuit with AMAX Coal Company and recorded the payment as a deferred charge
on the Company's balance sheet. In July 1991, the KCC approved the recovery
of the settlement plus a return equivalent to the carrying cost of the asset,
through the ECA over the remaining term of the terminated contract (through
1996).
Storm Damage Recovery: In October 1990, the Company asked the KCC for
approval of a plan to recover the cost of damage primarily from the March 13
and June 19, 1990 storms. Approximately $15 million of capital expenditures
were incurred. These costs have been included in the Company's electric plant
accounts. In May 1991, the Company amended this request to include the
estimated $5 million of capital expenditures associated with an April 1991
storm. In November 1991 and January 1992, the KCC approved the deferral and
recovery of the capital expenditures of the 1990 and 1991 storms,
respectively, as well as carrying charges thereon.
5. SHORT-TERM BORROWINGS
At December 31, 1993, the Company had bank credit arrangements available
of $35 million. In addition, the Company has uncommitted loan participation
agreements. Maximum short-term borrowings outstanding during 1993 and 1992
were $175.8 million on December 14, 1993 and $128 million on October 6, 1992.
The weighted average interest rates, including fees, were 3.5% for 1993, 6.4%
for the nine months ended December 31, 1992, 7.1% for the three months ended
March 31, 1992, and 7.8% for 1991.
6. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the KG&E Mortgage and
Deed of Trust dated April 1, 1940, as supplemented, is limited to a maximum of
$2 billion. Amounts of additional bonds which may be issued are subject to
property, earnings, and certain restrictive provisions of the Mortgage.
Electric plant is subject to the lien of the Mortgage except for
transportation equipment. During 1993, the Company refinanced $65 million of
first mortgage bonds by issuing $65 million of First Mortgage Bonds, 6 1/2%
Series due 2005. In 1992, the Company refinanced $125 million of first
mortgage bonds by issuing $135 million of First Mortgage Bonds, 7.60% Series
due 2003.
Debt discount and expenses are being amortized over the remaining lives
of each issue. The improvement and maintenance fund requirements for certain
first mortgage bond series can be met by bonding additional property. The
sinking fund requirements for certain pollution control series bonds can be
met only through the acquisition and retirement of outstanding bonds.
The 6.8% series, due 2004, the 6% and 5 7/8% series due 2007 and the 7%
series due 2031 are pledged as collateral for pollution control revenue bonds
issued by Kansas municipalities.
On September 20, 1993, the Company terminated a long-term revolving
credit agreement which provided for borrowings of up to $150 million. The
loan agreement, which was effective through October 1994, was repaid without
penalty. The weighted average interest rate, including fees, was 3.7% for
1993, 6.8% for the nine months ended December 31, 1992, 7.7% for the three
months ended March 31, 1992, and 8.4% for 1991.
The Company has a long-term agreement, expiring in 1995, which contains
provisions for the sale of accounts receivable and unbilled revenues
(receivables) and phase-in revenues up to a total of $180 million. Amounts
related to receivables are accounted for as sales while those related to
phase-in revenues are accounted for as collateralized borrowings. Additional
receivables are continually sold to replace those collected. At December 31,
1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million,
respectively, are considered sold under the agreement. The credit risk
associated with the sale of customer accounts receivable is considered
minimal. The weighted average interest rate, including fees, on this
agreement was 3.7% for 1993, 6.6% for the nine months ended December 31, 1992,
7.9% for the three months ended March 31, 1992, and 7.8% for 1991. At
December 31, 1993, an additional $16.4 million was available under the
agreement.
Bonds maturing and acquisition and retirement of bonds for sinking fund
requirements for the five years subsequent to December 31, 1993 are as
follows:
Maturing Retiring
Year Bonds Bonds
(Dollars in Thousands)
1994. . . . . . . $ - $ 238
1995. . . . . . . - 253
1996. . . . . . . 16,000 270
1997. . . . . . . - 833
1998. . . . . . . - 1,050
7. SALE-LEASEBACK OF LA CYGNE 2
In 1987, the Company sold and leased back its 50 percent undivided
interest in La Cygne 2 generating unit. The lease has an initial term of 29
years, with various options to renew the lease or repurchase the 50 percent
undivided interest. The Company remains responsible for its share of
operation and maintenance costs and other related operating costs of La Cygne
2. The lease is an operating lease for financial reporting purposes.
As permitted under the lease agreement, the Company, in 1992, requested
the Trustee Lessor to refinance $341.1 million of secured facility bonds of
the Trustee and owner of La Cygne 2. The transaction was requested to reduce
recurring future net lease expense. In connection with the refinancing on
September 29, 1992, a one-time payment of approximately $27 million was made
by the Company which has been deferred and is being amortized over the
remaining life of the lease and included in operating expense as part of the
future lease expense.
