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
Western Resources, Inc.
Western Resources, Inc. ("WRI") 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") and submits the following information:
1. WRI is a Kansas corporation whose principal executive offices are
located at 818 Kansas Ave., Topeka, Kansas, 66612. WRI's mailing address is
P.O. Box 889, Topeka, Kansas 66601.
WRI's principal business consists of the generation, transmission,
distribution and sale of electricity and the transportation and sale of
natural gas. Currently, WRI provides retail electric service to approximately
322,000 industrial, commercial, and residential customers in 323 Kansas
communities. WRI also provides wholesale electric generation and transmission
services to numerous municipal customers located in Kansas and, through
interchange agreements, to surrounding integrated systems. As a natural gas
utility, WRI distributes gas in Kansas and northeastern Oklahoma. WRI
provides natural gas service to approximately 643,000 retail customers.
WRI's subsidiaries are as follows:
Kansas Gas and Electric Company ("KGE") is a Kansas corporation with its
principal offices at 120 East First Street, Wichita, Kansas, 67201. KGE
provides electric services to customers in the southeastern portion of Kansas,
including the Wichita metropolitan area. At December 31, 1994, it rendered
electric services at retail to approximately 272,000 residential, commercial
and industrial customers and provides wholesale electric generation and
transmission services to numerous municipal customers located in Kansas, and
through interchange agreements, to surrounding integrated systems. KG&E does
not own or operate any gas properties.
Astra Resources, Inc. ("Astra") is a Kansas corporation with principal
offices at 1021 Main, Houston, Texas, 77002. Astra is a holding company for
non-utility activities, concentrating in the areas of natural gas gathering,
processing, compression and marketing.
KPL Funding, Inc. is a Kansas corporation established in connection with
the acquisition of KG&E.
The Kansas Power and Light Company is a Kansas corporation established
for the purpose of preserving the former corporate name of WRI in the state of
Kansas.
2(a). The principal electric generating stations of WRI, all of which
are located in Kansas, are as follows:
Accredited
Capacity - MW
Name and Location (WRI's Share)
Coal
JEC Unit 1, near St. Marys................... 447
JEC Unit 2, near St. Marys................... 457
JEC Unit 3, near St. Marys................... 448
Lawrence Energy Center, near Lawrence........ 539
Tecumseh Energy Center, near Tecumseh........ 236
Subtotal........................... 2,127
Gas/Oil
Hutchinson Energy Center, near Hutchinson.... 502
Abilene Energy Center, near Abilene.......... 65
Tecumseh Energy Center, near Tecumseh........ 38
Subtotal........................... 605
Total Accredited Capacity 2,732 MW
WRI maintains 19 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. WRI is also a
member of the Southwest Power Pool, the regional coordinating council for
electric utilities throughout the south-central United States.
WRI 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. In addition, WRI owns and operates transmission, distribution and other
facilities related to supplying natural gas service to its customers in Kansas
and Oklahoma.
2(b). The principal electric generating stations of KG&E, all of which are
located in Kansas, are as follows:
Accredited
Capacity - MW
Name and Location (KG&E's Share)
Nuclear
Wolf Creek, near Burlington ................. 545
Coal
LaCygne Unit 1, near LaCygne ................ 343
LaCygne Unit 2, near LaCygne ................ 335
JEC Unit 1, near St. Mary's ................. 140
JEC Unit 2, near St. Mary's ................. 143
JEC Unit 3, near St. Mary's ................. 140
Subtotal .......................... 1,101
Gas/Oil
Gordon Evans, Wichita ....................... 517
Murray Gill, Wichita ........................ 332
Subtotal .......................... 849
Diesel
Wichita, Wichita ............................ 3
Total Accredited Capacity 2,498 MW
KG&E maintains 17 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. 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
supplyits 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. In addition KG&E owns 47% interest in Wolf Creek Nuclear Operating
Corporation (WCNOC) a Delaware corporation. WCNOC operates the Wolf Creek
Generating Station on behalf of and as agent for its owners. KG&E has reserved
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.
3(a). For the year ended December 31, 1994, WRI sold 8,018,990,000 Kwh of
electric energy at retail, 2,309,303,000 Kwh of electric energy at wholesale,
and 91,978,000 Mcf of natural gas at retail. In early 1994, WRI sold its
Missouri natural gas operations which accounted for 14,020,000 Mcf of such
retail sales. For the year ended December 31, 1994, KG&E sold 7,867,868,000
Kwh of electric energy at retail and 1,589,974,000 Kwh of electric energy at
wholesale. All of KG&E's sales were within the State of Kansas.
(b). During 1994, neither WRI nor its subsidiaries distributed or
sold electric energy at retail outside the State of Kansas. During 1994, WRI
distributed or sold at retail 4,113,000 Mcf of natural gas in the state of
Oklahoma, representing 4.5% of the retail natural gas sales of WRI.
(c). During 1994, WRI sold, at wholesale, 284,798,000 Kwh of
electric energy to adjoining public utilities through interconnections at the
Kansas state line. During 1994, KG&E sold, at wholesale, 802,195,000 Kwh of
electric energy to adjoining public utilities through interconnections at the
Kansas state line. During 1994, neither WRI or KG&E sold natural or
manufactured gas at wholesale outside the state of Kansas or at the Kansas state
line.
(d). During 1994, WRI purchased 289,503,000 Kwh of electric energy
from outside the State of Kansas or at the Kansas state line. During 1994, WRI
purchased 12,328,906 Mcf of natural gas outside the state of Kansas or at the
state line. During 1994, KG&E purchased 302,079,000 Kwh of electric energy from
outside the State of Kansas or at the Kansas State line.
4. Neither WRI nor its subsidiaries hold, directly or indirectly, any
interest in an EWG or a foreign company.
The above-named claimant has caused this statement to be duly executed on
its behalf by its authorized officer on this 24th day of February, 1995.
Western Resources, Inc.
By: Richard D. Terrill
Richard D. Terrill
Secretary and Associate
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 and Associate General Counsel
Western Resources, Inc.
P.O. Box 889
818 Kansas Avenue
Topeka, Kansas 66601
PAGE
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:
PAGE
Exhibit A
WESTERN RESOURCES, INC.
