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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-3523
WESTERN RESOURCES, INC.
(Exact name of registrant as specified in its charter)
KANSAS 48-0290150
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
818 KANSAS AVENUE, TOPEKA, KANSAS 66612
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code 913/575-6300
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $5.00 par value New York Stock Exchange
(Title of each class) (Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, 4 1/2% Series, $100 par value
(Title of Class)
Indicated by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. ( )
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,897,474,000 of Common Stock and $11,398,000
of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which
there is no readily ascertainable market value) at March 18, 1996.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock.
Common Stock, $5.00 par value 63,249,141
(Class) (Outstanding at March 27, 1996)
Documents Incorporated by Reference:
Part Document
III Items 10-13 of the Company's Definitive Proxy Statement for
the Annual Meeting of Shareholders to be held May 7, 1996.
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 1995
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 19
Item 3. Legal Proceedings 21
Item 4. Submission of Matters to a Vote of
Security Holders 21
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 21
Item 6. Selected Financial Data 23
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 24
Item 8. Financial Statements and Supplementary Data 31
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 61
PART III
Item 10. Directors and Executive Officers of the
Registrant 61
Item 11. Executive Compensation 61
Item 12. Security Ownership of Certain Beneficial
Owners and Management 61
Item 13. Certain Relationships and Related Transactions 61
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 62
Signatures 66
PART I
ITEM 1. BUSINESS
ACQUISITION AND MERGER
On March 31, 1992, Western Resources, Inc. (formerly the Kansas Power
and Light Company) (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 (KGE) (the Merger). Simultaneously, KCA and
Kansas Gas and Electric Company merged and adopted the name Kansas Gas and
Electric Company (KGE).
Additional information relating to the Merger can be found in
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
GENERAL
The Company and its wholly-owned subsidiaries, include KPL, a rate
regulated electric and gas division of the Company, KGE, a rate regulated
electric utility and wholly-owned subsidiary of the Company, the Westar
companies, non-utility subsidiaries, and Mid Continent Market Center, Inc.
(Market Center), a regulated gas transmission service provider. KGE owns 47%
of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating Company for
Wolf Creek Generating Station (Wolf Creek). Corporate headquarters of the
Company are located at 818 Kansas Avenue, Topeka, Kansas 66612. At December
31, 1995, the Company had 4,047 employees.
The Company is an investor-owned holding Company. The Company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity and the delivery and sale of natural gas. The Company serves
approximately 601,000 electric customers in eastern and central Kansas and
approximately 648,000 natural gas customers in Kansas and northeastern
Oklahoma. The Company's non-utility subsidiaries market natural gas primarily
to large commercial and industrial customers, provide electronic security
services, and provide other energy-related products and services. The Company
has acquired 30.8 million shares of common stock of ADT Limited, representing
approximately 24% of ADT's outstanding common shares. ADT's principal
business is providing electronic security services.
In January 1996, the KCC initiated an order for a generic investigation
to analyze matters related to the potential restructuring of the electric
industry and the overall implications to both utilities and public interests
within the State of Kansas. This order was initiated given recent
developments at the Federal Energy Regulatory Commission (FERC), other state
regulatory agencies and increased competition among utilities related to large
industrial electric customers. The order was established as a means to define
the KCC's role within the electric generation industry as it may become more
competitive, and address any developments as they may occur. Currently, there
are no proceedings or actions at the KCC which would open the Company's
current electric markets to greater competition, nor establish guidelines as
to a change in the degree of regulatory oversight that the KCC has on the
Company's operations.
For discussion regarding competition in the electric utility industry and
the potential impact on the Company, see Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations, Other Information,
Competition.
To capitalize on opportunities in the non-regulated natural gas industry,
the Company established Market Center. Market Center, which began operations
on July 1, 1995, provides natural gas transportation, storage, and gathering
services, as well as balancing and title transfer capability. The Company
transferred certain natural gas transmission assets having a net book value of
approximately $50 million to the Market Center. Market Center will provide no
notice natural gas transportation and storage services to the Company under a
long-term contract.
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 $404 million. United Cities purchased the Company's natural gas
distribution system in and around the City of Palmyra, Missouri for $665,000.
As a result of the sales of the Missouri Properties, as described in Note
2 of the Notes to Consolidated Financial Statements, the Company recognized a
gain of approximately $19.3 million, net of tax, ($0.31 per share) and ceased
recording the results of operations for the Missouri Properties during the
first quarter of 1994. Consequently, the Company's results of operations for
the twelve months ended December 31, 1994 are not comparable to the results of
operations for the same period ending December 31, 1993.
The following table reflects, through the dates of the sales of the
Missouri Properties, the approximate operating revenues and operating income
for the years ended December 31, 1994 and 1993, and net utility plant at
December 31, 1993, related to the Missouri Properties (See Notes 2 and 3 of
the Notes to Consolidated Financial Statements included herein):
1994 1993
Percent Percent
of Total of Total
Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . . . . . . .$ 77,008 4.8% $349,749 18.3%
Operating income. . . . . . . . . . . 4,997 1.9% 20,748 7.1%
Net utility plant . . . . . . . . . . - - 296,039 6.6%
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.
The following information includes the operations of KGE since March 31,
1992 and excludes the activities related to the Missouri Properties following
the sales of those properties in the first quarter of 1994.
The percentages of Total Operating Revenues and Operating Income Before
Income Taxes attributable to the Company's electric and natural gas operations
for the past five years were as follows:
Total Operating Income
Operating Revenues Before Income Taxes
Year Electric Natural Gas Electric Natural Gas
1995 73% 27% 98% 2%
1994 69% 31% 97% 3%
1993 58% 42% 85% 15%
1992 57% 43% 89% 11%
1991 41% 59% 84% 16%
The difference between the percentage of electric operating revenues to
total operating revenues and the percentage of electric operating income to
total operating income as compared to the same percentages for natural gas
operations is due to the Company's level of investment in plant and its fuel
costs in each of these segments. The reduction in the percentages for the
natural gas operations in 1994 is due to the sales of the Missouri Properties.
The increase in the percentages for the electric operations in 1992 is due to
the Merger.
The amount of the Company's plant in service (net of accumulated
depreciation) at December 31, for each of the past five years was as follows:
Year Electric Natural Gas Total
(Dollars in Thousands)
1995 $3,676,576 $525,431 $4,202,007
1994 3,676,347 496,753 4,173,100
1993 3,641,154 759,619 4,400,773
1992 3,645,364 696,036 4,341,400
1991 1,080,579 628,751 1,709,330
ELECTRIC OPERATIONS
General
The Company supplies electric energy at retail to approximately 601,000
customers in 462 communities in Kansas. These include Wichita, Topeka,
Lawrence, Manhattan, Salina, and Hutchinson. The Company also supplies
electric energy at wholesale to the electric distribution systems of 67
communities and 5 rural electric cooperatives. The Company has contracts for
the sale, purchase or exchange of electricity with other utilities. The
Company also receives a limited amount of electricity through parallel
generation.
The Company's electric sales for the last five years were as follows
(includes KGE since March 31, 1992):
1995 1994 1993 1992 1991
(Thousands of MWH)
Residential 5,088 5,003 4,960 3,842 2,556
Commercial 5,453 5,368 5,100 4,473 3,051
Industrial 5,619 5,410 5,301 4,419 1,947
Wholesale and
Interchange 4,012 3,899 4,525 3,028 1,669
Other 108 106 103 91 315*
Total 20,280 19,786 19,989 15,853 9,538*
* Includes cumulative effect to January 1, 1991, of a change in revenue
recognition. The cumulative effect of this change increased electric
sales by 256,000 MWH for 1991.
The Company's electric revenues for the last five years were as follows
(includes KGE since March 31, 1992):
1995 1994 1993 1992 1991
(Dollars in Thousands)
Residential $ 396,025 $ 388,271 $ 384,618 $296,917 $160,831
Commercial 340,819 334,059 319,686 271,303 149,152
Industrial 268,947 265,838 261,898 211,593 78,138
Wholesale and
Interchange 104,992 106,243 118,401 98,183 70,262
Other 35,112 27,370 19,934 4,889 13,456
Total $1,145,895 $1,121,781 $1,104,537 $882,885 $471,839
Capacity
The aggregate net generating capacity of the Company's system is presently
5,240 megawatts (MW). The system comprises interests in 22 fossil fueled
steam generating units, one nuclear generating unit (47% interest), seven
combustion peaking turbines and one diesel generator located at eleven
generating stations. Two units of the 22 fossil fueled units (aggregating 100
MW of capacity) have been "mothballed" for future use (See Item 2.
Properties).
The Company's 1995 peak system net load occurred August 28, 1995 and
amounted to 3,979 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 19% above system peak responsibility at the
time of the peak.
The Company and ten companies in Kansas and western Missouri have agreed
to provide capacity (including margin), emergency and economy services for
each other. This arrangement is called the MOKAN Power Pool. The pool
participants also coordinate the planning of electric generating and
transmission facilities.
The Company is one of 47 members of the Southwest Power Pool (SPP). SPP's
responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri,
Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi.
In 1994, the Company joined the Western Systems Power Pool (WSPP). Under
this arrangement, over 103 electric utilities and marketers throughout the
western United States have agreed to market energy and to provide transmission
services. WSPP's intent is to increase the efficiency of the interconnected
power systems operations over and above existing operations. Services
available include short-term and long-term economy energy transactions, unit
commitment service, firm capacity and energy sales, energy exchanges, and
transmission service by intermediate systems.
In January 1994, the Company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA), whereby, the Company received a prepayment
of approximately $41 million for capacity (42 MW) and transmission charges
through the year 2013.
During 1994, KGE entered into an agreement with Midwest Energy, Inc.
(MWE), whereby KGE will provide MWE with peaking capacity of 61 MW through the
year 2008. KGE also entered into an agreement with Empire District Electric
Company (Empire), whereby KGE will provide Empire with peaking and base load
capacity (20 MW in 1994 increasing to 80 MW in 2000) through the year 2000.
In January 1995, the Company entered into another agreement with Empire,
whereby the Company will provide Empire with peaking and base load capacity
(10 MW in 1995 increasing to 162 MW in 2000) through the year 2010.
Future Capacity
The Company does not contemplate any significant expenditures in
connection with construction of any major generating facilities through the
turn of the century (See Item 7. Management's Discussion and Analysis,
Liquidity and Capital Resources). Although the Company's management believes,
based on current load-growth projections and load management programs, it will
maintain adequate capacity margins through 2000, in view of the lead time
required to construct large operating facilities, the Company may be required
before 2000 to consider whether to reschedule the construction of Jeffrey
Energy Center (JEC) Unit 4 or alternatively either build or acquire other
capacity.
Fuel Mix
The Company's coal-fired units comprise 3,242 MW of the total 5,240 MW of
generating capacity and the Company's nuclear unit provides 548 MW of
capacity. Of the remaining 1,450 MW of generating capacity, units that can
burn either natural gas or oil account for 1,369 MW, and the remaining units
which burn only oil or diesel fuel account for 81 MW (See Item 2. Properties).
During 1995, low sulfur coal was used to produce 74% of the Company's
electricity. Nuclear produced 21% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1996, based on the Company's estimate of the
availability of fuel, coal will be used to produce approximately 79% of the
Company's electricity and nuclear will be used to produce approximately 16%.
The Company's fuel mix fluctuates with the operation of nuclear powered
Wolf Creek which has an 18-month refueling and maintenance schedule. The
18-month schedule permits uninterrupted operation every third calendar year.
Wolf Creek was taken off-line on February 3, 1996 for its eighth refueling and
maintenance outage. The outage is expected to last approximately 60 days
during which time electric demand will be met primarily by the Company's
coal-fired operating units.
Nuclear
The owners of Wolf Creek have on hand or under contract 75% of the uranium
required for operation of Wolf Creek through the year 2003. The balance is
expected to be obtained through spot market and contract purchases. The
Company has contracts with the following three suppliers for uranium: Cameco,
Geomex Minerals, Inc., and Power Resources, Inc.
The Company has three contracts for uranium enrichment performed by
USEC, Urenco and Nuexco Trading Corp. These contractual arrangements cover
100% of Wolf Creek's uranium enrichment requirements for 1996-1997, 90% for
1998-1999, 95% for 2000-2001, and 100% for 2005-2014. The balance of the
1998-2005 requirements is expected to be obtained through a combination of
spot market and contract purchases. The decision not to contract for the full
enrichment requirements is one of cost rather than availability of service.
A contractual arrangement is in place with Cameco for the conversion of
uranium to uranium hexafluoride sufficient to meet Wolf Creek's requirements
through the year 2000.
The Company has entered into all of its uranium, uranium enrichment and
uranium hexaflouride arrangements during the ordinary course of business and
is not substantially dependent upon these agreements. The Company believes
there are other suppliers and plentiful sources available at reasonable prices
to replace, if necessary, these contracts. In the event that the Company were
required to replace these contracts, it would not anticipate a substantial
disruption of its business.
The Nuclear Waste Policy Act of 1982 established schedules, guidelines and
responsibilities for the Department of Energy (DOE) to develop and construct
repositories for the ultimate disposal of spent fuel and high-level waste.
The DOE has not yet constructed a high-level waste disposal site and has
announced that a permanent storage facility may not be in operation prior to
2010 although an interim storage facility may be available earlier. Wolf
Creek contains an on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
2006 while still maintaining full core off-load capability. The Company
believes adequate additional storage space can be obtained as necessary.
Additional information with respect to insurance coverage applicable to
the operations of the Company's nuclear generating facility is set forth in
Note 5 of the Notes to Consolidated Financial Statements.
Coal
The three coal-fired units at JEC have an aggregate capacity of 1,795 MW
(Company's 84% share) (See Item 2. Properties). The Company has a long-term
coal supply contract with Amax Coal West, Inc. (AMAX), a subsidiary of Cyprus
Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte
Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located in the
Powder River Basin in Campbell County, Wyoming. The contract expires December
31, 2020. The contract contains a schedule of minimum annual delivery
quantities based on MMBtu provisions. The coal to be supplied is surface
mined and has an average Btu content of approximately 8,300 Btu per pound and
an average sulfur content of .43 lbs/MMBtu (See Environmental Matters). The
average delivered cost of coal for JEC was approximately $1.13 per MMBtu or
$18.54 per ton during 1995.
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern (BN) and Union Pacific (UP) to JEC through
December 31, 2013. Rates are based on net load carrying capabilities of each
rail car. The Company provides 890 aluminum rail cars, under a 20 year lease,
to transport coal to JEC.
The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 672 MW (KGE's 50% share) (See Item 2. Properties). The operator,
Kansas City Power & Light Company (KCPL), maintains coal contracts summarized
in the following paragraphs.
