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, 1998
[ ] 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 785/575-6300
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. (x)
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,728,898,185 of Common Stock and $14,673,374 of
Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there
is no readily ascertainable market value) at April 8, 1999.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock.
Common Stock, $5.00 par value 66,336,621
(Class) (Outstanding at April 14, 1999)
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 June 3O, 1999.
<PAGE>
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 1998
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 26
Item 3. Legal Proceedings 29
Item 4. Submission of Matters to a Vote of
Security Holders 30
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 30
Item 6. Selected Financial Data 31
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 32
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 59
Item 8. Financial Statements and Supplementary Data 60
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 103
PART III
Item 10. Directors and Executive Officers of the
Registrant 103
Item 11. Executive Compensation 103
Item 12. Security Ownership of Certain Beneficial
Owners and Management 103
Item 13. Certain Relationships and Related Transactions 103
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 104
Signatures 111
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
Western Resources, Inc. is a publicly traded consumer services company,
incorporated in 1924. Our primary business activities are providing electric
generation, transmission and distribution services to approximately 620,000
customers in Kansas and providing monitored services to approximately 1.5
million customers in North America, the United Kingdom and Continental Europe.
In addition, through our 45% ownership interest in ONEOK, Inc. (ONEOK), natural
gas transmission and distribution services are provided to approximately 1.4
million customers in Oklahoma and Kansas. Rate regulated electric service is
provided by KPL, a division of the company, and Kansas Gas and Electric Company
(KGE), a wholly-owned subsidiary. Monitored services are provided by
Protection One, Inc. (Protection One), a publicly-traded, approximately
85%-owned subsidiary. KGE owns 47% of Wolf Creek Nuclear Operating Corporation
(WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek).
Our corporate headquarters are located at 818 Kansas Avenue, Topeka, Kansas
66612.
As of December 31, 1998, we had 6,960 employees. We did not experience any
strikes or work stoppages during 1998. Our current contract with the
International Brotherhood of Electrical Workers extends through June 30, 1999.
The contract covers approximately 1,440 employees. Protection One has
approximately 800 employees in France who are covered by a collective bargaining
agreement.
On February 7, 1997, we signed a merger agreement with Kansas City Power
& Light Company (KCPL) by which KCPL would be merged with and into the company
in exchange for company stock. In December 1997, representatives of our
financial advisor indicated that they believed it was unlikely that they would
be in a position to issue a fairness opinion required for the merger on the
basis of the previously announced terms.
On March 18, 1998, we and KCPL agreed to a restructuring of our February
7, 1997, merger agreement which will result in the formation of Westar Energy,
a new electric company. Under the terms of the merger agreement, our electric
utility operations will be transferred to KGE, and KCPL and KGE will be merged
into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed Westar
Energy. In addition, under the terms of the merger agreement, KCPL shareholders
will receive company common stock which is subject to a collar mechanism of not
less than .449 nor greater than .722, provided the amount of company common
stock received may not exceed $30.00, and one share of Westar Energy common
stock per KCPL share. The Western Resources Index Price is the 20 day average
of the high and low sale prices for company common stock on the New York Stock
Exchange ending ten days prior to closing. If the Western Resources Index Price
is less than or equal to $29.78 on the fifth day prior to the effective date of
the combination, either party may terminate the agreement. Upon consummation of
the combination, we will own approximately 80.1% of the outstanding equity of
Westar Energy and KCPL shareholders will own approximately 19.9%. As part of
the combination, Westar Energy will assume all of the electric utility related
assets and liabilities of Western Resources, KCPL and KGE.
<PAGE>
Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion
of indebtedness for borrowed money of Western Resources and KGE, and $800
million of debt of KCPL. Long-term debt of the company, excluding Protection
One, was $2.5 billion at December 31, 1998. Under the terms of the merger
agreement, it is intended that we will be released from our obligations with
respect to our debt to be assumed by Westar Energy.
Pursuant to the merger agreement, we have agreed, among other things, to
call for redemption all outstanding shares of our 4 1/2% Series Preferred Stock,
par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per
share, and 5% Series Preferred Stock, par value $100 per share.
Consummation of the merger is subject to customary conditions. On July 30,
1998, our shareholders and the shareholders of KCPL voted to approve the amended
merger agreement at special meetings of shareholders. We estimate the
transaction to close in 1999, subject to receipt of all necessary approvals from
regulatory and government agencies.
In testimony filed in February 1999, the KCC staff recommended the merger
be approved but with conditions which we believe would make the merger
uneconomical. The merger agreement allows us to terminate the agreement if
regulatory approvals are not acceptable. The KCC is under no obligation to
accept the KCC staff recommendation. In addition, legislation has been proposed
in Kansas that could impact the transaction. We do not anticipate the proposed
legislation to pass in its current form. We are not able to predict whether any
of these initiatives will be adopted or their impact on the transaction, which
could be material.
On August 7, 1998, we and KCPL filed an amended application with the
Federal Energy Regulatory Commission (FERC) to approve the Western
Resources/KCPL merger and the formation of Westar Energy.
We have received procedural schedule orders in Kansas and Missouri. These
schedules indicate hearing dates beginning May 3, 1999, in Kansas and July 26,
1999, in Missouri.
KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. We, KCPL and KGE have joint interests in certain electric
generating assets, including Wolf Creek. For additional information, see Item
2. Properties, Management's Discussion and Analysis of Financial Condition and
Results of Operations and Note 21 of Notes to Consolidated Financial Statements.
In November 1997, we completed a strategic alliance with ONEOK and
contributed substantially all of our natural gas business to ONEOK in exchange
for a 45% ownership interest in ONEOK. Our ownership interest is comprised of
approximately 3.2 million common shares and approximately 20.1 million
convertible preferred shares. If all the preferred shares were converted, we
would own approximately 45% of ONEOK's common shares presently outstanding.
Following the strategic alliance, the consolidated energy sales, related cost of
sales and operating expenses in 1997 for our natural gas business have been
replaced by investment earnings in ONEOK.
<PAGE>
Protection One had a year of rapid expansion and continued growth. During
the year, Protection One doubled the size of its customer base from about
750,000 customers to about 1.5 million customers. This growth was achieved
through acquisitions and Protection One's Dealer Program.
During 1998, Protection One invested approximately $549 million in security
company acquisitions. Highlights of this activity include:
- Network Multi-Family - A leading provider of monitored services
to multi-family dwellings. This acquisition added approximately
200,000 customers.
- Multimedia Security Services - A purchase of assets including a large
security monitoring center in Wichita, Kansas, that added about
147,000 customers.
- Compagnie Europeenne de Telesecurite - An acquisition of a French
monitored services provider which added 60,000 customers and
established a major presence in Western Europe.
In October 1998, Protection One announced an agreement to acquire Lifeline
Systems, Inc., (Lifeline) a leading provider of 24-hour personal emergency
response and support services in North America. Based on the average closing
price for the three trading days prior to April 8, 1999, the value of the
consideration to be paid under the merger agreement is approximately $129.2
million or $22.05 per Lifeline share in cash and stock. Lifeline has advised
Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 19 of the Notes to Consolidated Financial Statements included herein.
ELECTRIC UTILITY OPERATIONS
General
We supply electric energy at retail to approximately 620,000 customers in
471 communities in Kansas. These include Wichita, Topeka, Lawrence, Manhattan,
Salina, and Hutchinson. We also supply electric energy at wholesale to the
electric distribution systems of 64 communities and 4 rural electric
cooperatives. We have contracts for the sale, purchase or exchange of
electricity with other utilities. We also receive a limited amount of
electricity through parallel generation.
<PAGE>
Our electric energy deliveries for the last three years are as follows:
1998 1997 1996
(Thousands of MWH)
Residential. . . . 5,815 5,310 5,265
Commercial . . . . 6,199 5,803 5,667
Industrial . . . . 5,808 5,714 5,622
Wholesale and
Interchange. . . 4,826 5,334 5,908
Other. . . . . . . 108 107 105
Total. . . . . . 22,756 22,268 22,567
Our electric sales for the last three years are as follows:
1998 1997 1996
(Dollars in Thousands)
Residential. . . . $ 428,680 $ 392,751 $ 403,588
Commercial . . . . 356,610 339,167 351,806
Power Marketing. . 382,601 69,827 -
Industrial . . . . 257,186 254,076 262,989
Wholesale and
Interchange. . . 145,320 142,506 143,380
Other. . . . . . . 41,288 31,721 35,652
Total. . . . . . $1,611,685 $1,230,048 $1,197,415
Competition: The United States electric utility industry is evolving from
a regulated monopolistic market to a competitive marketplace. The 1992 Energy
Policy Act began deregulating the electricity industry. The Energy Policy Act
permitted the FERC to order electric utilities to allow third parties the use of
their transmission systems to sell electric power to wholesale customers. A
wholesale sale is defined as a utility selling electricity to a "middleman",
usually a city or its utility company, to resell to the ultimate retail
customer. As part of the 1992 KGE merger, we agreed to open access of our
transmission system for wholesale transactions. In 1996, the FERC issued Order
888 and 889 requiring all jurisdictional utilities to open their transmission
systems to all market participants on a nondiscriminatory basis and to separate
their generation market functions away from their transmission operations. As
required by this order, we have completed this separation.
For further discussion regarding competition and the potential impact on
the company, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Environmental Matters: We currently hold all Federal and State
environmental approvals required for the operation of our generating units. We
believe we are 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 our Jeffrey Energy
Center (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
<PAGE>
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 when needed to meet permit
limits.
The Kansas Department of Health and Environment (KDHE) regulations,
applicable to our other generating facilities, prohibit the emission of more
than 3.0 pounds of sulfur dioxide per million Btu of heat input. 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.
We must comply with the provisions of The Clean Air Act Amendments of 1990
that require a two-phase reduction in certain emissions. We have installed
continuous monitoring and reporting equipment to meet the acid rain
requirements. We do not expect material capital expenditures to be required to
meet Phase II sulfur dioxide and nitrogen oxide requirements.
All of our generating facilities are in substantial compliance with the
Best Practicable Technology and Best Available Technology regulations issued by
the 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 10 of the Notes to Consolidated Financial Statements included herein.
Regulation and rates: As a Kansas electric utility, we are subject to the
jurisdiction of the KCC which has general regulatory authority over our rates,
extensions and abandonments of service and facilities, valuation of property,
the classification of accounts and various other matters. We are subject to
the jurisdiction of the FERC and KCC with respect to the issuance of
securities.
Electric fuel costs are included in base rates. Therefore, if we wished
to recover an increase in fuel costs, we would have to file a request for
recovery in a rate filing with the KCC. That request could be denied in whole
or in part. Any increase in fuel costs from the projected average which we did
not recover through rates would reduce our earnings. The degree of any such
impact would be affected by a variety of factors, however, and thus cannot be
predicted.
We are 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, we are subject to the
<PAGE>
jurisdiction of the FERC, including our sales of electricity for resale. KGE is
also subject to the jurisdiction of the Nuclear Regulatory Commission for
nuclear plant operations and safety.
Additional information with respect to Rate Matters and Regulation as set
forth in Note 5 of Notes to Consolidated Financial Statements is included
herein.
Fossil Generation
Capacity: The aggregate net generating capacity of our system is presently
5,356 megawatts (MW). The system has interests in 22 fossil fueled steam
generating units, one nuclear generating unit (47% interest), seven combustion
peaking turbines and two diesel generators 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).
Our 1998 peak system net load occurred August 20, 1998, and amounted to
4,201 MW. Our net generating capacity together with power available from firm
interchange and purchase contracts, provided a capacity margin of approximately
14% above system peak responsibility at the time of the peak.
We received a prepayment in 1994 of approximately $41 million for capacity
(42 MW) and transmission charges through the year 2013 in an agreement with
Oklahoma Municipal Power Authority.
KGE has an agreement with Midwest Energy, Inc. (MWE) to provide MWE with
peaking capacity of 61 MW through the year 2008. KGE also entered into an
agreement with Empire District Electric Company (Empire) to provide Empire with
peaking and base load capacity (20 MW in 1994 increasing to 80 MW in 2000)
through the year 2000. We have another agreement with Empire to provide Empire
with peaking and base load capacity (10 MW in 1995 increasing to 162 MW in 2000)
through the year 2010.
Future Capacity: In order to meet the needs of our electric utility
customers, we plan to install three new combustion turbine generators for use as
peaking units. The installed capacity of the three new generators will
approximate 300 MW. The first two units are scheduled to be placed in operation
in 2000 and the third is scheduled to be placed in operation in 2001. We
estimate that the project will require $120 million in capital resources through
the completion of the projects in 2001. In addition, we plan to return an
inactive generation plant in Neosho, Kansas to active service in 1999 at an
estimated cost of $0.7 million.
On January 4, 1999, we and Empire signed a memorandum of understanding that
provides for the joint ownership of a 500-megawatt combined cycle generating
unit, which Empire will operate. We estimate that the project will require $90
million in capital resources and that we will own 40% of the generating unit.
Construction of the unit is expected to begin in the fall of 1999 with operation
beginning approximately 20 months later.
For further discussion regarding future capacity and cash requirements,
see Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
<PAGE>
Fuel Mix: Our coal-fired units comprise 3,347 MW of the total 5,356 MW of
generating capacity and our nuclear unit provides 547 MW of capacity. Of the
remaining 1,462 MW of generating capacity, units that can burn either natural
gas or oil account for 1,378 MW, and the remaining units which burn only diesel
fuel account for 84 MW (See Item 2. Properties).
During 1998, low sulfur coal was used to produce 73% of our electricity.
Nuclear produced 20% and the remainder was produced from natural gas, oil, or
diesel fuel. During 1999, based on our estimate of the availability of fuel,
coal will be used to produce approximately 77% of our electricity and nuclear
will be used to produce approximately 15%.
Our fuel mix fluctuates with the operation of nuclear powered Wolf Creek
as discussed below under Nuclear Generation.
Coal: The three coal-fired units at JEC have an aggregate capacity of
1,860 MW (our 84% share) (See Item 2. Properties). We have 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 $1.04 per MMBtu or $18.82 per ton during
1998.
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP)
railroads to JEC through December 31, 2013. Rates are based on net load
carrying capabilities of each rail car. We provide 868 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 677 MW (KGE's 50% share) (See Item 2. Properties). The operator,
KCPL, maintains coal contracts as 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. High Btu Kansas/Missouri
coal is blended with the Powder River Basin coal and is secured from time to
time under spot market arrangements. The blended fuel mix contains
approximately 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 1999. 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).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with BNSF and Kansas City Southern Railroad through December 31, 2000.
During 1998, the average delivered cost of all local and Powder River Basin
coal procured for La Cygne 1 was approximately $0.74 per MMBtu or $12.77 per ton
and the average delivered cost of Powder River Basin coal for La Cygne 2 was
<PAGE>
approximately $0.66 per MMBtu or $10.97 per ton.
The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 810 MW (See Item 2. Properties). The
company sourced low sulfur coal from Colorado through December 31, 1998 and
began sourcing coal from Montana under contracts through December 31, 2000. The
Colorado coal was transported by the UP and BNSF railroads under contracts
expiring December 31, 1998. The Colorado coal supplied in 1998 had an average
Btu content of approximately 11,292 Btu per pound and an average sulfur content
of .77 lbs/MMBtu (See Environmental Matters). During 1998, the average
delivered cost of Colorado coal for the Lawrence units was approximately $1.22
per MMBtu or $26.51 per ton and the average delivered cost of Colorado coal for
the Tecumseh units was approximately $1.27 per MMBtu or $27.79 per ton. Montana
coal is transported by BNSF railroad under a contract expiring December 31,
2000. The Montana coal supplied in 1998 had an average Btu content of
approximately 9,362 Btu per pound and an average sulfur content of
.36 lbs./MMBtu (See Environmental Matters). During 1998, the average delivered
cost of Montana coal for the Lawrence units was approximately $0.92 per MMBtu or
$17.52 per ton and the average delivered cost of Montana coal for the Tecumseh
units was approximately $0.94 per MMBtu or $17.55 per ton.
We have entered into all of our coal contracts in the ordinary course of
business and are not substantially dependent upon these contracts. We believe
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 we are required to replace our coal
agreements, we would not anticipate a substantial disruption of our business.
We have entered into all of our transportation contracts in the ordinary
course of business. At the time of entering into these contracts, we were not
substantially dependent upon these contracts due to the availability of
competitive rail options. Due to recent rail consolidation, there are now only
two rail carriers capable of serving our origin coal mines and our generating
stations. In the event one of these carriers became unable to provide reliable
service, we could experience a short-term disruption of our business. However,
due to the obligation of the remaining carriers to provide service under the
Interstate Commerce Act, we do not anticipate any substantial long-term
disruption of our business. See also Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations.
Natural Gas: We use natural gas as a primary fuel in our Gordon Evans,
Murray Gill, Neosho, Abilene, and Hutchinson Energy Centers and in the gas
turbine units at our 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 all facilities is supplied by readily
available gas from the short-term economical spot market and will supply the
system with the flexible natural gas supply to meet operational needs. For
Gordon Evans, Murray Gill and Neosho Energy Centers, we maintain firm natural
gas transportation capacity through Williams Gas Pipelines Central through April
1, 2010. For Abilene and Hutchinson Energy Centers, we maintain interruptible
natural gas transportation with Kansas Gas Service through March 31, 2001.
<PAGE>
Oil: We use oil as an alternate fuel when economical or when interruptions
to natural gas make it necessary. Oil is also used as a start-up fuel at the
JEC and La Cygne generating stations. All oil burned during the past several
years has been obtained by spot market purchases. At December 31, 1998, we had
approximately 3 million gallons of No. 2 oil and 23 million gallons of No. 6 oil
which we believe 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: Our contracts to supply fuel for our 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 1998 1997 1996
Per Million Btu:
Coal. . . . . . . . . . $1.15 $1.17 $1.14
Gas . . . . . . . . . . 2.29 2.88 2.50
Oil . . . . . . . . . . 4.40 3.72 4.01
Cents per KWH Generation . 1.31 1.32 1.30
KGE Plants 1998 1997 1996
Per Million Btu:
Nuclear . . . . . . . . $0.48 $0.51 $0.50
Coal. . . . . . . . . . 0.86 0.89 0.88
Gas . . . . . . . . . . 2.28 2.56 2.30
Oil . . . . . . . . . . 4.05 3.32 2.74
Cents per KWH Generation . 0.94 1.00 0.93
Nuclear Generation
The owners of Wolf Creek have on hand or under contract 100% of their
uranium needs for 1999 and 59% of the uranium required to operate Wolf Creek
through September 2003. The balance is expected to be obtained through spot
market and contract purchases. Wolf Creek has active contracts to acquire
uranium from Cameco Corporation and Geomex Minerals, Inc.
A contractual arrangement is in place with Cameco Corporation for the
conversion of uranium to uranium hexafluoride sufficient for the operation of
Wolf Creek through the year 2001.
Wolf Creek has active contracts for uranium enrichment with Urenco and
USEC. Contracted arrangements cover 88% of Wolf Creek's uranium enrichment
requirements for operation of Wolf Creek through March 2005. The balance is
expected to be obtained through spot market and term contract purchases.
<PAGE>
Wolf Creek has entered into all of its uranium, uranium hexaflouride and
uranium enrichment arrangements in the ordinary course of business and is not
substantially dependent upon these agreements. Wolf Creek believes there are
other suppliers available at reasonable prices to replace, if necessary, these
contracts. In the event that Wolf Creek were required to replace these
contracts, Wolf Creek would not anticipate a substantial disruption of its
business.
Nuclear fuel is amortized to cost of sales based on the quantity of heat
produced for the generation of electricity. Under the Nuclear Waste Policy Act
(NWPA) of 1982, the Department of Energy (DOE) is responsible for the permanent
disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-
tenth of a cent for each kilowatt-hour of net nuclear generation delivered and
sold for future disposal of spent nuclear fuel. These disposal costs are
charged to cost of sales and currently recovered through rates.
In 1996, a U.S. Court of Appeals issued a decision that the NWPA
unconditionally obligated the DOE to begin accepting spent fuel for disposal in
1998. In late 1997, the same court issued another decision precluding the DOE
from concluding that its delay in accepting spent fuel is "unavoidable" under
its contracts with utilities due to lack of a repository or interim storage
authority. By the end of 1997, KGE and other utilities had petitioned the DOE
for authority to suspend payments of their quarterly fees until such time as the
DOE begins accepting spent fuel. In January 1998, the DOE denied the petition
of the utilities.
In February 1998, Wolf Creek and other utilities petitioned the court to:
1) compel the DOE to submit to the court within 30 days a program, with
appropriate milestones, to dispose of used nuclear fuel beginning immediately,
2) declare that the utilities are relieved of their obligation to pay into the
Nuclear Waste Fund, and are authorized to escrow future fees unless and until
DOE begins disposing of their used fuel, 3) prohibit the federal government from
suspending or terminating its disposal contracts with the utilities or from
imposing any interest, penalties or other charges as a result of a utility's
suspension of waste fund payments, and 4) preclude the federal government from
using fees paid into the waste fund to compensate the utilities for damages or
additional costs they have incurred as a result of the agency's breach of its
obligation. In May 1998, the court issued an order disposing of all pending
motions and petitions. The court affirmed its conclusion that the sole remedy
for DOE's breach of its statutory obligation under the NWPA is a contract
remedy, and made clear that the court will not revisit the matter until the
utilities have completed their pursuit of that remedy. Wolf Creek intends to
pursue the appropriate contract remedy against the DOE.
A permanent disposal site may not be available for the industry until 2010
or later, although an interim facility may be available earlier. Under current
DOE policy, once a permanent site is available, the DOE will accept spent
nuclear fuel on a priority basis; the owners of the oldest spent fuel will be
given the highest priority. As a result, disposal services for Wolf Creek may
not be available prior to 2016. Wolf Creek has on-site temporary storage for
spent nuclear fuel. Under current regulatory guidelines, this facility can
provide storage space until about 2005. Wolf Creek has started plans to
increase its on-site spent fuel storage capacity. That project, expected to be
completed by
<PAGE>
2000, should provide storage capacity for all spent fuel expected to be
generated by Wolf Creek through the end of its licensed life in 2025.
The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that
the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate
Low-Level Radioactive Waste Compact and selected a site in northern Nebraska to
locate a disposal facility. The present estimate of the cost for such a
facility is about $154 million. WCNOC and the owners of the other five nuclear
units in the compact have provided most of the pre-construction financing for
this project. There is uncertainty as to whether this project will be
completed. Significant opposition to the project has been raised by Nebraska
officials and residents in the area of the proposed facility. Attempts have
been made through litigation and proposed legislation in Nebraska to slow down
or stop development of the facility.
In December 1998, the Nebraska agencies considering the developer's license
application for the facility issued an order denying the application. The
developer has filed for a "contested case hearing" regarding the license
denial. This is the next step in appealing the agencies decision.
Also in December 1998, WCNOC and other utilities that have provided
pre-construction financing filed suit against the state of Nebraska, the
licensing agencies and others, seeking damages related to the utilities
excessive costs incurred because of the agencies delay in reaching a decision in
this matter.
Wolf Creek has an 18-month refueling and maintenance schedule which permits
uninterrupted operation every third calendar year. Wolf Creek was taken
off-line on April 3, 1999, for its tenth refueling and maintenance outage. The
outage is expected to last approximately 35 days during which time electric
demand will be met primarily by the company's coal-fired generating units.
Additional information with respect to insurance coverage applicable to the
operations of our nuclear generating facility is set forth in Note 10 of the
Notes to Consolidated Financial Statements.
Power Delivery
The Power Delivery segment transports electricity from the generating
stations to approximately 620,000 customers. Power Delivery's assets include
substations, poles, wire, underground cable systems, and customer meters. Power
Delivery's objective is to provide low-cost electricity while maintaining a high
level of system reliability and customer service.
Power Delivery transports wholesale energy through its interconnections
with the company's neighboring utilities. We maintain interconnection
relationships through the following agreements.
We are a member 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,
<PAGE>
Louisiana, Arkansas, and Mississippi. We are also a member of the SPP
transmission tariff along with 10 other transmission providers in the region.
Revenues from this tariff are divided among the tariff members based upon
calculated impacts to their respective system. The tariff allows for both non-
firm and firm transmission access.
We are a member of the Western Systems Power Pool (WSPP). Under this
arrangement, electric utilities and marketers throughout the western United
States have agreed to market energy. Services available include short-term and
long-term economy energy transactions, unit commitment service, firm capacity
and energy sales and energy exchanges.
The Power Delivery segment includes the customer service portion of our
electric utility business. Customer service includes our phone center for
business and mass market accounts, our credit and collections function, billing,
meter reading, our meter shop, field service work, revenue accounting, walk-in
offices, day-to-day operational interface with the KCC staff, and theft,
diversion, and claims.
Because the electric utility business is seasonal, the KCC has adopted the
Kansas Cold Weather Rule (CWR). The CWR specifies that business procedures
related to disconnection of service for residential customers have certain
restrictions from November 1 through the following March 31. The CWR is
intended to prevent disconnections due to customers not paying their bills,
leaving the customers facing life threatening risks due to outside
temperatures. Disconnections for customers who do not pay their bills can occur
during this time frame under certain weather conditions. Various pay agreement
rules correspond to the CWR. Due to the CWR, collection efforts for unpaid
bills are much more intense from April 1 to October 31. Sales peaks correlate
directly with the seasonality of the midwestern weather and, therefore, the
workload for customer service is the heaviest from April through August.
MONITORED SERVICES
General: In addition to life safety and property monitoring services,
Protection One provides its customers with enhanced services that include:
- Extended service protection
- Patrol and alarm response
- Two-way voice communication
- Pager service
- Cellular back-up
- Mobile security services
Approximately 85% of Protection One's sales are contractually recurring for
monitoring alarm security systems and other related services.
Protection One's principal activity is immediately responding to the
security and safety needs of its customers 24 hours a day. Protection One's
sales are generated primarily from recurring monthly payments for monitoring and
maintaining the alarm systems that are installed in its customers' premises.
Security systems are designed to detect burglaries, fires and other events.
<PAGE>
Through a network of 66 service branches and four satellite offices in North
America and 49 service branches in continental Europe and the United Kingdom,
Protection One provides maintenance service of security systems and, in certain
markets, armed response to verify that an actual emergency has occurred.
Protection One provides its services to residential (both single family and
multifamily residences), commercial and wholesale customers of the alarm
monitoring industry. Although Protection One intends to grow its presence in
each of the customers classes, it believes that the residential customer class,
which represents in excess of 80% of its customer base, is the most attractive
class of the alarm business because of its lower penetration and stronger growth
prospects, higher gross margins and larger potential size. At December 31,
1998, Protection One's customer base composition was as follows:
Percentage of
Customer Class Total
Single Family 57%
Multifamily/Apartment 21%
Commercial 12%
Wholesale 10%
Total 100%
Wholesale customers represent those customers that are served by smaller
independent alarm dealers that do not have a monitoring station and, therefore,
subcontract monitoring services from Protection One. Of the approximately 10%
of Protection One's customer base that are wholesale customers, approximately
75% of those are residential customers.