Future minimum annual lease payments required under the lease agreement
are approximately $34.6 million for each year through 1998 and $715 million
over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale
has been deferred for financial reporting purposes, and is being amortized
over the initial lease term in proportion to the related lease expense. The
Company's lease expense, net of amortization of the deferred gain and the one-
time payment in 1992, was approximately $22.5 million for 1993, $20.6 million
for the nine months ended December 31, 1992, $7.5 million for the three months
ended March 31, 1992, and $30 million for 1991.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension
plans covering substantially all employees of the Company prior to the Merger.
Pension benefits are based on years of service and the employee's compensation
during the five highest paid consecutive years out of ten before retirement.
The Company's
policy is to fund pension costs accrued, subject to limitations set by the
Employee Retirement Income Security Act of 1974 and the Internal Revenue Code.
The following table provides information on the components of pension
cost for the Company's pension plans (millions of dollars):
1992
April 1 | Jan.1 to
1993 to Dec.31 | March 31 1991
(Successor) | (Predecessor)
Pension Cost: |
Service cost . . . . . . . . . . . $ 3.2 $ 2.5 | $ .8 $ 3.1
Interest cost on projected |
benefit obligation . . . . . . . 9.5 6.7 | 2.1 7.4
Return on plan assets. . . . . . . (14.1) (5.8) | (9.0) (14.0)
Net amortization & deferral. . . . 4.9 (1.0) | 6.7 5.4
Net pension cost . . . . . . . . $ 3.5 $ 2.4 | $ .6 $ 1.9
The following table sets forth the plans' actuarial present value and
funded status at November 30, 1993 and 1992 (the plan years) and a
reconciliation of such status to the December 31, 1993 and 1992 financial
statements (millions of dollars):
1993 1992
Funded Status:
Actuarial present value of benefit obligations:
Vested. . . . . . . . . . . . . . . . . . . . . $ 95.2 $ 82.9
Non-vested. . . . . . . . . . . . . . . . . . . 6.1 3.6
Total . . . . . . . . . . . . . . . . . . . . $101.3 $ 86.5
Plan assets at November 30 (principally debt
and equity securities) at fair value. . . . . . $119.9 $113.7
Projected benefit obligation at November 30 . . . (125.5) (110.8)
Plan assets in excess of projected benefit
obligation at November 30 . . . . . . . . . . . (5.6) 2.9
Unrecognized transition asset . . . . . . . . . . (1.7) (2.0)
Unrecognized prior service costs. . . . . . . . . 12.4 12.1
Unrecognized net gain . . . . . . . . . . . . . . (20.6) (26.1)
Accrued pension costs at December 31. . . . . . . $(15.5) $(13.1)
Year Ended December 31, 1993 1992
Actuarial Assumptions:
Discount rate . . . . . . . . . . . . . . . . . 7.0-7.75% 8.0-8.5%
Annual salary increase rate . . . . . . . . . . 5.0 % 6.0%
Long-term rate of return. . . . . . . . . . . . 8.0-8.5 % 8.0-8.5%
Early Retirement and Voluntary Separation Plans: In January 1992, the
Board of Directors approved an early retirement plan and a voluntary
separation program. The voluntary early retirement plan was offered to all
vested participants of the Company's defined benefit pension plan who reached
the age of 55 with 10 or more years of service on or before May 1, 1992.
Certain pension plan improvements were made including a waiver of the
actuarial reduction factors for early retirement and a cash incentive payable
as a monthly supplement up to 60 months or a lump sum payment. Of the 111
employees eligible for the early retirement option, 71, representing 6% of the
Company's work force, elected to retire on or before the May 1, 1992 deadline.
Another 29 employees, with 10 or more years of service, elected to participate
in the voluntary separation program. In addition, 61 employees received
Merger-related severance benefits. The actuarial cost, based on plan
provisions for early retirement and voluntary separation programs, and Merger-
related severance benefits, was approximately $3.9 million of which $1.8
million was included in the pension liability at December 31, 1992. The
actuarial cost was considered in purchase accounting for the Merger (See Note
1).
Postretirement: The Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of
1993. This statement requires the accrual of postretirement benefits other
than pensions, primarily medical benefits costs, during the years an employee
provides service.
Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, the annual expense under SFAS 106 was approximately $3.4 million
in 1993 (as compared to approximately $1.8 million of a cash basis) and the
Company's total obligation was approximately $23.9 million at December 31,
1993. To mitigate the impact of SFAS 106 expense, the Company has implemented
programs to reduce health care costs. In addition, the Company has received
an order from the KCC permitting the initial deferral of SFAS 106 expense. To
mitigate the impact SFAS 106 expense will have on rate increases, the Company
will include in the future computation of cost of service the actual SFAS 106
expense and an income stream generated from corporate-owned life insurance
policies (COLI) purchased in 1993 and 1992. To the extent SFAS 106 expense
exceeds income from the COLI program, this excess will be deferred (as allowed
by FASB Emerging Issues Task Force Issue No. 92-12) and offset by income
generated through the deferral period by the COLI program. Should the income
stream generated by the COLI program not be sufficient to offset the deferred
SFAS 106 expense, the KCC order allows recovery of such deficit through the
ratemaking process.