La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under
a variety of spot market transactions, discussed below. Illinois or
Kansas/Missouri coal is blended with the Powder River Basin coal and is
secured from time to time under spot market arrangements. La Cygne 1 uses a
blend of 85% Powder River Basin coal.
La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied
through several contracts, expiring at various times through 1998. This low
sulfur coal had an average Btu content of approximately 8,500 Btu per pound
and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters).
For 1996, KCPL has secured Powder River Basin coal from Powder River Coal
Company, a subsidiary of Peabody Coal Company. Transportation is covered by
KCPL through its Omnibus Rail Transportation Agreement with BN and Kansas City
Southern Railroad (KCS) through December 31, 2000.
During 1995, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.88 per MMBtu or $15.31
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.75 per MMBtu or $12.56 per ton.
The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 775 MW (See Item 2. Properties). The
Company contracted with Cyprus Amax Coal Company's Foidel Creek Mine located
in Routt County, Colorado for low sulfur coal through December 31, 1998.
During 1995, the average delivered cost of coal for the Lawrence units was
approximately $1.18 per MMBtu or $26.19 per ton and the average delivered cost
of coal for the Tecumseh units was approximately $1.17 per MMBtu or $26.14 per
ton. This coal is transported by Southern Pacific Lines and Atchison, Topeka
and Santa Fe Railway Company under a contract expiring December 31, 1998. The
coal supplied from Cyprus has an average Btu content of approximately 11,200
Btu per pound and an average sulfur content of .38 lbs/MMBtu (See
Environmental Matters). The Company anticipates that the Cyprus agreement
will supply the minimum requirements of the Tecumseh and Lawrence Energy
Centers and supplemental coal requirements will continue to be supplied from
coal markets in Wyoming, Utah, Colorado and/or New Mexico.
The Company has entered into all of its coal and transportation contracts
during the ordinary course of business and is not substantially dependent upon
these contracts. The Company believes there are other suppliers for and
plentiful sources of coal available at reasonable prices to replace, if
necessary, fuel to be supplied pursuant to these contracts. In the event that
the Company were required to replace its coal or transportation agreements, it
would not anticipate a substantial disruption of the Company's business.
Natural Gas
The Company uses natural gas as a primary fuel in its Gordon Evans, Murray
Gill, Abilene, and Hutchinson Energy Centers and in the gas turbine units at
its Tecumseh generating station. Natural gas is also used as a supplemental
fuel in the coal-fired units at the Lawrence and Tecumseh generating stations.
Natural gas for Gordon Evans and Murray Gill Energy Centers is supplied by
readily available gas from the spot market. Short-term economical spot market
purchases will supply the system with the flexible natural gas supply to meet
operational needs for the Gordon Evans and Murray Gill Energy Centers.
Natural gas for the Company's Abilene and Hutchinson stations is supplied from
the Company's main system (See Natural Gas Operations).
Oil
The Company uses oil as an alternate fuel when economical or when
interruptions to natural gas make it necessary. Oil is also used as a
supplemental fuel at JEC and La Cygne generating stations. All oil burned by
the Company during the past several years has been obtained by spot market
purchases. At December 31, 1995, the Company had approximately 3 million
gallons of No. 2 and 14 million gallons of No. 6 oil which is believed to be
sufficient to meet emergency requirements and protect against lack of
availability of natural gas and/or the loss of a large generating unit.
Other Fuel Matters
The Company's contracts to supply fuel for its coal and natural gas-fired
generating units, with the exception of JEC, do not provide full fuel
requirements at the various stations. Supplemental fuel is procured on the
spot market to provide operational flexibility and, when the price is
favorable, to take advantage of economic opportunities.
Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
KPL Plants 1995 1994 1993 1992 1991
Per Million Btu:
Coal $1.15 $1.13 $1.13 $1.30 $1.33
Gas 1.63 2.66 2.71 2.15 1.72
Oil 4.34 4.27 4.41 4.19 4.25
Cents per KWH Generation 1.31 1.32 1.31 1.49 1.52
KGE Plants 1995 1994 1993 1992 1991
Per Million Btu:
Nuclear $0.40 $0.36 $0.35 $0.34 $0.32
Coal 0.91 0.90 0.96 1.25 1.32
Gas 1.68 1.98 2.37 1.95 1.74
Oil 4.00 3.90 3.15 4.28 4.13
Cents per KWH Generation 0.82 0.89 0.93 0.98 1.09
Environmental Matters
The Company currently holds all Federal and State environmental approvals
required for the operation of its generating units. The Company believes it
is presently in substantial compliance with all air quality regulations
(including those pertaining to particulate matter, sulfur dioxide and nitrogen
oxides (NOx)) promulgated by the State of Kansas and the Environmental
Protection Agency (EPA).
The Federal sulfur dioxide standards, applicable to the Company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million Btu of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million Btu of heat input and (2) an
opacity greater than 20%. Federal NOx emission standards applicable to these
units prohibit the emission of more than 0.7 pounds of NOx per million Btu of
heat input.
The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the NOx
standards through boiler design and operating procedures. The JEC units are
also equipped with flue gas scrubbers providing additional sulfur dioxide and
particulate matter emission reduction capability.
The Kansas Department of Health and Environment (KDHE) regulations,
applicable to the Company's other generating facilities, prohibit the emission
of more than 2.5 pounds of sulfur dioxide per million Btu of heat input at the
Company's Lawrence generating units and 3.0 pounds at all other generating
units. There is sufficient low sulfur coal under contract (See Coal) to allow
compliance with such limits at Lawrence, Tecumseh and La Cygne 1 for the life
of the contracts. All facilities burning coal are equipped with flue gas
scrubbers and/or electrostatic precipitators.
The Clean Air Act Amendments of 1990 (the Act) require a two-phase
reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995
and Phase II effective in 2000 and a probable reduction in toxic emissions by
a future date yet to be determined. To meet the monitoring and reporting
requirements under the Act's 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 has applied for and has
been accepted for an early substitution permit to bring the co-owned La Cygne
Generating Station under the Phase I regulations.
The NOx and toxic limits, which were not set in the law, were proposed by
the EPA in January 1996. The Company is currently evaluating the steps it
will need to take in order to comply with the proposed new rules, but is
unable to determine its compliance options or related compliance costs until
the evaluation is finished later this year. The Company will have three years
to comply with the new rules.
All of the Company's generating facilities are in substantial compliance
with the Best Practicable Technology and Best Available Technology regulations
issued by EPA pursuant to the Clean Water Act of 1977. Most EPA regulations
are administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed
in Note 5 of the Notes to Consolidated Financial Statements included herein.
NATURAL GAS OPERATIONS
General
At December 31, 1995, the Company supplied natural gas at retail to
approximately 648,000 customers in 362 communities and at wholesale to eight
communities and two utilities in Kansas and Oklahoma. The natural gas systems
of the Company consist of distribution systems in both states purchasing
natural gas from various suppliers and transported by interstate pipeline
companies and the main system, an integrated storage, gathering, transmission
and distribution system. The Company also transports gas for its large
commercial and industrial customers which purchase gas on the spot market.
The Company earns approximately the same margin on the volume of gas
transported as on volumes sold except where discounting occurs in order to
retain the customer's load.
As discussed under General, above, on January 31, 1994, the Company sold
substantially all of its Missouri natural gas distribution properties and
operations to Southern Union and sold the remaining Missouri Properties to
United Cities on February 28, 1994. Additional information with respect to
the impact of the sales of the Missouri Properties is set forth in Notes 2 and
3 of the Notes to Consolidated Financial Statements.
The percentage of total natural gas deliveries, including transportation
and operating revenues for 1995, by state were as follows:
Total Natural Total Natural Gas
Gas Deliveries Operating Revenues
Kansas 96.4% 95.4%
Oklahoma 3.6% 4.6%
The Company's natural gas deliveries for the last five years were as
follows:
1995 1994(2) 1993 1992 1991
(Thousands of MCF)
Residential 55,810 64,804 110,045 93,779 97,297
Commercial 21,245 26,526 47,536 40,556 47,075
Industrial 548 605 1,490 2,214 2,655
Other 17,078(1) 43 41 94 14,960(3)
Transportation 48,292 51,059 73,574 68,425 78,055
Total 142,973 143,037 232,686 205,068 240,042
The Company's natural gas revenues for the last five years were as follows:
1995 1994(2) 1993 1992 1991
(Dollars in Thousands)
Residential $274,550 $332,348 $529,260 $440,239 $433,871
Commercial 94,349 125,570 209,344 169,470 182,486
Industrial 3,051 3,472 7,294 7,804 10,546
Other 31,860 11,544 30,143 27,457 33,434
Transportation 22,366 23,228 28,781 28,393 30,002
Total $426,176 $496,162 $804,822 $673,363 $690,339
(1) The increase in other gas sales reflects an increase in as-available
gas sales.
(2) Information reflects the sales of the Missouri Properties effective
January 31, and February 28, 1994.
(3) Includes cumulative effect to January 1, 1991, of a change in revenue
recognition. The cumulative effect of this change increased natural
gas sales by 14,838,000 MCF for 1991.
In compliance with orders of the state commissions applicable to all
natural gas utilities, the Company has established priority categories for
service to its natural gas customers. The highest priority is for residential
and small commercial customers and the lowest for large industrial customers.
Natural gas delivered by the Company from its main system for use as fuel for
electric generation is classified in the lowest priority category.
Interstate System
The Company distributes natural gas at retail to approximately 518,000
customers located in central and eastern Kansas and northeastern Oklahoma.
The largest cities served in 1995 were Wichita and Topeka, Kansas and
Bartlesville, Oklahoma. The Company has transportation agreements for
delivery of this gas which have terms varying in length from one to twenty
years, with the following non-affiliated pipeline transmission companies:
Williams Natural Gas Company (WNG), Kansas Pipeline Company (KPP), Panhandle
Eastern Pipeline Company (Panhandle), and various other intrastate suppliers.
The volumes transported under these agreements in 1995 and 1994 were as
follows:
Transportation Volumes (BCF's)
1995 1994
WNG 61.8 51.6
KPP 7.1 7.6
Panhandle 1.0 0.8
Others 8.0 9.3
The Company purchases this gas from various producers and marketers under
contracts expiring at various times. The Company purchased approximately 61.7
BCF or 79.3% of its natural gas supply from these sources in 1995 and 52.2 BCF
or 89.3% during 1994. Approximately 90.5 BCF of natural gas is made available
annually under these contracts which extend beyond the year 2000.
In October 1994, the Company executed a long-term gas purchase contract
(Base Contract) and a peaking supply contract with Amoco Production Company
for the purpose of meeting the requirements of the customers served from the
Company's interstate system over the WNG pipeline system. The Company
anticipates that the Base Contract will supply between 35% and 50% of the
Company's demand served by the WNG pipeline system. Amoco is one of various
suppliers over the WNG pipeline system and if this contract were canceled, the
Company could replace gas supplied by Amoco with gas from other suppliers.
Gas available under the Amoco contract is also available for sale by the
Company to other parties and sales are recorded as Other Revenue.
The Company also purchases natural gas from KPP under contracts expiring
at various times. These purchases were approximately 5.3 BCF or 6.7% of its
natural gas supply in 1995 and 4.4 BCF or 5.6% during 1994. The Company
purchases natural gas for the interstate system from intrastate pipelines and
from spot market suppliers under short-term contracts. These sources totaled
3.6 BCF and 3.8 BCF for 1995 and 1994 representing 4.6% and 6.5% of the
system requirements, respectively.
During 1995 and 1994, approximately 7.3 BCF and 8.0 BCF, respectively,
were transferred from the Company's main system to serve a portion of the
demand for Wichita, Kansas. These system transfers represent 9.4% and 13.7%,
respectively, of the interstate system supply.
The average wholesale cost per thousand cubic feet (MCF) purchased for the
distribution systems for the past five years was as follows:
Interstate Pipeline Supply
(Average Cost per MCF)
1995 1994 1993 1992 1991
WNG $ - $ - $3.57 $3.64
$3.61
Other 2.78 3.32 3.01 2.30 2.36
Total Average Cost 2.78 3.32 3.23 2.88 3.02
Main System
The Company serves approximately 130,000 customers in central and north
central Kansas with natural gas supplied through the main system. The
principal market areas include Salina, Manhattan, Junction City, Great Bend,
McPherson and Hutchinson, Kansas.
Natural gas for the Company's main system is purchased from a combination
of direct wellhead production, from the outlet of natural gas processing
plants, and from interstate pipeline interconnects all within the State of
Kansas. Such purchases are transported entirely through Company owned
transmission lines in Kansas.
Natural gas purchased for the Company's main system customer requirements
is transported and/or stored by the Market Center. The Company retains a
priority right to capacity on the Market Center necessary to serve the main
system customers. The Company has the opportunity to negotiate for the
purchase of natural gas with producers or marketers utilizing Market Center
services, which increases the potential supply available to meet main system
customer demands.
During 1995, the Company purchased approximately 8.7 BCF of natural gas
from Mesa Operating Limited Partnership (Mesa). Approximately 3.2 BCF of
natural gas was purchased through the spot market in 1995 which allowed the
Company to avoid minimum take requirements associated with long-term
contracts. These purchases represent approximately 39.7% and 14.6%,
respectively, of the Company's main system requirements during such periods.
Spivey-Grabs field in south-central Kansas supplied approximately 4.8 BCF
of natural gas in both 1995 and 1994, constituting 20.2% and 17.6%,
respectively, of the main system's requirements during such periods. Such
natural gas is supplied pursuant to contracts with producers in the
Spivey-Grabs field, most of which are for the life of the field, and under
which the Company expects to receive approximately 4.4 BCF or 23.6% of natural
gas in 1996. Based on a reserve study performed by an independent petroleum
engineering firm in 1995, significant quantities of gas will be available from
the Spivey-Grabs field for at least twenty years.
Other sources of gas for the main system of 3.4 BCF or 15.6% of the system
requirements were purchased from or transported through interstate pipelines
during 1995. The remainder of the supply for the main system during 1995 and
1994 of 2.2 BCF and 2.5 BCF representing 9.9% and 9.2%, respectively, was
purchased directly from producers or gathering systems.
During 1995 and 1994, approximately 7.3 BCF and 8.0 BCF, respectively, of
the total main system supply was transferred to the Company's interstate
system (See Interstate System).
The Company believes there is adequate natural gas available under
contract or otherwise available to meet the currently anticipated needs of the
main system customers.
The main system's average wholesale cost per MCF purchased for the past
five years was as follows:
Natural Gas Supply - Main System
(Average Cost per MCF)
1995 1994 1993 1992 1991
Mesa-Hugoton Contract $1.44 $1.81 $1.78(1) $1.47(2) $1.36(3)
Other 2.47 2.92 2.69 2.66 2.68
Total Average Cost 2.06 2.23 2.20 2.00 1.94
(1) Includes 2.5 BCF @ $1.31/MCF of make-up deliveries.