Strategy: Protection One's strategy is to become the largest provider of
life safety and property monitoring services based in North America and Europe.
Protection One intends to achieve its growth objectives by extending its
leadership position in large and growing residential markets and adding new
customers through its Dealer Program, "tuck-in" acquisitions, direct sales and
strategic alliances. Protection One believes that this strategy will lead to
continued growth in sales; earnings before interest, taxes, depreciation and
amortization; and earnings. Protection One is focused on:
- Adding new customers at lowest cost by developing new channels of
distribution
- Continuing to improve its operating efficiency and margins through
further integration of acquired accounts and better scale of
economies
- Enhancing revenues and margins by offering additional services to new
and existing customers
- Cross-selling value-added services to customers in each of its
divisions
- Continuing to improve its customer service
- Building a preeminent brand name in the security industry
Protection One's Dealer Program consists of independent companies with
residential and small commercial sales marketing and installation skills that
enter into exclusive contracts with Protection One to provide it with new
<PAGE>
monitoring customers for purchase on an ongoing basis.
Since November 1997, Protection One has completed in excess of 30
transactions, adding approximately one million new customers and establishing
its premier market position. Acquisitions, in conjunction with the Dealer
Program, allow Protection One to increase customer density, which results in
significant operating synergies. Protection One's acquisition strategy for 1999
and beyond is to focus on smaller, less expensive, "tuck-in" acquisitions that
can be quickly and easily integrated into its existing operations.
Strategic alliances provide Protection One with a proprietary source of
prospective customers and offer it the opportunity to generate new customers at
a substantially lower cost as well as advertise and build the Protection One
brand name. Protection One has aggressively pursued alliances with companies in
other industries that have significant residential customer bases. Approximately
95% of Protection One's strategic alliances are exclusive arrangements governed
by written contracts. Examples of companies with which Protection One has
established strategic alliances include electric and gas utilities, home
builders, realtors, mortgage companies and home improvement retailers.
The Security Alarm Industry: The North American alarm industry is large,
growing rapidly and characterized by a high degree of fragmentation, has low
residential penetration and is continuing a trend towards consolidation.
Protection One believes the European market is similarly fragmented and that the
residential customer class in Europe is substantially less penetrated than in
North America. In fact, Protection One believes that the residential
penetration rate in the European alarm market today closely resembles the
residential penetration rate in the North American alarm market in the early
1980s.
Large and Growing Market: Protection One estimates that the North American
security industry grew 8.6% in 1998, reaching total revenues of approximately
$16.75 billion. Of this total, Protection One estimates that recurring alarm
monitoring and leasing revenue comprised 20%, or approximately $3.4 billion, an
increase of 10.7% from $3.1 billion in 1997. Protection One also participates
in the recurring service and maintenance sector of the alarm industry, which
comprised 19%, or approximately $3.2 billion total industry revenues, an
increase of 8.9% from $2.9 billion in 1997. The aggregate growth of the markets
in which Protection One operates was 9.8% in 1997. SDM Magazine (formerly
Security Distribution and Marketing) reports that the largest 100 companies in
the United States alarm industry experienced growth of 14.8% in 1998, compared
to the industry growth rate of 8.6%. This disparity reflects the ongoing
consolidation of the security alarm industry as larger firms continue to
actively acquire smaller companies. Protection One believes that several
favorable demographic trends, including the aging of the United States
population, two-income families, home officing, as well as, the increased
perception of crime and a strong economy have all contributed to an increased
demand for security alarm services.
Increased Residential Penetration in North America and Europe: Protection
One and other industry sources estimate that there will be a substantial number
of new residential customers created in North America and Europe over the next
several years as more and more consumers elect to include home security in their
places of living.
<PAGE>
As the following chart indicates, only about 11% of the 122 million
households in North America currently have a monitored alarm system. With the
estimated terminal penetration in each customer class defined as the maximum
alarm penetration potential within each customer class - Protection One
estimates that there will be approximately 30-40 million new customers created
in the residential market over the next several years:
Customer Number of Customers % % Terminal
Class (in millions) Penetrated Penetration
Single Family 78 15% 30-40%
Multifamily
High Rise 12 - N/A
Multifamily
"Garden Style" 22 5 20-30
Manufactured
Housing 10 2 10-20
Total 122 11% 20-30%
The residential penetration of alarms in European households is estimated
by Protection One to be less than 5%. With a population of over 380 million
people in the 15 European Union countries (over 100 million larger than the
United States) and crime rates in most European Union countries generally higher
than the United States in most categories except murder, Protection One believes
the residential alarm penetration rate in Europe will increase significantly
over the next several years. Protection One currently operates in six European
countries with a combined population of over 232 million.
Trend Toward Consolidation: Over the last several years, many of the
largest security alarm companies in North America and Europe have been acquired
leaving few large national and Pan-European alarm companies. Potential new
entrants into the alarm industry are now faced with few, if any, major alarm
companies available for purchase. Protection One believes that larger, more
cost efficient alarm companies with access to capital will continue to grow
faster than the industry average. In most cases, the installation of security
systems requires alarm companies to fund the excess of installation-related
costs over installation revenues, a trend that continues to be prevalent in both
the residential and commercial customer classes.
In addition, Protection One believes the growth in false alarms is causing
some municipalities to consider alternatives to response by municipal police.
To the extent municipalities elect to require some form of private verification
of an alarm prior to police dispatch, such policies could impose additional
expenses on alarm monitoring companies and provide additional impetus for
consolidation. Due to Protection One's size, density in key markets and access
to capital, Protection One believes it is well positioned to take advantage of
consolidation opportunities in the industry.
Operations: Security alarm systems include devices installed at customers'
premises designed to detect or react to conditions such as intrusion or the
presence of fire or smoke.
<PAGE>
Protection One's alarm monitoring customer contracts generally have initial
terms ranging from one to five years in duration, and provide for automatic
renewal for a fixed period (typically one year) unless Protection One or the
customer elects to cancel the contract at the end of its term. Protection One
maintains eight major service centers in North America to provide monitoring
services to the majority of its customer base.
Through a service center in Orlando, Florida, Protection One provides
wholesale monitoring services to independent dealers. Under the typical
arrangement, dealers subcontract monitoring services to Protection One,
primarily because such dealers do not have their own monitoring capabilities.
Protection One's customer care centers are co-located in its service
centers and process non-emergency communications. Operators receive inbound
customer calls and the customer service group addresses customer questions and
concerns about billing, service, credit and alarm activation issues.
Dealer Marketing: In the last two years, Protection One has substantially
increased its advertising and marketing efforts to support the Dealer Program.
The Dealer Program offers dealers a wide variety of support services to assist
dealers as they grow their businesses. On behalf of the Dealer Program
participants, Protection One obtains purchase discounts on security systems,
coordinates cooperative dealer advertising and provides administrative,
marketing and employee training support services. Protection One believes that
these cost savings and services would not be available to Dealer Program
participants on an individual basis.
Dealer contracts provide for the purchase of the dealers' customer accounts
by Protection One on an ongoing basis. The dealers install specified alarm
systems (which have a Protection One logo on the keypad), arrange for customers
to enter into Protection One alarm monitoring agreements, and install Protection
One yard signs and window decals. In addition, Protection One requires dealers
to qualify prospective customers by meeting a minimum credit standard.
Branch Sales: The most common reason for the loss of customers is
customers moving out of their homes and businesses. Sales professionals and
centralized telesales representatives at Protection One's branch offices and
Chatsworth, California customer service center are responsible for tracking
previous customers' homes to sign up new owners when they move into such homes.
Competition: The security alarm industry is highly competitive and highly
fragmented in both North America and Europe. In North America, there are only
five national alarm companies that offer services across the United States and
Canada with the remainder being either large regional or small, privately held
alarm companies. Based on number of customers, the top five alarm companies in
North America, as estimated by Protection One are:
(1) ADT Security Services, a subsidiary of Tyco International,
Inc. (ADT)
(2) Protection One
(3) SecurityLink from Ameritech, Inc., a subsidiary of Ameritech
Corporation
<PAGE>
(4) Brinks Home Security Inc., a subsidiary of The Pittston
Services Group of North America
(5) Honeywell Inc.
In Europe, Protection One competes with ADT, SecurityLink from Ameritech,
Initial Shorrock (Rentokil Initial PLC) and Chubb Group Services Ltd. (Williams
PLC), as well as the securities subsidiaries of Securitas AB.
Other alarm service companies have adopted a strategy similar to Protection
One's that entails the purchase of alarm monitoring accounts both through
acquisitions of account portfolios and through dealer programs. Some
competitors have greater financial resources than Protection One, or may be
willing to offer higher prices than Protection One is prepared to offer to
purchase customer accounts. The effect of such competition may be to reduce the
purchase opportunities available to Protection One, thus reducing Protection
One's rate of growth, or to increase the price paid by Protection One for
customer accounts, which would adversely affect Protection One's return on
investment in such accounts and Protection One's results of operations.
Competition in the security alarm industry is based primarily on
reliability of equipment, market visibility, services offered, reputation for
quality of service, price and the ability to identify and solicit prospective
customers as they move into homes. Protection One believes that it competes
effectively with other national, regional and local security alarm companies due
to its reputation for reliable equipment and services, its prominent presence in
the areas surrounding its branch offices, its ability to offer combined
monitoring, repair and enhanced services, its low cost structure and its
marketing alliances.
Intellectual Property: Protection One owns trademarks related to the name
and logo for Protection One, Network Multifamily Security and CET, as well as a
variety of trade and service marks related to individual services Protection One
provides. Protection One owns certain proprietary software applications, which
Protection One uses to provide services to its customers.
Regulatory Matters: A number of local governmental authorities have
adopted or are considering various measures aimed at reducing the number of
false alarms. Such measures include:
- Subjecting alarm monitoring companies to fines or
penalties for transmitting false alarms
- Permitting of individual alarm systems and the
revocation of such permits following a specified number
of false alarms
- Imposing fines on alarm customers for false alarms
- Imposing limitations on the number of times the police
will respond to alarms at a particular location after a
specified number of false alarms
- Requiring further verification of an alarm signal before
the police will respond
<PAGE>
Protection One's operations are subject to a variety of other laws,
regulations and licensing requirements of both domestic and foreign federal,
state and local authorities. In certain jurisdictions, Protection One is
required to obtain licenses or permits, to comply with standards governing
employee selection and training, and to meet certain standards in the conduct of
its business. Many jurisdictions also require certain employees to obtain
licenses or permits. Those employees who serve as patrol officers are often
subject to additional licensing requirements, including firearm licensing and
training requirements in jurisdictions in which they carry firearms.
The alarm industry is also subject to requirements imposed by various
insurance, approval, listing, and standards organizations. Depending upon the
type of customer served, the type of security service provided, and the
requirements of the applicable local governmental jurisdiction, adherence to the
requirements and standards of such organizations is mandatory in some instances
and voluntary in others.
Protection One's advertising and sales practices are regulated in the
United States by both the Federal Trade Commission and state consumer protection
laws. In addition, certain administrative requirements and laws of the foreign
jurisdictions in which Protection One operates also regulate such practices.
Such laws and regulations include restrictions on the manner in which Protection
One promotes the sale of its security alarm systems, the obligation to provide
purchasers of its alarm systems with certain rescission rights and certain
foreign jurisdictions' restrictions on a company's freedom to contract.
Protection One's alarm monitoring business utilizes telephone lines and
radio frequencies to transmit alarm signals. The cost of telephone lines, and
the type of equipment which may be used in telephone line transmission, are
currently regulated by both federal and state governments. The operation and
utilization of radio frequencies are regulated by the Federal Communications
Commission and state public utilities commissions. In addition, the laws of
certain foreign jurisdictions in which Protection One operates regulate the
telephone communications with the local authorities.
Risk Management: The nature of the services provided by Protection One
potentially exposes it to greater risks of liability for employee acts or
omissions, or system failure, than may be inherent in other businesses.
Substantially all of Protection One's alarm monitoring agreements, and other
agreements, pursuant to which Protection One sells its products and services,
contain provisions limiting liability to customers in an attempt to reduce this
risk.
Protection One's alarm response and patrol services require its employees
to respond to emergencies that may entail risk of harm to such employees and to
others. Protection One employs over 100 patrol and alarm response officers who
are subject to extensive pre-employment screening and training. Officers are
subject to local and federal background checks and drug screening before being
hired, and are required to have gun and baton permits and state and city guard
licenses. Officers also must be licensed by states to carry firearms and to
provide patrol services. Although Protection One conducts extensive screening
and training of its employees, the nature of patrol and alarm response service
subjects it to greater risks related to accidents or employee behavior than
other
<PAGE>
types of businesses.
Protection One carries insurance of various types, including general
liability and errors and omissions insurance in amounts Protection One considers
adequate and customary for its industry and business. Protection One's loss
experience, and that of other security service companies, may affect the
availability and cost of such insurance. Certain insurance policies, and the
laws of some states, may limit or prohibit insurance coverage for punitive or
certain other types of damages, or liability arising from gross negligence.
GEOGRAPHIC INFORMATION
Geographic information is set forth in Note 19 of the Notes to Consolidated
Financial Statements included herein.
RISK FACTORS
In connection with the KCPL merger, please consider the following:
Uncertainty Regarding Trading Prices of Westar Energy Common Stock
Following the KCPL Merger: Upon consummation of the KCPL merger, KCPL common
shareholders will receive, among other things, shares of Westar Energy common
stock in exchange for shares of KCPL common stock. There has been no public
trading market for the shares of Westar Energy common stock . We and Westar
Energy will apply for listing of the Westar Energy common stock on the New York
Stock Exchange. However, there can be no assurance that an active trading
market will develop or, if a trading market develops, that such market will be
maintained. There can be no assurance of the prices at which the Westar Energy
common stock will trade and such trading prices may be higher or lower than
those indicated by a public market valuation analysis or a discounted cash flow
valuation analysis. The trading price of the Westar Energy common stock will be
determined in the marketplace and may be influenced by many factors, including,
among others, Westar Energy's performance, investor expectations for Westar
Energy, investor expectations of the dividend payout of comparable electric
utility companies, the trading volume in Westar Energy common stock, interest
rates and general economic and market conditions. The fact that Westar Energy
is controlled by a significant shareholder may cause Westar Energy to trade at
a discount to its valuation.
No Operating History as an Independent Company: Westar Energy does not have
an operating history as a unified entity. Westar Energy also will have a new
management team comprised primarily of members of management of KPL, KCPL and
KGE, in place at the commencement of its operation as a public company. KPL and
KGE have historically relied on Western Resources for various financial and
administrative services. After the KCPL Merger, Westar Energy will require its
own lines of credit, banking relationships and administrative functions.
Although we and KCPL believe that Westar Energy will operate efficiently as a
public corporation following consummation of the KCPL Merger, there can be no
such assurance.
<PAGE>
Uncertainty Regarding Volatility of Western Resources Common Stock Price:
There may be a significant time delay between the date on which our shareholders
and KCPL's shareholders voted for approval of the matters presented at their
respective special meetings and the date of the Western Resources stock
distribution. During this time delay, our common stock price may be affected by
general market conditions and other economic and business factors causing the
conversion ratio and the related value of our common stock per share of KCPL
common stock to fluctuate. Assuming that the Western Resources index price
ranges from $29.78 to $58.47, the conversion ratio per share could range from
.722 to .449 and the implied value per share of the Western Resources common
stock to holders of KCPL common stock could range from $21.50 to $26.25.
Uncertainty Regarding Western Resources' Regulatory Status: Under the terms
of the KCPL merger agreement, the electric utility operations of Western
Resources will be transferred to KGE. It is a condition to our obligation to
consummate this transfer that we be reasonably satisfied that following the
transfer, KGE will be exempt from all of the provisions of the Public Utility
Holding Company Act of 1935 (1935 Act) other than Section 9(a)(2). We
anticipate that, following consummation of the KCPL Merger, it will be exempt
under Section 3(a)(1) of the 1935 Act pursuant to Rule 2 thereunder from all
provisions of the 1935 Act except Section 9(a)(2). To qualify for an exemption
under Section 3(a)(1) of the 1935 Act, Westar Energy must be predominantly
intrastate in character and carry on its utility business substantially in the
state in which both we and Westar Energy are incorporated, Kansas. As a result
of the KCPL Merger, Westar Energy will derive utility revenues from outside of
the state of Kansas in an amount at the high-end of the range of out-of-state
utility revenues of utility subsidiaries of holding companies that have claimed
exemption from the 1935 Act under Section 3(a)(1) pursuant to Rule 2, which
permits a company to claim exemption by making an annual filing with the SEC.
Although we anticipate that after the KCPL Merger we will qualify for an
exemption under Section 3(a)(1) of the 1935 Act pursuant to Rule 2, there can be
no assurance that the SEC will not challenge our filing pursuant to Rule 2.
Nothing in the Merger Agreement would prevent us from becoming a registered
holding company following the consummation of the KCPL Merger. If we were to
become a registered holding company, we and our subsidiary companies would be
subject, in whole or in part, to extensive regulatory and reporting requirements
under the 1935 Act, relating to, among other things, the issue and sale of
securities, various charter amendments, the acquisition of any securities or
utility assets or any interest in another business, the disposition of utility
assets, certain proxy solicitations, intrasystem financings and other
affiliated transactions.
Uncertainty Regarding Future Dividend Policies: Pursuant to the Merger
Agreement, the dividend policy of Westar Energy will initially be set by the
Westar Energy Board of Directors so as to achieve a payout ratio that is
consistent with comparable electric utility companies. There can be no
assurance, however, as to the level of Westar Energy dividend following the KCPL
Merger. The dividend policy of Westar Energy will also be dependent upon
economic conditions, profitability and other factors which will be considered by
the Westar Energy Board of Directors from time to time. Moreover, our Board of
Directors will set Western Resources' dividend policy and there can be no
assurance as to the level of our dividend following the KCPL Merger.
<PAGE>
Regulated Industry: Electric utilities have historically operated in a
rate-regulated environment. Federal and state regulatory agencies having
jurisdiction over our rates and services, as well as KCPL's and other utilities
are initiating steps that are expected to result in a more competitive
environment for utilities services. Increased competition may create greater
risks to the stability of utility earnings. In a deregulated environment,
formerly regulated utility companies that are not responsive to a competitive
energy marketplace may suffer erosion in market share, revenues and profits as
competitors gain access to their service territories. This anticipated
increased competition for retail electricity sales may in the future reduce
Westar Energy's earnings.
In addition, consummation of the KCPL Merger requires the approval of
certain regulatory authorities, including the FERC. We and KCPL currently
contemplate that the KCPL Merger could be completed by the end of 1999; however,
there can be no assurance that we will have received all required regulatory
approvals prior to that time. Nor can there be any assurance that the KCPL
Merger will be consummated or, if consummated, that it will occur by the end of
1999.
Control by the Principal Shareholder of Westar Energy: Upon consummation
of the KCPL Merger, we will own, assuming there are no dissenting shares, 80.1%
of the diluted outstanding shares of Westar Energy common stock. As a result of
the KCPL Merger, we will generally be able to control the vote on all matters
submitted to a vote of the holders of shares of outstanding Westar Energy common
stock, including the election of Westar Energy's directors, amendments to the
Westar Energy Articles of Incorporation and Westar Energy Bylaws and approval of
significant corporate transactions and other actions pertaining to Westar Energy
which require approval of Westar Energy's shareholders. Notwithstanding this
fact, we agreed to certain arrangements relating to the election of directors of
Westar Energy after the closing of the KCPL Merger. Additionally, we will be in
a position to prevent a takeover of Westar Energy by one or more third parties,
which could deprive Westar Energy's shareholders of a control premium that might
otherwise be realized by them in connection with an acquisition of Westar
Energy.
Westar Energy presently expects to apply accounting standards that
recognize the economic effects of rate regulation and record regulatory assets
and liabilities related to its electric generation, transmission and
distribution operations. See Stranded Costs in Management's Discussion and
Analysis.
Regulatory changes, including competition, could adversely impact our,
Westar Energy's, and KCPL's ability to recover our investment in these assets.
As of December 31, 1998, Western Resources and KCPL have recorded regulatory
assets of approximately $364 million and $135 million, which are currently
subject to recovery in future rates. Of this amount, approximately $205 million
and $109 million, are receivables for future income tax benefits previously
passed on to customers. The remainder of the regulatory assets are items that
may give rise to stranded costs including coal contract settlement costs,
deferred plant costs and debt issuance costs.
In a competitive environment, we, Westar Energy and KCPL may not be able
to fully recover our entire investment in Wolf Creek. We and KCPL each
presently owns 47% of Wolf Creek, and following the KCPL Merger, Westar Energy
will own 94%
<PAGE>
of Wolf Creek. We may also have stranded costs from an inability to recover our
environmental remediation costs and long-term fuel contract costs in a
competitive environment. If we, KCPL or Westar Energy determine that we have
stranded costs and cannot recover our investment in these assets, our future net
utility income may be lower that our historical net utility income unless we can
compensate for the loss of such income with other measures.
For risk factors relating to Protection One, see its December 31, 1998
Annual Report on Form 10-K.
<PAGE>
EXECUTIVE OFFICERS OF THE COMPANY
<TABLE>
<CAPTION>
Other Offices or Positions
Name Age Present Office Held During Past Five Years
<S> <C> <C> <C>
David C. Wittig 43 Chairmen of the Board Executive Vice President,
(since January 1999) Corporate Strategy
Chief Executive Officer (May 1995 to March 1996)
(since July 1998)
and President Salomon Brothers Inc. -
(since March 1996) Managing Director, Co-Head of
Mergers and Acquisitions
(1989 to 1995)
Thomas L. Grennan 46 Executive Vice President, Senior Vice President, Electric Operations
Electric Operations (September 1998 to October 1998)
(since November 1998) Vice President, Generation Services
(May 1995 to September 1998)
Vice President, Electric Production
(February 1994 to May 1995)
Carl M. Koupal, Jr. 45 Executive Vice President Executive Vice President
and Chief Administrative Corporate Communications,
Officer (since July 1995) Marketing, and Economic Development
(January 1995 to July 1995)
Vice President, Corporate Marketing,
And Economic Development
(March 1992 to June 1995)
Douglas T. Lake 48 Executive Vice President, Bear Stearns & Co., Inc. -
Chief Strategic Officer Senior Managing Director
(since September 1998) (1995 to August 1998)
Dillon Read & Co. - Managing Director
(1991 to 1995)
William B. Moore 46 Acting Executive Vice Kansas Gas and Electric Company -
President, Chief Financial Chairman of the Board
Officer and Treasurer (June 1995 to January 1999)
(since October 1998) President (June 1995 to October 1998)
Western Resources, Inc. -
Vice President, Finance
(April 1992 to June 1995)
Richard D. Terrill 44 Vice President, Law and Secretary and Associate General
Corporate Secretary Counsel (April 1992 to July 1998)
(since July 1998)
</TABLE>
Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the executive officers, nor any
arrangements or understandings between any executive officer and other persons
pursuant to which he was appointed as an executive officer.
<PAGE>
ITEM 2. PROPERTIES
ELECTRIC UTILITY OPERATIONS
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 66
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 152
2 1967 Gas--Oil 382
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18
2 1950 Gas 18
3 1951 Gas 28
4 1965 Gas 191
Combustion Turbines 1 1974 Gas 50
2 1974 Gas 49
3 1974 Gas 52
4 1975 Diesel 78
Diesel Generator 1 1983 Diesel 3
Jeffrey Energy Center (84%)(2):
Steam Turbines 1 1978 Coal 617
2 1980 Coal 622
3 1983 Coal 621
La Cygne Station (50%)(2):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 334
Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (3)
3 1954 Coal 59
4 1960 Coal 119
5 1971 Coal 394
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 44
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (3)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 85
8 1962 Coal 153
Combustion Turbines 1 1972 Gas 20
2 1972 Gas 21
<PAGE>
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%)(2):
Nuclear 1 1985 Uranium 547
Total 5,356
(1) Based on MOKAN rating.
(2) The company jointly owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%). KCPL jointly owns 50% of
La Cygne Station and 47% of Wolf Creek Generating Station.
(3) These units have been "mothballed" for future use.
The company owns approximately 6,300 miles of transmission lines,
approximately 21,300 miles of overhead distribution lines, and approximately
4,200 miles of underground distribution lines. The company has all franchises
necessary to sell electricity within the territories from which substantially
all of its gross operating sales are derived.
MONITORED SERVICES
Protection One operates primarily from the following facilities, although
Protection One leases office space for its 66 service branch offices and 4
satellites in 33 states and Canada, 7 branch offices in the United Kingdom and
42 in continental Europe.
Size Principal
Location (Sq. ft.) Lease/Own Purpose
United States:
Addison, TX. . . . 28,512 Lease Service Center/
Administrative
Headquarters
Beaverton, OR. . . 44,600 Lease Service Center
Chatsworth, CA . . 43,472 Lease Customer Service Center
Culver City, CA. . 23,520 Lease Corporate Headquarters
Culver City, CA. . 8,029 Lease Administrative
Functions
Hagerstown, MD . . 21,370 Lease Service Center
Irving, TX . . . . 53,750 Lease Service Center
Irving, TX . . . . 54,394 Lease Financial/
Administrative
Headquarters
Orlando, FL. . . . 11,020 Lease Wholesale Service
Center
Wichita, KS. . . . 50,000 Own Service Center
Canada:
Ottawa, ON . . . . 7,937 Lease Administrative
Headquarters
Vancouver, BC. . . 5,177 Lease Monitoring and Service
Center
Europe:
Basingstoke, UK. . 3,500 Lease Financial/
Administrative
Headquarters
<PAGE>
Size Principal
Location (Sq. ft.) Lease/Own Purpose
Paris, FR. . . . . 3,498 Lease Financial/
Administrative
Headquarters
Vitrolles
(Marseilles) FR. . 6,813 Lease Administrative/Service
Center
FINANCING
Our 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 our 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 our results for the 12 months
ended December 31, 1998, $200 million of first mortgage bonds could be issued
(7.00% 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, 1998, we had approximately $283 million of net bondable property
additions not subject to an unfunded prior lien entitling us to issue up to $169
million principal amount of additional bonds. As of December 31, 1998, no first
mortgage 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, 1998, approximately $1.1 billion principal amount of
additional KGE first mortgage bonds could be issued (7.00% interest rate
assumed).
KGE's 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,
1998, KGE had approximately $1.5 billion of net bondable property additions not
subject to an unfunded prior lien entitling KGE to issue up to $1 billion
principal amount of additional KGE bonds. As of December 31, 1998, $17 million
in additional bonds could be issued on the basis of retired bonds.