CONSOLIDATING BALANCE SHEET
December 31, 1994
(Dollars in Thousands)
Kansas Gas GSEC and Consolid- Western
Western and KPL Astra ating Ad- Resources
Resources Electric Funding Resources justments Consolidated
ASSETS
UTILITY PLANT:
Electric plant in service . . . . . . . . . $1,835,769 $3,390,406 $ - $ - $ - $5,226,175
Natural gas plant in service. . . . . . . . 737,191 - - - - 737,191
2,572,960 3,390,406 - - - 5,963,366
Less - Accumulated depreciation . . . . . . 956,313 833,953 - - - 1,790,266
1,616,647 2,556,453 - - - 4,173,100
Construction work in progress . . . . . . . 52,416 32,874 - - - 85,290
Nuclear fuel (net). . . . . . . . . . . . . - 39,890 - - - 39,890
Net utility plant. . . . . . . . . . . . 1,669,063 2,629,217 - - - 4,298,280
OTHER PROPERTY AND INVESTMENTS:
Net non-utility investments . . . . . . . . 1,264,909 506 - 73,502 (1,264,900) 74,017
Decommissioning trust . . . . . . . . . . . - 16,944 - - - 16,944
Other . . . . . . . . . . . . . . . . . . . 212 11,055 - 2,289 - 13,556
1,265,121 28,505 - 75,791 (1,264,900) 104,517
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . 671 47 - 1,997 - 2,715
Accounts receivable and
unbilled revenues (net) . . . . . . . . . 132,885 67,833 - 19,042 - 219,760
Accounts receivable - associated companies. 846 64,393 11 - (65,250) -
Notes receivable - associated companies . . 38,155 - - - (38,155) -
Fossil fuel, at average cost. . . . . . . . 25,010 13,752 - - - 38,762
Gas stored underground (average cost) . . . 45,222 - - - - 45,222
Materials and supplies (average cost) . . . 25,224 30,921 - - - 56,145
Prepayments and other current assets. . . . 5,156 16,662 - 6,114 - 27,932
273,169 193,608 11 27,153 (103,405) 390,536
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes. . . . . . . . (903) 102,789 - - - 101,886
Deferred coal contract
settlement costs. . . . . . . . . . . . . 15,662 17,944 - - - 33,606
Phase-in revenues . . . . . . . . . . . . . - 61,406 - - - 61,406
Corporate-owned life insurance (net). . . . 7,617 9,350 - - - 16,967
Other deferred plant costs. . . . . . . . . - 31,784 - - - 31,784
Unamortized debt expense. . . . . . . . . . 30,460 27,777 - - - 58,237
Other . . . . . . . . . . . . . . . . . . . 51,969 40,430 - - - 92,399
104,805 291,480 - - - 396,285
TOTAL ASSETS . . . . . . . . . . . . . . $3,312,158 $3,142,810 $ 11 $ 102,944 ($1,368,305) $5,189,618
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statement). . . . . . . . $2,306,348 $1,925,196 $ 11 $ 39,686 ($1,264,900) $3,006,341
CURRENT LIABILITIES:
Short-term debt . . . . . . . . . . . . . . 258,200 50,000 - - - 308,200
Long-term debt due within one year. . . . . 80 - - - - 80
Notes payable - associated companies. . . . - - - 38,155 (38,155) -
Accounts payable. . . . . . . . . . . . . . 68,735 49,093 - 12,788 - 130,616
Accounts payable - associated companies . . 64,404 - - 127 (64,531) -
Accrued taxes . . . . . . . . . . . . . . . 70,154 15,737 - 1,075 - 86,966
Accrued interest and dividends. . . . . . . 52,732 8,337 - 864 (864) 61,069
Other . . . . . . . . . . . . . . . . . . . 56,774 11,160 - 946 145 69,025
571,079 134,327 - 53,955 (103,405) 655,956
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes . . . . . . . . . . . 278,400 689,169 - 3,445 - 971,014
Deferred investment tax credits . . . . . . 62,810 74,841 - - - 137,651
Deferred gain from sale-leaseback . . . . . - 252,341 - - - 252,341
Other . . . . . . . . . . . . . . . . . . . 93,521 66,936 - 5,858 - 166,315
434,731 1,083,287 - 9,303 - 1,527,321
COMMITMENTS AND CONTINGENCIES
TOTAL CAPITALIZATION AND LIABILITIES. . . $3,312,158 $3,142,810 $ 11 $ 102,944 ($1,368,305) $5,189,618
PAGE
Exhibit A
WESTERN RESOURCES, INC.
CONSOLIDATING STATEMENT OF INCOME
Year Ended December 31, 1994
(Dollars in Thousands,
except Per Share Amounts)
Kansas Gas GSEC and Consolid- Western
Western and KPL Astra ating Ad- Resources
Resources Electric Funding Resources justments Consolidated
OPERATING REVENUES:
Electric. . . . . . . . . . . . . . . . . . $ 501,901 $ 619,880 $ - $ - $ - $1,121,781
Natural gas . . . . . . . . . . . . . . . . 496,162 - - - - 496,162
Total operating revenues. . . . . . . . . 998,063 619,880 - - - 1,617,943
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . 130,383 90,383 - - - 220,766
Nuclear fuel. . . . . . . . . . . . . . . - 13,562 - - - 13,562
Power purchased . . . . . . . . . . . . . . 8,294 7,144 - - - 15,438
Natural gas purchases . . . . . . . . . . . 312,576 - - - - 312,576
Other operations. . . . . . . . . . . . . . 188,331 115,060 - - - 303,391
Maintenance . . . . . . . . . . . . . . . . 65,198 47,988 - - - 113,186
Depreciation and amortization . . . . . . . 80,173 71,457 - - - 151,630
Amortization of phase-in revenues . . . . . - 17,544 - - - 17,544
Taxes:
Federal income. . . . . . . . . . . . . . 26,265 50,212 - - - 76,477
State income. . . . . . . . . . . . . . . 6,718 12,427 - - - 19,145
General . . . . . . . . . . . . . . . . . 59,590 45,092 - - - 104,682
Total operating expenses. . . . . . . . 877,528 470,869 - - - 1,348,397
OPERATING INCOME. . . . . . . . . . . . . . . 120,535 149,011 - - - 269,546
OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . - (5,354) - - - (5,354)
Gain on sales of Missouri Properties. . . . 30,701 - - - - 30,701
Miscellaneous (net) . . . . . . . . . . . . 4,676 5,079 - 3,083 - 12,838
Equity earnings of subsidiary companies . . 107,609 - - - (107,609) -
Income taxes (net). . . . . . . . . . . . . (11,619) 7,290 - - - (4,329)
Total other income and deductions . . . . 131,367 7,015 - 3,083 (107,609) 33,856
INCOME BEFORE INTEREST CHARGES. . . . . . . . 251,902 156,026 - 3,083 (107,609) 303,402
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . 50,656 47,827 - - - 98,483
Other . . . . . . . . . . . . . . . . . . . 14,956 5,183 - - - 20,139
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . (1,157) (1,510) - - - (2,667)
Total interest charges. . . . . . . . . 64,455 51,500 - - - 115,955
NET INCOME. . . . . . . . . . . . . . . . . . 187,447 104,526 - 3,083 (107,609) 187,447
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . 13,418 - - - - 13,418
EARNINGS APPLICABLE TO COMMON STOCK . . . . . $ 174,029 $ 104,526 $ - $ 3,083 $ (107,609) $ 174,029
AVERAGE COMMON SHARES OUTSTANDING . . . . . . 61,617,873 61,617,873
EARNINGS PER AVERAGE COMMON
SHARE OUTSTANDING . . . . . . . . . . . . . $ 2.82 $ 2.82
PAGE
Exhibit A
WESTERN RESOURCES, INC.
CONSOLIDATING STATEMENT OF RETAINED EARNINGS
December 31, 1994
(Dollars in Thousands)
Kansas Gas GSEC and Consolid- Western
Western and KPL Astra ating Ad- Resources
Resources Electric Funding Resources justments Consolidated
BALANCE AT BEGINNING OF PERIOD. . . . . . . . $ 446,348 $ 180,044 $ 2,410 $ 461 $(182,915) $ 446,348
ADD:
Net income. . . . . . . . . . . . . . . . . 187,447 104,526 - 3,083 (107,609) 187,447
Total . . . . . . . . . . . . . . . . . . 633,795 284,570 2,410 3,544 (290,524) 633,795
DEDUCT:
Cash dividends:
Preferred and preference stock. . . . . . . 13,418 - - - - 13,418
Common stock. . . . . . . . . . . . . . . . 122,003 125,000 - - (125,000) 122,003
Total . . . . . . . . . . . . . . . . . . 135,421 125,000 - - (125,000) 135,421
BALANCE AT END OF PERIOD. . . . . . . . . . . $ 498,374 $ 159,570 $ 2,410 $ 3,544 $(165,524) $ 498,374
PAGE
WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The Consolidated Financial Statements of Western Resources, Inc.