(2) Includes 2.1 BCF @ $1.31/MCF of make-up deliveries.
(3) Includes 1.5 BCF @ $1.31/MCF of make-up deliveries.
The load characteristics of the Company's natural gas customers creates
relatively high volume demand on the main system during cold winter days. To
assure peak day service to high priority customers the Company owns and
operates
and has under contract natural gas storage facilities (See Item 2.
Properties).
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 11 of the Notes to Consolidated Financial Statements included herein.
FINANCING
The Company's ability to issue additional debt and equity securities is
restricted under limitations imposed by the charter and the Mortgage and Deed
of Trust of Western Resources and KGE.
Western Resources' mortgage prohibits additional Western Resources first
mortgage bonds from being issued (except in connection with certain
refundings) unless the Company's net earnings available for interest,
depreciation and property retirement for a period of 12 consecutive months
within 15 months preceding the issuance are not less than the greater of twice
the annual interest charges on, or 10% of the principal amount of, all first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on the Company's results for the 12 months ended December 31, 1995,
approximately $487 million principal amount of additional first mortgage bonds
could be issued (7.25% interest rate assumed).
Western Resources bonds may be issued, subject to the restrictions in the
preceding paragraph, on the basis of property additions not subject to an
unfunded prior lien and on the basis of bonds which have been retired. As of
December 31, 1995, the Company had approximately $485 million of net bondable
property additions not subject to an unfunded prior lien entitling the Company
to issue up to $291 million principal amount of additional bonds. As of
December 31, 1995, no additional bonds could be issued on the basis of retired
bonds.
KGE's mortgage prohibits additional KGE first mortgage bonds from being
issued (except in connection with certain refundings) unless KGE's net
earnings before income taxes and before provision for retirement and
depreciation of property for a period of 12 consecutive months within 15
months preceding the issuance are not less than two and one-half times the
annual interest charges on, or 10% of the principal amount of, all KGE first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on KGE's results for the 12 months ended December 31, 1995,
approximately $937 million principal amount of additional KGE first mortgage
bonds could be issued (7.25% interest rate assumed).
KGE bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1995, KGE had approximately $1.3 billion of net bondable property additions
not subject to an unfunded prior lien entitling KGE to issue up to $922
million principal amount of additional KGE bonds. As of December 31, 1995, $1
million in additional bonds could be issued on the basis of retired bonds.
The most restrictive provision of the Company's charter permits the
issuance of additional shares of preferred stock without certain specified
preferred stockholder approval only if, for a period of 12 consecutive months
within 15 months preceding the issuance, net earnings available for payment of
interest exceed one and one-half times the sum of annual interest requirements
plus dividend requirements on preferred stock after giving effect to the
proposed issuance. After giving effect to the annual interest and dividend
requirements on all debt and preferred stock outstanding at December 31, 1995,
such ratio was 2.18 for the 12 months ended December 31, 1995.
REGULATION AND RATES
The Company is subject as an operating electric utility to the
jurisdiction of the Kansas Corporation Commission (KCC) and as a natural gas
utility to the jurisdiction of the KCC and the Corporation Commission of the
State of Oklahoma (OCC), which have general regulatory authority over the
Company's rates, extensions and abandonments of service and facilities,
valuation of property, the classification of accounts and various other
matters.
The Company is subject to the jurisdiction of the FERC and KCC with
respect to the issuance of securities. There is no state regulatory body in
Oklahoma having jurisdiction over the issuance of the Company's securities.
The Company is exempt as a public utility holding company pursuant to
Section 3(a)(1) of the Public Utility Holding Company Act of 1935 from all
provisions of that Act, except Section 9(a)(2). Additionally, the Company
is subject to the jurisdiction of the FERC, including jurisdiction as to rates
with respect to sales of electricity for resale. The Company is not engaged
in the interstate transmission or sale of natural gas which would subject it
to the regulatory provisions of the Natural Gas Act. KGE is also subject to
the jurisdiction of the Nuclear Regulatory Commission as to nuclear plant
operations and safety.
Additional information with respect to Rate Matters and Regulation as set
forth in Note 4 of Notes to Consolidated Financial Statements is included
herein.
EMPLOYEE RELATIONS
As of December 31, 1995, the Company had 4,047 employees. The Company did
not experience any strikes or work stoppages during 1995. The Company's
current contract with the International Brotherhood of Electrical Workers was
negotiated in 1995 and extends through June 30, 1997. The contract covers
approximately 1,950 employees. The Company has contracts with three gas
unions representing approximately 595 employees. These contracts were
negotiated in 1992 and will expire June 6, 1996.
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
John E. Hayes, Jr. 58 Chairman of the Board President
and Chief Executive
Officer
David C. Wittig 40 President Executive Vice President,
(since March 1996) Corporate Strategy (since
May 1995)
Salomon Brothers, Inc.
Managing Director, Co-Head
of Mergers and Acquisitions
James S. Haines, Jr. 49 Executive Vice President Executive Vice President and Chief
and Chief Operating Administrative Officer (1992
Officer (since July 1995) to 1995)
Group Vice President-KGE
Steven L. Kitchen 50 Executive Vice President
and Chief Financial
Officer
Carl M. Koupal, Jr. 42 Executive Vice President Executive Vice President
and Chief Administrative Corporate Communications,
Officer (since July 1995) Marketing, and Economic Development
(since January 1995)
Vice President, Corporate Marketing,
And Economic Development, (1992 to
1994)
Director, Economic Development, (1985
to 1992) Jefferson City,Missouri
John K. Rosenberg 50 Executive Vice President
and General Counsel
Jerry D. Courington 50 Controller
Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the officers, nor any arrangements or
understandings between any officer and other persons pursuant to which he/she
was appointed as an officer.
ITEM 2. PROPERTIES
The Company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas, a natural gas integrated
storage, gathering, transmission and distribution system in Kansas, and a
natural gas distribution system in Kansas and Oklahoma.
During the five years ended December 31, 1995, the Company's gross
property additions totaled $1,025,952,000 and retirements were $190,118,000.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 66
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 150
2 1967 Gas--Oil 367
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18
2 1950 Gas 17
3 1951 Gas 28
4 1965 Gas 197
Combustion Turbines 1 1974 Gas 51
2 1974 Gas 49
3 1974 Gas 54
4 1975 Oil 78
Jeffrey Energy Center (84%)(3):
Steam Turbines 1 1978 Coal 587
2 1980 Coal 617
3 1983 Coal 591
La Cygne Station (50%)(3):
Steam Turbines 1 1973 Coal 341
2 1977 Coal 331
Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (1)
3 1954 Coal 56
4 1960 Coal 113
5 1971 Coal 370
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (1)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 88
8 1962 Coal 148
Combustion Turbines 1 1972 Gas 19
2 1972 Gas 20
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%)(3):
Nuclear 1 1985 Uranium 548
Total 5,240
(1) These units have been "mothballed" for future use.
(2) Based on MOKAN rating.
(3) The Company jointly owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).
NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES
The Company's transmission and storage facility compressor stations, all
located in Kansas, as of December 31, 1995, are as follows:
Mfr Ratings
of MCF/Hr
Capacity at
Driving Type of Mfr hp 14.65 Psia
Location Units Year Installed Fuel Ratings at 60 F
Abilene . . . . . 4 1930 Gas 4,000 5,920
Bison . . . . . . 1 1951 Gas 440 316
Brehm Storage . . 2 1982 Gas 800 486
Calista . . . . . 3 1987 Gas 4,400 7,490
Hope. . . . . . . 1 1970 Electric 600 44
Hutchinson. . . . 2 1989 Gas 1,600 707
Manhattan . . . . 1 1963 Electric 250 313
Marysville. . . . 1 1964 Electric 250 202
McPherson . . . . 1 1972 Electric 3,000 7,040
Minneola. . . . . 5 1952 - 1978 Gas 9,650 14,018
Pratt . . . . . . 3 1963 - 1983 Gas 1,700 3,145
Spivey. . . . . . 4 1957 - 1964 Gas 7,200 1,368
Ulysses . . . . . 12 1949 - 1981 Gas 17,430 6,667
Yaggy Storage . . 3 1993 Electric 7,500 5,000
The Company has contracted with the Market Center for underground storage
of working storage capacity of 2.08 BCF. This contract enables the Company to
supply customers up to 85 million cubic feet per day of gas supply to meet
winter peaking requirements.
The Company has contracted with WNG for additional underground storage in
the Alden field in Kansas. The contract, expiring March 31, 1998, enables the
Company to supply customers with up to 75 million cubic feet per day of gas
supply during winter peak periods. See Item I. Business, Gas Operations for
proven recoverable gas reserve information.
ITEM 3. LEGAL PROCEEDINGS
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. On March 1, 1995 this
litigation between the Company and the Bishop entities was jointly dismissed
with prejudice and the parties exchanged mutual releases of any and all
claims. The gas supply contracts at issue in the above litigations were
canceled. The agreements between the Company and the Bishop entities resolved
disputes between them in regulatory proceedings before the KCC, the Missouri
Public Service Commission, and the FERC.
Additional information on legal proceedings involving the Company is set
forth in Notes 3, 4, and 5 of Notes to Consolidated Financial Statements
included herein. See also Item 1. Business, Environmental Matters, and
Regulation and Rates.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Stock Trading
Western Resources common stock, which is traded under the ticker symbol
WR, is listed on the New York Stock Exchange. As of March 1, 1996, there were
40,831 common shareholders of record. For information regarding quarterly
common stock price ranges for 1995 and 1994, see Note 15 of Notes to
Consolidated Financial Statements included herein.
Dividends
Western Resources common stock is entitled to dividends when and as
declared by the Board of Directors. At December 31, 1995, the Company's
retained earnings were restricted by $857,600 against the payment of dividends
on common stock. However, prior to the payment of common dividends, dividends
must be first paid to the holders of preferred stock and second to the holders
of preference stock based on the fixed dividend rate for each series.
Dividends have been paid on the Company's common stock throughout the
Company's history. Quarterly dividends on common stock normally are paid on
or about the first of January, April, July, and October to shareholders of
record as of about the third day of the preceding month. Dividends increased
four cents per common share in 1995 to $2.02 per share. In January 1996, the
Board of Directors declared a quarterly dividend of 51 1/2 cents per common
share, an increase of one cent over the previous quarter. Future dividends
depend upon future earnings, the financial condition of the Company and other
factors. For information regarding quarterly dividend declarations for 1995
and 1994, see Note 15 of Notes to Consolidated Financial Statements included
herein.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, 1995 1994(1) 1993 1992(2) 1991
(Dollars in Thousands)
Income Statement Data:
Operating revenues:
Electric . . . . . . . . . . . $1,145,895 $1,121,781 $1,104,537 $ 882,885 $ 471,839
Natural gas. . . . . . . . . . 426,176 496,162 804,822 673,363 690,339
Total operating revenues . . 1,572,071 1,617,943 1,909,359 1,556,248 1,162,178
Operating expenses . . . . . . . 1,296,687 1,348,397 1,617,296 1,317,079 1,032,557
Allowance for funds used during
construction . . . . . . . . . 4,206 2,667 2,631 2,002 1,070
Income before cumulative effect
of accounting change . . . . . 181,676 187,447 177,370 127,884 72,285
Cumulative effect to January 1,
1991, of change in revenue
recognition. . . . . . . . . . - - - - 17,360
Net income . . . . . . . . . . . 181,676 187,447 177,370 127,884 89,645
Earnings applicable to common
stock. . . . . . . . . . . . . 168,257 174,029 163,864 115,133 83,268
December 31, 1995 1994(1) 1993 1992(2) 1991
(Dollars in Thousands)
Balance Sheet Data:
Gross plant in service . . . . . $6,128,527 $5,963,366 $6,222,483 $6,033,023 $2,535,448
Construction work in progress. . 100,401 85,290 80,192 68,041 17,114
Total assets . . . . . . . . . . 5,490,677 5,371,029 5,412,048 5,438,906 2,112,513
Long-term debt, preference
stock, and other mandatorily
redeemable securities . . . . . 1,641,263 1,507,028 1,673,988 2,077,459 690,612
Year Ended December 31, 1995 1994(1) 1993 1992(2) 1991
Common Stock Data:
Earnings per share before
cumulative effect of
accounting change. . . . . . . $ 2.71 $ 2.82 $ 2.76 $ 2.20 $ 1.91
Cumulative effect to January 1,
1991, of change in revenue
recognition per share. . . . . - - - - .50
Earnings per share . . . . . . . $ 2.71 $ 2.82 $ 2.76 $ 2.20 $ 2.41
Dividends per share. . . . . . . $ 2.02 $ 1.98 $ 1.94 $ 1.90 $ 2.04(3)
Book value per share . . . . . . $24.71 $23.93 $23.08 $21.51 $18.59
Average shares outstanding(000's) 62,157 61,618 59,294 52,272 34,566
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 3.14 3.42 2.79 2.27 2.69
Ratio of Earnings to Fixed
Charges. . . . . . . . . . . . 2.41 2.65 2.36 2.02 2.98
Ratio of Earnings to Combined
Fixed Charges and Preferred
and Preference Dividend
Requirements . . . . . . . . . 2.18 2.37 2.14 1.84 2.61
(1) Information reflects the sales of the Missouri Properties (Note 2).
(2) Information reflects the merger with KGE on March 31, 1992.
(3) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
GENERAL: Earnings were $2.71 per share of common stock based on
62,157,125 average common shares for 1995, a decrease from $2.82 in 1994 on
61,617,873 average common shares. Net income for 1995 decreased to $181.7
million compared to $187.4 million in 1994. The decrease in net income and
earnings per share is primarily due to the inclusion of the gain on the sales
of, and operating income from, the Company's natural gas distribution
properties and operations in the State of Missouri prior to the sales in the
first quarter of 1994.
Dividends for 1995 increased four cents per common share to $2.02 per
share. In January 1996, the Board of Directors declared a quarterly dividend
of 51 1/2 cents per common share, an increase of one cent over the previous
quarter.
The book value per share was $24.71 at December 31, 1995, compared to
$23.93 at December 31, 1994. The 1995 closing stock price of $33.38 was 135%
of book value. There were 62,855,961 common shares outstanding at December
31, 1995.
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."
The portion of the Missouri Properties purchased by Southern Union was
sold for $404 million. United Cities purchased the Company's natural gas
distribution system in and around the City of Palmyra, Missouri, for $665,000.
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 related to the Missouri Properties from the
Consolidated Balance Sheets. The gain is reflected in Other Income and
Deductions, on the Consolidated Statements of Income.