The most restrictive provision of our 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
<PAGE>
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, 1998, such ratio was 1.19 for the 12 months ended December 31,
1998.
In connection with the combination of the electric utility operations of
Western Resources, KCPL and KGE, Westar Energy will assume $1.9 billion of
indebtedness for borrowed money of Western Resources and KGE comprised primarily
of the companies' outstanding long-term debt. In connection with the transfer
of Western Resources' electric utility operations, which constitutes all of the
property subject to the Mortgage and Deed of Trust, dated July 1, 1939,
(Mortgage) between us and Harris Trust and Savings Bank, as trustee, and
substantially all of the assets of Western Resources, to Westar Energy, we in
accordance with the Mortgage will assign and be released from, and Westar
Energy will assume, the Mortgage and all of our obligations under the Mortgage
and all first mortgage bonds outstanding thereunder. Pursuant to the amended
and restated agreement and plan of merger, KGE's mortgage, by operation of law,
will be assumed by Westar Energy. We will not transfer and will continue to
hold our investments in unregulated operations, including Protection One and
ONEOK. See, Management's Discussion and Analysis of Financial Condition and
Results of Operations and Note 21 of Notes to Consolidated Financial Statements.
KCPL has outstanding first mortgage bonds (the "KCPL Bonds") which are
secured by a lien on substantially all of KCPL's fixed property and franchises
purported to be conveyed by the General Mortgage Indenture and Deed of Trust and
the various Supplemental Indentures creating the KCPL Bonds (collectively, the
"KCPL Mortgage"). Westar Energy has agreed to assume $800 million of debt from
KCPL. The KCPL mortgage will have a prior lien on the KCPL property and
franchises to be owned by Westar Energy.
ITEM 3. LEGAL PROCEEDINGS
On January 8, 1997, Innovative Business Systems, Ltd. (IBS) filed suit
against the company and Westinghouse Electric Corporation (WEC), Westinghouse
Security Systems, Inc. (WSS) and WestSec, Inc. (WestSec), a wholly-owned
subsidiary of the company established to acquire the assets of WSS, in Dallas
County, Texas district court (Cause No 97-00184) alleging, among other things,
breach of contract by WEC and interference with contract against the company in
connection with the sale by WEC of the assets of WSS to the company. On November
9, 1998, WEC settled this matter and the litigation was dismissed.
The Securities and Exchange Commission (SEC) has commenced a private
investigation relating, among other things, to the timeliness and adequacy of
disclosure filings with the SEC by the company with respect to securities of ADT
Ltd. The company is cooperating with the SEC staff relating to the
investigation.
The company understands that class action lawsuits relating to the
Protection One restatement of 1997 and 1998 financial statements and subsequent
decrease in stock price were recently filed naming Protection One, Western
Resources and certain officers of Protection One. The company has not yet been
served with a copy of the lawsuits. The company cannot predict the outcome or
the effect of this litigation.
<PAGE>
Additional information on legal proceedings involving the company is set
forth in Notes 3 and 10 of Notes to Consolidated Financial Statements included
herein. See also Item 1. Business, Environmental Matters and Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
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 the company's 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 April 1, 1999, there were
54,290 common shareholders of record. For information regarding quarterly
common stock price ranges for 1998 and 1997, see Note 22 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, 1998, 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 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 or about the third day of the preceding month. Dividends increased four
cents per common share in 1998 to $2.14 per share. The Company's currently
authorized quarterly dividend for 1999 is 53 1/2 cents per common share or
$2.14 on an annual basis is paid from its earnings and remains unchanged from
1998. The company's board of directors reviews its dividend policy on an
annual basis. The company expects the next review to be made in January 2000.
Among the factors typically considered in determining its dividend policy are
earnings, cash flows, capitalization ratios, competition and regulatory
conditions. In addition, the company expects the board of directors in its next
review to consider various factors such as greater participation in its dividend
reinvestment program, its new compensation plan that pays senior management
part of their annual compensation in stock and its business profile upon
completion of the KCPL merger. For information regarding quarterly dividend
declarations for 1998 and 1997, see Note 22 of Notes to Consolidated Financial
Statements included herein. See also Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations.
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31, 1998 (1) 1997(2) 1996 1995 1994
<S> <C> <C> <C> <C> <C>
(Restated)
(Dollars in Thousands)
Income Statement Data:
Sales:
Energy. . . . . . . . . . . $1,612,959 $1,999,418 $2,038,281 $1,743,930 $1,764,769
Security. . . . . . . . . . 421,095 152,347 8,546 344 -
Total sales. . . . . . . . . 2,034,054 2,151,765 2,046,827 1,744,274 1,764,769
Income from operations. . . . 230,514 154,425 388,553 373,721 370,672
Net income . . . . . . . . . 47,756 499,518 168,950 181,676 187,447
Earnings available for common
stock. . . . . . . . . . . 44,165 494,599 154,111 168,257 174,029
December 31, 1998 (1) 1997(2) 1996 1995 1994
(Restated)
(Dollars in Thousands)
Balance Sheet Data:
Total assets. . . . . . . . . $7,951,428 $6,959,550 $6,647,781 $5,490,677 $5,371,029
Long-term debt, preference
stock, and other mandatorily
redeemable securities. . . . 3,283,064 2,458,034 1,951,583 1,641,263 1,507,028
Year Ended December 31, 1998(1) 1997(2) 1996 1995 1994
(Restated)
Common Stock Data:
Basic earnings per share . . . . . $ 0.67 $ 7.59 $ 2.41 $ 2.71 $ 2.82
Dividends per share. . . . . . . . $ 2.14 $ 2.10 $ 2.06 $ 2.02 $ 1.98
Book value per share . . . . . . . $29.40 $30.88 $25.14 $24.71 $23.93
Average shares outstanding(000's) 65,634 65,128 63,834 62,157 61,618
Interest coverage ratio (before
income taxes). . . . . . . . . . 1.27 5.55 2.67 3.14 3.42
(1) Information reflects write-off of international power development activities.
(2) Information reflects the gain on the sale of Tyco common shares and reflects the strategic alliance with
ONEOK.
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis we explain the general financial
condition and the operating results for Western Resources, Inc. and its
subsidiaries. We explain:
- What factors impact our business
- What our earnings and costs were in 1998 and 1997
- Why these earnings and costs differed from year to year
- How our earnings and costs affect our overall financial condition
- What our capital expenditures were for 1998
- What we expect our capital expenditures to be for the years 1999
through 2001
- How we plan to pay for these future capital expenditures
- Any other items that particularly affect our financial condition or
earnings
As you read Management's Discussion and Analysis, please refer to our
Consolidated Statements of Income on page 63. These statements show our
operating results for 1998, 1997 and 1996. In Management's Discussion and
Analysis, we analyze and explain the significant annual changes of specific line
items in the Consolidated Statements of Income.
Forward-Looking Statements
Certain matters discussed here and elsewhere in this Annual Report are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect" or words of similar meaning. Forward-looking statements
describe our future plans, objectives, expectations or goals. Such statements
address future events and conditions concerning capital expenditures, earnings,
litigation, rate and other regulatory matters, possible corporate
restructurings, mergers, acquisitions, dispositions, liquidity and capital
resources, interest and dividend rates, Year 2000 Issue, environmental matters,
changing weather, nuclear operations, ability to enter new markets successfully
and capitalize on growth opportunities in nonregulated businesses, events in
foreign markets in which investments have been made, and accounting matters.
What happens in each case could vary materially from what we expect because of
such things as electric utility deregulation, including ongoing state and
federal activities; future economic conditions; legislative developments; our
regulatory and competitive markets; and other circumstances affecting
anticipated operations, sales and costs.
1998 HIGHLIGHTS
Continued Expansion of Monitored Services
Protection One, Inc. (Protection One) had a year of rapid expansion and
continued growth. During the year, Protection One doubled the size of its
customer base from about 750,000 customers to about 1.5 million customers. This
growth was achieved through acquisitions and Protection One's Dealer Program.
<PAGE>
During 1998, Protection One invested approximately $549 million in
security company acquisitions. Highlights of this activity include:
- Network Multi-Family - A leading provider of monitored services
to multi-family dwellings. This acquisition added approximately
200,000 customers.
- Multimedia Security Services - A purchase of assets, including a large
security monitoring center in Wichita, Kansas, that added about
147,000 customers.
- Compagnie Europeenne de Telesecurite (CET) - An acquisition of a French
monitored services provider which added 60,000 customers and
established a major presence in Western Europe.
Protection One financed these acquisitions primarily with cash advances
from Western Resources and from the sale of common shares. In June, Protection
One completed an equity offering that raised approximately $406 million in
aggregate proceeds. We purchased approximately 37.6 million Protection One
common shares of the 42.8 million common shares sold. The shares, which sold
for $9.50 per common share, increased our investment in Protection One by $357
million. Our approximate 85% investment in Protection One totals about $1.1
billion at December 31, 1998. During the year, Protection One refinanced a
large portion of its debt by issuing $250 million of senior unsecured notes,
issuing $350 million of senior subordinated notes and obtaining a $500 million
credit facility. Part of the proceeds from these offerings were used to repay
a $395 million intercompany obligation to us.
The Lifeline Transaction
In October 1998, Protection One announced an agreement to acquire
Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal
emergency response and support services in North America. Based on the average
closing price for the three trading days prior to April 8, 1999, the value of
the consideration to be paid under the merger agreement is approximately
$129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has
advised Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
Investment in ONEOK, INC.
We received approximately $40 million in cash dividends from our ONEOK,
Inc. (ONEOK) investment in 1998. Tax rules allow us to exclude 70% of these
dividends from the determination of taxable income. This 70% exclusion saves
us about $11 million in income taxes annually.
In December 1998, ONEOK announced its intention to purchase Southwest
Gas Corporation (Southwest). ONEOK will pay Southwest shareholders $28.50 per
common share and assume debt for a total transaction value of approximately $1.8
billion. ONEOK will add 1.2 million customers in higher growth markets in
Arizona, Nevada and California to its existing base of 1.4 million customers as
a result of this purchase. The merger is expected to create the largest
stand-alone gas distribution company in the United States.
<PAGE>
In February 1999, ONEOK was advised by Southwest that it had received an
unsolicited offer of $32 per share of common stock from Southern Union Company.
Southwest is evaluating both offers.
In November 1997, we completed our strategic alliance with ONEOK and
contributed substantially all of our natural gas business to ONEOK in exchange
for a 45% ownership interest in ONEOK. Our ownership interest is comprised of
approximately 3.2 million common shares and approximately 20.1 million
convertible preferred shares. If all the preferred shares were converted, we
would own approximately 45% of ONEOK's common shares presently outstanding.
Following the strategic alliance, the consolidated energy sales, related cost of
sales and operating expenses in 1997 for our natural gas business have been
replaced by investment earnings in ONEOK.
Electric Utility Operations
We experienced warmer weather during the summer months in 1998 than we
did in 1997 which improved net income by $19.8 million. The effect of our
electric rate decrease lowered 1998 net income $6.6 million.
In January 1997, the Kansas Corporation Commission (KCC) entered an
order reducing electric rates for both our KPL division (KPL) and Kansas Gas and
Electric Company (KGE). Significant terms of the order are as follows:
- We made permanent the May 1996 interim $8.7 million decrease in KGE
rates on February 1, 1997
- We reduced KGE's rates by $36 million annually on February 1, 1997
- We reduced KPL's rates by $10 million annually on February 1, 1997
- We rebated $5 million to all of our electric customers in January
1998
- We reduced KGE's rates by $10 million annually on June 1, 1998
- We rebated $5 million to all of our electric customers in January
1999
- We will reduce KGE's rates by $10 million more annually on June 1,
1999
These electric rate decreases have negatively impacted our net income.
The total annual cumulative effect of these rate decreases is approximately $75
million. All rate decreases are cumulative. Rebates are one-time events and do
not influence future rates.
Electric utility net income totaled approximately $133 million,
excluding one-time events, for 1998. Electric utility net income reflects a
debt allocation of $1.9 billion. Westar Energy, the new company to be created
as a result of the Kansas City Power & Light Company (KCPL) merger, will
assume $1.9 billion of debt from us and KGE after closing the KCPL merger. We
expect to own an 80.1% interest in Westar Energy which will combine our electric
operations with those of KCPL. For more information on the KCPL merger, see
OTHER INFORMATION.
Charge to Income to Exit International Power Development Activity
We decided to exit the international power development business during
the fourth quarter of 1998 in order to focus more attention on our consumer
service businesses. As a result of this decision, we recorded a charge to
income approximating $99 million, or $0.98 per share. The charge accrued exit
and shutdown costs, including severance
<PAGE>
to affected employees who were notified of the shutdown in December, recognized
the write-off of deferred development costs for projects we will cease
developing and recognized the write-off of goodwill created when we acquired The
Wing Group in 1996. We have also written down the value of certain equity
investments in foreign countries to their estimated fair value. We believe
negative political, economic, operating, and regulatory factors reduced the
value of our ownership interests in these investments and that this decrease is
not temporary. See Note 11 for further information.
Other Charges to Income
In the fourth quarter, we sold our investment in an equity security that
was unrelated to our core utility and monitored services businesses and
realized a pre-tax loss of about $13 million. In addition, we wrote down the
value of another investment due to declines in value which we believe were not
temporary. The pre-tax charge related to this investment approximated $6
million. Operating results for 1998 also included pre-tax severance
obligations and employee benefits of approximately $20 million.
Operating Results
Operating results for 1998 are difficult to compare to 1997 due
primarily to 1998 charges as discussed above in 1998 HIGHLIGHTS and the 1997
pre-tax gain on the sale of Tyco International Ltd. (Tyco) common stock of $864
million.
In addition to the gain on the sale of Tyco common stock recorded in
1997, we recorded charges which included $48 million of deferred KCPL merger
costs and approximately $24 million recorded by Protection One to recognize
higher than expected customer attrition and to record costs related to the
acquisition of Protection One.
In November 1997, we completed our strategic alliance with ONEOK and
contributed substantially all of our natural gas business to ONEOK in exchange
for a 45% ownership interest in ONEOK. Following the strategic alliance, the
consolidated sales, related cost of sales and operating expenses in 1997 for our
natural gas business have been replaced in 1998 by investment earnings from
ONEOK. Sales and cost of sales from our natural gas business in 1997 were $739
million and $538 million.
The following explains significant changes from prior year results in
sales, cost of sales, operating expenses, other income (expense), interest
expense, income taxes, and preferred and preference dividends.
Energy sales primarily include electric sales, power marketing sales
and, through November 1997, natural gas sales. Items included in energy cost of
sales are fuel expense, purchased power expense (including electricity we
purchase from others for resale), power marketing expense and, through
November 1997, natural gas purchased.
Electric Utility
Sales
Electric sales include sales from fossil generation, power marketing and
power delivery operations. The KCC and the Federal Energy Regulatory Commission
(FERC) authorize rates for our electric sales. Power marketing is only regulated
by the FERC. Our electric sales vary with levels of energy deliveries.
Changing weather affects the
<PAGE>
amount of electricity our customers use. Very hot summers and very cold winters
prompt more demand, especially among our residential customers. Mild weather
reduces demand.
Many things will affect our future electric sales. They include:
- The weather
- Our electric rates
- Competitive forces
- Customer conservation efforts
- Wholesale demand
- The overall economy of our service area
1998 compared to 1997: Total electric sales increased 31%. Electric
utility sales increased 6% due to increased retail energy deliveries as a result
of warmer summer temperatures and power marketing sales increased 448%. Our
annual $10 million electric rate decrease implemented on June 1, 1998, partially
offset this increase.
The following table reflects the change in electric energy deliveries,
as measured by kilowatt hours, for retail customers for 1998 compared to 1997.
Increase
Residential. . . . . 9.5%
Commercial . . . . . 6.8%
Industrial . . . . . 1.6%
Other. . . . . . . . 1.0%
Total retail . . . 5.9%
1997 compared to 1996: Electric sales increased 3% because of our
expansion of power marketing activity in 1997. Higher electric sales from power
marketing were offset by our reduced electric rates implemented February 1,
1997, which lowered revenues by an estimated $46 million annually.
Cost of Sales
1998 compared to 1997: Total electric cost of sales increased 83% in
1998 due mostly to higher power marketing cost of sales.
1997 compared to 1996: Our power marketing activity in 1997 increased
electric cost of sales by $70 million. Actual cost of fuel to generate
electricity (coal, nuclear fuel, natural gas or oil) and the amount of power
purchased from other utilities were $14 million higher. For further
explanations of cost of sales increases, see the fossil generation and nuclear
generation business segments discussion below.
Depreciation and Amortization Expense
1998 compared to 1997: Depreciation and amortization expense decreased
$22 million, or 12%, primarily because we had fully amortized a regulatory asset
during 1997. This decrease in amortization expense increased 1998 earnings
before interest and taxes from 1997.
1997 compared to 1996: Depreciation and amortization expense increased
$13 million, or 8%, primarily due to fully amortizing a regulated asset
associated with Wolf Creek nuclear generation facility (Wolf Creek).
<PAGE>
Stranded Costs
The definition of stranded costs for a utility business is the
investment in and carrying costs on property, plant and equipment and other
regulatory assets which exceed the amount that can be recovered in a competitive
market. We currently apply accounting standards that recognize the economic
effects of rate regulation and record regulatory assets and liabilities related
to our fossil generation, nuclear generation and power delivery operations.
If we determine that we no longer meet the criteria of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to
operations. Reasons for discontinuing SFAS 71 accounting treatment include
increasing competition that restricts our ability to charge prices needed to
recover costs already incurred and a significant change by regulators from a
cost-based rate regulation to another form of rate regulation. We periodically
review SFAS 71 criteria and believe our net regulatory assets, including those
related to generation, are probable of future recovery. If we discontinue SFAS
71 accounting treatment based upon competitive or other events, we may
significantly impact the value of our net regulatory assets and our utility
plant investments, particularly Wolf Creek. See OTHER INFORMATION for
initiatives taken to restructure the electric industry in Kansas.
Regulatory changes, including competition, could adversely impact our
ability to recover our investment in these assets. As of December 31, 1998, we
have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $364 million. Of this amount, $205 million is a
receivable for income tax benefits previously passed on to customers. The
remainder of the regulatory assets are items that may give rise to stranded
costs including coal contract settlement costs, deferred employee benefit costs,
deferred plant costs, and debt issuance costs.
In a competitive environment, we may not be able to fully recover our
entire investment in Wolf Creek. We presently own 47% of Wolf Creek. Our
ownership would increase to 94% when the KCPL combination is completed. We also
may have stranded costs from an inability to recover our environmental
remediation costs and long-term fuel contract costs in a competitive
environment. If we determine that we have stranded costs and we cannot recover
our investment in these assets, our future net utility income will be lower than
our historical net utility income has been unless we compensate for the loss
of such income with other measures.
Electric Utility Business Segments
We define and report our business segments based on how management
currently evaluates our business. Management has segmented our business based
on differences in products and services, production processes and management
responsibility. We manage our electric utility business segments' performance
based on their earnings before interest and taxes (EBIT). EBIT does not
represent cash flow from operations as defined by generally accepted accounting
principles, should not be construed as an alternative to operating income and is
indicative neither of operating performance nor cash flows available to fund the
cash needs of our company. Items excluded from EBIT are significant components
in understanding and assessing the financial performance of our company. We
believe presentation of EBIT enhances an understanding of financial condition,
results of operations and cash flows because EBIT is used by our company to
satisfy its debt service obligations, capital expenditures, dividends and other
operational needs, as well as to provide funds for growth. Our computation of
EBIT may not be comparable to other similarly titled measures of other
companies.
<PAGE>
Allocated sales are external sales collected from customers by our power
delivery segment that are allocated to our fossil generation and nuclear
generation business segments based on demand and energy cost. The following
discussion identifies key factors affecting our electric business segments.
Fossil Generation
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $525,974 $208,836 $144,056
Allocated sales . . . . . . . . 517,363 517,167 518,199
Depreciation and amortization . 53,132 53,831 52,303
EBIT. . . . . . . . . . . . . . 144,357 149,825 188,173
External sales increased over the last two years mostly because of
increased power marketing sales of $313 million in 1998 and $70 million in 1997.
In 1997, we made a strategic decision to expand our power marketing business to
better utilize our generating assets and reduce risk associated with energy
prices. We expanded into both the marketing of electricity and risk management
services to wholesale electric customers and the purchase of electricity for
our retail customers. Our margin from power marketing activities is
significantly less than our margins on our traditional electric sales. Our
power marketing activity has resulted in electric purchases and sales made in
areas outside of our historical marketing territory. Through December 31, 1998,
our power marketing activity has had an insignificant effect on EBIT.
The availability of our generating units and purchased power from other
companies impacts power marketing sales. In 1998, due to warmer than normal
weather throughout the Midwest and a lack of power available for purchase on the
wholesale market, the wholesale power market experienced extreme volatility in
prices and availability. We believe future volatility, such as that recently
experienced in the market, could impact our cost of power purchased and impact
our ability to participate in power trades.
EBIT for 1998 decreased from 1997 because we had higher purchased power
expense of $5 million due to a coal-fired generation station being unavailable
for the summer.
EBIT for 1997 decreased from 1996 due to higher cost of fuel and
purchased power expense discussed below, a $6 million expense of obsolete
inventory and other increased operating and maintenance expenses.
In 1997, actual cost of fossil fuel to generate electricity and the
amount of power purchased from other utilities were $14 million higher than in
1996. Our Wolf Creek nuclear generating station was off-line in the fourth
quarter of 1997 for scheduled maintenance and our La Cygne coal generation
station was off-line during 1997 for an extended maintenance outage. As a
result, we burned more natural gas to generate electricity at our facilities.
Natural gas is more costly to burn than coal and nuclear fuel for generating
electricity.
Railroad transportation limitations prevented scheduled fuel deliveries,
reducing our coal inventories. To compensate for a lack of coal, we purchased
more power from other utilities and burned more expensive natural gas to meet
our energy requirements. We also purchased more power from other utilities
because our Wolf Creek and La Cygne generating stations were not generating
electricity for parts of 1997.
<PAGE>
Nuclear Generation
1998 1997 1996
(Dollars in Thousands)
Allocated sales . . . . . . . . $117,517 $102,330 $100,592
Depreciation and amortization . 39,583 65,902 57,242
EBIT. . . . . . . . . . . . . . (20,920) (60,968) (51,585)
Nuclear fuel generation has no external sales because it provides all of
its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc.
The amounts above are our 47% share of Wolf Creek's operating results.
Allocated sales and EBIT were higher in 1998 because Wolf Creek operated
the entire year without any outages. In 1997, the Wolf Creek facility was
off-line for 58 days for a scheduled maintenance outage.
Depreciation and amortization expense for 1998 compared to 1997
decreased $26 million because we had fully amortized a regulatory asset during
1997. This decrease in amortization expense increased EBIT for 1998.
Decommissioning: Decommissioning is a nuclear industry term for the
permanent shut-down of a nuclear power plant when the plant's license expires.
The Nuclear Regulatory Commission (NRC) will terminate a plant's license and
release the property for unrestricted use when a company has reduced the
residual radioactivity of a nuclear plant to a level mandated by the NRC. The
NRC requires companies with nuclear power plants to prepare formal financial
plans. These plans ensure that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
The Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:
- Our annual decommissioning expense could be higher than in 1998
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the
Wolf Creek plant
We do not believe that such changes, if required, would adversely affect
our operating results due to our current ability to recover decommissioning
costs through rates (see Note 10).
Power Delivery
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $1,085,711 $1,021,212 $1,053,359
Allocated sales . . . . . . . . 66,492 66,492 71,492
Depreciation and amortization . 68,297 63,590 60,713
EBIT. . . . . . . . . . . . . . 196,398 173,809 218,936
<PAGE>
External sales and EBIT increased from 1997 to 1998. In addition to our
normal customer growth, we experienced warmer weather during the summer months
in 1998 than we did in 1997 which improved external sales approximately $42
million. The effect of our electric rate decrease lowered 1998 external sales
approximately $11 million.
External sales and EBIT decreased from 1996 to 1997 due to reduced
electric rates implemented February 1, 1997, which lowered revenues by an
estimated $46 million.
Monitored Services
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $421,095 $152,347 $8,546
Depreciation and amortization . 117,651 41,179 944
EBIT. . . . . . . . . . . . . . 56,727 (38,517) (3,555)
Restatement of 1997 Financial Statements: As a result of a decision by
Protection One to restate its 1997 financial statements, we have chosen to
restate our financial statements to conform to the changes reflected by
Protection One. We do not believe the restated operating results and financial
position are materially different from those which were reported in our December
31, 1997, Annual Report on Form 10K/A. See Note 2 to the consolidated financial
statements for further discussion of the restatement.
1998 compared to 1997: In 1998, Protection One operated and managed our
monitored services interests. The results discussed below reflect Protection
One on a stand-alone basis and do not take into consideration the minority
interest of about 15% at December 31, 1998. Results of operations for 1998
reflect adjustments made to restate quarterly earnings as discussed in Note 22
to the consolidated financial statements.
Monitored services business sales increased $269 million. The increase
is due to acquisitions and new customers purchased through Protection One's
Dealer Program. The Dealer Program consists of independent companies with
residential and small commercial sales, marketing and installation skills
provide Protection One with new monitoring customers for purchase on an ongoing
basis. Monthly recurring revenue represents the monthly fees paid by customers
for on-going monitored security service. At December 31, 1998, monthly
recurring revenue totaled about $38 million. Protection One added approximately
$17 million of monthly recurring revenue from acquisitions and approximately $5
million of monthly recurring revenue from its Dealer Program. Because
acquisitions and purchases from the Dealer Program occurred throughout the year,
not all of the $22 million of acquired monthly recurring revenue is reflected in
1998 results. Offsetting these revenue increases was Protection One's net
monthly recurring revenue attrition of 9%, a decrease from 13% in 1997 (see
further discussion below).
Cost of sales increased $93 million. Monitoring and related services
expenses increased by $71 million, or 217%, due to the acquisition of three
major service centers and three smaller satellite monitoring facilities in the
United States, as well as two service centers in Canada and two in Europe.
Monitoring and service activities at existing facilities increased as
well due to new customers generated by Protection One's Dealer Program.
<PAGE>
Selling, general and administrative expenses rose $31 million. The
increase in expenses resulted primarily from acquisitions, offset by a decrease
in sales and related expenses. Selling, general and administrative expenses as
a percentage of total revenues declined from 56% in 1997 to 27% in 1998. The
transition of Protection One's primary distribution channel from an internal
sales force to the Dealer Program resulted in sales commissions declining by
approximately $9 million. Protection One also reduced advertising and
telemarketing activities that formerly supported the internal sales force.