(the Company, Western Resources), include the accounts of its wholly-owned
subsidiaries, Astra Resources, Inc. (Astra), Kansas Gas and Electric Company
(KG&E) since March 31, 1992 (see Note 3), KPL Funding Corporation (KFC), and
Mid Continent Market Center, Inc. (Market Center). 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. All significant intercompany transactions have been
eliminated. The operations of Astra, KFC, and Market Center were not material
to the Company's results of operations. The Company is conducting its utility
business as KPL, Gas Service, and through its wholly-owned subsidiary, KG&E.
The Company is conducting its non-utility business through Astra.
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 Kansas
Corporation Commission (KCC), the Oklahoma Corporation Commission (OCC), and
the Federal Energy Regulatory Commission (FERC).
Utility Plant: Utility plant 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
4.08% in 1994, 4.10% in 1993, and 5.99% in 1992. 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 2.87% during 1994, 3.02% during 1993, and 3.03%
during 1992 of the average original cost of depreciable property.
Consolidated Statements of Cash Flows: For purposes of the Consolidated
Statements of Cash Flows, the Company considers highly liquid collateralized
debt instruments purchased with a maturity of three months or less to be cash
equivalents.
Cash paid for interest and income taxes for each of the three years ended
December 31, are as follows:
1994 1993 1992
(Dollars in Thousands)
Interest on financing activities (net of
amount capitalized). . . . . . . . . . . $134,785 $171,734 $128,505
Income taxes . . . . . . . . . . . . . . . 90,229 49,108 24,966
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 Statement of Financial Accounting
Standards No. 109 (SFAS 109) (see Note 13).
Investment tax credits previously deferred are being amortized to income
over the life of the property which gave rise to the credits.
Revenues: The Company accrues estimated unbilled electric and natural gas
revenues. This method of recognizing revenues best matches revenues with
costs of services provided to customers and also conforms the Company's
accounting treatment of unbilled revenues with the tax treatment of such
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 $61 million and $99 million are
recorded as a component of accounts receivable and unbilled revenues (net) on
the Consolidated Balance Sheets as of December 31, 1994 and 1993,
respectively.
The Company had reserves for doubtful accounts receivable of $3.4 million
and $4.3 million at December 31, 1994 and 1993, 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, 1994 and 1993, was $13.6 million and $17.4
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 in Corporate-owned Life
Insurance (net) on the Consolidated Balance Sheets:
1994 1993
(Dollars in Millions)
Cash surrender value of contracts. . . $ 408.9 $ 326.3
Borrowings against contracts . . . . . (391.9) (321.6)
COLI (net). . . . . . . . . . $ 17.0 $ 4.7
The COLI borrowings will be repaid upon receipt of proceeds from death
benefits under contracts. The Company recognizes increases in the cash
surrender value of contracts, resulting from premiums and investment earnings
on a tax free basis, and the tax deductible interest on the COLI borrowings in
Corporate-owned Life Insurance (net) on the Consolidated Statements of Income.
Interest expense related to KG&E's COLI for 1994, 1993, and the nine months
ended December 31, 1992, was $21.0 million, $11.9 million, and $5.3 million,
respectively.
As approved by the KCC, the Company is using a portion of the net income
stream generated by COLI policies purchased in 1993 and 1992 by the Company
(see Note 8) to offset Statement of Financial Accounting Standards No. 106
(SFAS 106) and Statement of Financial Accounting Standards No. 112 (SFAS 112)
expenses.
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
2. SALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES
On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties." With the sales the Company is no longer operating
as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The sale agreement provided for
estimated amounts in the sale price calculation to be adjusted to actual as of
January 31, 1994, within 120 days of closing. Disputes with respect to
proposed adjustments based upon differences between estimates and actuals were
to be resolved within 60 days of submission of the disputes by Southern Union
or submitted to arbitration by an accounting firm to be agreed to by both
parties. Southern Union proposed a number of adjustments to the purchase
price, some of which the Company has disputed. The Company maintains the
disputed adjustments are not permitted under the sale agreement. In the
opinion of the Company's management, the resolution of these purchase price
adjustments will not have a material impact on the Company's financial
position or results of operations. For information regarding litigation in
connection with the sale of the Missouri Properties to Southern Union, see
Note 4.
United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri for $665,000 in cash.
During the first quarter of 1994, the Company recognized a gain of
approximately $19.3 million, net of tax, on the sales of the Missouri
Properties. As of the respective dates of the sales of the Missouri
Properties, the Company ceased recording the results of operations, and
removed the assets and liabilities from the Consolidated Balance Sheet related
to the Missouri Properties. The gain is reflected in Other Income and
Deductions, on the Consolidated Statements of Income.
The following table reflects the approximate operating revenues and
operating income for the years ended December 31, 1994, 1993, and 1992, and
net utility plant at December 31, 1993 and 1992, related to the Missouri
Properties:
1994 1993 1992
Percent Percent Percent
of Total of Total of Total
Amount Company Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2%
Operating Income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7%
Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the
Missouri Properties. This unaudited financial information is based on
assumptions and allocations of expenses of the Company as a whole.
3. ACQUISITION AND MERGER
On March 31, 1992, the Company, through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company for $454 million in cash and 23,479,380
shares of common stock (the Merger). The Company also paid $20 million in
costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric
Company merged and adopted the name of Kansas Gas and Electric Company (KG&E).
The Merger was accounted for as a purchase. For income tax purposes the tax
basis of the KG&E assets was not changed by the Merger.
As the Company acquired 100 percent of the common and preferred stock of
KG&E, the Company recorded an acquisition premium of $490 million on the
Consolidated Balance Sheet for the difference in purchase price and book
value. This acquisition premium and related income tax requirement of $311
million under SFAS 109 have been classified as plant acquisition adjustment in
Electric Plant in Service on the Consolidated Balance Sheet. Under the
provisions of orders of the KCC, the acquisition premium is recorded as an
acquisition adjustment and not allocated to the other assets and liabilities
of KG&E.
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 and natural gas rates until August 1995. The KCC ordered refunds
totalling $32 million to the combined companies' customers to share with
customers the Merger-related cost savings achieved during the moratorium
period. Refunds of $8.5 million were made in April 1992 and December 1993 and
the remaining refund of $15 million was made in September 1994.
The KCC order approving the Merger required the legal reorganization of
KG&E so that it was no longer held as a separate subsidiary after January 1,
1995, unless good cause was shown why such separate existence should be
maintained. The Securities and Exchange Commission (SEC) order relating to
the Merger granted the Company an exemption under the Public Utility Holding
Company Act (PUHCA) until January 1, 1995. The Company has been granted
regulatory approval from the KCC which eliminates the requirement for a
combination. As a result of the sales of the Missouri Properties, the Company
is now exempt from regulation as a holding company under Section 3(a)(1) of
the PUHCA.
As the Merger did not occur until March 31, 1992, the twelve months ended
December 31, 1992, results of operations for the Company reported in its
statements of income, cash flows, and common stock equity reflect KG&E's
results of operations for only the nine months ended December 31, 1992. Pro
forma revenues of $1.7 billion, operating income of $269 million, net income
of $132 million and earnings per share of $2.03 for the year ended December
31, 1992 give effect to the Merger as if it had occurred at January 1, 1992.
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.