The following table reflects, through the dates of the sales of the
Missouri Properties, the approximate operating revenues and operating income
for the years ended December 31, 1994 and 1993, and net utility plant at
December 31, 1993, related to the Missouri Properties (See Note 2):
1994 1993
Percent Percent
of Total of Total
Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . $ 77,008 4.8% $349,749 18.3%
Operating income. . . . . 4,997 1.9% 20,748 7.1%
Net utility plant . . . . - - 296,039 6.6%
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.
For additional information regarding the sales of the Missouri Properties
and the pending litigation see Notes 2 and 3 of the Notes to Consolidated
Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES: The Company's liquidity is a function of
its ongoing construction and maintenance program designed to improve
facilities which provide electric and natural gas service and meet future
customer service requirements. Acquisitions and subsidiary investments also
affect the Company's liquidity.
During 1995, construction expenditures for the Company's electric system
were approximately $154 million and nuclear fuel expenditures were
approximately $28 million. It is projected that adequate capacity margins
will be maintained without the addition of any major generating facilities
through the turn of the century. The construction expenditures for
improvements on the natural gas system, including the Company's service line
replacement program, were approximately $55 million during 1995.
Capital expenditures for 1996 through 1998 are anticipated to be as
follows:
Electric Nuclear Fuel Natural Gas
(Dollars in Thousands)
1996. . . . . $117,600 $ 3,300 $56,300
1997. . . . . 126,500 22,300 43,800
1998. . . . . 119,100 20,800 42,100
These expenditures are estimates prepared for planning purposes and are
subject to revisions (See Note 5).
The Company's net cash flows to capital expenditures was 83% for 1995 and
during the last five years has averaged 97%. This ratio indicates the extent
to which the Company is able to fund its capital expenditures with cash flow
from operating activities. This ratio is calculated from the Company's
Consolidated Statements of Cash Flows as net cash flow from operating
activities, less changes in working capital, less dividends on preferred,
preference and common stock, divided by additions to utility plant. The
Company anticipates all of its cash requirements for capital expenditures
through 1998 will be provided from net operating cash flows.
The Company's capital needs through 2000 for bond maturities and cash
sinking fund requirements for bonds and preference stock are approximately
$236 million. This capital will be provided from internal and external
sources available under then existing financial conditions.
The embedded cost of long-term debt was 7.7% at December 31, 1995, an
increase from 7.6% at December 31, 1994. Higher interest rates on
variable-rate long-term debt contributed to the slight increase in the cost of
debt in 1995 compared to 1994.
On December 14, 1995 Western Resources Capital I, a wholly-owned trust,
of which the sole asset is subordinated debentures of the Company, sold in a
public offering four million preferred securities of 7 7/8% Cumulative
Quarterly Income Preferred Securities, Series A, for $100 million. The
securities are shown as Western Resources Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trust holding solely Subordinated
Debentures (Other Mandatorily Redeemable Securities) on the Consolidated
Balance Sheets and Consolidated Statements of Capitalization (See Note 7).
In January 1996, the Company acquired from Laidlaw Transportation Inc.
15.4 million shares of ADT Limited common stock for $215.6 million, as well as
an option to acquire an additional 15.4 million shares of ADT Limited common
stock. In March 1996, the Company exercised the option and acquired the
additional 15.4 million shares of ADT Limited common stock from Laidlaw
Transportation Inc. for approximately $228 million or $14.80 per share. The
Company's total investment in ADT common stock, representing approximately 24%
of ADT's shares currently outstanding, approximates $444 million. The
purchases were financed with short-term borrowings (See Note 5).
The Company's short-term financing requirements are satisfied, as needed,
through the sale of commercial paper, short-term bank loans and borrowings
under lines of credit maintained with banks. At December 31, 1995, short-term
borrowings amounted to $203 million, of which $26 million was commercial paper
(See Notes 10 and 12). At December 31, 1995, the Company had bank credit
arrangements available of $121 million.
The Company's short-term debt balance at December 31, 1995, decreased
approximately $105 million from December 31, 1994. The decrease is primarily
a result of the proceeds from the sale of the Other Mandatorily Redeemable
Securities being used to pay off short-term debt.
The Company has a Dividend Reinvestment and Stock Purchase Plan (DRIP).
Shares issued under the DRIP may be either original issue shares or shares
purchased on the open market.
The Company's capital structure at December 31, 1995, was 48 percent
common stock equity, 6 percent preferred and preference stock, 3 percent Other
Mandatorily Redeemable Securities, and 43 percent long-term debt. The capital
structure at December 31, 1995, including short-term debt and current
maturities of long-term debt, was 45 percent common stock equity, 5 percent
preferred and preference stock, 3 percent Other Mandatorily Redeemable
Securities, and 47 percent debt.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, interest
charges, and preferred and preference dividend requirements. The results of
operations of the Company exclude the activities related to the Missouri
Properties following the sales of those properties in the first quarter of
1994.
For additional information regarding the sales of the Missouri Properties
and the pending litigation, see Notes 2 and 3 of the Notes to Consolidated
Financial Statements. Additional information relating to changes between
years is provided in the Notes to Consolidated Financial Statements.
REVENUES
The operating revenues of the Company are based on sales volumes and rates
authorized by certain state regulatory commissions and the FERC. Future
natural gas and electric sales will be affected by weather conditions,
competition from other sources of energy, competing fuel sources, customer
conservation efforts, and the overall economy of the Company's service area.
In March 1992, in connection with the Company's acquisition of KGE, the
KCC approved the elimination of the Energy Cost Adjustment Clause (ECA) for
most retail customers of the Company effective April 1, 1992. The fuel costs
are now included in base rates and were established at a level intended by the
KCC to equal the projected average cost of fuel through August 1995.
Therefore, if the Company wished to recover an increase in fuel cost above the
projected average cost it would have to file a request for recovery in a rate
filing with the KCC which request could be denied in whole or in part. The
Company's fuel costs represented 19% of its total operating expenses for the
years ended December 31, 1995 and 1994, respectively. Any increase in fuel
costs from the projected average which the Company did not recover through
rates would impact the Company's earnings. The degree of any such impact
would be affected by a variety of factors, however, and thus cannot now be
predicted.
Natural gas revenues were reduced as a result of the sales of the Missouri
Properties. The Consolidated Statements of Income include revenues of $77
million for the portion of the first quarter of 1994 prior to the sales of the
Missouri Properties and revenues of $350 million from the Missouri Properties
for 1993. Following the sales of the Missouri Properties, no revenues related
to the Missouri Properties are included in the Consolidated Statements of
Income (See Note 2).
1995 Compared to 1994: Electric revenues increased two percent in 1995 as
a result of increased sales in all customer classes. The increase is
primarily attributable to a higher demand for air conditioning load during the
summer months of 1995 compared to 1994. The Company's service territory
experienced normal temperatures during the summer of 1995, but were more than
20% warmer, based on cooling degree days, compared to the summer of 1994. The
Company has filed an electric rate reduction request with the KCC (See Note
4).
Natural gas revenues decreased in 1995 primarily as a result of the sales
of Missouri Properties in the first quarter of 1994 (See Note 2). The Company
has filed a $36 million rate increase request for its Kansas natural gas
properties with the KCC (See Note 4).
Excluding natural gas sales related to the Missouri Properties, prior to
the sales of those properties in the first quarter of 1994, total natural gas
revenues remained virtually unchanged in 1995. Natural gas revenues increased
from increased transportation sales and as-available sales, but these
increases were offset by decreased commercial and industrial sales and a lower
unit cost of natural gas which is passed on to customers through the purchased
gas adjustment (PGA).
As-available gas is excess natural gas under contract that the Company did
not require for customer sales or storage that is typically sold to gas
marketers. According to the Company's tariff, the nominal margin made on
as-available gas sales, is returned 50% to customers through the PGA and 50%
is reflected in wholesale sales of the Company.
1994 Compared to 1993: Electric revenues increased two percent during
1994 primarily as a result of a four percent increase in commercial and
industrial electric sales. Residential electric sales increased one percent
despite four percent cooler temperatures during the primary air conditioning
load months of June, July, and August. Partially offsetting these increases
in electric revenues was a 14% decrease in wholesale and interchange sales as
a result of higher than normal sales in 1993 to other utilities while their
generating units were down due to the flooding of 1993.
Natural gas revenues and sales decreased significantly in 1994 as a result
of the sales of the Missouri Properties as previously mentioned above. Also
contributing to the decrease in natural gas revenues were reduced natural gas
sales for space heating as a result of much warmer temperatures during the
winter season of 1994 compared to 1993.
OPERATING EXPENSES
1995 Compared to 1994: Total operating expenses decreased four percent in
1995 compared to 1994. The decrease is largely due to the sales of Missouri
Properties, lower natural gas purchases resulting from lower sales, and lower
fuel expense resulting from a lower unit cost of fuel used for generation.
Partially offsetting this decrease were expenses related to an early
retirement program. In the second quarter of 1995, $7.6 million related to
early retirement programs was recorded as an expense.
The Company has filed a request with the KCC to increase the annual
depreciation expense for Wolf Creek Generating Station (See Note 4).
The Company anticipates its operating expenses (including fuel expenses)
will increase in 1996 as a result of Wolf Creek being taken out of service for
refueling and maintenance as discussed under "Fuel Mix" above.
1994 Compared to 1993: Total operating expenses decreased 17% during 1994
primarily as a result of the sales of the Missouri Properties (See Note 2).
Also contributing to the decrease were lower fuel costs for electric
generation and reduced natural gas purchases as a result of lower sales caused
by milder winter temperatures in 1994 compared to 1993.
Partially offsetting the decreases in operating expenses was higher income
tax expense. As of December 31, 1993, Kansas Gas and Electric Company (KGE)
had fully amortized its deferred income tax reserves related to the allowance
for borrowed funds used during construction capitalized for Wolf Creek
Generating Station. The completion of the amortization of these deferred
income tax reserves increased income tax expense and reduced net income by
approximately $12 million in 1994.
OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes,
decreased for the twelve months ended December 31, 1995 compared to 1994 as a
result of the gain on the sales of Missouri Properties recorded in the first
quarter of 1994 and additional interest expense on increased corporate-owned
life insurance (COLI) borrowings. Partially offsetting this decrease was the
recognition of income from death benefit proceeds under COLI contracts during
the fourth quarter of 1995 (See Notes 1 and 6 for discussion of current
legislation affecting COLI).
Other income and deductions, net of taxes, was higher for the twelve
months ended December 31, 1994 compared to 1993 due to the recognition of the
gain on the sales of the Missouri Properties of approximately $19.3 million,
net of tax (See Note 2). Partially offsetting this increase was increased
interest expense on COLI borrowings. Also partially offsetting the increase
was the recognition of income in 1993 from death benefit proceeds from COLI
policies.
INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS: Total
interest charges increased three percent for the twelve months ended December
31, 1995, primarily due to higher debt balances and higher interest rates on
short-term borrowings and variable long-term debt.
The Company's embedded cost of long-term debt increased to 7.7% at
December 31, 1995, compared to 7.6% and 8.1% at December 31, 1994 and 1993.
Higher interest rates on variable-rate long-term debt contributed to the
slight increase in the cost of debt in 1995 compared to 1994.
Total interest charges decreased 17% in 1994 compared to 1993 as a result
of lower debt balances and the refinancing of higher cost debt, as well as
increased COLI borrowings, the interest on which is reflected in Other Income
and Deductions, on the Consolidated Statements of Income. Partially
offsetting these decreases in interest expense were higher interest rates on
short-term borrowings.
MERGER IMPLEMENTATION: In accordance with the KCC Merger order,
amortization of the acquisition adjustment commenced August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. The Company can recover the amortization of the acquisition
adjustment through cost savings under a sharing mechanism approved by the KCC.
Based on the order issued by the KCC, with regard to the recovery of the
acquisition premium, the Company must achieve a level of savings on an annual
basis (considering sharing provisions) of approximately $27 million in order
to recover the entire acquisition premium. To the extent that the Company's
actual operations and maintenance expense is lower than the KCC-stipulated
index, the Company will realize merger savings. The Company has calculated,
in conformance with the KCC order, annual savings associated with the
acquisition to be in excess of $27 million for 1995. As management presently
expects to continue this level of savings, the amount is expected to be
sufficient to allow for the full recovery of the acquisition premium.
OTHER INFORMATION
INFLATION: Under the ratemaking procedures prescribed by the regulatory
commissions to which the Company is subject, only the original cost of plant
is recoverable in rates charged to customers. Therefore, because of
inflation, present and future depreciation provisions are inadequate for
purposes of maintaining the purchasing power invested by common shareholders
and the related cash flows are inadequate for replacing property. The impact
of this ratemaking process on common shareholders is mitigated to the extent
depreciable property is financed with debt that can be repaid with dollars of
less purchasing power. While the Company has experienced relatively low
inflation in the recent past, the cumulative effect of inflation on operating
costs may require the Company to seek regulatory rate relief to recover these
higher costs.
ENVIRONMENTAL: The Company has taken a proactive position with respect to
the potential environmental liability associated with former manufactured gas
sites and has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (See Note 5).
Although the Company currently has no Phase I affected units under the
Clean Air Act of 1990, the Company has applied for and has been accepted for
an early substitution permit to bring the co-owned La Cygne Station under the
Phase I guidelines. The oxides of nitrogen and toxic limits, which were not
set in the law, were proposed by the EPA in January 1996. The Company is
currently evaluating the steps it will need to take in order to comply with
the proposed new rules, but is unable to determine its compliance options or
related compliance costs until the evaluation is finished later this year.
The Company will have three years to comply with the new rules. (See Note 5).
COMPETITION: As a regulated utility, the Company currently has limited
direct competition for retail electric service in its certified service area.
However, there is competition, based largely on price, from the generation, or
potential generation, of electricity by large commercial and industrial
customers, and independent power producers.
The 1992 Energy Policy Act (Act) requires increased efficiency of energy
usage and has affected the way electricity is marketed. The Act also provides
for increased competition in the wholesale electric market by permitting the
FERC to order third party access to utilities' transmission systems and by
liberalizing the rules for ownership of generating facilities. As part of the
Merger, the Company agreed to open access of its transmission system for
wholesale transactions. During 1995, wholesale electric revenues represented
approximately nine percent of the Company's total electric revenues.
Operating in this competitive environment could place pressure on utility
profit margins and credit quality. Wholesale and industrial customers may
threaten to pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to
obtain reduced energy costs. Increasing competition has resulted in credit
rating agencies applying more stringent guidelines when making utility credit
rating determinations (See Note 1 for the effects of competition on Statement
of Financial Accounting Standards No. 71).