Amortization of intangibles and depreciation expense totaled $118
million in 1998. Protection One recorded $582 million of customer intangibles
and $549 million in cost allocated to goodwill during 1998 from its purchases of
monitored services companies, portfolios of customer accounts and individual new
customers through its Dealer Program. Protection One amortizes customer
accounts over 10 years and goodwill over 40 years, in each case using a
straight-line method.
Like most monitored services companies, Protection One invests
significant amounts to generate new customers and seeks to maintain
relationships with its customers by providing excellent service. Protection One
measures the loss of customers and revenues to verify that investments in new
customers are generating a satisfactory rate of return and that the policy of
amortizing the cost to acquire customer accounts over 10 years is reasonable.
Protection One calculates both gross customer losses and net monthly recurring
revenue loss as meaningful statistics. If future losses were to increase
substantially, Protection One could be required to shorten the 10-year period
used to amortize the investment in new customers. The resulting increase in
amortization expense could be significant. In addition, the SEC staff is
reviewing Protection One's amortization methodology used on customer accounts.
The SEC staff has questioned the appropriateness of the current accounting
method which Protection One believes is consistent with industry practices. A
significant change in the amortization method would likely have a material
effect on the company's results of operations. The intangible amortization
represents a non-cash charge to income. The net balance of customer accounts at
December 31, 1998, was approximately $1 billion.
EBIT increased $95 million in 1998. Included in 1998 EBIT is a
non-recurring gain approximating $16 million on the repurchase of customer
contracts covered by a financing arrangement. A charge of approximately $24
million adversely affected 1997 EBIT. The charge was needed to recognize higher
than expected customer attrition and to record costs related to the acquisition
of Protection One.
1997 compared to 1996: Monitored services business sales increased $144
million from a minimal amount recorded in 1996. This increase is because of our
December 30, 1996, purchase of the net assets of Westinghouse Security Systems,
Inc. (Westinghouse Security Systems) and the acquisition on November 24, 1997,
of 82.4% of Protection One.
Other Operating Expenses
In 1998, we recorded a $99 million charge to income associated with our
decision to exit the international power project development business as
previously discussed in 1998 HIGHLIGHTS.
In 1997, we recorded a charge totaling $48 million to write-off the
original merger costs associated with the KCPL transaction. In addition,
Protection One recorded a charge of $24 million in 1997 as discussed above in
Monitored Services.
<PAGE>
Other Income (Expense)
Other income (expense) includes miscellaneous income and expenses not
directly related to our operations.
1998 compared to 1997: Other income (expense) decreased $866 million due
to the following factors:
(Millions)
Other Income (Expense) in 1997 . . . . . . . . $ 922
1997
Non-recurring gain on the sale of our
TYCO common stock. . . . . . . . . . . . (864)
Investment earnings recorded on Hanover
and ADT investments. . . . . . . . . . . (33)
1998
Increase in earnings from the investment
in ONEOK . . . . . . . . . . . . . . . . 37
Recorded investment losses . . . . . . . . (22)
Non-recurring Protection One gains. . . . . 19
Increase in COLI death proceeds . . . . . . 13
Other miscellaneous . . . . . . . . . . . . (16)
Other income (expense) in 1998. . . . . . . $56
Interest Expense
1998 compared to 1997: Interest expense represents the interest we paid
on outstanding debt. Interest expense increased 17% due to higher long-term
debt. Our long-term debt balance increased $875 million due to our and
Protection One's issuance of new long-term debt used to reduce existing
short-term debt, to fund nonregulated operations and to finance a substantial
portion of Protection One's customer account growth. Lower short-term debt
interest expense partially offset the higher long-term debt interest expense.
Our short-term debt had a lower weighted average interest rate than the
long-term debt which replaced it.
1997 compared to 1996: We incurred $27 million more short-term debt
interest in 1997. Average short-term debt balances were higher in 1997 because
we used short-term debt to finance our investment in ADT Limited (which later
converted to Tyco) and to purchase the assets of Westinghouse Security Systems.
Short-term debt interest expense declined in the second half of 1997 after we
used the proceeds from the sale of Tyco common stock and a long-term debt
financing to reduce our short-term debt balance. From December 31, 1996, to
December 31, 1997, our short-term debt balance decreased $744 million. From
1996 to 1997, interest recorded on long-term debt increased $14 million, or 13%,
due to the issuance of $520 million in senior unsecured notes.
Income Taxes
1998 compared to 1997: Income tax expense declined significantly due to
the decline in taxable net income. In 1998, charges, primarily the charge to
income to exit the international power development business, significantly
lowered tax expense. Tax expense for 1997 included taxes related to the gain on
the sale of Tyco common stock.
<PAGE>
Our effective tax rate also declined from 1997. This decline is largely
attributable to non-taxable proceeds from our corporate-owned life insurance
policies and the benefit of excluding 70% of ONEOK dividends received from the
determination of taxable income. Non-deductible goodwill amortization, state
income taxes, depreciation, and other adjustments to our tax provision partially
offset the tax benefits described above.
1997 compared to 1996: Income taxes on the gain from the sale of Tyco
common stock increased total income tax expense by approximately $345 million.
Preferred and Preference Dividends
On April 1, 1998, we redeemed the 7.58% preference stock due 2007. On
July 1, 1996, we redeemed all the 8.5% preference stock due 2016. These
redemptions have resulted in a significant decline in preferred and preference
dividends since 1996. In accordance with the terms of the KCPL merger
agreement, we will be required to redeem all of the remaining preferred stock
prior to the merger.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and
maintenance costs associated with the electric utility business, continued
growth in the monitored services business and payment of common stock dividends.
Our ability to attract necessary financial capital on reasonable terms is
critical to our overall business plan. Historically, we have paid for
acquisitions with cash on hand, or the issuance of stock or short-term debt.
Our ability to provide the cash, stock or debt to fund our capital expenditures
depends upon many things, including available resources, our financial condition
and current market conditions.
As of December 31, 1998, we had $16 million in cash and cash
equivalents. We consider highly liquid debt instruments purchased with a
maturity of three months or less to be cash equivalents. Other than operations,
our primary source of short-term cash is from short-term bank loans, unsecured
lines of credit and the sale of commercial paper. At December 31, 1998, we had
approximately $313 million of short-term debt outstanding, of which $148 million
was commercial paper and $165 million was bank loans. We have arrangements with
certain banks to provide unsecured short-term lines of credit on a committed
basis totaling approximately $821 million.
We have also registered securities for sale with the Securities and
Exchange Commission. As of December 31, 1998, these included $400 million of
unsecured senior notes, $50 million of KGE first mortgage bonds and
approximately 11 million Western Resources common shares.
Our embedded cost of long-term debt was 7.4% at December 31, 1998, a
drop of 0.1% from December 31, 1997.
Cash Flows from Operating Activities
Cash from operations increased significantly from 1997 because of two
factors. First, taxes paid of approximately $345 million on the gain on the
sale of Tyco common stock reduced 1997 operating cash flow. Secondly, 1998
includes the first full year
<PAGE>
of Protection One operations. This increased operating cash flow from our
monitored services business by about $90 million from 1997.
Cash Flows from Investing Activities
During 1998, most of our cash used for investing purposes was to
continue the growth of our monitored services business. We used net cash of
about $827 million to expand this business through acquisitions, the Dealer
Program and installations. Protection One does not anticipate its 1999
expansion activity to be as significant as in 1998.
Capital expenditures totaled $183 million in 1998, slightly less than
1997 and 1996. We also purchased marketable securities and additional interests
in affordable housing tax credits.
In October 1998, Protection One announced an agreement to acquire
Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal
emergency response and support services in North America. Based on the average
closing price for the three trading days prior to April 8, 1999, the value of
the consideration to be paid under the merger agreement is approximately $129.2
million or $22.05 per Lifeline share in cash and stock. Lifeline has advised
Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
On January 25, 1999, Protection One's Board of Directors authorized a
private placement of common shares to Westar Capital, Inc., a wholly-owned
subsidiary of our company.
The private placement will allow us to maintain ownership in excess of
80% of Protection One's issued and outstanding common shares following the
issuance of Protection shares to Lifeline shareholders.
We may also acquire shares of Protection One common stock in open market
or privately negotiated transactions depending upon market conditions. Any open
market or private purchases will reduce or eliminate our need to purchase shares
in the private placement to maintain our ownership of at least 80%.
Cash Flows from Financing Activities
In July 1998, we issued $30 million of 6.8% Senior Notes due July 15,
2018. The notes are unsecured and unsubordinated obligations of the company.
In July 1998, we filed a shelf registration for $800 million in senior,
unsecured obligations of the company. In August 1998, we issued $400 million of
6.25% Putable/Callable Notes due on August 15, 2018, putable/callable on
August 15, 2003 under this shelf registration. Proceeds from these issuances
were used to reduce short-term debt incurred in connection with investments in
unregulated operations, the redemption of preferred securities and other general
corporate purposes.
On April 1, 1998, we redeemed our 7.58% Preference Stock due 2007 at a
premium, including dividends, for $53 million.
<PAGE>
Financing activities provided Protection One with $744 million of cash.
Protection One raised $642 million through the following new debt instruments:
(Dollars in Millions)
August 17, 1998: Senior unsecured
7 3/8% notes due in 2005 . . . . . . . . . . . $250
December 16, 1998: Senior subordinated
8 1/8% notes due in 2009 . . . . . . . . . . . 350
December, 1998: Borrowings under a
revolving credit facility. . . . . . . . . . . 42
$642
In December 1998, Protection One obtained a revolving credit facility.
Protection One can borrow under this facility at a range of interest rates based
on either (1) the Prime Rate or (2) a Eurodollar Rate. At December 31, 1998 the
senior credit facility had a weighted average interest rate of 6.8% and had an
outstanding balance of $42 million. The facility matures in December 2001.
Among other restrictions, Protection One is required under the revolving
credit facility to maintain a ratio of earnings before interest, taxes,
depreciation and amortization (EBITDA) to interest expense of not less than 2.75
to one and total debt cannot be greater than 5 times annualized most recent
quarter EBITDA for 1999 and 4.5 times thereafter. In addition, in light of the
restatement of its financial statements, Protection One has obtained a bank
waiver for prior representations concerning its financial statements.
Protection One also raised $406 million in aggregate proceeds through
the sale of common stock. We paid approximately $357 million of the total
amount raised; therefore, the proceeds net of applicable fees obtained from the
sale of common stock approximated $46 million.
Protection One used proceeds from these financing transactions primarily
to fund acquisitions and Dealer Program growth. Protection One also repaid $512
million of existing debt, including a $395 million intercompany obligation with
us.
Capital Structure
Our capital structures at December 31, 1998, and 1997 were as follows:
1998 1997
Common stock . . . . . . . . . . . . . . . 37% 45%
Preferred and preference stock . . . . . . 1% 2%
Western Resources obligated
mandatorily redeemable preferred
securities of subsidiary trust holding
solely company subordinated debentures . 4% 5%
Long-term debt . . . . . . . . . . . . . . 58% 48%
Total. . . . . . . . . . . . . . . . . . . 100% 100%
Security Ratings
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch)
and Moody's Investors Service (Moody's) are independent credit-rating agencies.
These agencies rate our debt securities. These ratings indicate the agencies'
assessment of
<PAGE>
our ability to pay interest and principal on these securities. These ratings
affect how much we will have to pay as interest on securities we sell to obtain
additional capital. The better the rating, the less interest we will have to
pay on the new debt securities we sell.
At December 31, 1998, ratings with these agencies were as follows:
Kansas Gas
Western Western and Electric
Resources' Western Resources' Company's
Mortgage Resources' Short-term Mortgage
Bond Unsecured Debt Bond
Rating Agency Rating Debt Rating Rating
S&P A- BBB A-2 BBB+
Fitch A- BBB+ F-2 A-
Moody's A3 Baa1 P-2 A3
Following the announcement of our restructured merger agreement with
KCPL, S&P placed its ratings of Western Resources and KGE bonds on CreditWatch
with positive implications. Moody's changed the direction of its ongoing review
of Western Resources' debt rating from possible downgrade to possible upgrade.
Future Cash Requirements
We believe that internally generated funds and new and existing credit
agreements will be sufficient to meet our operating and capital expenditure
requirements, debt service and dividend payments through the year 2001.
Uncertainties affecting our ability to meet these requirements with internally
generated funds include the effect of competition and inflation on operating
expenses, sales volume, regulatory actions, compliance with future environmental
regulations, availability of earnings to pay dividends, the availability of
generating units and weather. The amount of these requirements and our ability
to fund them will also be significantly impacted by the pending combination of
our electric utility operations with KCPL.
In order to meet the needs of our electric utility customers, we plan to
install three new combustion turbine generators for use as peaking units. The
installed capacity of the three new generators will approximate 300 MW. The
first two units are scheduled to be placed in operation in 2000 and the third is
scheduled to be placed in operation in 2001. We estimate that the project will
require $120 million in capital resources through the completion of the projects
in 2001. In addition, we are planning to return our inactive generation plant
in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7
million.
On January 4, 1999, we and the Empire District Electric Company (Empire)
signed a memorandum of understanding that provides for the joint ownership of a
500-megawatt combined cycle generating unit, which Empire will operate. We
estimate that the project will require $90 million in capital resources and we
will own 40% of the generating unit. Construction of the unit is expected to
begin in the fall of 1999 with operation beginning approximately 20 months
later.
Our business requires a significant capital investment. We currently
expect that through the year 2001, we will need cash mostly for:
<PAGE>
- Ongoing utility construction and maintenance programs designed
to maintain and improve facilities providing electric service.
- Growth within the monitored services business,
including acquisition of customer accounts.
Capital expenditures for 1998 and anticipated capital expenditures for
1999 through 2001 are as follows:
Fossil Nuclear Power Monitored
Generation Generation Delivery Services Other Total
(Dollars in Thousands)
1998 . . $ 46,400 $25,800 $78,000 $859,500 $47,700 $1,057,400
1999 . . 117,900 19,700 90,800 434,400 20,700 683,500
2000 . . 149,900 32,200 79,700 355,100 2,300 619,200
2001 . . 109,100 21,200 78,600 373,700 200 582,800
Monitored services capital expenditures include anticipated acquisitions
and purchases of customer accounts. Other primarily represents our commitments
to our Affordable Housing Tax Credit (AHTC) program. See discussion in OTHER
INFORMATION below.
These estimates are prepared for planning purposes and may be revised
(see Note 10). Actual expenditures may differ from our estimates. Electric
expenditures shown in the table above do not take into account the pending
combination of our electric utility operations with KCPL (see Note 21).
Bond maturities will require cash of approximately $435 million through
the year 2003. Protection One is required to retire its $500 million revolving
credit facility in the year 2001. At December 31, 1998, $42 million was
outstanding under this facility.
Dividend Policy
Our currently authorized quarterly dividend for 1999 of 53 1/2 cents per
common share or $2.14 on an annual basis is paid from our earnings and remains
unchanged from 1998. Our board of directors reviews our dividend policy on an
annual basis. We expect the next review to be made in January 2000. Among the
factors typically considered in determining our dividend policy are earnings,
cash flows, capitalization ratios, competition and regulatory conditions. In
addition, we expect the board of directors in its next review to consider
various factors such as greater participation in our dividend reinvestment
program, our new compensation plan that pays senior management part of their
annual compensation in stock and our business profile upon completion of the
KCPL merger.
OTHER INFORMATION
Competition and Enhanced Business Opportunities
The United States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the electricity industry. The Energy Policy Act permitted
the FERC to order electric utilities to allow third parties the use of their
transmission systems to sell electric power to wholesale customers. A wholesale
sale is defined as a
<PAGE>
utility selling electricity to a "middleman", usually a city or its utility
company, to resell to the ultimate retail customer. As part of the 1992 KGE
merger, we agreed to open access of our transmission system for wholesale
transactions. FERC also requires us to provide transmission services to others
under terms comparable to those we provide to ourselves. During 1998,
wholesale electric sales represented approximately 12% of total electric sales,
excluding power marketing sales.
Various states have taken steps to allow retail customers to purchase
electric power from providers other than their local utility company. The Kansas
Legislature created a Retail Wheeling Task Force (the Task Force) in 1997 to
study the effects of a deregulated and competitive market for electric services.
Legislators, regulators, consumer advocates and representatives from the
electric industry made up the Task Force. Several bills were introduced to the
Kansas Legislature in the 1998 legislative session, but none passed. Hearings
on retail wheeling bills are being held in the 1999 legislature. The outcome
of retail wheeling legislation in Kansas remains uncertain.
We believe successful providers of energy in a deregulated market will
provide energy-related services. We believe consumers will demand innovative
options and insist on efficient products and services to meet their
energy-related needs. We believe that our strong core utility business provides
a platform to offer the efficient energy products and services that customers
will desire. We continue to seek new ways to add value to the lives and
businesses of our customers. We recognize that our current customer base must
expand beyond our existing service area.
Increased competition for retail electricity sales may reduce future
electric utility earnings compared to our historical electric utility earnings.
After all ordered electric rate decreases are implemented, our rates will range
from 73% to 90% of the national average for retail customers. Because of these
reduced rates, we expect to retain a substantial part of our current volume of
energy deliveries in a competitive environment.
While operating in this competitive environment may place pressure on
our profit margins, common dividends and credit ratings, we expect it to create
opportunities. Wholesale and industrial customers may pursue cogeneration,
self-generation, retail wheeling, municipalization or relocation to other
service territories in an attempt to cut their energy costs. Credit rating
agencies are applying more stringent guidelines when rating utility companies
due to increasing competition.
We offer competitive electric rates for industrial improvement projects
and economic development projects in an effort to maintain and increase electric
load.
To better position ourselves for the competitive energy environment, we
are pursuing a merger with KCPL, we have consummated a strategic alliance with
ONEOK (see Note 8) and we hold a controlling interest in Protection One
(see Note 4).
In light of competitive developments, we are pursuing the following
strategic plan:
- Maintain a strong core energy business.
- Seek out and pursue business lines that are compatible
with our investment criteria and growth strategies;
i.e., customer growth and monthly, recurring revenues.
- Promote cross-marketing strategies among our consumer
services businesses.
<PAGE>
Year 2OOO Issue
We are currently addressing the effect of the Year 2000 Issue on
information systems and operations. We face the Year 2000 Issue because many
computer systems and applications abbreviate dates by eliminating the first two
digits of the year, assuming that these two digits are always "19". On January
1, 2000, some computer programs may incorrectly recognize the date as January 1,
1900. Some computer systems and applications may incorrectly process critical
information or may stop processing altogether because of the date abbreviation.
Calculations using dates beyond December 31, 1999, may affect computer
applications before January 1, 2000.
Electric Utility Operations: We have recognized the potential adverse
effects the Year 2000 Issue could have on our utility operations. In 1996, we
established a formal Year 2000 readiness program to investigate and correct
these problems in the main computer systems of our company. In 1997, we
expanded the program to include all business units and departments of our
utility operations, using a common methodology. The Year 2000 Issues concerning
the Wolf Creek nuclear operating plant are discussed below.
The goal of our Year 2000 readiness program is to identify and assess
all critical computer programs, computer hardware and embedded systems
potentially affected by the Year 2000 date change, to repair or replace those
systems found to be incompatible with Year 2000 dates, and to develop
predetermined actions to be used as contingencies in the event any critical
business function fails unexpectedly or is interrupted. The program is directed
by a written policy which provides the guidance and methodology to the
departments and business units to follow. Due to varying degrees of exposure
of departments and business units to the Year 2000 Issue, some departments and
business units are further along in their readiness efforts than others. All
departments have completed the awareness, inventory, and assessment phases, and
have developed their initial contingency plans. Most smaller departments and
business units have completed the assessment, remediation, and testing phases.
The majority of our current efforts are in the remediation and testing phases.
Overall, based on manhours as a measure of work effort, we believe we are
approximately 74% complete with our readiness efforts.
The estimated progress of our departments and business units, exclusive
of Protection One and Wolf Creek Nuclear Operating Corporation (WCNOC), at
December 31, 1998, based on manhours, is as follows:
Percentage
Department/Business Unit Completion
Fossil Fuel . . . . . . . . . . . . . . . 81%
Power Delivery . . . . . . . . . . . . . 73%
Information Technology. . . . . . . . . . 76%
Administrative. . . . . . . . . . . . . . 69%
Our Year 2000 readiness program addresses all Information Technology
(IT) and non-IT issues which may be impacted by the Year 2000 Issue. We have
included commercial computer software, including mainframe, client/server, and
desktop software; internally developed computer software, including mainframe,
client/server, and desktop software; computer hardware, including mainframe,
client/server, desktop, network, communications, and peripherals; devices using
embedded computer chips, including plant equipment, controls, sensors,
facilities equipment, heating, ventilating, and air
<PAGE>
conditioning (HVAC) equipment; and relationships with third-party vendors,
suppliers, and customers. Our program requires testing as a method for
verifying the Year 2000 readiness of an item. For those items which are
impossible to test, other methods are being used to identify the readiness
status, provided adequate contingency plans are established to provide a
workaround or backup for the item. Our Year 2000 readiness efforts for
utility operations were substantially completed at the end of 1998 except for
those items scheduled for normal maintenance or upgrade during 1999.
We estimate that total costs to update all of our electric utility
operating systems for Year 2000 readiness, excluding costs associated with WCNOC
discussed below, to be approximately $6.5 million, of which $4.2 million
represents IT costs and $2.3 million represents non-IT costs. As of December
31, 1998, we have expended approximately $4.1 million of these costs, of which
$3.2 million represent IT costs and $0.9 million represent non-IT costs. Based
on what we know, we expect to incur the remaining $2.4 million, of which $1.0
million represents IT costs and $1.4 million represents non-IT costs, by the
end of 1999. These costs include labor costs for both company employees and
contract personnel used in our Year 2000 program, and non-labor costs for
software tools used in our remediation and testing efforts, replacement
software, replacement hardware, replacement embedded devices, and miscellaneous
costs associated with their testing and replacement.
We have identified the following major areas of risk relating to our
Year 2000 Issue exposure: 1) vendors and suppliers, 2) internal plant controls
and systems, 3) telecommunications, including phone systems and cellular phones,
4) large customers, and 5) rail transportation. We consider vendors and
suppliers a risk because of the lack of control we have over their operations.
We are in the process of contacting by letter each vendor or supplier critical
to our operations for information pertaining to their Year 2000 readiness. We
consider our plant controls and systems a risk due to the complexity, variety,
and extent of the embedded systems. We consider telecommunications a risk
because it performs a critical function in a large number of our business
processes and plant control functions. We consider large customers a risk
because of the influence their electrical usage patterns have on our electrical
generation and distribution systems. We consider rail transportation a risk
because of our dependence for delivery of coal used at our coal-fired generating
plants.
The most reasonably likely worst case scenario we anticipate is the loss
or partial interruption of local and long-distance telephone service, the
interruption or significant delay to rail service affecting the coal deliveries
to our generating plants, the unscheduled shut-down of the Wolf Creek nuclear
operating plant, the potential loss of load from one or more large customers,
and the loss of minimal generating capacity in the region for brief periods of
time. Approximately 62% of our generating capacity utilizes coal as fuel.
We are addressing these risks in our contingency plans, and have or will
be implementing a number of action plans in advance to mitigate these and other
potential risks. Our contingency plans include pre-established actions to deal
with potential operational impacts. For example, we have installed a
company-wide trunked radio system which can be used in place of the commercial
telecommunications systems, in the event those systems are interrupted. We plan
to place in service, at reduced output, generating units which would normally
not be in service to help accommodate load shifts that would be caused by a
large customer suddenly dropping or significantly reducing their electricity
usage, or in the event of unexpected loss of some of our generation capacity or
generation capacity of others in the region. In addition, we generally maintain
more than a 30-day supply of coal at each of our coal-fired generating plants,
<PAGE>
reducing the effect of any temporary interruption of rail transportation and an
unscheduled temporary shut-down of the Wolf Creek nuclear operating plant
discussed below.
While all business units and departments have developed contingency
plans to cover essential business functions and anticipated possible Year
2000-related failure or interruption, these plans are continually reviewed and
updated based on information learned as our Year 2000 readiness efforts
proceed.
Wolf Creek Nuclear Operating Corporation: WCNOC has been evaluating and
adjusting all known date-sensitive systems and equipment for Year 2000
compliance. WCNOC is developing a plan to effect the readiness of the plant for
the coming of the Year 2000. This plan is designed to closely parallel the
guidance provided by the Nuclear Energy Institute and the NRC. WCNOC is
partnering with several industry groups to share information regarding
evaluating items that are Year 2000 sensitive. As applications and devices are
confirmed to be Year 2000 non-compliant, business decisions are being made to
repair or retire the item.
On May 11,1998 the NRC issued Generic Letter 98-01 entitled "Year 2000
Readiness of Computer Systems at Nuclear Power Plants." This letter expressed
the NRC's expectations with regard to Year 2000 readiness. The letter also
requires the licensee to file its Year 2000 plan and status report no later than
July 1, 1999.
WCNOC is developing contingency plans to address risk associated with
Year 2000 Issues. These plans generally follow the guidance contained in
NUCLEAR ENERGY INSTITUTE/NUCLEAR UTILITY SOFTWARE MANAGEMENT GROUP 98-07,
NUCLEAR UTILITY READINESS CONTINGENCY PLANNING. The steps to be taken involve
the determination of which items present a critical risk to the facility, review
of the identified risks, determining mitigation strategies, and ensuring that
each responsible organization develops appropriate contingency plans.
In order to assess the licensees progress in preparing for Year 2000,
the NRC scheduled audits at various nuclear power plant facilities during 1998
and early 1999. One of these audits was conducted at WCNOC during the month of
November 1998. The findings of this audit were as follows:
- The NEI/NUSMG 97-07 guidance is being followed. The Wolf Creek licensee
has not identified any systems needed for safe shutdown as having Year
2000 problems.
- Wolf Creek is making use of its existing quality assurance and
modification programs and procedures to achieve Year 2000 readiness.
Furthermore, Wolf Creek is engaged in extensive information sharing
and interfaces with other entities on Year 2000 Issues.
- The need for Year 2000 contingency planning is understood by the Wolf Creek
licensee and in keeping with the NEI/NUSMG 98-07 recommendation, one
individual has been designated as the single point of contact for
contingency planning.
- Wolf Creek is at the detailed assessment phase except for the items of
minimal significance designated as Limited Use Databases and
spreadsheets, which come under the category of Limited Use Hardware/
Software. Year 2000 readiness for Wolf Creek is scheduled for
September 15, 1999, and can be achieved based on the effort underway.
<PAGE>
- Executive management support was found to be aggressive at Wolf Creek.
Management at Wolf Creek has dedicated the fiscal resources needed
for successful completion of the year 2000 readiness program.