4. LEGAL PROCEEDINGS
On June 1, 1994, Southern Union filed an action against the Company, The
Bishop Group, Ltd., and other entities affiliated with The Bishop Group, in
the Federal District Court for the Western District of Missouri (the Court)
(Southern Union Company v. Western Resources, Inc. et al., Case No. 94-509-CV-
W-1) alleging, among other things, breach of the Missouri Properties sale
agreement relating to certain gas supply contracts between the Company and
various Bishop entities that Southern Union assumed, and requesting
unspecified monetary damages as well as declaratory relief. On August 1,
1994, the Company filed its answer and counterclaim denying all claims
asserted against it by Southern Union and requesting declaratory judgment with
respect to certain adjustments in the purchase price for the Missouri
Properties proposed by Southern Union and disputed by the Company. On August
24, 1994, Southern Union filed claims against the Company for alleged purchase
price adjustments totalling $19 million. The Company subsequently agreed that
approximately $4 million of the purchase price adjustments were subject to
arbitration. On January 18, 1995, the Court held the remaining $15 million of
proposed adjustments to the purchase price were subject to arbitration under
the sale agreement. In the opinion of the Company's management, the disputed
adjustments are not proper adjustments to the purchase price. For additional
information regarding the sales of the Missouri Properties see Note 2.
On August 15, 1994, the Bishop entities filed an answer and claims against
Southern Union and the Company alleging, among other things, breach of those
certain gas supply contracts. The Bishop entities claimed damages up to $270
million against the Company and Southern Union. The Company's management
believes that through the sale agreement, Southern Union assumed all
liabilities arising out of or related to gas supply contracts associated with
the Missouri Properties. The Company's management also believes it is not
liable for any claims asserted against it by the Bishop entities and will
vigorously defend such claims.
The Company received a civil investigative demand from the U.S. Department
of Justice seeking certain information in connection with the department's
investigation "to determine whether there is, has been, or may be a violation
of the Sherman Act Sec. 1-2" with respect to the natural gas business in
Kansas and Missouri. The Company is cooperating with the Department of
Justice, but is not aware of any violation of the antitrust laws in connection
with its business operations.
The Company and its subsidiaries are involved in various other legal and
environmental proceedings. Management believes that adequate provision has
been made within the Consolidated Financial Statements for these other matters
and accordingly believes their ultimate dispositions will not have a material
adverse effect upon the business, financial position, or results of operations
of the Company.
5. RATE MATTERS AND REGULATION
The Company, under rate orders from the KCC, OCC and the FERC, recovers
increases in fuel and natural gas costs through fuel adjustment clauses for
wholesale and certain retail electric customers and various purchased gas
adjustment clauses (PGA) for natural gas customers. The KCC and the OCC
require the annual difference between actual gas cost incurred and cost
recovered through the application of the PGA be deferred and amortized through
rates in subsequent periods.
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 Kansas retail electric customers of both the Company and KG&E
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. Any variance
in fuel costs from the projected average will impact the Company's earnings.
FERC Proceedings: On August 19, 1994, Williams Natural Gas Company (WNG)
filed a revised application with the FERC to direct bill approximately $14.7
million of FERC Order No. 636 (FERC 636) transition costs to the Company
related to natural gas sales service in Kansas and Oklahoma. These costs are
currently being recovered from the Company's current Kansas and Oklahoma
customers. The Company believes any future transition costs ultimately will
be recovered through charges to its customers, and any unrecovered transition
costs will not be material to the Company's financial position or results of
operations. For additional information with respect to FERC 636 see
Management's Discussion and Analysis.
On October 5, 1994, WNG filed an application with the FERC to direct bill
to the Company up to $30.4 million of settlement costs paid to Amoco
Production Company (Amoco) related to litigation between WNG and Amoco
regarding the proper price to be paid for gas purchased by WNG from Amoco.
The proposed direct bill is related to natural gas service rendered by the
Company in Kansas and Oklahoma. At December 31, 1994, $14.2 million of these
costs have been billed to the Company. The Company believes substantially all
of these costs and any future settlement costs ultimately will be recovered
through charges to its Kansas and Oklahoma customers, and any unrecovered
settlement costs will not be material to the Company's financial position or
results of operations.
KCC Proceedings: On December 22, 1994, the Company, in conjunction with
the Market Center, filed an application with the KCC to form a natural gas
market center in Kansas. The Market Center will provide natural gas
transportation, storage, and gathering services, as well as balancing, and
title transfer capability. Upon approval from the KCC, the Company intends to
transfer certain natural gas transmission assets having a value of
approximately $52.1 million to the Market Center. In addition, the Company
intends to extend credit to the Market Center enabling the Market Center to
borrow up to an aggregate principal amount of $25 million on a term basis to
construct new facilities and $5 million on a revolving credit basis for
working capital. The Market Center will provide no notice natural gas
transportation and storage services to the Company under a long-term contract.
The Company will continue to operate and maintain the Market Center's assets
under a separate contract.
On January 24, 1992, the KCC issued an order allowing the Company to
continue the deferral of service line replacement program costs incurred since
January 1, 1992, including depreciation, property taxes, and carrying costs
for recovery in the next general rate case. At December 31, 1994,
approximately $7.2 million of these deferrals have been included in Deferred
Charges and Other Assets, Other on the Consolidated Balance Sheet.
On December 30, 1991, the KCC approved a permanent natural gas rate
increase of $39 million annually and the Company discontinued the deferral of
accelerated line survey costs on January 1, 1992. Approximately $3.1 million
of these deferred costs remain in Deferred Charges and Other Assets, Other on
the Consolidated Balance Sheet at December 31, 1994, with the balance being
included in rates and amortized to expense during a 43-month period,
commencing January 1, 1992.
Tight Sands: In December 1991 the KCC, and the OCC approved agreements
authorizing the Company to refund to customers approximately $40 million of
the proceeds of the Tight Sands antitrust litigation settlement to be
collected on behalf of Western Resources' natural gas customers. To secure
the refund of settlement proceeds, the Commissions authorized the
establishment of an independently administered trust to collect and maintain
cash receipts received under Tight Sands settlement agreements and provide for
the refunds made. The trust has a term of ten years.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring the
accrual of phase-in revenues be discontinued by KG&E effective December 31,
1988. Effective January 1, 1989, KG&E began amortizing the phase-in revenue
asset on a straight-line basis over 9 1/2 years. At December 31, 1994,
approximately $61 million of deferred phase-in revenues remained on the
Consolidated Balance Sheet.
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KG&E 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 was recorded as a deferred charge and is included in Deferred Charges
and Other Assets on the Consolidated Balance Sheet. The settlement resulted
in the termination of a long-term coal contract. The KCC permitted KG&E to
recover this settlement as follows: 76 percent of the settlement plus a return
over the remaining term of the terminated contract (through 2002) and 24
percent to be amortized to expense with a deferred return equivalent to the
carrying cost of the asset.
In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit
with AMAX Coal Company and recorded the payment as a deferred charge in
Deferred Charges and Other Assets on the Consolidated Balance Sheet. The KCC
approved the recovery of the settlement plus a return, equivalent to the
carrying cost of the asset, over the remaining term of the terminated contract
(through 1996).
FERC Order No. 528: In 1990, the FERC issued Order No. 528 which
authorized new methods for the allocation and recovery of take-or-pay
settlement costs by natural gas pipelines from their customers. Settlements
were reached between the Company's two largest gas pipelines and their
customers in FERC proceedings related to take-or-pay issues. The settlements
address the allocation of take-or-pay settlement costs between the pipelines
and their customers. However, the amount which one of the pipelines will be
allowed to recover is yet to be determined. Litigation continues between the
Company and a former upstream pipeline supplier to one of the Company's
pipeline suppliers concerning the amount of such costs which may ultimately be
allocated to the Company's pipeline supplier. The Company's share of any
costs allocated to the Company's pipeline supplier will be charged to the
Company. Due to the uncertainty concerning the amount to be recovered by the
Company's current suppliers and of the outcome of the litigation between the
Company and its current pipeline's upstream supplier, the Company is unable to
estimate its future liability for take-or-pay settlement costs. However, the
KCC has approved mechanisms which are designed to allow the Company to recover
these take-or-pay costs from its customers.