The Company is providing competitive electric rates for industrial
expansion projects and economic development projects in an effort to maintain
and increase electric load. During 1996, the Company will lose a major
industrial customer to cogeneration resulting in a reduction to pre-tax
earnings of approximately $7 to $8 million annually. This customer's decision
to develop its own cogeneration project was based largely on factors other
than energy cost.
To capitalize on opportunities in the non-regulated natural gas industry,
the Company, through its wholly-owned subsidiary Mid Continent Market Center,
Inc. (Market Center), has established a natural gas market center in Kansas.
The Market Center, which began operations on July 1, 1995, provides natural
gas transportation, storage, and gathering services, as well as balancing, and
title transfer capability. The Company transferred certain natural gas
transmission assets having a net book value of approximately $50 million to
the Market Center. The Market Center will provide no notice natural gas
transportation and storage services to the Company under a long-term contract.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 32
Financial Statements:
Consolidated Balance Sheets, December 31, 1995 and 1994 33
Consolidated Statements of Income for the years ended
December 31, 1995, 1994 and 1993 34
Consolidated Statements of Cash Flows for the years ended
1995, 1994 and 1993 35
Consolidated Statements of Taxes for the years ended
December 31, 1995, 1994 and 1993 36
Consolidated Statements of Capitalization, December 31, 1995
and 1994 37
Consolidated Statements of Common Stock Equity for the years
ended December 31, 1995, 1994 and 1993 38
Notes to Consolidated Financial Statements 39
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the
conditions under which they are required or the information is included in the
financial statements and schedules presented:
I, II, III, IV, and V.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors
of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Western Resources, Inc., and subsidiaries as
of December 31, 1995 and 1994, and the related consolidated statements of
income, cash flows, taxes and common stock equity for each of the three years
in the period ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Western
Resources, Inc., and subsidiaries as of December 31, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
As explained in Note 6 to the consolidated financial statements,
effective January 1, 1993, the Company changed its method of accounting for
postretirement benefits and effective January 1, 1994, the Company changed its
method of accounting for postemployment benefits.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 26, 1996
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thouands)
December 31,
1995 1994(1)
ASSETS
UTILITY PLANT (Notes 1 and 8):
Electric plant in service . . . . . . . . . . . . . . . . $5,341,074 $5,226,175
Natural gas plant in service. . . . . . . . . . . . . . . 787,453 737,191
6,128,527 5,963,366
Less - Accumulated depreciation . . . . . . . . . . . . . 1,926,520 1,790,266
4,202,007 4,173,100
Construction work in progress . . . . . . . . . . . . . . 100,401 85,290
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 53,942 39,890
Net utility plant. . . . . . . . . . . . . . . . . . . 4,356,350 4,298,280
OTHER PROPERTY AND INVESTMENTS:
Net non-utility investments . . . . . . . . . . . . . . . 90,044 74,017
Decommissioning trust (Note 5). . . . . . . . . . . . . . 25,070 16,944
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 9,225 13,556
124,339 104,517
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 2,414 2,715
Accounts receivable and unbilled revenues (net) (Note 1). 257,292 219,760
Fossil fuel, at average cost. . . . . . . . . . . . . . . 54,742 38,762
Gas stored underground, at average cost . . . . . . . . . 28,106 45,222
Materials and supplies, at average cost . . . . . . . . . 57,996 56,145
Prepayments and other current assets. . . . . . . . . . . 20,973 27,932
421,523 390,536
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 9) . . . . . . . . . . 282,476 283,297
Deferred coal contract settlement costs (Note 4). . . . . 27,274 33,606
Phase-in revenues (Note 4). . . . . . . . . . . . . . . . 43,861 61,406
Corporate-owned life insurance (net) (Notes 1 and 6). . . 44,143 16,967
Other deferred plant costs. . . . . . . . . . . . . . . . 31,539 31,784
Unamortized debt expense. . . . . . . . . . . . . . . . . 56,681 58,237
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 102,491 92,399
588,465 577,696
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $5,490,677 $5,371,029
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See statements):
Common stock equity . . . . . . . . . . . . . . . . . . . $1,553,110 $1,474,455
Cumulative preferred and preference stock . . . . . . . . 174,858 174,858
Western Resources obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely subordinated debentures. . . . . . . . . . . . . 100,000 -
Long-term debt (net). . . . . . . . . . . . . . . . . . . 1,391,263 1,357,028
3,219,231 3,006,341
CURRENT LIABILITIES:
Short-term debt (Note 12) . . . . . . . . . . . . . . . . 203,450 308,200
Long-term debt due within one year (Note 10). . . . . . . 16,000 80
Accounts payable. . . . . . . . . . . . . . . . . . . . . 149,194 130,616
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 68,569 86,966
Accrued interest and dividends. . . . . . . . . . . . . . 62,157 61,069
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 40,266 69,025
539,636 655,956
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 9). . . . . . . . . . . . . . 1,167,470 1,152,425
Deferred investment tax credits (Note 9). . . . . . . . . 132,286 137,651
Deferred gain from sale-leaseback (Note 13) . . . . . . . 242,700 252,341
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 189,354 166,315
1,731,810 1,708,732
COMMITMENTS AND CONTINGENCIES (Notes 3 and 5)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $5,490,677 $5,371,029
(1) Information reflects the sales of the Missouri Properties (Note 2).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thouands, Except Per Share Amounts)
Year Ended December 31,
1995 1994(1) 1993
OPERATING REVENUES (Notes 1 and 4):
Electric. . . . . . . . . . . . . . . . . . . . . . . $1,145,895 $1,121,781 $1,104,537
Natural gas . . . . . . . . . . . . . . . . . . . . . 426,176 496,162 804,822
Total operating revenues. . . . . . . . . . . . . . 1,572,071 1,617,943 1,909,359
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 211,994 220,766 237,053
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 19,425 13,562 13,275
Power purchased . . . . . . . . . . . . . . . . . . . 15,739 15,438 16,396
Natural gas purchases . . . . . . . . . . . . . . . . 263,790 312,576 500,189
Other operations. . . . . . . . . . . . . . . . . . . 317,279 303,391 349,160
Maintenance . . . . . . . . . . . . . . . . . . . . . 108,641 113,186 117,843
Depreciation and amortization . . . . . . . . . . . . 156,915 151,630 164,364
Amortization of phase-in revenues . . . . . . . . . . 17,545 17,544 17,545
Taxes (See Statements):
Federal income. . . . . . . . . . . . . . . . . . . 70,132 76,477 62,420
State income. . . . . . . . . . . . . . . . . . . . 18,388 19,145 15,558
General . . . . . . . . . . . . . . . . . . . . . . 96,839 104,682 123,493
Total operating expenses. . . . . . . . . . . . . 1,296,687 1,348,397 1,617,296
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 275,384 269,546 292,063
OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (2,668) (5,354) 7,841
Gain on sales of Missouri Properties (Note 2) . . . . - 30,701 -
Miscellaneous (net) . . . . . . . . . . . . . . . . . 23,447 12,838 18,418
Income taxes (net) (See Statements) . . . . . . . . . 5,128 (4,329) (777)
Total other income and deductions . . . . . . . . 25,907 33,856 25,482
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 301,291 303,402 317,545
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 95,962 98,483 123,551
Other . . . . . . . . . . . . . . . . . . . . . . . . 27,859 20,139 19,255
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . . . . . . (4,206) (2,667) (2,631)
Total interest charges. . . . . . . . . . . . . . 119,615 115,955 140,175
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 181,676 187,447 177,370
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 13,419 13,418 13,506
EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . $ 168,257 $ 174,029 $ 163,864
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 62,157,125 61,617,873 59,294,091
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING . . . . . $ 2.71 $ 2.82 $ 2.76
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 2.02 $ 1.98 $ 1.94
(1) Information reflects the sales of the Missouri Properties (Note 2).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thouands)
Year Ended December 31,
1995 1994(1) 1993
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 181,676 $ 187,447 $ 177,370
Depreciation and amortization . . . . . . . . . . . . . . 150,186 151,630 164,364
Other amortization (including nuclear fuel) . . . . . . . 15,193 10,905 11,254
Gain on sale of utility plant (net of tax) . . . . . . . (951) (19,296) -
Deferred taxes and investment tax credits (net) . . . . . 14,972 (16,555) 27,686
Amortization of phase-in revenues . . . . . . . . . . . . 17,545 17,544 17,545
Corporate-owned life insurance. . . . . . . . . . . . . . (28,548) (17,246) (21,650)
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640)
Amortization of acquisition adjustment. . . . . . . . . . 6,729 - -
Changes in other working capital items (net of effects
from the sales of the Missouri Properties):
Accounts receivable and unbilled revenues (net)(Note 1) (37,532) (75,630) (15,536)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . (15,980) (7,828) 18,073
Gas stored underground. . . . . . . . . . . . . . . . . 17,116 (5,403) (37,144)
Accounts payable. . . . . . . . . . . . . . . . . . . . 18,578 (41,682) (43,169)
Accrued taxes . . . . . . . . . . . . . . . . . . . . . (19,024) 20,756 7,485
Other . . . . . . . . . . . . . . . . . . . . . . . . . 8,179 41,309 25,400
Changes in other assets and liabilities . . . . . . . . . (11,555) 31,480 (45,927)
Net cash flows from operating activities. . . . . . . . 306,944 267,791 276,111
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 236,827 237,696 237,631
Utility investment. . . . . . . . . . . . . . . . . . . . - - 2,500
Sales of utility plant. . . . . . . . . . . . . . . . . . (1,723) (402,076) -
Non-utility investments (net) . . . . . . . . . . . . . . 15,408 9,041 14,271
Corporate-owned life insurance policies . . . . . . . . . 55,175 54,914 55,833
Death proceeds of corporate-owned life insurance policies (11,187) (1,251) (10,590)
Net Cash flows (used in) from investing activities. . . 294,500 (101,676) 299,645
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . (104,750) (132,695) 218,670
Bank term loan retired. . . . . . . . . . . . . . . . . . - - (230,000)
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - 235,923 223,500
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (105) (223,906) (366,466)
Revolving credit agreements (net) . . . . . . . . . . . . 50,000 (115,000) (35,000)
Other long-term debt issued . . . . . . . . . . . . . . . - - 70,999
Other long-term debt retired. . . . . . . . . . . . . . . - (67,893) (63,956)
Other mandatorily redeemable securities . . . . . . . . . 100,000 - -
Borrowings against life insurance policies. . . . . . . . 49,279 70,633 211,538
Repayment of borrowings against life insurance policies . (5,384) (225) (1,350)
Common stock issued (net) . . . . . . . . . . . . . . . . 36,161 - 125,991
Preference stock redeemed . . . . . . . . . . . . . . . . - - (2,734)
Dividends on preferred, preference, and common stock. . . (137,946) (134,806) (127,316)
Net cash flows used in (from) financing activities. . . (12,745) (367,969) 23,876
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (301) 1,498 342
CASH AND CASH EQUIVALENTS:
Beginning of the period . . . . . . . . . . . . . . . . . 2,715 1,217 875
End of the period . . . . . . . . . . . . . . . . . . . . $ 2,414 $ 2,715 $ 1,217
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
Capitalized). . . . . . . . . . . . . . . . . . . . . . $ 136,548 $ 134,785 $ 171,734
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 84,811 90,229 49,108
(1) Information reflects the sales of the Missouri Properties (Note 2).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES
(Dollars in Thouands)
Year Ended December 31,
1995 1994(1) 1993
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 51,218 $ 98,748 $ 41,200
Deferred taxes arising from:
Alternative minimum tax credit. . . . . . . . . . . . . 23,925 - -
Depreciation and other property related items . . . . . (1,813) 29,506 25,552
Energy and purchased gas adjustment clauses . . . . . . 5,239 9,764 (8,192)
Natural gas line survey and replacement program . . . . 1,192 (313) 355
Missouri property sales . . . . . . . . . . . . . . . . - (36,343) -
Prepaid power sale. . . . . . . . . . . . . . . . . . . (23) (13,759) -
Other . . . . . . . . . . . . . . . . . . . . . . . . . (7,046) (800) 6,166
Amortization of investment tax credits. . . . . . . . . . (6,789) (6,739) (1,982)
Total Federal income taxes. . . . . . . . . . . . . . 65,903 80,064 63,099
Less:
Federal income taxes applicable to non-operating items:
Missouri property sales . . . . . . . . . . . . . . . . - 9,485 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . (4,229) (5,898) 679
Total Federal income taxes applicable to
non-operating items . . . . . . . . . . . . . . . . (4,229) 3,587 679
Total Federal income taxes charged to operations. . 70,132 76,477 62,420
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 17,203 17,758 9,869
Deferred (net). . . . . . . . . . . . . . . . . . . . . . 286 2,129 5,787
Total State income taxes. . . . . . . . . . . . . . . 17,489 19,887 15,656
Less:
State income taxes applicable to non-operating items. . . (899) 742 98
Total State income taxes charged to operations. . . 18,388 19,145 15,558
GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 83,738 86,687 84,583
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 26 5,116 22,878
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 13,075 12,879 16,032
Total general taxes charged to operations . . . . . 96,839 104,682 123,493
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $185,359 $200,304 $201,471
The effective income tax rates set forth below are computed by dividing total Federal and State income
taxes by the sum of such taxes and net income. The difference between the effective rates and the Federal
statutory income tax rates are as follows:
Year Ended December 31, 1995 1994(1) 1993
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . 31.8% 35.3% 31.0%
EFFECT OF:
State income taxes. . . . . . . . . . . . . . . . . . . . (4.3) (4.6) (4.0)
Amortization of investment tax credits. . . . . . . . . . 2.5 2.4 2.7
Corporate-owned life insurance. . . . . . . . . . . . . . 3.2 2.1 3.0
Flow through and amortization, net . . . . . . . . . . . . (.2) (.7) 3.1
Other differences . . . . . . . . . . . . . . . . . . . . 2.0 .5 (.8)
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . . . . 35.0% 35.0% 35.0%
(1) Information reflects the sales of the Missouri Properties (Note 2).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thouands)
December 31,
1995 1994
COMMON STOCK EQUITY (See Statements):
Common stock, par value $5 per share,
authorized 85,000,000 shares, outstanding
62,855,961 and 61,617,873 shares, respectively . . $ 314,280 $ 308,089
Paid-in capital. . . . . . . . . . . . . . . . . . . 697,962 667,992
Retained earnings. . . . . . . . . . . . . . . . . . 540,868 498,374
1,553,110 48% 1,474,455 49%
CUMULATIVE PREFERRED AND PREFERENCE STOCK (Note 7):
Preferred stock not subject to mandatory redemption,
Par value $100 per share, authorized
600,000 shares, outstanding -
4 1/2% Series, 138,576 shares . . . . . . . . 13,858 13,858
4 1/4% Series, 60,000 shares. . . . . . . . . 6,000 6,000
5% Series, 50,000 shares. . . . . . . . . . . 5,000 5,000
24,858 24,858
Preference stock subject to mandatory redemption,
Without par value, $100 stated value,
authorized 4,000,000 shares,
outstanding -
7.58% Series, 500,000 shares. . . . . . . . . 50,000 50,000
8.50% Series, 1,000,000 shares. . . . . . . . 100,000 100,000
150,000 150,000
174,858 6% 174,858 6%
WESTERN RESOURCES OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY
TRUST HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (Note 7): 100,000 3% - 0%
LONG-TERM DEBT (Note 10):
First mortgage bonds . . . . . . . . . . . . . . . . 841,000 841,000
Pollution control bonds. . . . . . . . . . . . . . . 521,817 521,922
Revolving credit agreement. . . . . . . . . . . . . 50,000 -
Less:
Unamortized premium and discount (net) . . . . . . 5,554 5,814
Long-term debt due within one year . . . . . . . . 16,000 80
1,391,263 43% 1,357,028 45%
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . $3,219,231 100% $3,006,341 100%
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY
(Dollars in Thouands)
Common Paid-in Retained
Stock Capital Earnings
BALANCE DECEMBER 31, 1992, 58,045,550 shares. . . . . $290,228 $559,636 $398,503
Net income. . . . . . . . . . . . . . . . . . . . . . 177,370
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,506)
Common stock, $1.94 per share . . . . . . . . . . . (116,019)
Expenses on common and preference stock . . . . . . . (3,453)
Issuance of 3,572,323 shares of common stock. . . . . 17,861 111,555
BALANCE DECEMBER 31, 1993, 61,617,873 shares. . . . . 308,089 667,738 446,348
Net income. . . . . . . . . . . . . . . . . . . . . . 187,447
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,418)
Common stock, $1.98 per share . . . . . . . . . . . (122,003)
Expenses on common stock. . . . . . . . . . . . . . . (228)
Distribution of common stock under the Customer
Stock Purchase Plan . . . . . . . . . . . . . . . . 482
BALANCE DECEMBER 31, 1994, 61,617,873 shares. . . . . 308,089 667,992 498,374
Net income. . . . . . . . . . . . . . . . . . . . . . 181,676
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,419)
Common stock, $2.02 per share . . . . . . . . . . . (125,763)
Expenses on common stock. . . . . . . . . . . . . . . (772)
Issuance of 1,238,088 shares of common stock. . . . . 6,191 30,742
BALANCE DECEMBER 31, 1995, 62,855,961 shares. . . . . $314,280 $697,962 $540,868
The Notes to Consolidated Financial Statements are an integral part of this statement.