Since Wolf Creek was designed during the 1970s and 1980s, most of the
originally installed electronic plant equipment did not contain microprocessors.
During this time frame, the NRC would not allow components required for safe
shutdown of the plant to contain microprocessors. For these reasons, there is
minimal Year 2000 risk associated with being able to safely shutdown the plant
and maintain it in a safe shutdown condition. During the years since original
construction, microprocessor based electronic components have been added in
non-safe shutdown applications. Some of these (only two identified thus far and
no others are anticipated) could shutdown the plant. Special attention will be
paid to these devices to ensure that there is minimal Year 2000 risk associated
with them.
In the original design and through plant modifications, microprocessor
based components were installed in plant monitoring applications such as the
radiation monitoring equipment and the plant information computer. Similarly,
in the area of non-plant operation computers and applications, WCNOC has several
items which will require remediation. There is a possibility that these devices
could cause a Year 2000 problem. Failure to adequately remediate any Year 2000
problems could require the plant's operations be limited or shutdown.
WCNOC estimates that the most reasonably likely worst case scenario
would be a temporary plant shutdown due to external electrical grid
disturbances. While these disturbances may result in a temporary shutdown, the
safety of the plant will not be compromised and the unit should restart shortly
after the grid disturbance has been corrected.
The table below sets forth estimates of the status of the components of
WCNOC's Year 2000 readiness program at December 31, 1998.
<TABLE>
<CAPTION>
Estimated
Completion Percentage
Phase Date Completion
<S> <C> <C>
Identification and assessment of plant components Mar 99 89%
Identification and assessment of computers/software (Note 1) Jun 99 64%
Identification and Assessment of Other Areas (Note 2) Jun 99 47%
Identified remediations complete (Note 3) Sep 99 31%
Comprehensive testing guidelines 100%
Comprehensive testing (Note 4) Jun 99 13%
Contingency planning guidelines 100%
Contingency planning individual plans Mar 99 15%
Note 1 - Several computers are on three year lease and will not be obtained until 1999.
Note 2 - Includes items such as measuring/test and telecommunications equipment.
Note 3 - Two major modifications are currently scheduled to be completed after June 1999,
the remaining remediations are presently scheduled for completion prior to July 1999.
Note 4 - Several tests will not be performed until remediations are complete.
</TABLE>
WCNOC has established a goal of completing all assessments of affected
systems by the end of the second quarter of 1999, with remediations being
completed by the end of the third quarter. Remediations are being planned and
initiated as the detailed assessment phase identifies the need, not at the end
of the assessment period. The areas where the greatest potential for necessary
remediations and/or more complex remediations could result were the first ones
targeted for assessment so remediation
<PAGE>
planning could be started earlier. Many remediations will be completed before
the end of the assessment period. In addition, WCNOC is communicating with
others with which its systems interface or on which they rely with respect to
those companies' Year 2000 compliance. Letters have been sent to all pertinent
vendors to acquire this information.
WCNOC has estimated the costs to complete the Year 2000 project at $4.6
million ($2.1 million, our share). As of December 31, 1998, $1.4 million ($0.6
million, our share) had been spent on the project. A summary of the projected
costs to complete and actual costs incurred through December 31, 1998, is as
follows:
Projected Actual
Costs Costs
(Dollars in Thousands)
Wolf Creek Labor and Expenses. . $ 494 $ 261
Contractor Costs . . . . . . . . 646 493
Remediation Costs. . . . . . . . 3,493 611
Total. . . . . . . . . . . . . $4,633 $1,365
Approximately $3.5 million ($1.6 million, our share) of WCNOC's total
Year 2000 cost is associated with remediation. Of these remediation costs, $2.4
million ($1.1 million, our share) are associated with seven major jobs which are
in the initial stages. All of these costs are being expensed as they are
incurred and are being funded on a daily basis along with our normal costs of
operations. In order to minimize the effects of delaying other information
technology projects, WCNOC has and will continue to augment staffing during the
identification and remediation phases of the project. This staffing, which will
include both programmers and technical support personnel, will also be available
during the testing and initial operating phases of the various systems.
Monitored Services Operations: Protection One is reviewing its computer
programs, computer hardware and embedded systems critical to its businesses and
operational needs to identify and correct any components that could be affected
by the change of the date to January 1, 2000. Protection One will continue its
reviews until January 1, 2000, particularly with respect to the acquisition of
businesses that include additional computer systems and equipment. In addition,
changes in the date of compliance or preparedness within companies that provide
services or equipment to Protection One will require management to continue its
evaluations.
Protection One's Year 2000 readiness program addresses:
- Commercial computer software, including mainframe, client/service
and desktop software
- Internally developed computer software, including mainframe, client/
server and desktop software
- Computer hardware, including mainframe, client/server and desk top,
network, communications, and peripherals
- Devices using embedded computer chips, including controls, sensors,
facilities equipment, heating, ventilating and air conditioning
equipment
- Relationships with third-party vendors and suppliers
<PAGE>
Based on the results of its on-going reviews, Protection One believes
that the Year 2000 Issue does not pose material operational problems. However,
the most reasonably likely worst case scenario is to be found in the area of
external services, specifically firms providing electrical power, heating,
ventilating and air conditioning, and local and long distance
telecommunications.
While Protection One believes the total collapse of service provided is
highly unlikely, one or more of the following scenarios could occur:
- Temporary disruption or unpredictable provision of nationwide long-
distance service
- Temporary or unpredictable provision of local telephone service, or
- Temporary interruption or unpredictable provision of electrical power.
To the extent customers did not receive timely and adequate responses to
alarms, Protection One would be required to rely on its specific disclaimer, in
most of its customers agreements of liability for the acts or omissions of third
party agencies. The enforcability of such disclaimers may be subject to
judicial scrutiny in jurisdictions in which Protection One operates.
Protection One estimates the total cost to update all critical operating
systems for Year 2000 readiness will be approximately $5 million. At December
31, 1998, approximately $1.1 million of these costs had been incurred. The
costs of the Year 2000 project and the date on which Protection One plans to
complete the Year 2000 modifications, estimated to be during 1999, is based on
the best estimates, which were derived utilizing numerous assumptions of future
events including the continued availability of certain resources, third party
modification plans and other factors. However, there can be no guarantee that
these estimates will be achieved and actual results could differ materially from
those plans. Specific factors that might cause such material differences
include, but are not limited to, the availability and cost of personnel trained
in this area, the ability to locate and correct all relevant computer codes, and
similar uncertainties.
Market Risk Disclosure
Market Price Risks: We are exposed to market risk, including changes in
commodity prices, equity and debt instrument investment prices and interest
rates.
Commodity Price Exposure: In our commodity price risk management
activities, we engage in both trading and non-trading activities. In these
activities, we utilize a variety of financial instruments, including forward
contracts involving cash settlements or physical delivery of an energy
commodity, options, swaps which require payments (or receipt of payments) from
counterparties based on the differential between specified prices for the
related commodity, and futures traded on electricity and natural gas.
We are involved in trading activities primarily to minimize risk from
market fluctuations, to maintain a market presence and to enhance system
reliability. Although we attempt to balance our physical and financial purchase
and sale contracts in terms of quantities and contract terms, net open positions
can exist or are established due to the origination of new transactions and our
assessment of, and response to, changing market conditions. To the extent we
have an open position, we are exposed to the risk that fluctuating market prices
may adversely impact our financial position or results from operations.
<PAGE>
We manage and measure the exposure of our trading portfolio using a
variance/covariance value-at-risk (VAR) model, which simulates forward price
curves in the energy markets to estimate the size of future potential losses.
The quantification of market risk using VAR methodologies provides a consistent
measure of risk across diverse energy markets and products. The use of this
method requires a number of key assumptions including the selection of a
confidence level for losses and the estimated holding period.
We express VAR as a potential dollar loss based on a 95% confidence
level using a one-day holding period. As of December 31, 1998, our VAR
(unaudited) for our trading activities was approximately $100,000. Our Risk
Oversight Committee sets the VAR limit. We employ additional risk control
mechanisms such as stress testing, daily loss limits, and commodity position
limits.
We have considered a number of risks and costs associated with the
future contractual commitments included in our energy portfolio, including
credit risks associated with the financial condition of counterparties, product
location (basis) differentials and other risks which management policy dictates.
The counterparties in our portfolio consist primarily of large energy marketers
and major utility companies. The creditworthiness of our counterparties could
impact our overall exposure to credit risk, either positively or negatively.
However, we maintain credit policies with regard to our counterparties that in
our management's view minimize overall credit risk.
We are also exposed to commodity price changes outside of trading
activities. We use derivatives for non-trading purposes primarily to reduce
exposure relative to the volatility of cash market prices. Given the amount of
power purchased for utility operations during 1998, we would have had exposure
of approximately $5 million of operating income for a 10% increase in price per
MW of electricity. Based upon mmbtu's of natural gas and fuel oil burned during
1998, we had exposure of approximately $4 million of operating income for a 10%
change in average price paid per mmbtu. Quantities of natural gas and
electricity could vary dramatically year to year based on weather, unit outages
and nuclear refueling.
Investment Portfolio: We have approximately $288 million of equity and
debt securities as of December 31, 1998. We do not hedge these investments and
are exposed to the risk of changing market prices. We classify these securities
as "available for sale" for accounting purposes and mark them to market on the
balance sheet at the end of each period. However, net income is not affected
until the securities are sold. Management estimates that its investments will
generally be consistent with trends and movements of the overall stock market
barring any unusual situations. An immediate 10% change in the market price of
our equity securities would have a $13 million effect on other comprehensive
income. The value of the debt securities in our portfolio changes inversely
with fluctuations in interest rates.
Interest Rate Exposure: We have approximately $602 million of variable
rate debt, including current maturities of fixed rate debt, as of December 31,
1998. A 100 basis point change in each debt series benchmark rate would impact
net income on an annual basis by approximately $5 million.
<PAGE>
Merger Agreement with Kansas City Power & Light Company
On February 7, 1997, we signed a merger agreement with KCPL by which
KCPL would be merged with and into the company in exchange for company stock.
In December 1997, representatives of our financial advisor indicated that they
believed it was unlikely that they would be in a position to issue a fairness
opinion required for the merger on the basis of the previously announced terms.
On March 18, 1998, we and KCPL agreed to a restructuring of our
February 7, 1997, merger agreement which will result in the formation of Westar
Energy, a new electric company. Under the terms of the merger agreement, our
electric utility operations will be transferred to KGE, and KCPL and KGE will be
merged into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed
Westar Energy. In addition, under the terms of the merger agreement, KCPL
shareholders will receive company common stock which is subject to a collar
mechanism of not less than .449 nor greater than .722, provided the amount of
company common stock received may not exceed $30.00, and one share of Westar
Energy common stock per KCPL share. The Western Resources Index Price is the
20 day average of the high and low sale prices for company common stock on the
New York Stock Exchange ending ten days prior to closing. If the Western
Resources Index Price is less than or equal to $29.78 on the fifth day prior to
the effective date of the combination, either party may terminate the agreement.
Upon consummation of the combination, we will own approximately 80.1% of the
outstanding equity of Westar Energy and KCPL shareholders will own approximately
19.9%. As part of the combination, Westar Energy will assume all of the
electric utility related assets and liabilities of Western Resources, KCPL and
KGE.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9
billion of indebtedness for borrowed money of Western Resources and KGE, and
$800 million of debt of KCPL. Long-term debt of the company, excluding
Protection One, was $2.5 billion at December 31,1998. Under the terms of the
merger agreement, it is intended that we will be released from our obligations
with respect to our debt to be assumed by Westar Energy.
Pursuant to the merger agreement, we have agreed, among other things, to
call for redemption all outstanding shares of our 4 1/2% Series Preferred Stock,
par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per
share, and 5% Series Preferred Stock, par value $100 per share.
Consummation of the merger is subject to customary conditions. On July
30, 1998, our shareholders and the shareholders of KCPL voted to approve the
amended merger agreement at special meetings of shareholders. We estimate the
transaction to close in 1999, subject to receipt of all necessary approvals from
regulatory and government agencies.
In testimony filed in February 1999, the KCC staff recommended the
merger be approved but with conditions which we believe would make the merger
uneconomical. The merger agreement allows us to terminate the agreement if
regulatory approvals are not acceptable. The KCC is under no obligation to
accept the KCC staff recommendation. In addition, legislation has been proposed
in Kansas that could impact the transaction. We do not anticipate the proposed
legislation to pass in its current form. We are not able to predict whether any
of these initiatives will be adopted or their impact on the transaction, which
could be material.
<PAGE>
On August 7, 1998, we and KCPL filed an amended application with the
FERC to approve the Western Resources/KCPL merger and the formation of Westar
Energy.
We have received procedural schedule orders in Kansas and Missouri.
These schedules indicate hearing dates beginning May 3, 1999, in Kansas and July
26, 1999, in Missouri.
In February 1999, KCPL advised us that its Hawthorne generating station
(479 MW coal facility) suffered material damage to its boiler which could
prevent the unit's operation for an extended period. We are not able to
ascertain at this time the impact of this matter on the merger.
KCPL is a public utility company engaged in the generation,
transmission, distribution, and sale of electricity to customers in western
Missouri and eastern Kansas. We, KCPL and KGE have joint interests in certain
electric generating assets, including Wolf Creek. For additional information,
see Note 21. Following the closing of the combination, Westar Energy is expected
to have approximately one million electric utility customers in Kansas and
Missouri, approximately $8.2 billion in assets and the ability to generate
almost 8,800 megawatts of electricity.
At December 31, 1998, we had deferred approximately $14 million related
to the KCPL transaction. These costs will be included in the determination of
total consideration upon consummation of the transaction.
Affordable Housing Tax Credit Program
In 1997, we received authorization from the KCC to invest up to $114
million in AHTC investments. An example of an AHTC project is housing for
residents who are elderly or meet certain income requirements. At December 31,
1998, we had invested approximately $65 million to purchase limited partnership
interests. We are committed to investing approximately $25 million more in AHTC
investments by April 1, 2001. These investments are accounted for using the
equity method of accounting. Based upon an order received from the KCC, income
generated from the AHTC investments, primarily tax credits, will be used to
offset costs associated with postretirement and postemployment benefits offered
to our employees.
Pronouncements Issued but Not Yet Effective
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). This statement establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting. SFAS 133 is
effective for fiscal years beginning after June 15, 1999. SFAS 133 cannot be
applied retroactively. SFAS 133 must be applied to (a) derivative instruments
and (b) certain derivative instruments embedded in hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1997, and, at the
company's election, before January 1, 1998. The company will adopt SFAS 133 no
later than January 1, 2000.
<PAGE>
Management is presently evaluating the impact that adoption of SFAS 133 will
have on the company's financial position and results of operations. Adoption of
SFAS 133, however, could increase volatility in earnings and other comprehensive
income.
In December 1998, the Emerging Issues Task Force reached consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF Issue 98-10). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires
energy trading contracts to be recorded at fair value on the balance sheet, with
the changes in the fair value included in earnings. The company will adopt EITF
Issue 98-10 during 1999. Management does not expect the impact of adopting EITF
Issue 98-10 to be material to the company's financial position or results of
operations.
<PAGE>
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to market risk disclosure is set forth in Other
Information of Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations included herein.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 61
Financial Statements:
Consolidated Balance Sheets, December 31, 1998 and 1997 62
Consolidated Statements of Income for the years ended
December 31, 1998, 1997 and 1996 63
Consolidated Statements of Comprehensive Income for the
years ended December 31, 1998, 1997 and 1996 64
Consolidated Statements of Cash Flows for the years ended
1998, 1997 and 1996 65
Consolidated Statements of Cumulative Preferred and
Preference Stock, December 31, 1998 and 1997 66
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 1998, 1997 and 1996 67
Notes to Consolidated Financial Statements 68
Financial Schedules:
Schedule II - Valuation and Qualifying Accounts 110
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, III, IV, and V.
<PAGE>
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 cumulative preferred and preference stock of Western Resources,
Inc., and subsidiaries as of December 31, 1998 and 1997, and the related
consolidated statements of income, comprehensive income, cash flows, and
shareholders' equity for each of the three years in the period ended December
31, 1998. (1997 restated, see Note 2.) These consolidated financial statements
and the schedule referred to below are the responsibility of the company's
management. Our responsibility is to express an opinion on these consolidated
financial statements and this schedule 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, 1998 and 1997, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. Schedule II - Valuation and Qualifying
Accounts is presented for purposes of complying with the Securities and Exchange
Commission rules and is not part of the basic financial statements. The
schedule has been subjected to the auditing procedures applied in the audit of
the basic financial statements and in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 27, 1999 (Except with respect
to the matter discussed in Note 2, as
to which the date is April 5, 1999)
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<CAPTION>
December 31,
1998 1997
ASSETS Restated
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 16,394 $ 76,608
Accounts receivable (net) . . . . . . . . . . . . . . . . 222,715 325,043
Inventories and supplies (net). . . . . . . . . . . . . . 95,590 86,398
Marketable securities . . . . . . . . . . . . . . . . . . 288,077 75,258
Prepaid expenses and other. . . . . . . . . . . . . . . . 57,225 25,483
Total Current Assets. . . . . . . . . . . . . . . . . . 680,001 588,790
PROPERTY, PLANT AND EQUIPMENT (NET) . . . . . . . . . . . . 3,795,143 3,786,528
OTHER ASSETS:
Investment in ONEOK . . . . . . . . . . . . . . . . . . . 615,094 596,206
Customer accounts (net) . . . . . . . . . . . . . . . . . 1,014,428 541,146
Goodwill (net). . . . . . . . . . . . . . . . . . . . . . 1,188,253 844,759
Regulatory assets . . . . . . . . . . . . . . . . . . . . 364,213 380,421
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 294,296 221,700
Total Other Assets. . . . . . . . . . . . . . . . . . . 3,476,284 2,584,232
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . $7,951,428 $6,959,550
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt. . . . . . . . . . . $ 165,838 $ 21,217
Short-term debt . . . . . . . . . . . . . . . . . . . . . 312,472 236,500
Accounts payable. . . . . . . . . . . . . . . . . . . . . 127,834 151,166
Accrued liabilities . . . . . . . . . . . . . . . . . . . 252,367 222,410
Accrued income taxes. . . . . . . . . . . . . . . . . . . 32,942 27,360
Deferred security revenues. . . . . . . . . . . . . . . . 57,703 33,900
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 85,690 47,737
Total Current Liabilities . . . . . . . . . . . . . . . 1,034,846 740,290
LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . . . . . . . . . . . . 3,063,064 2,188,034
Western Resources obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely company subordinated debentures. . . . . . . . . 220,000 220,000
Deferred income taxes and investment tax credits. . . . . 938,659 1,069,907
Minority interests. . . . . . . . . . . . . . . . . . . . 205,822 165,530
Deferred gain from sale-leaseback . . . . . . . . . . . . 209,951 221,779
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 316,245 259,521
Total Long-Term Liabilities . . . . . . . . . . . . . . 4,953,741 4,124,771
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Cumulative preferred and preference stock . . . . . . . . 24,858 74,858
Common stock, par value $5 per share, authorized
85,000,000 shares, outstanding 65,909,442 and
65,409,603 shares, respectively . . . . . . . . . . . . 329,548 327,048
Paid-in capital . . . . . . . . . . . . . . . . . . . . . 775,337 760,553
Retained earnings . . . . . . . . . . . . . . . . . . . . 823,590 919,911
Accumulated other comprehensive income. . . . . . . . . . 9,508 12,119
Total Shareholders' Equity. . . . . . . . . . . . . . . 1,962,841 2,094,489
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY. . . . . . . . . . $7,951,428 $6,959,550
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<CAPTION>
Year Ended December 31,
1998 1997 1996
Restated
<S> <C> <C> <C>
SALES:
Energy. . . . . . . . . . . . . . . . . . . . . . . . $1,612,959 $1,999,418 $2,038,281
Security. . . . . . . . . . . . . . . . . . . . . . . 421,095 152,347 8,546
Total Sales . . . . . . . . . . . . . . . . . . . . 2,034,054 2,151,765 2,046,827
COST OF SALES:
Energy. . . . . . . . . . . . . . . . . . . . . . . . 691,468 928,723 879,328
Security. . . . . . . . . . . . . . . . . . . . . . . 131,791 38,800 3,798
Total Cost of Sales . . . . . . . . . . . . . . . . 823,259 967,523 883,126
GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . . 1,210,795 1,184,242 1,163,701
OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . . 337,507 384,313 374,369
Depreciation and amortization . . . . . . . . . . . . 280,673 256,725 201,331
Selling, general and administrative expense . . . . . 263,185 316,479 199,448
Write-off international development activities. . . . 98,916 - -
Write-off deferred merger costs . . . . . . . . . . . - 48,008 -
Monitored services special charge . . . . . . . . . . - 24,292 -
Total Operating Expenses. . . . . . . . . . . . . . 980,281 1,029,817 775,148
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . 230,514 154,425 388,553
OTHER INCOME (EXPENSE):
Investment earnings . . . . . . . . . . . . . . . . . 21,739 37,784 20,647
Gain on sale of Tyco securities . . . . . . . . . . . - 864,253 -
Special charges from ADT . . . . . . . . . . . . . . - - (18,181)
Minority interests. . . . . . . . . . . . . . . . . . 382 3,586 -
Other . . . . . . . . . . . . . . . . . . . . . . . . 34,207 16,265 12,841
Total Other Income (Expense). . . . . . . . . . . . 56,328 921,888 15,307
EARNINGS BEFORE INTEREST AND TAXES. . . . . . . . . . . 286,842 1,076,313 403,860
INTEREST EXPENSE:
Interest expense on long-term debt. . . . . . . . . . 170,855 119,972 105,741
Interest expense on short-term debt and other . . . . 55,265 73,836 46,810
Total Interest Expense. . . . . . . . . . . . . . . 226,120 193,808 152,551
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . 60,722 882,505 251,309
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . 14,557 382,987 82,359
NET INCOME BEFORE EXTRAORDINARY GAIN. . . . . . . . . . 46,165 499,518 168,950
EXTRAORDINARY GAIN, NET OF TAX. . . . . . . . . . . . . 1,591 - -
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 47,756 499,518 168,950
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 3,591 4,919 14,839
EARNINGS AVAILABLE FOR COMMON STOCK . . . . . . . . . . $ 44,165 $ 494,599 $ 154,111
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 65,633,743 65,127,803 63,833,783
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING:
EARNINGS AVAILABLE FOR COMMON STOCK BEFORE
EXTRAORDINARY GAIN. . . . . . . . . . . . . . . . . . $ 0.65 $ 7.59 $ 2.41
EXTRAORDINARY GAIN. . . . . . . . . . . . . . . . . . . .02 - -
EARNINGS AVAILABLE FOR COMMON STOCK . . . . . . . . . . $ 0.67 $ 7.59 $ 2.41
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 2.14 $ 2.10 $ 2.06
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
<CAPTION>
Year Ended
December 31,
1998 1997 1996
Restated
<S> <C> <C> <C>
Net income. . . . . . . . . . . . . . . . . . . . . . . . . $ 47,756 $499,518 $168,950
Other comprehensive (loss) income, before tax:
Unrealized holding gains (losses) on marketable
securities arising during the year . . . . . . . . . . (17,244) 25,248 -
Less: Reclassification adjustment for losses
included in net income. . . . . . . . . . . . . . . . . 14,029 - -
Unrealized (loss) gain on marketable securities (net). . (3,215) 25,248 -
Unrealized loss on currency translation . . . . . . . . . (1,026) - -
Other comprehensive (loss) income, before tax . . . . . . . (4,241) 25,248 -
Income tax benefit (expense). . . . . . . . . . . . . . . . 1,630 (13,129) -
Other comprehensive income, net of tax. . . . . . . . . . . (2,611) 12,119 -
Comprehensive income. . . . . . . . . . . . . . . . . . . . $ 45,145 $511,637 $168,950
The Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<CAPTION>
Year ended December 31,
1998 1997 1996
Restated
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 47,756 $ 499,518 $ 168,950
Adjustments to reconcile net income to net cash
provided by operating activities:
Extraordinary gain. . . . . . . . . . . . . . . . . . . . (1,591) - -
Depreciation and amortization . . . . . . . . . . . . . . 280,673 256,725 201,331
Equity in earnings from investments . . . . . . . . . . . (6,064) (25,405) (9,373)
(Gain)/loss on sale of securities . . . . . . . . . . . . 14,029 (864,253) -
Write-off international development activities. . . . . . 98,916 - -
Write-off deferred merger costs . . . . . . . . . . . . . - 48,008 -
Monitored services special charge . . . . . . . . . . . . - 24,292 -
Changes in working capital items (net of effects
from acquisitions):
Accounts receivable (net) . . . . . . . . . . . . . . . 118,844 14,156 (47,474)
Inventories and supplies (net). . . . . . . . . . . . . (8,000) 3,249 10,624
Marketable securities . . . . . . . . . . . . . . . . . 6,293 (10,461) -
Prepaid expenses and other. . . . . . . . . . . . . . . (26,988) 9,230 (14,900)
Accounts payable. . . . . . . . . . . . . . . . . . . . (33,613) (48,298) 15,353
Accrued liabilities . . . . . . . . . . . . . . . . . . (42,411) 68,623 10,261
Accrued income taxes. . . . . . . . . . . . . . . . . . 5,582 9,869 26,377
Changes in other assets and liabilities . . . . . . . . . (53,214) (73,810) (98,759)
Net cash flows from (used in) operating activities. . . 400,212 (88,557) 262,390
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment (net). . . . . (182,885) (207,989) (188,952)
Customer account acquisitions . . . . . . . . . . . . . . (277,667) (45,163) -
Monitored services acquisitions,
net of cash acquired. . . . . . . . . . . . . . . . . . (549,196) (438,717) (368,535)
Purchase of ADT common stock. . . . . . . . . . . . . . . - - (589,362)
Proceeds from issuance of stock by subsidiary (net) . . . 45,565 - -
Purchases of marketable securities . . . .. . . . . . . . (261,036) - -
Proceeds from sale of marketable securities . . . . . . . 27,895 1,533,530 -
Other investments (net) . . . . . . . . . . . . . . . . . (91,451) (45,318) (6,563)
Net cash flows (used in) from investing activities. . . (1,288,775) 796,343 (1,153,412)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 75,972 (744,240) 777,290
Proceeds of long-term debt. . . . . . . . . . . . . . . . 1,096,238 520,000 225,000
Retirements of long-term debt . . . . . . . . . . . . . . (167,068) (293,977) (16,135)
Issuance of other mandatorily redeemable securities . . . - - 120,000
Issuance of common stock (net). . . . . . . . . . . . . . 17,284 25,042 33,212
Redemption of preference stock. . . . . . . . . . . . . . (50,000) - (100,000)
Cash dividends paid . . . . . . . . . . . . . . . . . . . (144,077) (141,727) (147,035)
Net cash flows from (used in) financing activities. . . 828,349 (634,902) 892,332
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (60,214) 72,884 1,310
CASH AND CASH EQUIVALENTS:
Beginning of the period . . . . . . . . . . . . . . . . . 76,608 3,724 2,414
End of the period . . . . . . . . . . . . . . . . . . . . $ 16,394 $ 76,608 $ 3,724
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized). . . . . . . . . . . . . . . . . . . . . . $ 220,848 $ 193,468 $ 170,635
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 47,196 404,548 66,692
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During 1997, the company contributed the net assets of its natural gas business totaling
approximately $594 million to ONEOK in exchange for an ownership interest of 45% in ONEOK.