6. SHORT-TERM DEBT
The Company's short-term financing requirements are satisfied, through the
sale of commercial paper, short-term bank loans and borrowings under unsecured
lines of credit maintained with banks. Information concerning these
arrangements for the years ended December 31, 1994, 1993, and 1992, is set
forth below:
Year Ended December 31, 1994 1993 1992
(Dollars in Thousands)
Lines of credit at year end. . . . $145,000(1) $145,000 $250,000(2)
Short-term debt out-
standing at year end . . . . . . 308,200 440,895 222,225
Weighted average interest rate
on debt outstanding at year
end (including fees) . . . . . . 6.25% 3.67% 4.70%
Maximum amount of short-
term debt outstanding during
the period. . . .. . . . . . . . $485,395 $443,895 $263,900
Monthly average short-term debt. . 214,180 347,278 179,577
Weighted daily average interest
rates during the year
(including fees) . . . . . . . . 4.63% 3.44% 4.90%
(1) Decreased to $121 million in January 1995.
(2) Decreased to $155 million in January 1993.
In connection with the commitments, the Company has agreed to pay certain
fees to the banks. Available lines of credit and the unused portion of the
revolving credit facility are utilized to support the Company's outstanding
short-term debt.
7. COMMITMENTS AND CONTINGENCIES
As part of its ongoing operations and construction program, the Company
has commitments under purchase orders and contracts which have an unexpended
balance of approximately $77 million at December 31, 1994. Approximately $32
million is attributable to modifications to upgrade the three turbines at
Jeffrey Energy Center to be completed by December 31, 1998. Plans for future
construction of utility plant are discussed in the Management's Discussion and
Analysis section.
In January 1994, the Company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA). Under the agreement, the Company received a
prepayment of approximately $41 million for which the Company will provide
capacity and transmission services to OMPA through the year 2013.
Manufactured Gas Sites: The Company was previously associated with 20
former manufactured gas sites located in Kansas which may contain coal tar and
other potentially harmful materials. These sites were operated decades ago by
predecessor companies, and were owned by the Company for a period of time
after operations had ceased. The Company and the Kansas Department of Health
and Environment (KDHE) conducted preliminary assessments of the sites at a
cost of approximately $500,000. The results of the preliminary investigations
determined the Company does not have a connection to four of the sites. Of
the remaining 16 sites, the site investigation and risk assessment field work
of the highest priority site was completed in 1994 at a total cost of
approximately $450,000. The Company has not received the final report so as
to determine the extent of contamination and the amount of any possible
remediation.
The Company and KDHE entered into a consent agreement governing all future
work at these sites. The terms of the consent agreement will allow the
Company to investigate the 16 sites and set remediation priorities based upon
the results of the investigations and risk analysis. The prioritized sites
will be investigated over a 10 year period. The agreement will allow the
Company to set mutual objectives with the KDHE in order to expedite effective
response activities and to control costs and environmental impact. The
Company is aware of other utilities in Region VII of the EPA (Kansas,
Missouri, Nebraska, and Iowa) which have incurred remediation costs for
manufactured gas sites ranging between $500,000 and $10 million, depending on
the site, and that the KCC has issued an accounting order which will permit
another Kansas utility to recover its 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 required and number of years over which
the remediation must be completed.
Superfund Sites: The Company has been identified as one of numerous
potentially responsible parties in four hazardous waste sites listed by the
EPA as Superfund sites. One site is a groundwater contamination site in
Wichita, Kansas (Wichita site), two are soil contamination sites in Missouri
(Missouri sites), and one site is a solid waste land-fill located in
Edwardsville, Kansas (Edwardsville site). Settlement agreements releasing the
Company from liability for future response or costs have been entered into at
the Edwardsville site and one of the Missouri sites. The Company's obligation
at the remaining Missouri site and the Wichita site appears to be limited
based on the Company's experience at similar sites given its limited exposure
and settlement costs. In the opinion of the Company's management, the
resolution of these matters will not have a material impact on the Company's
financial position or results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in sulfur dioxide and oxides of nitrogen (NOx) 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 installed continuous monitoring and reporting equipment at a total
cost of approximately $10 million. The Company does not expect additional
equipment to reduce sulfur emissions to be necessary under Phase II. Although
the Company currently has no Phase I affected units, the Company applied for
an early substitution permit to bring the co-owned La Cygne Station under the
Phase I guidelines.
The NOx and air toxic limits, which were not set in the law, will be
specified in future EPA regulations. The EPA's proposed NOx regulations were
ruled invalid by the Court and until such time as the EPA resubmits new
proposed regulations, the Company will be unable to determine its compliance
options or related compliance costs.
Other Environmental Matters: As part of the sale of the Company's
Missouri Properties to Southern Union, Southern Union assumed responsibility
under an agreement for any environmental matters related to the Missouri
Properties purchased by Southern Union pending at the date of the sale or that
may arise after closing. For any environmental matters pending or discovered
within two years of the date of the agreement, and after pursuing several
other potential recovery options, the Company may be liable for up to a
maximum of $7.5 million under a sharing arrangement with Southern Union
provided for in the agreement.
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 on net nuclear generation.
These fees are included as part of nuclear fuel expense and amounted to $3.8
million for 1994, $3.5 million for 1993, and $1.6 million for 1992.
The Company along with the other co-owners of Wolf Creek are among 14
companies that filed a lawsuit on June 20, 1994, seeking an interpretation of
the DOE's obligation to begin accepting spent nuclear fuel for disposal in
1998. The Federal Nuclear Waste Policy Act requires DOE ultimately to accept
and dispose of nuclear utilities' spent fuel. The DOE has filed a motion to
have this case dismissed. The issue to be decided in this case is whether DOE
must begin accepting spent fuel in 1998 or at a future date. Wolf Creek
contains an on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
the year 2006 while still maintaining full core off-load capability. The
Company believes adequate additional storage space can be obtained as
necessary.
Decommissioning: On June 9, 1994, the KCC issued an order approving the
decommissioning cost of the 1993 Wolf Creek Decommissioning Cost Study which
estimates the Company's share of Wolf Creek decommissioning costs, under the
immediate dismantlement method, to be approximately $595 million primarily
during the period 2025 through 2033, or approximately $174 million in 1993
dollars. These costs were calculated using an assumed inflation rate of 3.45%
over the remaining service life, in 1993, of 32 years.
Decommissioning costs are being charged to operating expenses in
accordance with the KCC order. Electric rates charged to customers provide
for recovery of these decommissioning costs over the life of Wolf Creek.
Amounts so expensed ($3.5 million in 1994 increasing annually to $5.5 million
in 2024) and earnings on trust fund assets are deposited in an external trust
fund. The assumed return on trust assets is 5.9%.
The Company's investment in the decommissioning fund, including
reinvested earnings was $16.9 million and $13.2 million at December 31, 1994
and December 31, 1993, respectively. These amounts are reflected in
Decommissioning Trust, and the related liability is included in Deferred
Credits and Other Liabilities, Other on the Consolidated Balance Sheets.
The Company carries $118 million in premature decommissioning insurance.
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 $8.9 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 major nuclear
incident involving any of the nation's licensed reactors. This assessment is
subject to an inflation adjustment based on the Consumer Price Index and
applicable premium taxes. 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" ($500 million) and
Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The Company's share of any remaining proceeds can be
used for property damage up to $1.2 billion (Company's share) and premature
decommissioning costs up to $118 million (Company's share) in excess of funds
previously collected for decommissioning (as discussed under
"Decommissioning").
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 $13 million per year.