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) and its wholly-owned subsidiaries, include KPL, a rate-regulated
electric and gas division of the Company, Kansas Gas and Electric Company
(KGE), a rate-regulated electric utility and wholly-owned subsidiary of the
Company, the Westar companies, non-utility subsidiaries, and Mid Continent
Market Center, Inc. (Market Center), a regulated gas transmission service
provider. KGE owns 47% 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 non-utility subsidiaries
were not material to the Company's overall results of operations.
The Company is an investor-owned holding Company. The Company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity and the delivery and sale of natural gas. The Company serves
approximately 601,000 electric customers in eastern and central Kansas and
approximately 648,000 natural gas customers in Kansas and northeastern
Oklahoma. The Company's non-utility subsidiaries which market natural gas
primarily to large commercial and industrial customers, provide other energy
related products and services and provide electronic security services.
The Company prepares its financial statements in conformity 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). The financial statements
require management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, to disclose contingent assets and
liabilities at the balance sheet date, and to report amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
The Company follows the accounting for regulated enterprises prescribed by
Statement of Financial Accounting Standards No. 71 "Accounting for the Effects
of Certain Types of Regulations" (SFAS 71). This pronouncement requires
deferral of certain costs and obligations based upon approvals received from
regulators to permit recovery or require refund of these costs and revenues in
future periods. Consequently, the recorded net book value of certain assets
and liabilities may be different than that which would otherwise be recorded
by unregulated enterprises. On a continuing basis, the Company reviews the
continued applicability of SFAS 71 based on the current regulatory and
competitive environment. Although recent developments suggest the electric
generation industry may become more competitive, the degree to which
regulatory oversight of the Company will be lifted and competition will be
permitted is uncertain. Currently, there are no proceedings or actions at the
KCC to open the Company's electric markets to greater competition. As a
result, the Company continues to believe that accounting under SFAS 71 is
appropriate. If the Company were to determine that the use of SFAS 71 were no
longer appropriate, it would be required to write-off the deferred costs and
obligations that represent regulatory assets and liabilities referred to
above. It may also be necessary for the Company to reduce the carrying value
of a portion of its plant and equipment to the extent that it is expected to
become impaired. At this time, it is not possible to estimate the amount of
the Company's plant and equipment, if any, that would be considered
unrecoverable in such circumstances, as the effect of any future competition
on the Company's rates is not clear at this time.
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
6.31% in 1995, 4.08% in 1994, and 4.10% in 1993. The cost of additions to
utility plant and replacement units of property are 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.
In accordance with regulatory decisions made by the KCC, amortization of
the acquisition premium of approximately $801 million resulting from the KGE
purchase began in August of 1995. The premium is being amortized over 40
years and has been classified as electric plant in service. Accumulated
amortization through December 31, 1995 totaled $6.7 million.
In March 1995, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
(SFAS 121). This Statement imposes stricter criteria for regulatory assets by
requiring that such assets be probable of future recovery at each balance
sheet date. The Company will adopt this standard on January 1, 1996 and does
not expect that adoption will have a material impact on the financial position
or results of operations based on the Company's current regulatory structure.
This conclusion may change in the future if increases in competition influence
regulation and wholesale and retail pricing in the electric industry.
Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.84% during 1995, 2.87% during 1994, and 3.02%
during 1993 of the average original cost of depreciable property. The methods
and rates of depreciation used by the Company have not varied materially from
the methods and rates which would have been used if the Company were not
regulated and not subject to the provisions prescribed by SFAS 71. In the
past, the methods and rates have been determined by depreciation studies and
approved by the various regulatory bodies. The Company periodically evaluates
its depreciation rates considering the past and expected future experience in
the operation of its facilities. The Company has proposed to more rapidly
recover the Company's investment in nuclear generating assets of Wolf Creek to
reduce the capital costs to a level more closely paralleling that of
non-nuclear generating facilities (For information regarding such proposal,
see Note 4).
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.
Income Taxes: The Company accounts for income taxes in accordance with the
provisions of Statement of Financial Accounting Standards No. 109 "Accounting
for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets and
liabilities are recognized based on temporary differences in amounts recorded
for financial reporting purposes and their respective tax bases (See Note 9).
Investment tax credits previously deferred are being amortized to income
over the life of the property which gave rise to the credits.
Revenues: Operating revenues for both electric and natural gas services
include estimated amounts for services rendered but unbilled at the end of
each year. Unbilled revenues of $66 million and $61 million are recorded as a
component of accounts receivable and unbilled revenues (net) on the
Consolidated Balance Sheets as of December 31, 1995 and 1994, respectively.
The Company's recorded reserves for doubtful accounts receivable totaled
$4.9 million and $3.4 million at December 31, 1995 and 1994, respectively.
Investments: The Company records its investment and ownership percentage
of earnings or losses utilizing the equity method of accounting when the
Company's ownership interest allows it to exert significant influence over the
operations of an investee.
In December 1995, a non-regulated subsidiary's net assets were exchanged
for a 20% equity interest in a corporation supplying gas compression units to
natural gas producers. This investment is valued at approximately $56
million, and is included in net non-utility investments on the Consolidated
Balance Sheets as of December 31, 1995.
Debt Issuance and Reacquisition Expense: Debt premium, discount, and
issuance expenses are amortized over the life of each issue. Under regulatory
procedures, debt reacquisition expenses are amortized over the remaining life
of the reacquired debt or, if refinanced, the life of the new debt.
Risk Management: The Company is exposed to price risk from fluctuating
natural gas prices resulting from gas marketing activities of a non-regulated
subsidiary. This subsidiary utilizes various financial instruments to
mitigate much of its exposure to fluctuating market prices of commodities.
These financial instruments are designated as hedges and as such, gains or
losses associated with these financial instruments are deferred until the
commodity being hedged is delivered.
At December 31, 1995, this subsidiary had entered into natural gas
financial instruments with a contractual volume of 11.05 billion cubic feet
expiring through 2000. The market value of these instruments as of December
31, 1995, was $2.7 million more than the contract value.
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, 1995 and 1994, was $28.5 million and $13.6
million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts
related to corporate-owned life insurance contracts (COLI) are recorded in
Corporate-owned Life Insurance (net) on the Consolidated Balance Sheets:
1995 1994
(Dollars in Millions)
Cash surrender value of contracts. . . $ 479.9 $ 408.9
Borrowings against contracts . . . . . (435.8) (391.9)
COLI (net). . . . . . . . . . $ 44.1 $ 17.0
Income is recorded for increases in cash surrender value and net death
proceeds. Interest expense is recognized for COLI borrowings except for
certain contracts entered into in 1993 and 1992. The net income generated
from COLI contracts purchased prior to 1992 including the tax benefit of the
interest deduction and premium expenses are recorded as Corporate-owned Life
Insurance (net) on the Consolidated Statements of Income. The income from
increases in cash surrender value and net death proceeds was $22.7 million in
1995, $15.6 million in 1994, and $19.7 million in 1993. The interest expense
deduction taken was $25.4 million for 1995, $21.0 million for 1994, and $11.9
million for 1993.
The COLI contracts entered into in 1993 and 1992 were established to
mitigate the cost of postretirement and postemployment benefits. As approved
by the KCC, the Company is using the net income stream generated by these COLI
policies to offset the costs of postretirement and postemployment benefits. A
significant portion of this income stream relates to the tax deduction
currently taken for interest incurred on contract borrowings under these COLI
policies. The amount of the interest deduction used to offset these benefits
costs was $7.0 million for 1995, $5.8 million for 1994, and $4.5 million for
1993.
Federal legislation is pending, which, if enacted, may substantially
reduce or eliminate the tax deduction for interest on COLI borrowings, and
thus reduce a significant portion of the net income stream generated by the
COLI contracts (See Note 6).
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."
The portion of the Missouri Properties purchased by Southern Union was
sold for $404 million. For information regarding litigation in connection
with the sale of the Missouri Properties to Southern Union, see Note 3.
United Cities purchased the Company's natural gas distribution system in and
around the City of Palmyra, Missouri for $665,000.
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 included in the Company's consolidated results for the years
ended December 31, 1994 and 1993, and net utility plant at December 31, 1993,
related to the Missouri Properties:
1994 1993
Percent Percent
of Total of Total
Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . $ 77,008 4.8% $349,749 18.3%
Operating income. . . . . 4,997 1.9% 20,748 7.1%
Net utility plant . . . . - - 296,039 6.6%
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. 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,
alleging, among other things, breach of the Missouri Properties sale agreement
relating to certain gas supply contracts between the Company and various
Bishop entities. Southern Union assumed these contracts upon the sale of the
Missouri Properties and requested 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
including claims related to the purchase price of the Missouri Properties.
The disputed purchase price adjustments were submitted to an arbitrator in
February 1995. Based on the decision of the arbitrator rendered in April
1995, Southern Union paid the Company $3.6 million including interest. For
additional information regarding the sales of the Missouri Properties, see
Note 2.
In May, 1995, Southern Union filed its amended complaint against the
Company, alleging a variety of new theories in support of its revised damage
claims. Southern Union now claims that it has overpaid the Company from
between $38 to $53 million dollars for the Missouri Properties. The Company
has filed its amended answer denying each and every claim made by Southern
Union in its amended complaint. The Company has filed motions for summary
judgment against the amended complaint. The resolution of this matter is not
expected to have a material adverse impact on the Company.
Subject to the approval of the KCC, the Company has entered into five
new gas supply contracts with certain Bishop entities which are currently
regulated by the KCC. A contested hearing was held for the approval of those
contracts. While the case was under consideration by the KCC, the FERC issued
an order under which it extended jurisdiction over the Bishop entities. On
November 3, 1995, the KCC stayed its consideration of the contracts between
the Company and the Bishop entities until the FERC takes final appealable
action on its assertion of jurisdiction over the Bishop entities.
The Company and its subsidiaries are involved in various other legal,
environmental, and regulatory 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 Company's overall financial position
or results of operations.
4. RATE MATTERS AND REGULATION
The Company, under rate orders from the KCC, OCC, and 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.
KCC Rate Proceedings: On August 17, 1995, the Company filed with the KCC
a request to more rapidly recover its investment in its assets of Wolf Creek
over the next seven years. If the request is granted, depreciation expense
for Wolf Creek will increase by approximately $50 million for each of the next
seven years. As a result of this proposal, the Company will also seek to
reduce electric rates for KGE customers by approximately $9 million annually
for the same seven year period.
The request also reduces the annual depreciation expense by approximately
$11 million for electric transmission, distribution and certain generating
plant assets to reflect the effect of increasing useful lives of these
properties. Hearings before the KCC on the depreciation changes and voluntary
rate reductions are expected to occur in May 1996.
In addition, the Company filed a $36 million annual rate increase request
for its Kansas natural gas properties. The increase is being sought to
recover costs associated with its service line replacement program as well as
other increased operating costs (See discussion below regarding KCC order
issued on January 24, 1992). In February 1996, the KCC staff submitted
testimony related to this rate increase supporting the Company's increase of
current gas rates of $36 million annually. The ultimate decision related to
the Company's request resides with the KCC. Hearings before the KCC on the
gas rate increase proposal began February 19, 1996, with an order expected by
April 1996.
On June 30, 1995, the KCC granted a certificate authorizing the
business operations of the Market Center. The Market Center, which began
operations on July 1, 1995, provides natural gas transportation, storage, and
gathering services, as well as balancing, and title transfer capability. The
Company transferred certain natural gas transmission assets having a net book
value of approximately $50 million to the Market Center.
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, 1995,
approximately $14.2 million of these deferrals have been included in Deferred
Charges and Other Assets, Other, on the Consolidated Balance Sheet.
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 ordered the accrual of phase-in
revenues to be discontinued by KGE effective December 31, 1988. KGE began
amortizing the phase-in revenue asset on a straight-line basis over 9 1/2
years beginning January 1, 1989. At December 31, 1995, approximately $44
million of deferred phase-in revenues remain to be recovered.
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KGE 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 KGE to
recover this settlement as follows: 76% of the settlement plus a return 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, KGE 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).