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CUMULATIVE PREFERRED AND PREFERENCE STOCK
(Dollars in Thousands)
<CAPTION>
December 31,
1998 1997
Restated
<S> <C> <C>
CUMULATIVE PREFERRED AND PREFERENCE STOCK:
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
TOTAL CUMULATIVE PREFERRED AND PREFERENCE STOCK . . . . . . . . $ 24,858 $ 74,858
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Dollars in Thousands)
<CAPTION>
Year Ended December 31,
1998 1997 1996
Restated
<S> <C> <C> <C>
Cumulative Preferred and
Preference Stock:
Beginning balance. . . . . . . . . . . . . . . $ 74,858 $ 74,858 $ 174,858
Redemption of preference stock . . . . . . . . (50,000) - (100,000)
Ending balance . . . . . . . . . . . . . . . . 24,858 74,858 74,858
Common Stock:
Beginning balance. . . . . . . . . . . . . . . 327,048 323,126 314,280
Issuance of common stock . . . . . . . . . . . 2,500 3,922 8,846
Ending balance . . . . . . . . . . . . . . . . 329,548 327,048 323,126
Paid-in Capital:
Beginning balance. . . . . . . . . . . . . . . 760,553 739,433 697,962
Expenses on common stock . . . . . . . . . . . - (5) -
Issuance of common stock . . . . . . . . . . . 14,784 21,125 41,471
Ending balance . . . . . . . . . . . . . . . . 775,337 760,553 739,433
Retained Earnings:
Beginning balance. . . . . . . . . . . . . . . 919,911 562,121 540,868
Net income . . . . . . . . . . . . . . . . . . 47,756 499,518 168,950
Dividends on preferred and preference stock. . (3,591) (4,919) (14,839)
Dividends on common stock. . . . . . . . . . . (140,486) (136,809) (131,611)
Issuance of common stock . . . . . . . . . . . - - (1,247)
Ending balance . . . . . . . . . . . . . . . . 823,590 919,911 562,121
Accumulated Other Comprehensive
Income:
Beginning balance. . . . . . . . . . . . . . . 12,119 - -
Unrealized (loss) gain on marketable
securities . . . . . . . . . . . . . . . . (3,215) 25,248 -
Unrealized loss on currency translation. . . . (1,026) - -
Income tax benefit (expense) . . . . . . . . . 1,630 (13,129) -
Ending balance . . . . . . . . . . . . . . . . 9,508 12,119 -
Total Shareholders' Equity . . . . . . . . . . . $1,962,841 $2,094,489 $1,699,538
The Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
<PAGE>
WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business: Western Resources, Inc. (the company) is a
publicly traded consumer services company. The company's primary business
activities are providing electric generation, transmission and distribution
services to approximately 620,000 customers in Kansas and providing monitored
services to approximately 1.5 million customers in North America, the United
Kingdom and Continental Europe. In addition, through the company's 45%
ownership interest in ONEOK, Inc. (ONEOK), natural gas transmission and
distribution services are provided to approximately 1.4 million customers in
Oklahoma and Kansas. Rate regulated electric service is provided by KPL, a
division of the company and Kansas Gas and Electric Company (KGE), a
wholly-owned subsidiary. Monitored services are provided by Protection One,
Inc. (Protection One), a publicly-traded, approximately 85%-owned subsidiary.
Principles of Consolidation: The company prepares its financial
statements in conformity with generally accepted accounting principles. The
accompanying consolidated financial statements include the accounts of Western
Resources and its wholly-owned and majority-owned subsidiaries. All material
intercompany accounts and transactions have been eliminated. Common stock
investments that are not majority-owned are accounted for using the equity
method when the company's investment allows it the ability to exert
significant influence.
The company currently applies accounting standards for its rate
regulated electric business that recognize the economic effects of rate
regulation in accordance with Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation", (SFAS 71) and,
accordingly, has recorded regulatory assets and liabilities when required by a
regulatory order or when it is probable, based on regulatory precedent, that
future rates will allow for recovery of a regulatory asset.
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 dates and to
report amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Cash and Cash Equivalents: The company considers highly liquid
collateralized debt instruments purchased with a maturity of three months or
less to be cash equivalents.
Available-for-sale Securities: The company classifies marketable equity
securities accounted for under the cost method as available-for-sale. These
securities are reported at fair value based on quoted market prices. Cumulative
unrealized gains and losses, net of the related tax effect, are reported as a
separate component of shareholders' equity until realized. Current changes in
unrealized gains and losses are reported as a component of other comprehensive
income.
<PAGE>
At December 31, 1998, an unrealized gain of $10 million (net of deferred
taxes of $12 million) was included in shareholders' equity. These securities
had a fair value of approximately $288 million and a cost of approximately $266
million at December 31, 1998. At December 31, 1997, an unrealized gain of $12
million (net of deferred taxes of $13 million) was included in shareholders'
equity. These securities had a fair value of approximately $75 million and a
cost of approximately $50 million at December 31, 1997.
Property, Plant and Equipment: Property, plant and equipment is stated
at cost. For utility 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 6.00% in 1998, 5.80% in 1997 and 5.70% in 1996.
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 value are charged to accumulated depreciation. Inventories
and supplies for the company's utility business are stated at average cost.
In accordance with regulatory decisions made by the Kansas Corporation
Commission (KCC), the acquisition premium of approximately $801 million
resulting from the acquisition of KGE in 1992 is being amortized over 40 years.
The acquisition premium is classified as electric plant in service.
Accumulated amortization as of December 31, 1998 and 1997 totaled $68.0
million and $47.9 million, respectively.
Depreciation: Utility plant is depreciated on the straight-line method
at rates approved by regulatory authorities. Utility plant is depreciated on an
average annual composite basis using group rates that approximated 2.88% during
1998, 2.89% during 1997 and 2.97% during 1996. Nonutility property, plant and
equipment of approximately $62 million at December 31, 1998 is depreciated on a
straight-line basis over the estimated useful lives of the related assets.
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, 1998 and 1997, was $39.5 million and $20.9 million,
respectively.
Customer Accounts: Customer accounts are stated at cost. The cost
includes amounts paid to dealers and the estimated fair value of accounts
acquired in business acquisitions. Internal costs incurred in support of
acquiring customer accounts are expensed as incurred.
The cost of customer accounts is amortized on a straight-line basis over
a 10-year period. It is Protection One's policy to evaluate acquired customer
account loss on a quarterly basis utilizing historical loss rates for the
customer accounts in total and, when necessary, adjust amortization over the
remaining useful life. The Securities and Exchange Commission (SEC) staff has
questioned the appropriateness of the current accounting method which Protection
One believes is consistent with industry practices. A significant change in the
amortization method would likely have a
<PAGE>
material effect on the company's results of operations. The accumulated
amortization of customer accounts as of December 31, 1998 and 1997 was
approximately $117 million and $29 million, respectively.
Goodwill: Goodwill, which represents the excess of the purchase price
over the fair value of net assets acquired, is generally amortized on a
straight-line basis over 40 years. The accumulated amortization of goodwill as
of December 31, 1998 and 1997 approximated $32 million and $9 million,
respectively.
Regulatory Assets and Liabilities: Regulatory assets represent probable
future revenue associated with certain costs that will be recovered from
customers through the ratemaking process. The company has recorded these
regulatory assets in accordance with SFAS 71. If the company were required to
terminate application of that statement for all of its regulated operations, the
company would have to record the amounts of all regulatory assets and
liabilities in its Consolidated Statements of Income at that time. The
company's earnings would be reduced by the total amount in the table below, net
of applicable income taxes. Regulatory assets reflected in the consolidated
financial statements are as follows:
December 31, 1998 1997
(Dollars in Thousands)
Recoverable taxes. . . . . . . . . . . . $205,416 $212,996
Debt issuance costs. . . . . . . . . . . 73,635 75,336
Deferred employee benefit costs. . . . . 36,128 37,875
Deferred plant costs . . . . . . . . . . 30,657 30,979
Coal contract settlement costs . . . . . 12,259 16,032
Other regulatory assets, . . . . . . . . 6,118 7,203
Total regulatory assets . . . . . . . . $364,213 $380,421
Recoverable income taxes: Recoverable income taxes represent amounts due
from customers for accelerated tax benefits which have been previously
flowed through to customers and are expected to be recovered in the
future as the accelerated tax benefits reverse.
Debt issuance costs: Debt reacquisition expenses are amortized over the
remaining term of the reacquired debt or, if refinanced, the term of the
new debt. Debt issuance costs are amortized over the term of the
associated debt.
Deferred employee benefit costs: Deferred employee benefit costs
are expected to be recovered from income generated through the company's
Affordable Housing Tax Credit investment program.
Deferred plant costs: Disallowances related to the Wolf Creek nuclear
generating facility.
Coal contract settlement costs: The company deferred costs associated
with the termination of certain coal purchase contracts. These costs
are being amortized over periods ending in 2002 and 2013.
<PAGE>
The company expects to recover all of the above regulatory assets in
rates. A return is allowed on deferred plant costs and coal contract settlement
costs and approximately $53 million of debt issuance costs.
Minority Interests: Minority interests represent the minority
shareholders' proportionate share of the shareholders' equity and net income of
Protection One.
Sales: Energy sales are recognized as services are rendered and include
estimated amounts for energy delivered but unbilled at the end of each year.
Unbilled sales of $39 million and $37 million are recorded as a component of
accounts receivable (net) on the Consolidated Balance Sheets at December 31,
1998 and 1997, respectively. Security sales are recognized when installation of
an alarm system occurs and when monitoring or other security-related services
are provided.
The company's allowance for doubtful accounts receivable totaled $29.5
million and $8.4 million at December 31, 1998 and 1997, respectively.
Income Taxes: Deferred tax assets and liabilities are recognized for
temporary differences in amounts recorded for financial reporting purposes and
their respective tax bases. Investment tax credits previously deferred are
being amortized to income over the life of the property which gave rise to the
credits.
Affordable Housing Tax Credit Program (AHTC): The company has received
authorization from the KCC to invest up to $114 million in AHTC investments. At
December 31, 1998 and 1997, the company had invested approximately $65 million
and $17 million to purchase AHTC investments in limited partnerships. The
company is committed to investing approximately $25 million more in AHTC
investments by April 1, 2001. These investments are accounted for using the
equity method. Based upon an order received from the KCC, income generated from
the AHTC investments, primarily tax credits, will be used to offset costs
associated with postretirement and postemployment benefits offered to the
company's employees.
Risk Management: The company is involved in trading activities primarily
to minimize risk from market fluctuations, maintain a market presence and to
enhance system reliability. In these activities, the company utilizes a variety
of financial instruments, including forward contracts involving cash settlements
or physical delivery of an energy commodity, options, swaps which require
payments (or receipt of payments) from counterparties based on the differential
between specified prices for the related commodity and futures traded on
electricity and natural gas. For the company's trading operation, the company
accounts for these transactions at the time of delivery or settlement, accruing
in the interim only for net losses as they become evident on firm purchase
commitments.
Cash Surrender Value of Life Insurance: The following amounts related to
corporate-owned life insurance policies (COLI) are recorded in other long-term
assets on the Consolidated Balance Sheets at December 31:
<PAGE>
1998 1997
(Dollars in Millions)
Cash surrender value of policies. . . . $587.5 $547.7
Borrowings against policies . . . . . . (558.5) (524.3)
COLI (net). . . . . . . . . . . . . . . $ 29.0 $ 23.4
Income is recorded for increases in cash surrender value and net death
proceeds for approximately 83% of the cash surrender value and 85% of the policy
borrowings at December 31, 1998. Interest incurred on amounts borrowed is
offset against policy income. Income recognized from death proceeds is highly
variable from period to period. Death benefits recognized as other income
approximated $13.7 million in 1998, $0.6 in 1997 and $5.5 in 1996. The balance
of the policies were acquired to mitigate the cost of postretirement and
postemployment benefits, in accordance with an order from the KCC.
New Pronouncements: Effective January 1, 1998, the company adopted the
provisions of Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" (SFAS 130). This statement establishes standards for
reporting and display of comprehensive income and its components.
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). This statement establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting and is effective for
fiscal years beginning after June 15, 1999. SFAS 133 cannot be applied
retroactively. SFAS 133 must be applied to (a) derivative instruments and
(b) certain derivative instruments embedded in hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1997 and, at the
company's election, before January 1, 1998. The company will adopt SFAS 133
no later than January 1, 2000. Management is presently evaluating the impact
that adoption of SFAS 133 will have on the company's financial position and
results of operations. Adoption of SFAS 133, however, could increase volatility
in earnings and other comprehensive income.
In December 1998, the Emerging Issues Task Force reached consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF Issue 98-10). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires
energy trading contracts to be recorded at fair value on the balance sheet, with
the changes in the fair value included in earnings. The company will adopt EITF
Issue 98-10 during 1999. Management does not expect the impact of adopting EITF
Issue 98-10 to be material to the company's financial position or results of
operations.
<PAGE>
Reclassifications: Certain amounts in prior years have been
reclassified to conform with classifications used in the current year
presentation.
2. RESTATEMENT OF 1997 FINANCIAL STATEMENTS
As a result of a decision by Protection One, an 85 percent owned
subsidiary, to restate its 1997 financial statements, the company has chosen to
restate its 1997 financial statements to conform to the changes adopted by
Protection One. This restatement resulted from decisions by Protection One:
- To expense as incurred, yard signs, including those which were removed
and replaced, following the decision to transition all monitored
services operations to the Protection One brand in the fourth quarter
of 1997. The costs of this yard sign change-out had previously been
estimated and accrued at December 31, 1997. This adjustment increased
previously reported net income by approximately $5.7 million and
decreased current liabilities by $12.3 million at December 31, 1997.
- To adjust certain purchase price allocations, reverse amounts which
had previously been accrued to transition new customers and adjust an
obligation to repurchase certain customer accounts sold under a
financing agreement to estimated fair value. These adjustments
reduced net income by approximately $0.3 million and reduced current
liabilities by approximately $22.2 million at December 31, 1997.
The total effect of the 1997 restatement was to increase previously
reported net income in 1997 by approximately $5.4 million ($0.08 per common
share) and increase previously reported retained earnings at December 31, 1997,
by the same amount. The restatement did not impact previously reported sales
and does not impact the company's net cash flow. (See Note 22 for the impact of
the restatement on quarterly results for 1998).
3. LEGAL PROCEEDINGS
On January 8, 1997, Innovative Business Systems, Ltd. (IBS) filed suit
against the company and Westinghouse Electric Corporation (WEC), Westinghouse
Security Systems, Inc. (WSS) and WestSec, Inc. (WestSec), a wholly-owned
subsidiary of the company established to acquire the assets of WSS, in Dallas
County, Texas district court (Cause No 97-00184) alleging, among other things,
breach of contract by WEC and interference with contract against the company in
connection with the sale by WEC of the assets of WSS to the company. On November
9, 1998, WEC settled this matter and the litigation was dismissed.
The SEC has commenced a private investigation relating, among other
things, to the timeliness and adequacy of disclosure filings with the SEC by
the company with respect to securities of ADT Ltd. The company is cooperating
with the SEC staff relating to the investigation.
<PAGE>
The company understands that class action lawsuits relating to the
Protection One restatement of 1997 and 1998 financial statements and subsequent
decrease in stock price were recently filed naming Protection One, Western
Resources and certain officers of Protection One. The company has not yet been
served with a copy of the lawsuits. The company cannot predict the outcome or
the effect of this litigation.
The company and its subsidiaries are involved in various other legal,
environmental and regulatory proceedings. Management believes that adequate
provision has been made and accordingly believes that the ultimate dispositions
of these matters will not have a material adverse effect upon the company's
overall financial position or results of operations.
4. MONITORED SERVICES BUSINESS
During 1998, the company continued its growth in the monitored services
business through its ownership in Protection One. Protection One experienced
rapid growth in its customer base as a result of several significant
acquisitions. The more significant acquisitions were Protection One's purchase
of the assets of Multimedia Security Services for approximately $233 million
and its purchase of the stock of Compagnie Europeenne de Telesecurite for
approximately $140 million. Each acquisition was accounted for as a purchase
and, accordingly, the operating results for each acquired company have been
included in the company's consolidated financial statements since the date of
acquisition. Total purchase consideration has been allocated to the net assets
acquired based on estimates of fair value. Protection One's purchase price
allocations for 1998 acquisitions are preliminary and may be adjusted as
additional information is obtained. During the first quarter of 1998, the
company transferred its investment in Network Multi-Family to Protection One at
a cost that approximated $180 million.
Consideration paid, assets acquired and liabilities assumed in
connection with these and other acquisitions made by Protection One during 1998
were as follows:
(Dollars in Thousands)
Fair value of assets acquired,
net of cash acquired . . . . . . $820,251
Cash paid, net of cash acquired. . 549,196
Total liabilities assumed. . . . . $271,055
The following table presents the unaudited pro forma financial
information considering Protection One's monitored services acquisitions in 1998
and 1997. The pro forma information reflects the actual operating results of
each company prior to its acquisition and includes adjustments to interest
expense, intangible amortization, and income taxes. The table assumes
acquisitions in 1998 occurred as of January 1, 1997. The 1997 acquisitions are
assumed to have occurred on January 1, 1996.
<PAGE>
Year Ended December 31, 1998 1997 1996
(Dollars in Thousands, Except Per Share Data)
(Unaudited)
Sales . . . . . . . . . . . $2,175,089 $2,462,849 $2,280,122
Earnings available for
common stock . . . . . . . 33,556 463,264 133,581
Earnings per share . . . . . $0.51 $7.11 $2.09
The unaudited pro forma financial information is not necessarily
indicative of the results of operations had the entities been combined for the
entire period nor do they purport to be indicative of results which will be
obtained in the future.
In October 1998, Protection One announced an agreement to acquire
Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal
emergency response and support services in North America. Based on the average
closing price for the three trading days prior to April 8, 1999, the value of
the consideration to be paid under the merger agreement is approximately $129.2
million or $22.05 per Lifeline share in cash and stock. Lifeline has advised
Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
In December 1997, Protection One incurred charges of approximately $24
million to recognize higher than expected customer attrition and record costs
related to the acquisition of Protection One. These charges are as follows:
Impairment of customer accounts $12,750
Protection One merger related costs:
Inventory and other asset losses 3,558
Disposition of fixed assets 4,128
Closure of duplicate facilities 1,991
Severance compensation and benefits 1,865
11,542
Total charges $24,292
Impairment of customer accounts: Protection One wrote down the value of
the customer base of part of its business due to excess customer losses
experienced in 1997. The excess customer losses were due to (1) the effects of
transitioning the customer base from one service provider to another and, (2)
the relative quality of certain classes of customer accounts acquired in an
acquisition due to use of a prior aggressive marketing plan accompanied by
limited credit checking.
Inventory and other asset losses: Protection One reduced the value of
inventory held at branches due to conversion to the external Dealer Program as
its primary marketing channel.
Disposition of fixed assets: Protection One reduced the net book value
of computer and telecommunication equipment due to plans to migrate certain
monitoring, customer service and financial operations to new software and
hardware platforms in the
<PAGE>
first quarter of 1998. At December 31, 1998, Protection One continued to use
certain components of this equipment due to unplanned delays experienced in the
implementation of replacement systems. The remaining equipment is expected to
be fully retired in 1999.
Closure of duplicate facilities: Protection One committed to a plan to
close 38 branch locations in cities with two or more branches and where the
customer base did not justify such a large presence. At December 31, 1998, all
such locations were closed. The remaining amount accrued at December 31, 1998,
represents obligations for vacated lease facilities and approximates $1 million.
Severance compensation and benefits: Upon the company's purchase of
approximately 82.4% of Protection One in November 1997, the affected employees
were notified of their severance package. Actual payments approximated the
amount accrued.
Protection One recognized a non-recurring gain in 1998 when customer
accounts were repurchased pursuant to a financing agreement. Terms of the
agreement required Protection One to purchase these accounts at fair value.
The purchase price negotiated was less than the estimated value. As a result, a
non-recurring gain which approximated $16 million was recorded as other income.
5. RATE MATTERS AND REGULATION
KCC Rate Proceedings: In January 1997, the KCC entered an order reducing
electric rates for both KPL and KGE. Significant terms of the order are as
follows:
- The company made permanent an interim $8.7 million rate reduction
implemented by KGE in May 1996. This reduction was effective
February 1, 1997.
- The company reduced KGE's annual rates by $36 million effective
February 1, 1997.
- The company reduced KPL's annual rates by $10 million effective
February 1, 1997.
- The company rebated $5 million to all of its electric customers in
January 1998.
- The company reduced KGE's annual rates by an additional $10 million
on June 1, 1998.
- The company rebated an additional $5 million to all of its electric
customers in January 1999.
- The company will reduce KGE's annual rates by an additional $10 million
on June 1, 1999.
All rate decreases are cumulative. Rebates are one-time events and do
not influence future rates.
<PAGE>
6. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK, AND OTHER MANDATORILY
REDEEMABLE SECURITIES
The company's Restated Articles of Incorporation, as amended, provide
for 85,000,000 authorized shares of common stock. At December 31, 1998,
65,909,442 shares were outstanding.
The company has a Direct Stock Purchase Plan (DSPP). Shares issued
under the DSPP may be either original issue shares or shares purchased on the
open market. The company issued original issue shares under DSPP from January
1, 1995 until October 15, 1997. Between November 1, 1997 and March 16, 1998,
shares for DSPP were satisfied on the open market. All other shares have been
original issue shares. During 1998, a total of 653,570 shares were issued under
DSPP including 499,839 original issue shares and 153,731 shares purchased on
the open market. At December 31, 1998, 591,047 shares were available under
the DSPP registration statement.
Preferred Stock 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.
Preference Stock Subject to Mandatory Redemption: On April 1, 1998, the
company redeemed the 7.58% Preference Stock due 2007 at a premium, including
dividends, for $53 million.
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. These distributions are recorded as interest
expense. 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.
On July 31, 1996, Western Resources Capital II, a wholly-owned trust, of
which the sole asset is subordinated debentures of the company, sold in a public
offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income Preferred
Securities, Series B, for $120 million. The trust interests represented by the
preferred securities are redeemable at the option of Western Resources Capital
II, on or after July 31, 2001, at $25 per preferred security plus accumulated
and unpaid distributions. Holders of the securities are entitled to receive
distributions at an annual rate of 8-1/2% of the liquidation preference value
of $25. Distributions are payable quarterly and in substance are tax deductible
by the company. These distributions are recorded as interest expense. The sole
asset of the trust is $124 million principal amount of 8-1/2% Deferrable
Interest Subordinated Debentures, Series B due July 31, 2036.
In addition to the company's obligations under the Subordinated
Debentures discussed above, the company has agreed to guarantee, on a
subordinated basis, payment
<PAGE>
of distributions on the preferred securities. These undertakings constitute a
full and unconditional guarantee by the company of the trust's obligations under
the preferred securities.
7. LONG-TERM DEBT
The amount of the company's first mortgage bonds authorized by its
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. During the years 1999 through 2003, $125 million of bonds will
mature in 1999, $75 million of bonds will mature in 2000, $100 million of bonds
will mature in 2002 and $135 million of bonds will mature in 2003. No other
bonds will mature during this time period.
The company's unsecured debt represents general obligations that are not
secured by any of the company's properties or assets. Any unsecured debt will
be subordinated to all secured debt of the company, including it's first
mortgage bonds. The notes are structurally subordinated to all secured and
unsecured debt of the company's subsidiaries.
Long-term debt outstanding is as follows at December 31:
1998 1997
(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 58,420
133,920 133,920
KGE
First mortgage bond series:
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
300,000 300,000
<PAGE>
Pollution control bond series:
5.10% due 2023 . . . . . . . . . . . . . 13,673 13,757
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
387,613 387,697
Western Resources
6 7/8% unsecured senior notes due 2004 . 370,000 370,000
7 1/8% unsecured senior notes due 2009 . 150,000 150,000
6.80% unsecured senior notes due 2018. . 29,985 -
6.25% unsecured senior notes due 2018,
putable/callable 2003. . . . . . . . . 400,000 -
949,985 520,000
Protection One
Revolving credit facility. . . . . . . . 42,417 -
6.75% unsecured convertible senior
subordinated discount notes due 2003 . 53,950 102,500
13.625% unsecured senior
subordinated discount notes due 2005 . 125,590 171,926
7.375% unsecured senior notes due 2005 . 250,000 -
8.125% unsecured senior
subordinated notes due 2009. . . . . . 350,000 -
Customer repurchase agreement,
due 1998 . . . . . . . . . . . . . . . - 69,129
Recourse financing agreements (6). . . . 93,541 -
Other. . . . . . . . . . . . . . . . . . 2,574 -
918,072 343,555
Other long-term agreements . . . . . . . . 8,325 4,798
Unamortized debt premium . . . . . . . . . 13,918 -
Less:
Unamortized debt discount . . . . . . . . (7,931) (5,719)
Long-term debt due within one year . . . . (165,838) (21,217)
Long-term debt (net) . . . . . . . . . . . $3,063,064 $2,188,034
Rates at December 31, 1998: (1) 3.55%, (2) 3.45%, (3) 3.50%, (4) 3.75%
(5) 3.75% and (6) 15% implicit rate for operating lease agreements sold with
recourse - average term approximately 4 years.
Protection One maintains a $500 million revolving credit facility that
expires in December 2001. Under the terms of this agreement, Protection One
may, at its option, borrow at different market-based interest rates. At
December 31, 1998, $42.4 million was borrowed under this facility.
The senior subordinated discount notes of Protection One contain
covenants which, among other matters, limit Protection One's ability to incur
certain indebtedness, make restricted payments and merge, consolidate or sell
assets.
<PAGE>
The convertible senior subordinated notes of Protection One are
convertible at any time into common stock at a price of $11.19 per share. The
indenture under which these notes were issued contains covenants which limit
Protection One's ability to incur certain indebtedness.
Among other restrictions, Protection One is required under the revolving
credit facility to maintain a ratio of earnings before interest, taxes,
depreciation and amortization (EBITDA) to interest expense of not less than 2.75
to one and total debt cannot be greater than 5 times annualized most recent
quarter EBITDA for 1999 and 4.5 times thereafter. In addition, in light of the
restatement of its financial statements, Protection One has obtained a bank
waiver for prior representations concerning its financial statements.