Although the Company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or an
extended outage, the Company's 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 through rates, would have a material adverse effect on the
Company's financial condition and results of operations.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS)
completed an examination of KG&E's federal income tax returns for the years
1984 through 1988. In April 1992, KG&E received the examination report and
upon review filed a written protest in August 1992. In October 1993, KG&E
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, KG&E 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.
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, 1994, WCNOC's nuclear fuel commitments (Company's share) were
approximately $12.6 million for uranium concentrates expiring at various times
through 1997, $122.9 million for enrichment expiring at various times through
2014, and $56.5 million for fabrication through 2012. At December 31, 1994,
the Company's coal and natural gas contract commitments in 1994 dollars under
the remaining terms of the contracts were approximately $3 billion and $9
million, respectively. The largest coal contract expires in 2020, with the
remaining coal contracts expiring at various times through 2013. The majority
of natural gas contracts continue through 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
is being 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.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension
plans covering substantially all employees. 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 tables provide information on the components of pension
cost, funded status, and actuarial assumptions for the Company's pension
plans:
Year Ended December 31, 1994 1993 1992
(Dollars in Thousands)
Pension Cost:
Service cost. . . . . . . . . . $ 10,197 $ 9,778 $ 9,847
Interest cost on projected
benefit obligation. . . . . . 29,734 35,688 29,457
(Gain) loss on plan assets. . . 7,351 (64,113) (38,967)
Deferred investment gain (loss) (38,457) 29,190 7,705
Net amortization. . . . . . . . 245 (669) (948)
Net pension cost. . . . . . $ 9,070 $ 9,874 $ 7,094
December 31, 1994 1993 1992
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $278,545 $353,023 $316,100
Non-vested . . . . . . . . . 19,132 26,983 19,331
Total. . . . . . . . . . . $297,677 $380,006 $335,431
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $375,521 $490,339 $452,372
Projected benefit obligation . . . 378,146 468,996 424,232
Funded status. . . . . . . . . . . (2,625) 21,343 28,140
Unrecognized transition asset. . . (2,205) (2,756) (3,092)
Unrecognized prior service costs . 47,796 64,217 55,886
Unrecognized net gain. . . . . . . (56,079) (108,783) (106,486)
Accrued pension costs. . . . . . . $(13,113) $(25,979) $(25,552)
Year Ended December 31, 1994 1993 1992
Actuarial Assumptions:
Discount rate. . . . . . . . . . 8.0-8.5% 7.0-7.75% 8.0-8.5%
Annual salary increase rate. . . 5.0% 5.0% 6.0%
Long-term rate of return . . . . 8.0-8.5% 8.0-8.5% 8.0-8.5%
Retirement and Voluntary Separation Plans: In January 1992, the Board of
Directors approved early retirement plans and voluntary separation programs.
The voluntary early retirement plans were offered to all vested participants
in the Company's defined 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 as a lump sum payment. Of the 738 employees eligible for the
early retirement option, 531, representing ten percent of the combined
Company's work force, elected to retire on or before the May 1, 1992,
deadline. Seventy-one of those electing to retire were employees of KG&E
acquired March 31, 1992 (see Note 3). Another 67 employees, with 10 or more
years of service, elected to participate in the voluntary separation program.
Of those, 29 were employees of KG&E. In addition, 68 employees received
Merger-related severance benefits, including 61 employees of KG&E. The
actuarial cost, based on plan provisions for early retirement and voluntary
separation programs, and Merger-related severance benefits for the KG&E
employees were considered in purchase accounting for the Merger. The
actuarial cost of the former Kansas Power and Light Company employees, of
approximately $11 million, was expensed in 1992.
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 benefit 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, SFAS 106 expense was approximately $12.4 million and $26.5 million
for 1994 and 1993, respectively. The Company's total SFAS 106 obligation was
approximately $114.6 million and $166.5 million at December 31, 1994 and 1993
respectively. The reduction in both the 1994 obligation and expense is
primarily the result of the sales of the Missouri Properties. To mitigate the
impact of SFAS 106 expense, the Company has implemented programs to reduce
health care costs. In addition, the Company 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 COLI. To the extent SFAS 106 expense exceeds
income from the COLI program, this excess is being deferred (in accordance
with the provisions of the FASB Emerging Issues Task Force Issue No. 92-12)
and will be 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
the cost of retiree health care and life insurance benefits as expense when
claims and premiums for life insurance policies were paid. The cost of
providing health care and life insurance benefits to 2,928 retirees was $8.1
million in 1992.
The following table summarizes the status of the Company's postretirement
plans for financial statement purposes and the related amounts included in the
Consolidated Balance Sheets:
December 31, 1994 1993
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . $ 68,570 $ 111,499
Active employees fully eligible . . . . . . . 13,549 11,848
Active employees not fully eligible . . . . . 32,484 43,109
Unrecognized prior service cost . . . . . . . 9,391 18,195
Unrecognized transition obligation. . . . . . (117,967) (160,731)
Unrecognized net gain (loss). . . . . . . . . 14,489 (7,100)
Balance sheet liability . . . . . . . . . . . . . $ 20,516 $ 16,820
Year Ended December 31, 1994 1993
Assumptions:
Discount rate . . . . . . . . . . . . . . . . . 8.0-8.5 % 7.75%
Annual compensation increase rate . . . . . . . 5.0 % 5.0 %
Expected rate of return . . . . . . . . . . . . 8.5 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 12% was
assumed for 1994, decreasing 1% per year to 5% in 2001 and thereafter. 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 $4.7 million
and the aggregate of the service and interest cost components by $0.3 million.
Postemployment: The Company adopted Statement of Financial Accounting
Standards No. 112 (SFAS 112) in the first quarter of 1994, which established
accounting and reporting standards for postemployment benefits. The statement
requires the Company to recognize the liability to provide postemployment
benefits when the liability has been incurred. The Company received an order
from the KCC permitting the initial deferral of SFAS 112 expense. To mitigate
the impact SFAS 112 expense will have on rate increases, the Company will
include in the future computation of cost of service the actual SFAS 112
transition costs and expenses and an income stream generated from COLI. The
1994 expense under SFAS 112 was approximately $2.7 million. At December 31,
1994, the Company's SFAS 112 liability recorded on the Consolidated Balance
Sheet was approximately $8.4 million.
Savings: The Company maintains savings plans in which substantially all
employees participate. The Company matches employees' contributions up to
specified maximum limits. 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 Company stock fund. The Company's contributions were $5.1 million,
$5.8 million, and $5.4 million for 1994, 1993, and 1992, respectively.
Missouri Property Sale: Effective January 31, 1994, the Company transferred
a portion of the assets and liabilities of the Company's pension plan to a
pension plan established by Southern Union. The amount of assets transferred
equal the projected benefit obligation for employees and retirees associated
with Southern Union's portion of the Missouri Properties plus an additional $9
million.
9. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1994
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 152,816 $ 98,124 343 50
Jeffrey 1 (b) Jul 1978 276,689 122,721 587 84
Jeffrey 2 (b) May 1980 285,579 109,743 600 84
Jeffrey 3 (b) May 1983 387,646 134,199 588 84
Wolf Creek (c) Sep 1985 1,376,335 317,311 545 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with UtiliCorp United Inc.
(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 on the Consolidated Statements of Income. The Company's
share of other transactions associated with the plants is included in the
appropriate classification in the Company's Consolidated Financial Statements.
10. LEASES
At December 31, 1994, the Company had leases covering various property and
equipment. Certain lease agreements meet the criteria, as set forth in
Statement of Financial Accounting Standards No. 13, for classification as
capital leases.