5. 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 $92 million at December 31, 1995. Approximately $20
million is attributable to modifications to upgrade the three turbines at
Jeffrey Energy Center to be completed by December 31, 1998.
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.
Investment: On December 21, 1995 the Company entered into Stock Purchase
and Equity Agreements with Laidlaw Transportation Inc. to acquire up to 30.8
million common shares of ADT Limited (ADT). ADT's principal business is
providing electronic security services. On January 26, 1996, the Company
purchased 15.4 million of such ADT common shares for $215.6 million ($14 per
share). The Company purchased the remaining 15.4 million common shares held
by Laidlaw Transportation Inc. on March 18, 1996 for approximately $228
million or $14.80 per share.
The shares purchased represent approximately 24% of ADT's common equity.
The Company intends to account for its investment in ADT using the equity
method of accounting.
Manufactured Gas Sites: The Company has been associated with 15 former
manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials. The Company and the Kansas Department of
Health and Environment (KDHE) entered into a consent agreement governing all
future work at the 15 sites. The terms of the consent agreement will allow
the Company to investigate these 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 costs incurred for site investigation and risk assessment in 1995 and 1994
were minimal. The Company is aware of other Midwestern utilities which have
incurred remediation costs ranging between $500,000 and $10 million per site.
The KCC has permitted 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 is one of numerous potentially responsible
parties at a groundwater contamination site in Wichita, Kansas (Wichita site)
which is listed by the EPA as a Superfund site. The Company has previously
been associated with other Superfund sites of which the Company's liability
has been classified as de minimis and any potential obligations have been
settled at minimal cost. In 1994, the Company settled Superfund obligations
at three sites for a total of $57,500. The Company's obligation at the
Wichita site appears to be limited based on this experience. In the opinion
of the Company's management, the resolution of this matter is not expected to
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 certain 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 from 1993 through 1995. The Company does not expect additional
equipment acquisitions or other material expenditures to be needed to meet
Phase II sulfur dioxide requirements.
Other Environmental Matters: As part of the sale of the Company's
Missouri Properties to Southern Union, Southern Union assumed responsibility
for any environmental matters related to the Missouri Properties. The Company
may be liable for up to a maximum of $7.5 million for 15 years after the date
of the sale under a sharing arrangement with Southern Union for environmental
matters pending or discovered within the two year period ended January 31,
1996.
Decommissioning: The Company accrues decommissioning costs over the
expected life of the Wolf Creek generating facility. The accrual is based on
estimated unrecovered decommissioning costs which consider inflation over the
remaining estimated life of the generating facility and are net of expected
earnings on amounts recovered from customers and deposited in an external
trust fund.
On June 9, 1994, the KCC issued an order approving the estimated
decommissioning costs as determined by a 1993 Wolf Creek Decommissioning Cost
Study to be recovered in rates. The cost study estimated the Company's share
of decommissioning costs to be $595 million or approximately $174 million in
1993 dollars. The decommissioning costs are currently expected to be incurred
during the period 2025 through 2033. These costs were calculated using an
assumed inflation rate of 3.45% and an average after tax expected return on
trust fund assets of 5.9%. Decommissioning costs are being charged to
operating expenses in accordance with the KCC order. Amounts expensed
approximated $3.6 million in 1995 and will increase annually to $5.5 million
in 2024.
The Company's investment in the decommissioning fund, including
reinvested earnings approximated $25.0 million and $16.9 million at December
31, 1995 and December 31, 1994, respectively. Trust fund earnings accumulate
in the fund balance and increase the recorded decommissioning liability.
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 staff of the SEC has questioned certain current accounting practices
used by nuclear electric generating station owners regarding the recognition,
measurement, and classification of decommissioning costs for nuclear electric
generating stations. In response to these questions, the FASB is expected to
issue new accounting standards for removal costs, including decommissioning in
1996. If current electric utility industry accounting practices for such
decommissioning costs are changed: (1) annual decommissioning expenses could
increase, (2) the estimated present value of decommissioning costs could be
recorded as a liability rather than as accumulated depreciation, and (3) trust
fund income from the external decommissioning trusts could be reported as
investment income rather than as a reduction to decommissioning expense.
When revised accounting guidance is issued, the Company will also have to
evaluate its effect on accounting for removal costs of other long-lived
assets. At this time, the Company is not able to predict what effect such
changes would have on results of operations, financial position, or related
regulatory practices until the final issuance of revised accounting guidance.
The Company carries premature decommissioning insurance which 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. This decommissioning insurance will only be
available if the insurance funds are not needed to implement the NRC-approved
plan for stabilization and decontamination.
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. If this liability limitation is insufficient, the U.S.
Congress will consider taking whatever action is necessary to compensate the
public for valid claims. 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 totaling 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 or premature decommissioning costs up to $1.3 billion
(Company's share). Premature decommissioning insurance cost recovery is
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 under the current policies of approximately $11
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.
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 and coal. Some of these contracts contain provisions for price
escalation and minimum purchase commitments. At December 31, 1995, WCNOC's
nuclear fuel commitments (Company's share) were approximately $15.3 million
for uranium concentrates expiring at various times through 2001, $120.8
million for enrichment expiring at various times through 2014, and $72.7
million for fabrication through 2025. At December 31, 1995, the Company's
coal contract commitments in 1995 dollars under the remaining terms of the
contracts were approximately $2.5 billion. The largest coal contract expires
in 2020, with the remaining coal contracts expiring at various times through
2013.
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.
6. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains qualified 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.
Salary Continuation: The Company maintains a non-qualified Executive
Salary Continuation Program for the benefit of certain management employees,
including executive officers.
The following tables provide information on the components of pension and
salary continuation costs under Statement of Financial Accounting Standards
No. 87 "Employers' Accounting for Pension Plans" (SFAS 87), funded status and
actuarial assumptions for the Company:
Year Ended December 31, 1995 1994 1993
(Dollars in Thousands)
SFAS 87 Expense:
Service cost. . . . . . . . . . $ 11,059 $ 10,197 $ 9,778
Interest cost on projected
benefit obligation. . . . . . 32,416 29,734 35,688
(Gain) loss on plan assets. . . (102,731) 7,351 (64,113)
Deferred investment gain (loss) 70,810 (38,457) 29,190
Net amortization. . . . . . . . 1,132 245 (669)
Net expense . . . . . . . . $ 12,686 $ 9,070 $ 9,874
December 31, 1995 1994 1993
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $331,027 $278,545 $353,023
Non-vested . . . . . . . . . 21,775 19,132 26,983
Total. . . . . . . . . . . $352,802 $297,677 $380,006
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $444,608 $375,521 $490,339
Projected benefit obligation . . . 456,707 378,146 468,996
Funded status. . . . . . . . . . . (12,099) (2,625) 21,343
Unrecognized transition asset. . . (527) (2,205) (2,756)
Unrecognized prior service costs . 57,087 47,796 64,217
Unrecognized net (gain). . . . . . (75,312) (56,079) (108,783)
Accrued liability. . . . . . . . $(30,851) $(13,113) $(25,979)
Year Ended December 31, 1995 1994 1993
Actuarial Assumptions:
Discount rate. . . . . . . . . . 7.5% 8.0-8.5% 7.0-7.75%
Annual salary increase rate. . . 4.75% 5.0% 5.0%
Long-term rate of return . . . . 8.5-9.0% 8.0-8.5% 8.0-8.5%
Postretirement: The Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (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, postretirement benefits expenses approximated $15.0 million and
$12.4 million for 1995 and 1994, respectively. The Company's total
postretirement benefit obligation approximated $123.2 million and $114.6
million at December 31, 1995 and 1994, respectively. In addition, the Company
received an order from the KCC permitting the initial deferral of SFAS 106
expense in excess of amounts previously recognized. To mitigate the impact
incremental SFAS 106 expense will have on rate increases, the Company will
include in the future computation of cost of service the actual postretirement
benefits expenses and an income stream generated from COLI contracts purchased
in 1993 and 1992. To the extent postretirement benefits expenses exceed
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. Because these expenses were deferred, there was no effect on the
results of continuing operations in 1995. At December 31, 1995, approximately
$25.3 million of postretirement expenses had been deferred pursuant to the KCC
order. Pending federal legislation may substantially reduce or eliminate tax
benefits associated with COLI contracts. If this legislation is enacted or
should the income stream generated by the COLI program not be sufficient to
offset postretirement benefit costs on an accrual basis, the KCC order allows
the Company to seek recovery of a deficiency through the ratemaking process.
Regulatory precedents established by the KCC generally permit the accrual
costs of postretirement benefits to be recovered in rates.
The following table summarizes the status of the Company's postretirement
benefit plans for financial statement purposes and the related amounts
included in the Consolidated Balance Sheets:
December 31, 1995 1994
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . $ 81,402 $ 68,570
Active employees fully eligible . . . . . . . 7,645 13,549
Active employees not fully eligible . . . . . 34,144 32,484
Total . . . . . . . . . . . . . . . . . . . 123,191 114,603
Fair value of plan assets . . . . . . . . . . . . 46 -
Funded Status . . . . . . . . . . . . . . . . . . (123,145) (114,603)
Unrecognized prior service cost . . . . . . . . . (8,900) (9,391)
Unrecognized transition obligation. . . . . . . . 111,443 117,967
Unrecognized net (gain) . . . . . . . . . . . . . (7,271) (14,489)
Accrued postretirement benefit costs. . . . . . . $(27,873) $(20,516)
Year Ended December 31, 1995 1994
Actuarial Assumptions:
Discount rate . . . . . . . . . . . . . . . . . 7.5 % 8.0-8.5 %
Annual salary increase rate . . . . . . . . . . 4.75 % 5.0 %
Expected rate of return . . . . . . . . . . . . 9.0 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 11%
was assumed for 1995, decreasing one percent per year to five percent in 2001
and thereafter. The health care cost trend rate has a significant effect on
the projected benefit obligation. Increasing the trend rate by one percent
each year would increase the present value of the accumulated projected
benefit obligation by $4.3 million and the aggregate of the service and
interest cost components by $0.4 million.
Postemployment: The Company adopted Statement of Financial Accounting
Standards No. 112 "Employers' Accounting for Postemployment Benefits" (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 contracts purchased in 1993
and 1992. At December 31, 1995 approximately $8.3 million of postemployment
expenses had been deferred pursuant to the KCC order. Pending federal
legislation may substantially reduce or eliminate tax benefits associated with
COLI contracts. If this legislation is enacted or should the income stream
generated by the COLI program not be sufficient to offset postemployment
benefit costs on an accrual basis, the KCC order allows the Company to seek
recovery of such deficit through the ratemaking process. The 1995 and 1994
expense under SFAS 112 was approximately $3.6 million and $2.7 million,
respectively. At December 31, 1995 and 1994, the Company's SFAS 112 liability
recorded on the Consolidated Balance Sheets was approximately $8.7 million and
$8.4 million, respectively.
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, $5.1 million, and $5.8 million for 1995, 1994, and 1993,
respectively.
7. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK,
AND OTHER MANDATORILY REDEEMABLE SECURITIES
The Company's Restated Articles of Incorporation, as amended, provides for
85,000,000 authorized shares of common stock. At December 31, 1995,
62,855,961 shares were outstanding.
The Company has a Dividend Reinvestment and Stock Purchase Plan (DRIP).
Shares issued under the DRIP may be either original issue shares or shares
purchased on the open market. At December 31, 1995, 3,017,627 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 $106.23, $105.67, and $105.10 per share beginning July 1,
1995, 1996 and 1997, 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 $105.31,
$104.55, and $103.79 per share beginning April 1, 1995, 1996, and 1997,
respectively.
Other Mandatorily Redeemable Securities: On December 14, 1995, Western
Resources Capital I, a wholly-owned trust, issued four million preferred
securities of 7 7/8% Cumulative Quarterly Income Preferred Securities, Series
A, for $100 million. The trust interests represented by the preferred
securities are redeemable at the option of Western Resources Capital I, on or
after December 11, 2000, at $25 per preferred security plus accrued interest
and unpaid dividends. Holders of the securities are entitled to receive
distributions at an annual rate of 7 7/8% of the liquidation preference value
of $25. Distributions are payable quarterly, and in substance are tax
deductible by the Company. The sole asset of the trust is $103 million
principal amount of 7 7/8% Deferrable Interest Subordinated Debentures, Series
A due December 11, 2025 (the Subordinated Debentures).
In addition to the Company's obligations under the Subordinated
Debentures, the Company has agreed, pursuant to a guarantee issued to the
trust, the provisions of the trust agreement establishing the trust and a
related expense agreement to guarantee on a subordinated basis payment of
distributions on the preferred securities (but not if the trust does not have
sufficient funds to pay such distributions) and to pay all of the expenses of
the trust (collectively, the "Back-up Undertakings").
Considered together, the Back-up Undertakings constitute a full and
unconditional guarantee by the Company of the trust obligations under the
preferred securities. The securities are shown as Western Resources Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trust holding solely
Subordinated Debentures on the Consolidated Balance Sheets and Consolidated
Statements of Capitalization.
8. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1995
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 155,566 $ 99,133 341 50
Jeffrey 1 (b) Jul 1978 285,357 116,771 587 84
Jeffrey 2 (b) May 1980 289,443 109,858 617 84
Jeffrey 3 (b) May 1983 389,157 143,862 591 84
Wolf Creek (c) Sep 1985 1,371,878 335,941 548 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% 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.
9. INCOME TAXES
Under SFAS 109, temporary differences gave rise to deferred tax assets and
deferred tax liabilities at December 31, 1995 and 1994, respectively, as
follows:
1995 1994
(Dollars in Thousands)
Deferred Tax Assets:
Deferred gain on sale-leaseback. . . . . $ 105,007 $ 110,556
Alternative Minimum tax carry forwards . 18,740 41,163
Other. . . . . . . . . . . . . . . . . . 30,789 29,162
Total Deferred Tax Assets. . . . . . . $ 154,536 $ 180,881
Deferred Tax Liabilities:
Accelerated Depreciation & Other . . . . $ 653,134 $ 661,433
Acquisition Premium. . . . . . . . . . . 315,513 318,190
Deferred Future Income Taxes . . . . . . 282,476 283,297
Other. . . . . . . . . . . . . . . . . . 70,883 70,386
Total Deferred Tax Liabilities. . . . $1,322,006 $1,333,306
Accumulated Deferred
Income Taxes, Net $1,167,470 $1,152,425
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, 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.
At December 31, 1995, the Company has alternative minimum tax credits
generated prior to April 1, 1992, which carry forward without expiration, of
$18.7 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, 1995.
10. LONG-TERM DEBT
The amount of Western Resources' first mortgage bonds authorized by the
Western Resources Mortgage and Deed of Trust, dated July 1, 1939, as
supplemented, is unlimited. The amount of KGE's first mortgage bonds
authorized by the KGE 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.