8. STRATEGIC ALLIANCE WITH ONEOK, INC.
In November 1997, the company completed its strategic alliance with
ONEOK. The company contributed substantially all of its regulated and
non-regulated natural gas business to ONEOK in exchange for a 45% ownership
interest in ONEOK.
The company's ownership interest in ONEOK is comprised of approximately
3.2 million common shares and approximately 20.1 million convertible preferred
shares. If all the preferred shares were converted, the company would own
approximately 45% of ONEOK's common shares presently outstanding. The agreement
with ONEOK allows the company to appoint two members to ONEOK's board of
directors. The company accounts for its common ownership in accordance with the
equity method of accounting. Subsequent to the formation of the strategic
alliance, the consolidated energy revenues, related cost of sales and operating
expenses for the company's natural gas business have been replaced by investment
earnings in ONEOK.
9. SHORT-TERM DEBT
The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling approximately $821
million. The agreements provide the company with the ability to borrow at
different market-based interest rates. The company pays commitment or facility
fees in support of these lines of credit. Under the terms of the agreements,
the company is required, among other restrictions, to maintain a total debt to
total capitalization ratio of not greater than 65% at all times. The unused
portion of these lines of credit are used to provide support for commercial
paper.
In addition, the company has agreements with several banks to borrow on
an uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these agreements. The company also
uses commercial paper to fund its short-term borrowing requirements.
<PAGE>
Information regarding the company's short-term borrowings, comprised of
borrowings under the credit agreements, bank loans and commercial paper, is as
follows:
December 31, 1998 1997
(Dollars in Thousands)
Borrowings outstanding at year end:
Bank loans. . . . . . . . . . . . $164,700 $161,000
Commercial paper notes. . . . . . 147,772 75,500
Total . . . . . . . . . . . . . $312,472 $236,500
Weighted average interest rate on
debt outstanding at year end
(including fees). . . . . . . . . 5.94% 6.28%
Weighted average short-term debt
outstanding during the year . . . $529,255 $787,507
Weighted daily average interest
rates during the year
(including fees). . . . . . . . . 5.93% 5.93%
Unused lines of credit supporting
commercial paper notes. . . . . . $820,900 $772,850
10. 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 $86.9 million at December 31, 1998.
Affordable Housing Tax Credit Program: At December 31, 1998, the
company had invested approximately $65 million to purchase AHTC investments in
limited partnerships. The company is committed to investing approximately $25
million more in AHTC investments by April 1, 2001.
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. At December 31, 1998, the costs
incurred for preliminary site investigation and risk assessment have been
minimal. In accordance with the terms of the strategic alliance with ONEOK,
ownership of twelve of these sites and the responsibility for clean-up of these
sites were transferred to ONEOK. The ONEOK agreement limits the company's
future liability associated with these sites to an immaterial amount. The
company's investment earnings from ONEOK could be impacted by these costs.
<PAGE>
Clean Air Act: The company must comply with the provisions of The Clean
Air Act Amendments of 1990 that require a two-phase reduction in certain
emissions. The company has installed continuous monitoring and reporting
equipment to meet the acid rain requirements. The company does not expect
material capital expenditures to be required to meet Phase II sulfur dioxide and
nitrogen oxide requirements.
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.
In February 1997, the KCC approved the 1996 Decommissioning Cost Study.
Based on the study, the company's share of Wolf Creek's decommissioning costs,
under the immediate dismantlement method, is estimated to be approximately $624
million during the period 2025 through 2033, or approximately $192 million in
1996 dollars. These costs were calculated using an assumed inflation rate of
3.6% over the remaining service life from 1996 of 29 years.
Decommissioning costs are currently being charged to operating expense
in accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf Creek.
Amounts expensed approximated $3.8 million in 1998 and will increase annually to
$5.6 million in 2024. These amounts are deposited in an external trust fund.
The average after-tax expected return on trust assets is 5.7%.
The company's investment in the decommissioning fund, including
reinvested earnings approximated $52.1 million and $43.5 million at December 31,
1998 and 1997, respectively. Trust fund earnings accumulate in the fund
balance and increase the recorded decommissioning liability.
The Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:
- The company's annual decommissioning expense could be higher
than in 1998
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment
in the Wolf Creek plant
The company does not believe that such changes, if required, would
adversely affect its operating results due to its current ability to recover
decommissioning costs through rates.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.7 billion for a single
nuclear incident. If this liability limitation is insufficient, the U.S.
Congress will consider taking
<PAGE>
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. The remaining balance is provided by an assessment
plan mandated by the Nuclear Regulatory Commission (NRC). Under this plan, the
Owners are jointly and severally subject to a retrospective assessment of up to
$88.1 million ($41.4 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
Nuclear Electric Insurance Limited (NEIL). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination in accordance with a plan by the NRC. The company's share of
any remaining proceeds can be used for property damage. If an accident at Wolf
Creek exceeds $500 million in property damage and decontamination expenses and
the decision is made to decommission the plant, the company's share of any
remaining proceeds can be used to make up a shortfall in the decommissioning
trust fund.
The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If 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 $7 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, 1998, Wolf Creek's
nuclear fuel commitments (company's share) were approximately $6.1 million for
uranium concentrates expiring at various times through 2001, $24.9 million for
enrichment expiring at various times through 2003 and $60.1 million for
fabrication through 2025.
At December 31, 1998, the company's coal contract commitments in 1998
dollars under the remaining terms of the contracts were approximately $2.3
billion. The largest coal contract expires in 2020, with the remaining coal
contracts expiring at various times through 2013.
<PAGE>
At December 31, 1998, the company's natural gas transportation
commitments in 1998 dollars under the remaining terms of the contracts was
approximately $30.3 million. The natural gas transportation contracts provide
firm service to the company's gas burning facilities expiring at various times
through 2010.
11. INTERNATIONAL POWER DEVELOPMENT ACTIVITIES
During the fourth quarter of 1998, management decided to exit the
international power development business. This business had been conducted by
the company's wholly owned subsidiary, The Wing Group (Wing). The company
acquired Wing in February 1996 in an acquisition accounted for as a purchase.
Wing's principal office was located near Houston, Texas and power development
activities were primarily conducted in emerging markets. The company has
acquired a 50% interest in a joint venture which has a 49% interest in four 55
MW generating facilities in the People's Republic of China. The company also
owns a 37.5% interest in a 160 MW merchant generating facility in Colombia, and
a 9% interest in a 478 MW power generating facility in the Republic of Turkey.
Unfavorable economic, political and regulatory developments in certain
emerging markets where development efforts were focused required management to
reexamine this business. In exiting this business, management has decided to
discontinue existing development efforts and cease future development activity.
The company had been spending approximately $10 million annually to fund
development efforts.
The company was required to record a charge to income as a result of
exiting this business. The charge to earnings has been presented as a separate
line item as a component of operating expenses in the accompanying Consolidated
Statements of Income. The detailed components of this charge are as follows:
(Dollars in Thousands)
Write-down equity investments to fair
market value . . . . . . . . . . . . . . . $57,030
Accrued exit fees, shut-down and
severance costs. . . . . . . . . . . . . . 22,900
Deferred development costs associated
with projects to be abandoned. . . . . . . 6,735
Unamortized goodwill associated with the
acquisition of Wing. . . . . . . . . . . . 12,251
Total charge. . . . . . . . . . . . . . $98,916
Overall negative economic, competitive and political factors, together
with currently anticipated cash flows, have reduced the value of certain equity
investments presently held. The decline in value of these investments required
management to write down the investments to fair market value. Management
considers this decline in value to be other than temporary. In assessing the
value, management talked to others with investment experience in emerging
markets and applied a discounted cash flow analysis to estimate fair market
value.
<PAGE>
In accordance with the exit plan, the company will discontinue all
development activity on February 1, 1999 and close all Wing offices. The
employees of Wing were notified prior to December 31, 1998, of their termination
effective February 1, 1999. Severance costs have been accrued for the
approximately 30 affected employees. The company's exit plan calls for all
significant aspects of the closure to be completed during 1999.
12. UNCONSOLIDATED SUBSIDIARIES
The company's investments in unconsolidated subsidiaries which are
accounted for by the equity method are as follows:
<TABLE>
<CAPTION>
Equity Earnings,
Ownership at Investment at Year Ended
December 31, December 31, December 31
1998 1998 1997 1998 1997
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
ONEOK, Inc. (1). . . . . . 45% $615,094 $596,206 $6,064 $1,970
Affordable Housing Tax
Credit limited
partnerships (2). . . . . 5% to 30% 89,618 51,571 - -
International companies
and joint ventures (3). . 37% to 50% 10,500 16,299 - -
Other. . . . . . . . . . . 32% - 3,312 (672) -
(1) The company also received approximately $40 million of preferred and common dividends
in 1998. Refer to Note 8 for further information regarding the company's strategic
alliance with ONEOK.
(2) Investment is aggregated. Individual investments are not significant. Based on an
order received by the KCC, equity earnings from these investments are used to offset
costs associated with postretirement and postemployment benefits offered to the
company's employees.
(3) Investment is aggregated. Individual investments are not significant. During 1998,
the company recognized a non-temporary decline in value of its foreign equity investments
as discussed in Note 11.
</TABLE>
The following summarized financial information for the company's
investment in ONEOK is presented as of and for the period ended November 30,
1998 and 1997, the most recent period for which public information is available.
November 30, 1998 1997
(Dollars in Thousands)
Balance Sheet:
Current assets . . . . . $ 404,358 $ 532,681
Non-current assets . . . 2,091,797 1,761,561
Current liabilities. . . 338,466 443,080
Non-current liabilities. 993,668 729,920
Equity . . . . . . . . . 1,164,021 1,121,242
<PAGE>
Year Ended November 30, 1998 1997
(Dollars in Thousands)
Income Statement:
Revenues . . . . . . . . $1,908,713 $1,227,335
Operating expenses . . . 1,767,286 1,134,024
Net income . . . . . . . 103,525 59,614
13. EMPLOYEE BENEFIT PLANS
Pension: The company maintains qualified noncontributory defined
benefit pension plans covering substantially all utility employees. Pension
benefits are based on years of service and the employee's compensation during
the five highest paid consecutive years out of ten before retirement. The
company's policy is to fund pension costs accrued, subject to limitations set by
the Employee Retirement Income Security Act of 1974 and the Internal Revenue
Code. The company also maintains a non-qualified Executive Salary Continuation
Program for the benefit of certain management employees, including executive
officers.
Postretirement Benefits: The company accrues the cost of postretirement
benefits, primarily medical benefit costs, during the years an employee provides
service.
The following tables summarize the status of the company's pension and
other postretirement benefit plans:
<TABLE>
<CAPTION>
Pension Benefits Postretirement Benefits
December 31, 1998 1997 1998 1997
(Dollars in Thousands)
<S> <C> <C> <C> <C>
Change in Benefit Obligation:
Benefit obligation, beginning of year. $462,964 $483,862 $ 83,673 $122,993
Service cost . . . . . . . . . . . . . 7,952 11,337 1,405 2,102
Interest cost. . . . . . . . . . . . . 31,278 35,836 5,763 9,098
Plan participants' contributions . . . - - 858 1,122
Benefits paid. . . . . . . . . . . . . (24,682) (27,764) (5,630) (10,167)
Assumption changes . . . . . . . . . . 36,268 (19,184) 6,801 -
Actuarial losses (gains) . . . . . . . 10,095 (1,532) (5,351) 4,421
Plan amendments. . . . . . . . . . . . - 6,866 - -
Curtailments, settlements and special
term benefits (1) . . . . . . . . . . (131,818) (26,457) - (45,896)
Benefit obligation, end of year. . . . $392,057 $462,964 $ 87,519 $ 83,673
Change in Plan Assets:
Fair value of plan assets,
beginning of year . . . . . . . . . . $584,792 $496,206 $ 118 $ 78
Actual return on plan assets . . . . . 66,106 113,235 6 3
Employer contribution. . . . . . . . . 2,197 2,220 5,679 10,204
Plan participants' contributions . . . - - - -
Benefits paid. . . . . . . . . . . . . (23,910) (26,869) (5,630) (10,167)
Settlements (1). . . . . . . . . . . . (187,654) - - -
Fair value of plan assets,
end of year . . . . . . . . . . . . . $441,531 $584,792 $ 173 $ 118
<PAGE>
Funded status. . . . . . . . . . . . . $ 49,474 $121,828 $(87,346) $(83,555)
Unrecognized net (gain)/loss . . . . . (104,023) (193,313) 1,814 (828)
Unrecognized transition
obligation, net . . . . . . . . . . 244 (369) 56,159 60,146
Unrecognized prior service cost. . . . 36,309 39,763 (4,131) (4,592)
Accrued postretirement benefit costs . $(17,996) $(32,091) $(33,504) $(28,829)
Actuarial Assumptions:
Discount rate. . . . . . . . . . . . . 6.75% 7.5% 6.75% 7.5%
Expected rate of return. . . . . . . . 9.0% 9.0% 9.0% 9.0%
Compensation increase rate . . . . . . 4.75% 4.75% 4.75% 4.75%
Components of net periodic benefit cost:
Service cost . . . . . . . . . . . . . $ 7,952 $ 11,337 $ 1,405 $ 2,102
Interest cost. . . . . . . . . . . . . 31,278 35,836 5,763 9,098
Expected return on plan assets . . . . (39,069) (39,556) (11) (4)
Amortization of unrecognized
transition obligation, net. . . . . . (32) (79) 3,988 6,202
Amortization of unrecognized prior
service costs . . . . . . . . . . . . 3,455 4,918 (461) (720)
Amortization of (gain)/loss, net . . . (5,885) (3,755) (396) (107)
Other. . . . . . . . . . . . . . . . . - 519 - -
Net periodic benefit cost. . . . . . . $ (2,301) $ 9,220 $ 10,288 $ 16,571
(1) The pension and postretirement benefit plans recorded a curtailment expense due to the
significant reduction in future years of service due to the transfer of employees to
ONEOK in November 1997. In July 1998, pension plan assets were transferred to ONEOK
resulting in a settlement loss.
</TABLE>
For measurement purposes, an annual health care cost growth rate of 8%
was assumed for 1998, decreasing 1% per year to 5% in 2001 and thereafter. The
health care cost trend rate has a significant effect on the projected benefit
obligation. Increasing the trend rate by 1% each year would increase the
present value of the accumulated projected benefit obligation by $2.1 million
and the aggregate of the service and interest cost components by $0.2 million.
In accordance with an order from the KCC, the company has deferred
postretirement and postemployment expenses in excess of actual costs paid. In
1997, the company received authorization from the KCC to invest in AHTC
investments. Income from the AHTC investments will be used to offset the
deferred and incremental costs associated with postretirement and postemployment
benefits offered to the company's employees. The income generated from the AHTC
investments replaces the income stream from corporate-owned life insurance
contracts purchased in 1993 and 1992 which was used for the same purpose.
Savings: The company maintains savings plans in which substantially all
employees participate, with the exception of Protection One employees. 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 $3.8 million, $5.0 million and $4.6 million for
1998, 1997 and 1996, respectively.
Protection One also maintains a savings plan. Contributions, made at
Protection One's election, are allocated among participants based upon the
respective contributions made by the participants through salary reductions
during the year. Protection One's matching contributions may be made in
Protection One common stock, in
<PAGE>
cash or in a combination of both stock and cash. Protection One's matching
contribution to the plan for 1998 and 1997 was $992,000 and $34,000,
respectively.
Protection One maintains a qualified employee stock purchase plan that
allows eligible employees to acquire shares of Protection One common shares at
85% of fair market value of the common stock. A total of 650,000 shares of
common stock have been reserved for issuance in this program.
Stock Based Compensation Plans: The company, excluding Protection One,
has a long-term incentive and share award plan (LTISA Plan), which is a
stock-based compensation plan. The LTISA Plan was implemented to help ensure
that key employees and board members (Plan Participants) were properly incented
to increase shareholder value. Under the LTISA Plan, the company may grant
awards in the form of stock options, dividend equivalents, share appreciation
rights, restricted shares, restricted share units, performance shares and
performance share units to Plan Participants. Up to three million shares of
common stock may be granted under the LTISA Plan.
Stock options and restricted shares under the LTISA plan are as follows:
<TABLE>
<CAPTION>
December 31, 1998 1997 1996
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding, beginning of year 665,400 $30.282 205,700 $29.250 - $ -
Granted. . . . . . . . . . . . 925,300 40.293 459,700 30.750 205,700 29.250
Exercised. . . . . . . . . . . - - - - - -
Forfeited. . . . . . . . . . . - - - - - -
Outstanding, end of year . . . 1,590,700 $36.106 665,400 $30.282 205,700 $29.250
Weighted-average fair value
of options granted during
the year . . . . . . . . . . $6.55 $3.00 $3.26
</TABLE>
Stock options and restricted shares issued and outstanding at December
31, 1998, are as follows:
<TABLE>
<CAPTION>
Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Contractual Exercise
Price Outstanding Life in Years Price
<S> <C> <C> <C> <C>
Options:
1998. . . . . . . . . . $38.625-43.125 788,800 10.0 $40.581
1997. . . . . . . . . . 30.750 459,700 9.0 30.750
1996. . . . . . . . . . 29.250 205,700 7.7 29.250
1,454,200
Restricted shares:
1998. . . . . . . . . . 38.625 136,500 4.0 38.625
Total issued. . . . . 1,590,700
</TABLE>
An equal amount of dividend equivalents is issued to recipients of stock
options. The weighted-average grant-date fair value of the dividend equivalent
was $6.88 and $6.21 in 1998 and 1997, respectively. The value of each dividend
equivalent is calculated as a percentage of the accumulated dividends that would
have been paid or payable on a share of company common stock. This percentage
ranges from zero to 100%, based upon certain company performance factors. The
dividend equivalents expire after
<PAGE>
nine years from date of grant.
The fair value of stock options and dividend equivalents were estimated
on the date of grant using the Black-Scholes option-pricing model. The model
assumed the following at December 31:
1998 1997
Dividend yield. . . . . . . . . . 6.16% 6.58%
Expected stock price volatility . 17.82% 13.56%
Risk-free interest rate:
Stock options . . . . . . . . . 4.87% 6.72%
Dividend equivalents (1). . . . 4.63% 6.36%
(1) Assuming an award percentage of 100% and dividend
accumulation period of five years.
Protection One Stock Warrants and Options: Protection One has
outstanding stock warrants and options which were considered reissued and
exercisable upon the company's acquisition of Protection One on November 24,
1997. The 1997 Long-Term Incentive Plan (the LTIP), approved by the Protection
One stockholders on November 24, 1997, provides for the award of incentive stock
options to directors, officers and key employees. Under the LTIP, 4.2 million
shares are reserved for issuance subject to such adjustment as may be necessary
to reflect changes in the number or kinds of shares of common stock or other
securities of Protection One. The LTIP provides for the granting of options
that qualify as incentive stock options under the Internal Revenue Code and
options that do not so qualify.
During 1998, Protection One granted options under the LTIP to purchase
an aggregate of 1,246,500 shares of common stock to employees, including 690,000
shares granted to officers of Protection One. Each option has a term of 10
years and vests 100% on the third anniversary of the option grant. The purchase
price of the shares issuable pursuant to the options is equal to (or greater
than) the fair market value of the common stock at the date of the option grant.
A summary of warrant and option activity for Protection One from the
date of the acquisition transaction is as follows:
December 31, 1998 1997
Weighted- Weighted-
Average Average
Exercise Exercise
Shares Price Shares Price
Outstanding, beginning of year(1) 2,366,435 $ 5.805 2,366,741 $5.805
Granted . . . . . . . . . . . . . 1,246,500 11.033 - -
Exercised (109,595) 5.564 (306) 0.050
Forfeited . . . . . . . . . . . . (117,438) 10.770 - -
Adjustment to May 1995 warrants . 36,837 - - -
Outstanding, end of year. . . . . 3,422,739 $ 7.494 2,366,435 $5.805
<PAGE>
(1) There was no outstanding stock or options prior to November 24, 1997.
Stock options and warrants issued and outstanding at December 31, 1998,
are as follows:
Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Remaining Life Exercise
Price Outstanding (Years) Price
Exercisable:
$ 6.375-$ 9.125 136,560 6 $ 6.588
8.000- 10.313 349,000 7 8.062
13.750- 15.500 142,000 7 14.883
9.500 217,000 8 9.500
15.000 50,000 8 15.000
14.268 50,000 3 14.268
3.633 103,697 2 3.633
0.167 428,400 5 0.167
3.890 786,277 6 3.890
0.050 305 8 0.050
2,263,239
Not Exercisable:
$11.033 1,120,500 9 $11.033
9.500- 12.500 39,000 9 11.942
1,159,500
Total outstanding 3,422,739
The company holds a call option for an additional 2,750,238 shares of
Protection One common stock, exercisable at a call price of $15.50 per share.
The option expires on the earlier of (i) 45 days following the last date on
which any Protection One convertible notes are still outstanding or (ii) October
31, 1999.
The weighted average fair value of options granted during 1998 and
estimated on the date of grant was $6.87. The fair value was calculated using
the following assumptions:
Year ended
December 31, 1998
Dividend yield. . . . . . . . . 0.00%
Expected stock price volatility 61.72%
Risk free interest rate . . . . 5.50%
Expected option life. . . . . . 6 years
The company accounts for both the company's and Protection One's plans
under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees," and the related interpretations. Had compensation expense been
determined pursuant to Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation," the company would have recognized
additional compensation costs during 1998, 1997 and 1996 as shown in the table
below.
<PAGE>
Year Ended December 31, 1998 1997 1996
(Dollars in Thousands, Except Per Share Amounts)
Earnings available for common stock:
As reported . . . . . . . . . . $44,165 $494,599 $154,111
Pro forma . . . . . . . . . . . 42,640 494,436 153,877
Earnings per common share
(basic and diluted):
As reported . . . . . . . . . . $0.67 $7.59 $2.41
Pro forma . . . . . . . . . . . 0.65 7.59 2.41
Split Dollar Life Insurance Program: The company has established a
split dollar life insurance program for the benefit of the company and certain
of its executives. Under the program, the company has purchased a life
insurance policy on the executive's life, and, upon the executive's death, the
executive's beneficiary is entitled to a death benefit in an amount equal to the
face amount of the policy reduced by the greater of (i) all premiums paid by
the company or (ii) the cash surrender value of the policy, which amount, at
the death of the executive, will be returned to the company. The company
retains an equity interest in the death benefit and cash surrender value of
the policy to secure this repayment obligation.
Subject to the conditions described below, beginning on the earlier of
(i) three years from the date of the policy or (ii) the first day of the next
calendar year following the date of the executive's retirement, the executive is
allowed to transfer to the company from time to time, in whole or in part, his
interest in the death benefit under the policy at a discount equal to $1 for
each $1.50 of the portion of the death benefit for which the executive officer
may designate the beneficiary, subject to adjustment based on the total return
to shareholders from the date of the policy unless the participant retires from
the company within six months of the date of the participant's agreement. Any
adjustment would result in an exchange of no more than one dollar for each
dollar of death benefit nor less than one dollar for each two dollars of death
benefit. The program has been designed such that upon the executive's death
the company will recover its premium payments from the policy and any amounts
paid by the company to the executive for the transfer of his interest in the
death benefit. The cash surrender value of these policies has been recorded in
other assets. The insurance premium and the estimated value of the executives'
agreements have been expensed. The company has accrued approximately $57
million at December 31, 1998 for this program. Under current tax rules,
payments to certain participants in exchange for their interest in the death
benefits may not be fully deductible by the company for income tax purposes.
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".
<PAGE>
Cash and cash equivalents, short-term borrowings and variable-rate debt
are carried at cost which approximates fair value. The decommissioning trust is
recorded at fair value and is based on the quoted market prices at December 31,
1998 and 1997. The fair value of fixed-rate debt, redeemable preference stock
and other mandatorily redeemable securities is estimated based on quoted market
prices for the same or similar issues or on the current rates offered for
instruments of the same remaining maturities and redemption provisions. The
estimated fair values of contracts related to commodities have been determined
using quoted market prices of the same or similar securities.
The recorded amounts of accounts receivable and other current financial
instruments approximate fair value.
The fair value estimates presented herein are based on information
available at December 31, 1998 and 1997. 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. Because a substantial portion of the
company's operations are regulated, the company believes that any gains or
losses related to the retirement of debt or redemption of preferred securities
would not have a material effect on the company's financial position or results
of operations.
The carrying values and estimated fair values of the company's financial
instruments are as follows:
Carrying Value Fair Value
December 31, 1998 1997 1998 1997
(Dollars in Thousands)
Decommissioning trust. . $ 52,093 $ 43,514 $ 52,093 $ 43,514
Fixed-rate debt, net of
current maturities . . 2,956,692 2,019,103 3,076,709 2,101,167
Redeemable preference
stock. . . . . . . . . - 50,000 - 51,750
Other mandatorily
redeemable securities. 220,000 220,000 226,800 226,088
In its commodity price risk management activities, the company engages
in both trading and non-trading activities. In these activities, the company
utilizes a variety of financial instruments, including forward contracts
involving cash settlements or physical delivery of an energy commodity, options,
swaps which require payments (or receipt of payments) from counterparties based
on the differential between specified prices for the related commodity, and
futures traded on electricity and natural gas. For a discussion of the
accounting policy for these instruments, see Note 1.
The company is involved in trading activities primarily to minimize risk
from market fluctuations, maintain a market presence and to enhance system
reliability. Although the company attempts to balance its physical and
financial purchase and sale
<PAGE>
contracts in terms of quantities and contract terms, net open positions can
exist or are established due to the origination of new transactions and the
company's assessment of, and response to, changing market conditions.
The company uses derivatives for non-trading purposes primarily to
reduce exposure relative to the volatility of cash market prices.
December 31, 1998 1997
(Dollars in Thousands)
Notional Notional
Volumes Estimated Volumes Estimated
(MWH's) Fair Value (MWH's) Fair Value
Forward contracts:
Purchased. . . . 1,535,600 $46,361 359,200 $8,604
Sold . . . . . . 1,535,600 46,141 359,200 8,806
Options:
Purchased. . . . 148,800 $ 361 803,200 $1,607
Sold . . . . . . 64,000 195 120,800 512
Forward contracts and options had a net unrealized gain of $40,000 at
December 31, 1998, and a net unrealized loss of $127,000 at December 31, 1997.
15. GAIN ON SALE OF EQUITY SECURITIES
During 1996, the company acquired 27% of the common shares of ADT
Limited, Inc. (ADT) and made an offer to acquire the remaining ADT common
shares. ADT rejected this offer and in July 1997, ADT merged with Tyco
International Ltd. (Tyco). ADT and Tyco completed their merger by exchanging
ADT common stock for Tyco common stock.