Prior to the adoption of SFAS 106 the Company's policy was to recognize
expenses as claims were paid. The costs of benefits were $0.8 million for the
nine months ended December 31, 1992, $0.2 million for the three months ended
March 31, 1992, and $2.0 million for 1991.
The following table summarizes the status of the Company's postretirement
plans for financial statement purposes and the related amount included in the
balance sheet:
December 31, 1993
(Dollars in Millions)
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . . $ 12.4
Active employees fully eligible . . . . . . . . 8.4
Active employees not fully eligible . . . . . . 3.1
Unrecognized prior service cost . . . . . . . . (.1)
Unrecognized transition obligation. . . . . . . (20.4)
Unrecognized net loss . . . . . . . . . . . . . (1.7)
Balance sheet liability . . . . . . . . . . . . . . $ 1.7
For measurement purposes, an annual health care cost growth rate of 13%
was assumed for 1994, decreasing to 6% by 2002 and thereafter. The
accumulated post retirement benefit obligation was calculated using a
weighted-average discount rate of 7.75%, a weighted-average compensation
increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%.
The health care cost trend rate has a significant effect on the projected
benefit obligation. Increasing the trend rate by 1% each year would increase
the present value of the accumulated projected benefit obligation by $.6
million and the aggregate of the service and interest cost components by $.1
million.
Postemployment: The FASB has issued Statement of Financial Accounting
Standards No. 112 (SFAS 112), which establishes accounting and reporting
standards for postemployment benefits. The new statement will require the
Company to recognize the liability to provide postemployment benefits when the
liability has been incurred. The Company adopted SFAS 112 effective January
1, 1994. To mitigate the impact adopting SFAS 112 will have on rate
increases, the Company will file an application with the KCC for an order
permitting the initial deferral of SFAS 112 transition costs and expenses and
its inclusion in the future computation of cost of service net of an income
stream generated from COLI. At December 31, 1993, the Company estimates SFAS
112 liability to total approximately $700,000.
Savings Plans: The Company maintains a 401(k) savings plans in which
substantially all employees participate. The Company matches employees'
contributions up to a maximum limit of 3 percent of the employees' salary.
Prior to the Merger, the Company's matching contribution was based on the
Company's performance during the prior year and the level of employee
contributions. The funds of the plans are deposited with a trustee and
invested at each employee's option in one or more investment funds, including
a Western Resources common stock fund. The Company's contributions were $2.9
for 1993, $1.7 million for the nine months ended December 31, 1992, $0.2
million for the three months ended March 31, 1992, and $2.0 million for 1991.
9. INCOME TAXES
The Company adopted SFAS No. 96, Accounting for Income Taxes (SFAS 96) in
1987. This statement required the Company to establish deferred tax assets
and liabilities, as appropriate, for all temporary differences, and to adjust
deferred tax balances to reflect changes in tax rates expected to be in effect
during the periods the temporary differences reverse. SFAS 96 was superseded
by SFAS 109 issued in February 1992 and the Company adopted the provisions of
that standard prospectively in the first quarter of 1992. The accounting for
SFAS 109 is substantially the same as SFAS 96.
In accordance with various rate orders received from the KCC, the Company
has not yet collected through rates the amounts necessary to pay a significant
portion of the net deferred income tax liabilities. As management believes it
is probable that the net future increases in income taxes payable will be
recovered from customers through future rates, it has recorded a deferred
asset for these amounts. These assets are also a temporary difference for
which deferred income tax liabilities have been provided. Accordingly, the
adoption of SFAS 109 did not have a material effect on the Company's results
of operations.
At December 31, 1993, the Company had unused investment tax credits of
approximately $7.1 million available for carryforward to future years which,
if not utilized, will expire in the years 2000 through 2002 (see Note 3). In
addition, the Company has alternative minimum tax credits generated prior to
April 1, 1992, which carryforward without expiration, of $53.9 million which
may be used to offset future regular tax to the extent the regular tax exceeds
the alternative minimum tax. These credits have been applied in determining
the Company's net deferred income tax liability and corresponding deferred
future income taxes at December 31, 1993.
Deferred income taxes result from temporary differences between the
financial statement and tax basis of the Company's assets and liabilities.