Rental payments for capital and operating leases and estimated rental
commitments are as follows:
Capital Operating
Year Ended December 31, Leases Leases
(Dollars in Thousands)
1992 $ 2,426 $ 52,701
1993 3,272 55,011
1994 2,987 55,076
Future Commitments:
1995 3,783 48,524
1996 3,627 46,211
1997 1,511 42,851
1998 - 41,464
1999 - 39,955
Thereafter - 753,062
Total $ 8,921 $972,067
Less Interest 784
Net obligation $ 8,137
In 1987, KG&E sold and leased back its 50 percent undivided interest in
the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of
29 years, with various options to renew the lease or repurchase the 50 percent
undivided interest. KG&E 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 La Cygne 2 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. At December 31, 1994, approximately $24.8
million of this deferral remained on the Consolidated Balance Sheet.
Future minimum annual lease payments, included in the table above,
required under the La Cygne 2 lease agreement are approximately $34.6 million
for each year through 1999 and $680 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale of
La Cygne 2 has been deferred for financial reporting purposes, and is being
amortized ($9.6 million per year) over the initial lease term in proportion to
the related lease expense. KG&E's lease expense, net of amortization of the
deferred gain and a one-time payment, was approximately $22.5 million for 1994
and 1993, and $20.6 million for the nine months ended December 31, 1992.
11. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the Western Resources
Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited.
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 each Mortgage.
On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds,
6.20% Series due January 15, 2006.
On January 31, 1994, the Company redeemed the remaining $2,466,000
principal amount of Gas Service Company (GSC) 8 1/2% Series First Mortgage
Bonds due 1997. In addition, the Company had the GSC Mortgage and Deed of
Trust discharged.
Debt discount and expenses are being amortized over the remaining lives of
each issue. The Western Resources and KG&E improvement and maintenance fund
requirements for certain first mortgage bond series can be met by bonding
additional property. With the retirement of certain Western Resources and
KG&E pollution control series bonds, there are no longer any bond sinking fund
requirements. During 1995, $80 thousand of bonds will be redeemed, during
1996, $16 million of bonds will mature and $125 million of bonds will mature
in 1999.
On November 1, 1994, the Company terminated a long-term agreement which
contained 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 were accounted for as sales while those related to
phase-in revenues were accounted for as collateralized borrowings. At
December 31, 1993, outstanding receivables amounting to $56.8 million were
considered sold under the agreement. The weighted average interest rate,
including fees, on this agreement was 4.6% for 1994, 3.7% for 1993, and 6.6%
for the nine months ended December 31, 1992.
In January 1993, the Company renegotiated its $600 million bank term loan
and revolving credit facility used to finance the Merger into a $350 million
revolving credit facility, secured by KG&E common stock. On October 5, 1994,
the Company extended the term of this facility to expire on October 5, 1999.
The unused portion of the revolving credit facility may be used to provide
support for outstanding short-term debt. At December 31, 1994, there was no
outstanding balance under the facility.
Long-term debt outstanding at December 31, 1994 and 1993, was as follows:
1994 1993
(Dollars in Thousands)
Western Resources
First mortgage bond series:
7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000
7 5/8% due 1999. . . . . . . . . . . . . - 19,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000
8 1/8% due 2007. . . . . . . . . . . . . - 30,000
8 5/8% due 2017. . . . . . . . . . . . . - 50,000
8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000
7.65% due 2023. . . . . . . . . . . . . 100,000 100,000
525,000 624,000
Pollution control bond series:
5.90 % due 2007. . . . . . . . . . . . . - 31,000
6 3/4% due 2009. . . . . . . . . . . . . - 45,000
Variable due 2032 (1). . . . . . . . . . 45,000 -
Variable due 2032 (2). . . . . . . . . . 30,500 -
6% due 2033. . . . . . . . . . . . . 58,500 58,500
134,000 134,500
KG&E
First mortgage bond series:
5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000
7.60 % due 2003. . . . . . . . . . . . . 135,000 135,000
6 1/2% due 2005. . . . . . . . . . . . . 65,000 65,000
6.20 % due 2006. . . . . . . . . . . . . 100,000 -
316,000 216,000
Pollution control bond series:
6.80 % due 2004. . . . . . . . . . . . . - 14,500
5 7/8% due 2007. . . . . . . . . . . . . - 21,940
6% due 2007. . . . . . . . . . . . . - 10,000
5.10 % due 2023. . . . . . . . . . . . . 13,982 -
Variable due 2027 (3). . . . . . . . . . 21,940 -
7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500
Variable due 2032 (4). . . . . . . . . . 14,500 -
Variable due 2032 (5). . . . . . . . . . 10,000 -
387,922 373,940
GSC
First mortgage bond series:
8 1/2 % due 1997. . . . . . . . . . . . . - 2,466
- 2,466
Other pollution control obligations. . . . - 13,980
Revolving credit agreement . . . . . . . . - 115,000
Other long-term agreement. . . . . . . . . - 53,913
Less:
Unamortized debt discount. . . . . . . . 5,814 6,607
Long-term debt due within one year . . . 80 3,204
$1,357,028 $1,523,988
Rates at December 31, 1994: (1) 3.94%, (2) 4.05%, (3) 4.10%,
(4) 4.10% and (5) 4.10%
12. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK
The Company's Restated Articles of Incorporation, as amended, provides for
85,000,000 authorized shares of common stock. At December 31, 1994,
61,617,873 shares were outstanding.
The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend
Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the CSPP and
DRIP may be either original issue shares or shares purchased on the open
market. At December 31, 1994, 2,031,794 shares were available under the CSPP
registration statement and 1,183,323 shares were available under the DRIP
registration statement.
Not subject to mandatory redemption: The cumulative preferred stock is
redeemable in whole or in part on 30 to 60 days notice at the option of the
Company.
Subject to mandatory redemption: The mandatory sinking fund provisions of
the 8.50% Series preference stock require the Company to redeem 50,000 shares
annually beginning on July 1, 1997, at $100 per share. The Company may, at
its option, redeem up to an additional 50,000 shares on each July 1, at $100
per share. The 8.50% Series also is redeemable in whole or in part, at the
option of the Company, subject to certain restrictions on refunding, at a
redemption price of $106.80, $106.23 and $105.67 per share beginning July 1,
1994, 1995 and 1996, respectively.
The mandatory sinking fund provisions of the 7.58% Series preference stock
require the Company to redeem 25,000 shares annually beginning on April 1,
2002, and each April 1 through 2006 and the remaining shares on April 1, 2007,
all at $100 per share. The Company may, at its option, redeem up to an
additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series
also is redeemable in whole or in part, at the option of the Company, subject
to certain restrictions on refunding, at a redemption price of $106.06,
$105.31, and $104.55 per share beginning April 1, 1994, 1995, and 1996,
respectively.
13. INCOME TAXES
The Company adopted the provisions of SFAS 109 in the first quarter of
1992. KG&E adopted the provisions of SFAS 96 in 1987 and SFAS 109 in 1992.
These statements require 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.
In accordance with various rate orders received from the KCC and the OCC,
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 impact on the
Company's results of operations.
At December 31, 1994, the Company has alternative minimum tax credits
generated prior to April 1, 1992, which carryforward without expiration, of
$41.2 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, 1994.