Debt discount and expenses are being amortized over the remaining lives of
each issue. The Western Resources and KGE 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 KGE
pollution control series bonds, there are no longer any bond sinking fund
requirements. During 1996, $16 million of bonds will mature. $125 million of
bonds will mature in 1999 and $75 million of bonds will mature in 2000.
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 KGE 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, 1995, there was $50
million outstanding under the facility.
Long-term debt outstanding at December 31, 1995 and 1994, was as follows:
1995 1994
(Dollars in Thousands)
Western Resources
First mortgage bond series:
7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000
8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000
7.65% due 2023. . . . . . . . . . . . . 100,000 100,000
525,000 525,000
Pollution control bond series:
Variable due 2032 (1). . . . . . . . . . 45,000 45,000
Variable due 2032 (2). . . . . . . . . . 30,500 30,500
6% due 2033. . . . . . . . . . . . . 58,420 58,500
133,920 134,000
KGE
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. . . . . . . . . . . . . 100,000 100,000
316,000 316,000
Pollution control bond series:
5.10 % due 2023. . . . . . . . . . . . . 13,957 13,982
Variable due 2027 (3). . . . . . . . . . 21,940 21,940
7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500
Variable due 2032 (4). . . . . . . . . . 14,500 14,500
Variable due 2032 (5). . . . . . . . . . 10,000 10,000
387,897 387,922
Revolving Credit Agreement 50,000 -
Less:
Unamortized debt discount. . . . . . . . 5,554 5,814
Long-term debt due within one year . . . 16,000 80
$1,391,263 $1,357,028
Rates at December 31, 1995: (1) 4.05%, (2) 4.049%, (3) 4.00%,
(4) 3.925% and (5) 4.00%
11. SEGMENTS OF BUSINESS
The Company is principally 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, 1995 1994(1) 1993
(Dollars in Thousands)
Operating revenues:
Electric. . . . . . . . . . . $1,145,895 $1,121,781 $1,104,537
Natural gas . . . . . . . . . 426,176 496,162 804,822
1,572,071 1,617,943 1,909,359
Operating expenses excluding
income taxes:
Electric. . . . . . . . . . . 788,900 768,317 791,563
Natural gas . . . . . . . . . 419,267 484,458 747,755
1,208,167 1,252,775 1,539,318
Income taxes:
Electric. . . . . . . . . . . 94,042 100,078 73,425
Natural gas . . . . . . . . . (5,522) (4,456) 4,553
88,520 95,622 77,978
Operating income:
Electric. . . . . . . . . . . 262,953 253,386 239,549
Natural gas . . . . . . . . . 12,431 16,160 52,514
$ 275,384 $ 269,546 $ 292,063
Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,470,359 $4,346,312 $4,231,277
Natural gas . . . . . . . . . 712,858 654,483 1,040,513
Other corporate assets(2) . . 307,460 370,234 140,258
$5,490,677 $5,371,029 $5,412,048
Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 133,421 $ 123,696 $ 126,034
Natural gas . . . . . . . . . 23,494 27,934 38,330
156,915 $ 151,630 $ 164,364
Maintenance:
Electric. . . . . . . . . . . $ 87,942 $ 88,162 $ 87,696
Natural gas . . . . . . . . . 20,699 25,024 30,147
$ 108,641 $ 113,186 $ 117,843
Capital expenditures:
Electric. . . . . . . . . . . $ 153,931 $ 152,384 $ 137,874
Nuclear fuel. . . . . . . . . 28,465 20,590 5,702
Natural gas . . . . . . . . . 54,431 64,722 94,055
$ 236,827 $ 237,696 $ 237,631
(1)Information reflects the sales of the Missouri Properties (Note 2).
(2)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
(Dollars in Thousands, Unaudited)
Natural gas revenues. . . . . . . . . $ 77,008 $349,749
Operating expenses excluding
income taxes. . . . . . . . 69,114 326,329
Income taxes. . . . . . . . . . . . . 2,897 2,672
Operating income. . . . . . . . . . . 4,997 20,748
Identifiable assets . . . . . . . . . - 398,464
Depreciation and amortization . . . . 1,274 12,668
Maintenance . . . . . . . . . . . . . 1,099 10,504
Capital expenditures. . . . . . . . . 3,682 38,821
12. 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, 1995, 1994, and 1993, is set
forth below:
Year Ended December 31, 1995 1994 1993
(Dollars in Thousands)
Available lines of credit. . . . . $121,075 $145,000 $145,000
Short-term debt out-
standing at year end . . . . . . 203,450 308,200 440,895
Weighted average interest rate
on debt outstanding at year
end (including fees) . . . . . . 6.02% 6.25% 3.67%
Maximum amount of short-
term debt outstanding during
the period. . . .. . . . . . . . $355,615 $485,395 $443,895
Monthly average short-term debt. . 301,871 214,180 347,278
Weighted daily average interest
rates during the year
(including fees) . . . . . . . . 6.15% 4.63% 3.44%
In connection with the above arrangements, 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.
13. LEASES
At December 31, 1995, the Company had leases covering various property and
equipment. Certain lease agreements in 1994 and 1993 met the criteria, as set
forth in Statement of Financial Accounting Standards No. 13, "Accounting for
Leases", for classification as capital leases. Capital lease payments were
$3.0 million and $3.3 million in 1994 and 1993, respectively. At December 31,
1995, the Company had no capital leases.
Rental payments for operating leases and estimated rental commitments are
as follows:
Operating
Year Ended December 31, Leases
(Dollars in Thousands)
1993 $ 55,011
1994 55,076
1995 63,353
Future Commitments:
1996 55,992
1997 49,892
1998 45,069
1999 41,882
2000 41,292
Thereafter 721,744
Total $955,871
In 1987, KGE sold and leased back its 50% 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% undivided
interest. KGE 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, 1995, approximately $23.7
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 2000 and $646 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. KGE's lease expense, net of amortization of the
deferred gain and a one-time payment, was approximately $22.5 million for
1995, 1994, and 1993.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in Statement of Financial Accounting Standards No. 107
"Disclosures about Fair Value of Financial Instruments":
Cash and Cash Equivalents-
The carrying amount approximates the fair value because of the
short-term maturity of these investments.
Decommissioning Trust-
The carrying amount is recorded at the fair value of the
decommissioning trust and is based on quoted market prices at
December 31, 1995 and 1994.
Variable-rate Debt-
The carrying amount approximates the fair value because of the
short-term variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of
the estimated value of each issue taking into consideration the
interest rate, maturity, and redemption provisions of each issue.
Redeemable Preference Stock-
The fair value of the redeemable preference stock is based on the
sum of the estimated value of each issue taking into consideration
the dividend rate, maturity, and redemption provisions of each issue.
Other Mandatorily Redeemable Securities-
The fair value of the other mandatorily redeemable securities is based
on the sum of the estimated value of each issue taking into
consideration the dividend rate, maturity, and redemption provisions
of each issue.
The carrying values and estimated fair values of the Company's financial
instruments are as follows:
Carrying Value Fair Value
December 31, 1995 1994 1995 1994
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . .$ 2,414 $ 2,715 $ 2,414 $ 2,715
Decommissioning trust. . . 25,070 16,944 25,070 16,633
Variable-rate debt . . . . 811,190 822,045 811,190 822,045
Fixed-rate debt. . . . . . 1,240,877 1,240,982 1,294,365 1,171,866
Redeemable preference
stock. . . . . . . . . . 150,000 150,000 160,405 155,375
Other Mandatorily
Redeemable Securities. . 100,000 - 102,000 -
The fair value estimates presented herein are based on information
available as of December 31, 1995 and 1994. 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.
Certain subsidiaries of the Company use financial instruments to hedge
price fluctuations in their portfolios of commodity transactions. The
financial instruments used include futures and options traded on the New York
Mercantile Exchange and swaps and options traded in the over-the-counter
market. These subsidiaries are subject to credit risk on its over-the-counter
transactions and monitors the creditworthiness of its counterparties, which
consist primarily of large financial institutions.
15. 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)
1995
Operating revenues. . . . . . . $417,546 $333,380 $423,860 $397,285
Operating income. . . . . . . . 68,517 48,029 99,429 59,409
Net income. . . . . . . . . . . 41,575 21,716 71,905 46,480
Earnings applicable to
common stock. . . . . . . . . 38,220 18,362 68,550 43,125
Earnings per share. . . . . . . $ 0.62 $ 0.30 $ 1.10 $ 0.69
Dividends per share . . . . . . $ 0.505 $ 0.505 $ 0.505 $ 0.505
Average common shares
outstanding . . . . . . . . . 61,747 61,886 62,244 62,712
Common stock price:
High. . . . . . . . . . . . . $ 33 3/8 $ 32 1/2 $ 32 7/8 $ 34
Low . . . . . . . . . . . . . $ 28 5/8 $ 30 1/4 $ 29 3/4 $ 31
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
(1) Information reflects the sales of the Missouri Properties (Note 2).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the Company's Directors required by Item 10 is
set forth in the Company's definitive proxy statement for its 1996 Annual
Meeting of Shareholders to be filed with the Commission. Such information is
incorporated herein by reference to the material appearing under the caption
Election of Directors in the proxy statement to be filed by the Company with
the Commission. See EXECUTIVE OFFICERS OF THE Company on page 18 for the
information relating to the Company's Executive Officers as required by Item
10.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is set forth in the Company's
definitive proxy statement for its 1996 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the captions Information Concerning
the Board of Directors, Executive Compensation, Compensation Plans, and Human
Resources Committee Report in the proxy statement to be filed by the Company
with the Commission.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is set forth in the Company's
definitive proxy statement for its 1996 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the caption Beneficial Ownership of
Voting Securities in the proxy statement to be filed by the Company with the
Commission.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein.
FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1995 and 1994
Consolidated Statements of Income, for the years ended December 31, 1995,
1994 and 1993
Consolidated Statements of Cash Flows, for the years ended December 31,
1995, 1994 and 1993
Consolidated Statements of Taxes, for the years ended December 31, 1995,
1994 and 1993
Consolidated Statements of Capitalization, December 31, 1995 and
1994
Consolidated Statements of Common Stock Equity, for the years ended
December 31, 1995, 1994 and 1993
Notes to Consolidated Financial Statements
SCHEDULES
Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, II, III, IV, and V
REPORTS ON FORM 8-K
Form 8-K dated December 22, 1995.
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -Restated Articles of Incorporation of the Company, as amended I
May 25, 1988. (filed as Exhibit 4 to Registration Statement
No. 33-23022)
3(b) -Certificate of Correction to Restated Articles of Incorporation. I
(filed as Exhibit 3(b) to the December 1991 Form 10-K)
3(c) -Amendment to the Restated Articles of Incorporation, as amended
May 5, 1992 (filed electronically)
3(d) -Amendments to the Restated Articles of Incorporation of the I
Company (filed as Exhibit 3 to the June 1994 Form 10-Q)
3(e) -By-laws of the Company. (filed electronically)
3(f) -Certificate of Designation of Preference Stock, 8.50% Series, I
without par value. (filed as Exhibit 3(d) to the December
1993 Form 10-K)
3(g) -Certificate of Designation of Preference Stock, 7.58% Series, I
without par value. (filed as Exhibit 3(e) to the December
1993 Form 10-K)
4(a) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I
and Harris Trust and Savings Bank, Trustee. (filed as Exhibit
4(a) to Registration Statement No. 33-21739)
4(b) -First through Fifteenth Supplemental Indentures dated July 1, I
1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1,
1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1,
1954, September 1, 1961, April 1, 1969, September 1, 1970,
February 1, 1975, May 1, 1976 and April 1, 1977, respectively.
(filed as Exhibit 4(b) to Registration Statement No. 33-21739)
4(c) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
4(d) -Seventeenth Supplemental Indenture dated February 1, 1978. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(e) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(f) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(g) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(h) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(i) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)
4(j) -Twenty-Third Supplemental Indenture dated July 2, 1986. (filed I
as Exhibit 4(j) to Registration Statement No. 33-12054)
4(k) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. (filed I
as Exhibit 4(k) to Registration Statement No. 33-21739)
4(l) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(m) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
Description
4(n) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(o) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(p) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)
4(q) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(r) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Form S-3, Registration Statement
No. 33-50069)
4(s) -Thirty-Second Supplemental Indenture dated April 15, 1994,
(filed electronically)
Instruments defining the rights of holders of other long-term debt not
required to be filed as exhibits will be furnished to the Commission
upon request.
10(a) -A Rail Transportation Agreement among Burlington Northern I
Railroad Company, the Union Pacific Railroad Company and the
Company (filed as Exhibit 10 to the June 1994 Form 10-Q)
10(b) -Agreement between the Company and AMAX Coal West Inc. I
effective March 31, 1993. (filed as Exhibit 10(a) to the
December 1993 Form 10-K)
10(c) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed as Exhibit 10(b) to the
December 1993 Form 10-K)
10(d) -Letter of Agreement between The Kansas Power and Light Company I
and John E. Hayes, Jr., dated November 20, 1989. (filed as
Exhibit 10(w) to the December 1989 Form 10-K)
10(e) -Amended Agreement and Plan of Merger by and among The Kansas I
Power and Light Company, KCA Corporation, and Kansas Gas and
Electric Company, dated as of October 28, 1990, as amended by
Amendment No. 1 thereto, dated as of January 18, 1991. (filed
as Annex A to Registration Statement No. 33-38967)
10(f) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 1993 Form 10-K)
10(g) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I
December 1993 Form 10-K)
10(h) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 1993 Form 10-K)
10(i) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 1993 Form 10-K)
10(j) -Executive Salary Continuation Plan of Western Resources, Inc.,
as revised, effective September 22, 1995. (filed electronically)
10(k) -Executive Salary Continuation Plan for John E. Hayes, Jr.,
Dated March 15, 1995. (filed electronically)
10(l) -Stock Purchase Agreement between the Company and Laidlaw
Transportation Inc., dated December 21, 1995.
(filed electronically)
10(l)1-Equity Agreement between the Company and Laidlaw Transportation
Inc., dated December 21, 1995. (filed electronically)
Description
10(m) -Letter Agreement between the Company and David C. Wittig,
dated April 27, 1995. (filed electronically)
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
21 -Subsidiaries of the Registrant. (filed electronically)
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
(filed electronically)
27 -Financial Data Schedules (filed electronically)
99 -Kansas Gas and Electric Company's Annual Report on Form 10-K
for the year ended December 31, 1995 (filed electronically)
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
WESTERN RESOURCES, INC.
March 27, 1996 By JOHN E. HAYES, JR.
John E. Hayes, Jr., Chairman of the Board
and Chief Executive Officer