The sources of these differences and their cumulative tax effects are as
follows:
December 31, 1993
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (350,105) $ (350,105)
Energy and purchased gas
adjustment clauses . . . . . . . 3,257 - 3,257
Phase-in revenues. . . . . . . . . - (35,573) (35,573)
Deferred gain on sale-leaseback. . 116,186 - 116,186
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (7,797) (7,797)
Deferred compensation/pension
liability. . . . . . . . . . . . 10,856 - 10,856
Acquisition premium. . . . . . . . - (300,814) (300,814)
Deferred future income taxes . . . - (109,178) (109,178)
Other. . . . . . . . . . . . . . . - (12,873) (12,873)
Total Deferred Income Taxes. . . . . $ 170,181 $ (816,340) $ (646,159)
December 31, 1992
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (324,972) $ (324,972)
Energy and purchased gas
adjustment clauses . . . . . . . 2,691 - 2,691
Phase-in revenues. . . . . . . . . - (37,564) (37,564)
Deferred gain on sale-leaseback. . 104,573 - 104,573
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (9,263) (9,263)
Deferred compensation/pension
liability. . . . . . . . . . . . 11,002 - 11,002
Acquisition premium. . . . . . . . - (313,721) (313,721)
Deferred future income taxes . . . - (146,962) (146,962)
Other. . . . . . . . . . . . . . . 3,138 - 3,138
Total Deferred Income Taxes. . . . . $ 161,286 $ (832,482) $ (671,196)
10. LEGAL PROCEEDINGS
The Company is involved in various other legal and environmental
proceedings. Management believes that adequate provision has been made
within the financial statements for these matters and accordingly believes
their ultimate dispositions will not have a material adverse effect upon
the business or financial position of the Company.
A provision of $12 million was recorded in miscellaneous expenses on the 1991
statement of income with respect to various legal matters.
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in Statement of Financial Accounting Standards No. 107:
Cash and Cash Equivalents-
The carrying amount approximates the fair value because of the short-term
maturity of these investments.
Decommissioning Trust-
The fair value of the decommissioning trust is based on quoted market
prices at December 31, 1993 and 1992.
Variable-rate Debt-
The carrying amount approximates the fair value because of the short-term
variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of the estimated
value of each issue taking into consideration the coupon rate, maturity,
and redemption provisions of each issue.
The estimated fair values of the Company's financial instruments are as follows:
Carrying Value Fair Value
December 31, 1993 1992 1993 1992
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . . $ 63 $ 892 $ 63 $ 892
Decommissioning trust. . . 13,204 9,272 13,929 9,500
Variable-rate debt . . . . 478,743 375,909 478,743 375,909
Fixed-rate debt. . . . . . 603,920 679,145 660,750 705,970
12. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50
Jeffrey 1 (b) Jul 1978 65,803 28,717 140 20
Jeffrey 2 (b) May 1980 64,375 25,552 135 20
Jeffrey 3 (b) May 1983 95,336 31,084 140 20
Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with Western Resources, UtiliCorp United Inc., and a third
party
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity represent the Company's share. The Company's share of
operating expenses of the plants in service above, as well as such expenses for
a 50 percent undivided interest in La Cygne 2 (representing 335 MW capacity)
sold and leased back to the Company in 1987, are included in operating
expenses in the statements of income. The Company's share of other
transactions associated with the plants is included in the appropriate
classification in the Company's financial statements.
13. QUARTERLY FINANCIAL STATISTICS (Unaudited)
(Dollars in Thousands)
The amounts in the table are unaudited but, in the opinion of management,
contain all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the results of such periods. The business
of the Company is seasonal in nature and, in the opinion of management,
comparisons between the quarters of a year do not give a true indication of
overall trends and changes in operations.
1993
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr.
(Successor)
Operating revenues. . . . . $136,097 $191,941 $150,478 $138,481
Operating income. . . . . . 26,188 52,874 35,545 32,774
Net income. . . . . . . . . 13,692 46,406 24,274 23,731
Earnings applicable
to common stock . . . . . 13,692 46,406 24,274 23,731
1992
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr.
(Successor) |(Predecessor)
|
Operating revenues. . . . . $127,058 $167,825 $128,655| $130,713
Operating income. . . . . . 29,282 49,541 29,174| 22,165
Net income. . . . . . . . . 15,528 35,987 20,426| 6,040
Earnings applicable |
to common stock . . . . . 15,528 35,987 20,426| 5,835
14. RELATED PARTY TRANSACTIONS
Subsequent to the Merger, the cash management function, including cash
receipts and disbursements, for KG&E has been assumed by Western Resources.
As a result, the proceeds of cash collections, including short-term
borrowings, less disbursements related to KG&E transactions have been recorded
by the Companies through an intercompany account which, at December 31, 1993,
resulted in a net advance by KG&E to Western Resources of $192.8 million.