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, 1994
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (661,433) $ (661,433)
Energy and purchased gas
adjustment clauses . . . . . . . - (1,441) (1,441)
Phase-in revenues. . . . . . . . . - (27,677) (27,677)
Natural gas line survey and
replacement program. . . . . . . - (4,083) (4,083)
Deferred gain on sale-leaseback. . 110,556 - 110,556
Alternative minimum tax credits. . 41,163 - 41,163
Deferred coal contract
settlements. . . . . . . . . . . - (12,966) (12,966)
Deferred compensation/pension
liability. . . . . . . . . . . . 12,284 - 12,284
Acquisition premium. . . . . . . . - (318,190) (318,190)
Deferred future income taxes . . . - (101,886) (101,886)
Loss on reacquisition of debt. . . - (10,792) (10,792)
Prepaid power sale . . . . . . . . 16,878 - 16,878
Other. . . . . . . . . . . . . . . - (13,427) (13,427)
Total Deferred Income Taxes. . . . . $ 180,881 $(1,151,895) $ (971,014)
December 31, 1993
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (653,592) $ (653,592)
Energy and purchased gas
adjustment clauses . . . . . . . 2,452 - 2,452
Phase-in revenues. . . . . . . . . - (35,573) (35,573)
Natural gas line survey and
replacement program. . . . . . . - (7,721) (7,721)
Deferred gain on sale-leaseback. . 116,186 - 116,186
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (14,980) (14,980)
Deferred compensation/pension
liability. . . . . . . . . . . . 11,301 - 11,301
Acquisition premium. . . . . . . . - (301,394) (301,394)
Deferred future income taxes . . . - (111,159) (111,159)
Loss on reacquisition of debt. . . - (9,298) (9,298)
Other. . . . . . . . . . . . . . . - (4,741) (4,741)
Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $ (968,637)
14. SEGMENTS OF BUSINESS
The Company is a public utility engaged in the generation, transmission,
distribution, and sale of electricity in Kansas and the transportation,
distribution, and sale of natural gas in Kansas and Oklahoma.
Year Ended December 31, 1994(1) 1993 1992(2)
(Dollars in Thousands)
Operating revenues:
Electric. . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885
Natural gas . . . . . . . . . 496,162 804,822 673,363
1,617,943 1,909,359 1,556,248
Operating expenses excluding
income taxes:
Electric. . . . . . . . . . . 768,317 791,563 632,169
Natural gas . . . . . . . . . 484,458 747,755 642,910
1,252,775 1,539,318 1,275,079
Income taxes:
Electric. . . . . . . . . . . 100,078 73,425 41,184
Natural gas . . . . . . . . . (4,456) 4,553 816
95,622 77,978 42,000
Operating income:
Electric. . . . . . . . . . . 253,386 239,549 209,532
Natural gas . . . . . . . . . 16,160 52,514 29,637
$ 269,546 $ 292,063 $ 239,169
Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,346,312 $4,231,277 $4,390,117
Natural gas . . . . . . . . . 654,483 1,040,513 918,729
Other corporate assets(3) . . 188,823 140,258 130,060
$5,189,618 $5,412,048 $5,438,906
Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 123,696 $ 126,034 $ 105,842
Natural gas . . . . . . . . . 27,934 38,330 38,171
$ 151,630 $ 164,364 $ 144,013
Maintenance:
Electric. . . . . . . . . . . $ 88,162 $ 87,696 $ 73,104
Natural gas . . . . . . . . . 25,024 30,147 28,507
$ 113,186 $ 117,843 $ 101,611
Capital expenditures:
Electric. . . . . . . . . . . $ 152,384 $ 137,874 $ 95,465
Nuclear fuel. . . . . . . . . 20,590 5,702 15,839
Natural gas . . . . . . . . . 64,722 94,055 91,189
$ 237,696 $ 237,631 $ 202,493
(1)Information reflects the sales of the Missouri Properties (Note 2).
(2)Information reflects the merger with KG&E on March 31, 1992 (Note 3).
(3)Principally cash, temporary cash investments, non-utility assets, and
deferred charges.
The portion of the table above related to the Missouri Properties is as
follows:
1994 1993 1992
(Dollars in Thousands, Unaudited)
Natural gas revenues. . . . . . . . . $ 77,008 $349,749 $299,202
Operating expenses excluding
income taxes. . . . . . . . 69,114 326,329 288,558
Income taxes. . . . . . . . . . . . . 2,897 2,672 (533)
Operating income. . . . . . . . . . . 4,997 20,748 11,177
Identifiable assets . . . . . . . . . - 398,464 361,612
Depreciation and amortization . . . . 1,274 12,668 13,172
Maintenance . . . . . . . . . . . . . 1,099 10,504 9,640
Capital expenditures. . . . . . . . . 3,682 38,821 36,669
15. 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, 1994 and 1993.
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 interest
rate, maturity, and redemption provisions of each issue.
Redeemable Preference Stock-
The fair value of the redeemable preference stock is based on the sum of
the estimated value of each issue taking into consideration the dividend
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, 1994 1993 1994 1993
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . . $ 2,715 $ 1,217 $ 2,715 $ 1,217
Decommissioning trust. . . 16,944 13,204 16,633 13,929
Variable-rate debt . . . . 822,045 931,352 822,045 931,352
Fixed-rate debt. . . . . . 1,240,982 1,364,886 1,171,866 1,473,569
Redeemable preference
stock. . . . . . . . . . 150,000 150,000 155,375 160,780
The fair value estimates presented herein are based on information
available as of December 31, 1994 and 1993. These fair value estimates have
not been comprehensively revalued for the purpose of these financial
statements since that date, and current estimates of fair value may differ
significantly from the amounts presented herein.
16. QUARTERLY RESULTS (UNAUDITED)
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.
First Second Third Fourth
(Dollars in Thousands, except Per Share Amounts)
1994(1)
Operating revenues. . . . . . . $538,372 $341,132 $379,213 $359,226
Operating income. . . . . . . . 73,782 53,899 83,884 57,981
Net income. . . . . . . . . . . 66,133 30,247 57,679 33,388
Earnings applicable to
common stock. . . . . . . . . 62,779 26,892 54,324 30,034
Earnings per share. . . . . . . $ 1.02 $ 0.44 $ 0.88 $ 0.48
Dividends per share . . . . . . $ 0.495 $ 0.495 $ 0.495 $ 0.495
Average common shares
outstanding . . . . . . . . . 61,618 61,618 61,618 61,618
Common stock price:
High. . . . . . . . . . . . . $ 34 7/8 $ 29 3/4 $ 29 5/8 $ 29 1/4
Low . . . . . . . . . . . . . $ 28 1/4 $ 26 1/8 $ 26 3/4 $ 27 3/8
1993
Operating revenues. . . . . . . $579,581 $400,411 $419,018 $510,349
Operating income. . . . . . . . 85,950 60,282 81,225 64,606
Net income. . . . . . . . . . . 54,814 30,723 56,807 35,026
Earnings applicable to
common stock. . . . . . . . . 51,468 27,320 53,405 31,671
Earnings per share. . . . . . . $ 0.89 $ 0.47 $ 0.90 $ 0.51
Dividends per share . . . . . . $ 0.485 $ 0.485 $ 0.485 $ 0.485
Average common shares
outstanding . . . . . . . . . 58,046 58,046 59,441 61,603
Common stock price:
High. . . . . . . . . . . . . $ 35 3/4 $ 36 1/8 $ 37 1/4 $ 37
Low . . . . . . . . . . . . . $ 30 3/8 $ 32 3/4 $ 35 $ 32 3/4
(1) Information reflects the sales of the Missouri Properties (Note 2).
Exhibit B
Financial Data Schedule
[ARTICLE] OPUR3
[MULTIPLIER] 1,000
[PERIOD-TYPE] YEAR
[FISCAL-YEAR-END] DEC-31-1994
[PERIOD-END] DEC-31-1994
[BOOK-VALUE] PER-BOOK
[TOTAL-ASSETS] 5,189,618
[TOTAL-OPERATING-REVENUES] 1,617,943
[NET-INCOME] 187,447