Following the ADT and Tyco merger, the company's equity investment in
ADT became an available-for-sale security. During the third quarter of 1997,
the company sold its Tyco common shares for approximately $1.5 billion. The
company recorded a pre-tax gain of $864 million on the sale and recorded tax
expense of approximately $345 million in connection with this gain.
<PAGE>
16. INCOME TAXES
Income tax expense is composed of the following components at
December 31:
1998 1997 1996
(Dollars in Thousands)
Currently payable:
Federal. . . . . . . . . . . $ 52,993 $336,150 $54,644
State. . . . . . . . . . . . 10,881 72,143 20,280
Deferred:
Federal. . . . . . . . . . . (39,067) (15,945) 14,808
State. . . . . . . . . . . . (4,185) (2,696) (615)
Amortization of investment
tax credits . . . . . . . . . (6,065) (6,665) (6,758)
Total income tax expense . . . $ 14,557 $382,987 $82,359
Under SFAS 109, temporary differences gave rise to deferred tax assets
and deferred tax liabilities as follows at December 31:
1998 1997
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . . . $ 92,427 $ 97,634
Monitored services deferred tax assets. . . . 132,802 98,712
Other. . . . . . . . . . . . . . . . . . . . 138,506 94,008
Total deferred tax assets. . . . . . . . . $ 363,735 $ 290,354
Deferred tax liabilities:
Accelerated depreciation and other . . . . . $ 615,492 $ 625,176
Acquisition premium. . . . . . . . . . . . . 291,156 299,162
Deferred future income taxes . . . . . . . . 206,114 213,658
Other. . . . . . . . . . . . . . . . . . . . 85,987 112,555
Total deferred tax liabilities . . . . . . $1,198,749 $1,250,551
Investment tax credits . . . . . . . . . . . . $ 103,645 $ 109,710
Accumulated deferred income taxes, net . . . . $ 938,659 $1,069,907
In accordance with various rate orders, the company has not yet
collected through rates certain accelerated tax deductions which have been
passed on to customers. 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 also are a
temporary difference for which deferred income tax liabilities have been
provided.
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 tax rates and the federal statutory income
tax rates are as follows:
<PAGE>
Year Ended December 31, 1998 1997 1996
Effective income tax rate. . . . . . . . . 24.0% 43.4% 32.8%
Effect of:
State income taxes. . . . . . . . . . . . (4.5) (5.0) (5.1)
Amortization of investment tax credits. . 10.0 0.8 2.7
Corporate-owned life insurance policies . 15.0 0.9 3.7
Accelerated depreciation flow through
and amortization, net . . . . . . . . . (2.9) (0.4) (0.2)
Adjustment to tax provision . . . . . . . (11.3) (3.7) -
Dividends received deduction. . . . . . . 16.0 - -
Amortization of goodwill. . . . . . . . . (11.4) - -
Other . . . . . . . . . . . . . . . . . . 0.1 (1.0) 1.1
Statutory federal income tax rate. . . . . 35.0% 35.0% 35.0%
17. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at
December 31:
1998 1997
(Dollars in Thousands)
Electric plant in service. . . . . . . $5,646,176 $5,564,695
Less - accumulated depreciation. . . . 2,015,880 1,895,084
3,630,296 3,669,611
Construction work in progress. . . . . 77,927 60,006
Nuclear fuel (net) . . . . . . . . . . 39,497 40,696
Net utility plant. . . . . . . . . . 3,747,720 3,770,313
Non-utility plant in service . . . . . 62,324 20,237
Less - accumulated depreciation. . . . 14,901 4,022
Net property, plant and equipment. . $3,795,143 $3,786,528
The carrying value of long-lived assets, including intangibles, are
reviewed for impairment whenever events or changes in circumstances indicate
they may not be recoverable.
18. LEASES
At December 31, 1998, the company had leases covering various property
and equipment. The company currently has no significant capital leases.
Rental payments for operating leases and estimated rental commitments
are as follows:
<PAGE>
Operating
Year Ended December 31, Leases
(Dollars in Thousands)
1996 . . . . . . . . . . . . . . $ 63,181
1997 . . . . . . . . . . . . . . 71,126
1998 . . . . . . . . . . . . . . 70,796
Future Commitments:
1999 . . . . . . . . . . . . . . 64,355
2000 . . . . . . . . . . . . . . 58,573
2001 . . . . . . . . . . . . . . 55,073
2002 . . . . . . . . . . . . . . 55,293
2003 . . . . . . . . . . . . . . 57,530
Thereafter . . . . . . . . . . . 650,893
Total. . . . . . . . . . . . . . $941,717
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. The company recognized a gain
on the sale which was deferred and is being amortized over the initial lease
term.
In 1992, the company deferred costs associated with the refinancing of
the secured facility bonds of the Trustee and owner of La Cygne 2. These costs
are being amortized over the life of the lease and are included in operating
expense. Approximately $20.3 million of this deferral remained on the
Consolidated Balance Sheet at December 31, 1998.
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 2002, $39.4 million in 2003, and $537.2 million over the
remainder of the lease. KGE's lease expense, net of amortization of the
deferred gain and refinancing costs, was approximately $28.9 million for 1998,
$27.3 million for 1997, and $22.5 million for 1996.
19. SEGMENTS OF BUSINESS
In 1998, the company adopted SFAS 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement requires the company to
define and report the company's business segments based on how management
currently evaluates its business. Management has segmented its business based
on differences in products and services, production processes, and management
responsibility. Based on this approach, the company has identified four
reportable segments: fossil generation, nuclear generation, power delivery and
monitored services.
<PAGE>
Fossil generation, nuclear generation and power delivery represent the
three business segments that comprise the company's regulated electric utility
business in Kansas. Fossil generation produces power for sale to external
wholesale customers outside the company's historical marketing territory and
internally to the power delivery segment. Power marketing is a component of the
company's fossil generation segment which attempts to minimize market
fluctuation risk, enhance system reliability and maintain a market presence.
Nuclear generation represents the company's 47% ownership in the Wolf Creek
nuclear generating facility. This segment does not have any external sales.
The power delivery segment consists of the transmission and distribution of
power to approximately 620,000 wholesale and retail customers in Kansas.
The company's monitored services business was expanded in November 1997
with the acquisition of a majority interest in Protection One. Protection One
provides monitored services to approximately 1.5 million customers in North
America, the United Kingdom, and Continental Europe.
Other represents the company's non-utility operations and natural gas
business.
The accounting policies of the segments are substantially the same as
those described in the summary of significant accounting policies. The company
evaluates segment performance based on earnings before interest and taxes.
Unusual items, such as charges to income, may be excluded from segment
performance depending on the nature of the charge or income. The company's
ONEOK investment, marketable securities investments and other equity method
investments do not represent operating segments of the company. The company has
no single external customer from which it receives ten percent or more of its
revenues.
<TABLE>
<CAPTION>
Year Ended December 31, 1998:
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services (1)Other (2)Items Total
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
External sales. . . $ 525,974 $ - $1,085,711 $ 421,095 $ 1,342 $ (68) $2,034,054
Allocated sales . . 517,363 117,517 66,492 - - (701,372) -
Depreciation and
amortization . . . 53,132 39,583 68,297 117,651 2,010 - 280,673
Earnings before
interest and taxes 144,357 (20,920) 196,398 56,727 (101,988) 12,268 286,842
Interest expense. . 226,120
Earnings before
income taxes . . . 60,722
Identifiable assets 1,360,102 1,121,509 1,788,943 2,511,319 1,269,013 (99,458) 7,951,428
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1997:
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery (3)Services (4,5)Other (6)Items Total
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
External sales. . . $ 208,836 $ - $1,021,212 $ 152,347 $ 769,416 $ (46) $2,151,765
Allocated sales . . 517,167 102,330 66,492 - - (685,989) -
Depreciation and
amortization . . . 53,831 65,902 63,590 41,179 32,223 - 256,725
Earnings before
interest and taxes 149,825 (60,968) 173,809 (38,517) 914,747 (62,583) 1,076,313
Interest expense. . 193,808
Earnings before
income taxes . . . 882,505
Identifiable assets 1,337,591 1,154,522 1,721,021 1,593,286 1,238,088 (84,958) 6,959,550
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1996:
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services (5)Other Items Total
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
External sales. . . $ 144,056 $ - $1,053,359 $ 8,546 $ 840,827 $ 39 $2,046,827
Allocated sales . . 518,199 100,592 71,492 - - (690,283) -
Depreciation and
amortization . . . 52,303 57,242 60,713 944 30,129 - 201,331
Earnings before
interest and taxes 188,173 (51,585) 218,936 (3,555) 62,385 (10,494) 403,860
Interest expense. . 152,551
Earnings before
income taxes . . . 251,309
Identifiable assets 1,330,048 1,190,335 1,637,980 488,849 2,000,569 - 6,647,781
(1) Earnings before interest and taxes (EBIT) includes investment earnings of $21.7 million and
write-off of international power development activities of $98.9 million.
(2) Identifiable assets includes eliminating and reclassing balances to consolidate the monitored
services business.
(3) EBIT includes monitored services special charge of $24.3 million.
(4) EBIT includes investment earnings of $37.8 million and gain on sale of Tyco securities of
$864.2 million.
(5) Includes natural gas operations. The company contributed substantially all of its natural
gas business in exchange for a 45% equity interest in ONEOK in November 1997.
(6) EBIT includes write-off of deferred merger costs of $48 million. Identifiable assets
includes eliminating and reclassing balances to consolidate the monitored services
business.
</TABLE>
Geographic Information: Prior to 1998, the company did not have
international sales or international property, plant and equipment. The
company's sales and property, plant and equipment as of and for the period
ending December 31, 1998 are as follows:
North America International
Operations Operations Total
(Dollars in Thousands)
External sales . . . . . $1,990,329 $43,725 $2,034,054
Property, plant and
equipment, net . . . . 3,787,872 7,271 3,795,143
<PAGE>
2O. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1998
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 162,756 $109,336 343 50
Jeffrey 1 (b) Jul 1978 297,020 134,054 617 84
Jeffrey 2 (b) May 1980 292,555 128,210 622 84
Jeffrey 3 (b) May 1983 405,054 160,671 621 84
Wolf Creek (c) Sep 1985 1,377,348 429,934 547 47
(a) Jointly owned with KCPL
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity presented above 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 334 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.
21. MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY
On February 7, 1997, the company signed a merger agreement with Kansas
City Power & Light Company (KCPL) by which KCPL would be merged with and into
the company in exchange for company stock. In December 1997, representatives of
the company's financial advisor indicated that they believed it was unlikely
that they would be in a position to issue a fairness opinion required for the
merger on the basis of the previously announced terms.
On March 18, 1998, the company and KCPL agreed to a restructuring of
their February 7, 1997, merger agreement which will result in the formation of
Westar Energy, a new regulated electric utility company. Under the terms of the
merger agreement, the electric utility operations of the company will be
transferred to KGE, and KCPL and KGE will be merged into NKC, Inc., a subsidiary
of the company. NKC, Inc. will be renamed Westar Energy. In addition, under
the terms of the merger agreement, KCPL shareholders will receive company
common stock which is subject to a collar mechanism of not less than .449 nor
greater than .722, provided the amount of company common stock received may not
exceed $30.00, and one share of Westar Energy common stock per KCPL share. The
Western Resources Index Price is the 20 day average of the high and low sale
prices for company common stock on the NYSE ending ten days prior to closing.
If the Western Resources Index Price is less than or equal to $29.78 on the
fifth day prior to the effective date of the combination, either party may
terminate the agreement. Upon consummation of the combination, the company will
own approximately 80.1% of the outstanding equity of Westar Energy and KCPL
shareholders will own approximately 19.9%. As part of the combination, Westar
Energy will assume all of the electric utility
<PAGE>
related assets and liabilities of the company, KCPL and KGE.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9
billion of indebtedness for borrowed money of the company and KGE, and $800
million from KCPL. Long-term debt of the company, excluding Protection One, was
$2.5 billion at December 31, 1998, and $2.1 billion at December 31, 1997. Under
the terms of the merger agreement, it is intended that the company will be
released from its obligations with respect to the company's debt to be assumed
by Westar Energy.
Pursuant to the merger agreement, the company has agreed, among other
things, to redeem all outstanding shares of its 4 1/2% Series Preferred Stock,
par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per
share, and 5% Series Preferred Stock, par value $100 per share.
Consummation of the merger is subject to customary conditions. On July
30, 1998, the company's shareholders and the shareholders of KCPL voted to
approve the amended merger agreement at special meetings of shareholders. The
company estimates the transaction to close in 1999, subject to receipt of all
necessary approvals from regulatory and government agencies.
In testimony filed in February 1999, the KCC staff recommended the
merger be approved but with conditions which we believe would make the merger
uneconomical. The merger agreement allows the company to terminate the
agreement if regulatory approvals are not acceptable. The KCC is under no
obligation to accept the KCC staff recommendation. In addition, legislation has
been proposed in Kansas that could impact the transaction. The company does not
anticipate the proposed legislation to pass in its current form. The company
is not able to predict whether any of these initiatives will be adopted or their
impact on the transaction, which could be material.
On August 7, 1998, the company and KCPL filed an amended application
with the Federal Energy Regulatory Commission (FERC) to approve the Western
Resources/KCPL merger and the formation of Westar Energy.
The company has received procedural schedule orders in Kansas and
Missouri. These schedules indicate hearing dates beginning May 3, 1999, in
Kansas and July 26, 1999, in Missouri.
KCPL is a public utility company engaged in the generation,
transmission, distribution, and sale of electricity to customers in western
Missouri and eastern Kansas. The company, KCPL and KGE have joint interests in
certain electric generating assets, including Wolf Creek.
At December 31, 1998, the company had deferred approximately $14 million
related to the KCPL transaction. These costs will be included in the
determination of total consideration upon consummation of the transaction.
For additional information on the Merger Agreement with Kansas City
Power & Light Company, see the company's Registration Statement on Form S-4
filed on June 9, 1998.
<PAGE>
22. 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 electric 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)
1998 (Restated)
Sales . . . . . . . . . . . . . $382,343 $463,301 $701,402 $487,008
Income from operations(1) . . . 64,795 72,314 156,307 (62,902)
Net income(1) . . . . . . . . . 29,813 31,006 71,422 (84,485)
Earnings applicable to
common stock. . . . . . . . . 28,583 29,209 71,140 (84,767)
Basic earnings per share. . . . $ 0.44 $ 0.45 $ 1.08 $ (1.29)
Dividends per share . . . . . . $ 0.535 $ 0.535 $ 0.535 $ 0.535
Average common shares
outstanding . . . . . . . . . 65,410 65,543 65,707 65,870
Common stock price:
High. . . . . . . . . . . . . $ 44.188 $ 42.688 $ 41.625 $ 43.250
Low . . . . . . . . . . . . . $ 40.000 $ 36.875 $ 37.688 $ 32.563
1997 (Restated)
Sales . . . . . . . . . . . . . $626,198 $454,006 $559,996 $511,565
Income from operations(2) . . . 103,297 57,498 110,391 (116,761)
Net income(2),(3) . . . . . . . 41,033 24,335 508,372 (74,222)
Earnings applicable to
common stock. . . . . . . . . 39,803 23,106 507,142 (75,452)
Basic earnings per share. . . . $ 0.61 $ 0.36 $ 7.77 $ (1.15)
Dividends per share . . . . . . $ 0.525 $ 0.525 $ 0.525 $ 0.525
Average common shares
outstanding . . . . . . . . . 64,807 65,045 65,243 65,408
Common stock price:
High. . . . . . . . . . . . . $ 31.50 $ 32.75 $ 35.00 $ 43.438
Low . . . . . . . . . . . . . $ 30.00 $ 29.75 $ 32.25 $ 33.625
(1) The loss in the fourth quarter of 1998, is primarily attributable to a
$99 million charge to income to exit the company's international power
development business.
(2) During the fourth quarter of 1997, the company expensed deferred costs
of approximately $48 million associated with the original KCPL merger
agreement. Protection One recorded a charge to income of approximately $24
million.
(3) During the third quarter of 1997, the company recorded a pre-tax gain of
approximately $864 million upon selling its Tyco common stock.
<PAGE>
The summarized information for the fourth quarter of 1997 and for each
quarter in 1998 have been revised to reflect a restatement at Protection One.
The restatement expenses yard signs previously capitalized and includes the
impact of reversing the accrual for the signage charge previously recorded at
December 31, 1997 (see Note 2). The impact of the adjustments made to the
company's previously reported quarterly results in 1998, net of tax and net of
the minority interest is as follows:
(Dollars in Thousands)
Expense yard signs as incurred $ 8,312
Increase bad debt provision 3,090
Other (554)
Decrease in net income $10,848
The impact of these adjustments on the quarterly results previously
reported is as follows. (Amounts are net of tax and net of minority interest):
Net Income
(dollars in thousands) Earnings Per Share
Increase (Decrease) Increase (Decrease)
1998 - First Quarter $ (655) $(0.01)
Second Quarter (3,813) (0.05)
Third Quarter (1,343) (0.02)
Fourth Quarter (5,037) (0.08)
1997 - Fourth Quarter $ 5,424 $0.08
<PAGE>
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 1999 Annual
Meeting of Shareholders to be filed with the SEC. 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
SEC. See EXECUTIVE OFFICERS OF THE COMPANY in the proxy statement 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 1999 Annual Meeting of Shareholders to be
filed with the SEC. 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 SEC.
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 1999 Annual Meeting of Shareholders to be
filed with the SEC. 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 SEC.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
<PAGE>
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, 1998 and 1997
Consolidated Statements of Income, for the years ended December 31, 1998,
1997 and 1996
Consolidated Statements of Comprehensive Income, for the years ended
December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows, for the years ended December 31, 1998,
1997 and 1996
Consolidated Statements of Cumulative Preferred and Preference Stock, December
31, 1998 and 1997
Consolidated Statements of Shareholders' Equity, for the years ended December
31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements
SCHEDULES
Schedule II - Valuation and Qualifying Accounts
Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, III, IV, and V
REPORTS ON FORM 8-K
Form 8-K filed January 5, 1998 - Press release regarding merger with
Kansas City Power and Light Company.
Form 8-K filed March 23, 1998 - Amended and Restated Agreement and Plan
of Merger between the company and KCPL, dated as of March 18, 1998.
Form 8-K filed July 13, 1998 - Kansas City Power and Light Company
December 31, 1997 Form 10-K and March 31, 1998 Form 10-Q.
Form 8-K filed August 3, 1998 - Computations of Ratio of Earnings to
Fixed Charges and Computations of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend Requirements, press release reporting
second quarter earnings issued July 30, 1998, and press release announcing
approval by shareholders of KCPL merger agreement issued July 30, 1998.
Form 8-K filed August 6, 1998 - Kansas City Power and Light Company June
30, 1998 Form 10-Q.
<PAGE>
Form 8-K filed January 28, 1999 - Press release regarding annual
earnings and dividends declared.
Form 8-K filed April 1, 1999 - Press release reporting Western Resources
extends filing period for 10-K.
<PAGE>
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -Amended and Restated Agreement and Plan of Merger between I
the company and KCPL, dated as of March 18, 1998.
(filed as Exhibit 99.2 to the March 23, 1998 Form 8-K)
3(b) -By-laws of the company, as amended March 19, 1997. (filed
as Exhibit 3 to the March 31, 1997 Form 10-Q) I
3(c) -Agreement and Plan of Merger between the company and KCPL, I
dated as of February 7, 1997. (filed as Exhibit 99.2 to the
February 10, 1997 Form 8-K)
3(d) -Agreement between the company and ONEOK dated as of I
December 12, 1996. (filed as Exhibit 99.2 to the December 12,
1997 Form 8-K)
3(e) -Form of Shareholder Agreement between New ONEOK and the I
company. (filed as Exhibit 99.3 to the December 12, 1997
Form 8-K)
3(f) -Restated Articles of Incorporation of the company, as amended I
through May 25, 1988, filed as Exhibit 4 to Registration
Statement, SEC File No. 33-23022 (incorporated by reference).
3(g) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated March 29, 1991.
3(h) -Certificate of Designations for Preference Stock, 8.5% Series, I
without par value, dated March 31, 1991 and filed as exhibit
3(d) to December 1993 Form 10-K (incorporated by reference).
3(i) -Certificate of Correction to Restated Articles of Incorporation I
of the company dated December 20, 1991, filed as exhibit 3(b)
to December 1991 Form 10-K (incorporated by reference).
3(j) -Certificate of Designations for Preference Stock, 7.58% Series, I
without par value, dated April 8, 1992 and filed as exhibit 3(e)
to December 1993 form 10-K (incorporated by reference).
3(k) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated May 8, 1992, filed as exhibit 3(c) to
December 31, 1994 Form 10-K (incorporated by reference).
3(l) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated May 26, 1994, filed as exhibit 3 to June 1994
Form 10-Q (incorporated by reference).
3(m) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated May 14, 1996, filed as exhibit 3(a) to June
1996 Form 10-Q (incorporated by reference).
3(n) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated May 12, 1998, filed as exhibit 3 to March
1998 Form 10-Q (incorporated by reference).
4(a) -Deferrable Interest Subordinated Debentures dated November 29, I
1995, between the company and Wilmington Trust Delaware, Trustee
(filed as Exhibit 4(c) to Registration Statement No. 33-63505)
<PAGE>
4(b) -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(c) -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(d) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
4(e) -Seventeenth Supplemental Indenture dated February 1, 1978. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(f) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(g) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(h) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(i) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)
4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986. I
(filed as Exhibit 4(j) to Registration Statement No. 33-12054)
4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. I
(filed as Exhibit 4(k) to Registration Statement No. 33-21739)
4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)
4(r) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(s) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Registration Statement No. 33-50069)
4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994, I
(filed as Exhibit 4(s) to the December 31, 1994 Form 10-K)
4(u) -Debt Securities Indenture dated August 1, 1998 , I
(filed as Exhibit 4.1 to the September 1998 Form 10-Q)
4(v) -Form of Note for $400 million 6.25% Putable/Callable Notes due I
August 15, 2018, Putable/Callable August 15, 2003
(filed as Exhibit 4.2 to the September 1998 Form 10-Q)
<PAGE>
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) -Long-term Incentive and Share Award Plan (filed as Exhibit I
10(a) to the June 1996 Form 10-Q)
10(b) -Form of Employment Agreement with officers of the Company I
(filed as Exhibit 10(b) to the June 1996 Form 10-Q)
10(c) -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(d) -Agreement between the Company and AMAX Coal West Inc. I
effective March 31, 1993. (filed as Exhibit 10(a) to the
December 31, 1993 Form 10-K)
10(e) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed as Exhibit 10(b) to the
December 31, 1993 Form 10-K)
10(f) -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 31, 1989 Form 10-K)
10(g) -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(h) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 31, 1993 Form 10-K)
10(i) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I
December 31, 1993 Form 10-K)
10(j) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 31, 1993 Form 10-K)
10(k) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 31, 1993 Form 10-K)
10(l) -Executive Salary Continuation Plan of Western Resources, Inc., I
as revised, effective September 22, 1995. (filed as Exhibit
10(j)to the December 31, 1995 Form 10-K)
10(m) -Executive Salary Continuation Plan for John E. Hayes, Jr., I
Dated March 15, 1995. (filed as Exhibit 10(k) to the
December 31, 1995 Form 10-K)
10(n) -Stock Purchase Agreement between the company and Laidlaw I
Transportation Inc., dated December 21, 1995. (filed as
Exhibit 10(l) to the December 31, 1995 Form 10-K)
10(o) -Equity Agreement between the company and Laidlaw Transportation I
Inc., dated December 21, 1995. (filed as Exhibit 10(l)1 to the
December 31, 1995 Form 10-K)
10(p) -Letter Agreement between the company and David C. Wittig, I
dated April 27, 1995. (filed as Exhibit 10(m) to the
December 31, 1995 Form 10-K)
<PAGE>
10(q) -Transaction Confirmation for $400 million 6.25% Putable/Callable I
Notes due August 15, 2018, Putable/Callable August 15, 2003.
(filed as Exhibit 10.1 to the September 30, 1998 Form 10-Q)
10(r) -Amendment to Letter Agreement between the company and David C. I
Wittig, dated April 27, 1995 (filed as Exhibit 10.2 to the
September 30, 1998 Form 10-Q)
10(q) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 I
to the September 30, 1998 Form 10-Q)
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 Schedule (filed electronically)
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)
<CAPTION>
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts(a) Deductions of Period
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1996
Allowances deducted from
assets for doubtful accounts. . $ 5,087 $10,848 $1,857 $(11,537) $ 6,255
Year ended December 31, 1997
Allowances deducted from
assets for doubtful accounts. . 6,255 16,592 4,578 (19,034) 8,391
Monitored services special
charge (b). . . . . . . . . . . - 3,856 - - 3,856
Year ended December 31, 1998
Allowances deducted from
assets for doubtful accounts. . 8,391 24,726 2,289 (5,862) 29,544
Monitored services special
charge (b). . . . . . . . . . . 3,856 - - (2,831) 1,025
Accrued exit fees, shut-down
and severance costs (c) . . . . - 22,900 - - 22,900
(a) Allowances recorded on receivables purchased in conjunction with acquisitions of customer
accounts.
(b) Consists of costs to close duplicate facilities and severance and compensation benefits.
(c) See Note 11 to the Consolidated Financial Statements for further information.
</TABLE>
<PAGE>
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.
April 14, 1999
By /s/ DAVID C. WITTIG
David C. Wittig, Chairman of the Board,
President and Chief Executive Officer
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board,
/s/ DAVID C. WITTIG President and Chief Executive April 14, 1999
(David C. Wittig) Officer
(Principal Executive Officer)
Acting Executive Vice President
/s/ WILLIAM B. MOORE and Chief Financial Officer April 14, 1999
(William B. Moore) (Principal Financial and
Accounting Officer)
/s/ FRANK J. BECKER
(Frank J. Becker)
/s/ C. Q. CHANDLER
(C. Q. Chandler)
/s/ THOMAS R. CLEVENGER
(Thomas R. Clevenger)
/s/ JOHN C. DICUS Directors April 14, 1999
(John C. Dicus)
/s/ DAVID H. HUGHES
(David H. Hughes)
/s/ RUSSELL W. MEYER, JR.
(Russell W. Meyer, Jr.)
/s/ JANE DESNER SADAKA
(Jane Desner Sadaka)
/s/ LOUIS W. SMITH
(Louis W. Smith)
<PAGE>
Exhibit 3
CERTIFICATE OF AMENDMENT TO RESTATED ARTICLES
OF INCORPORATION, AS AMENDED, OF
THE KANSAS POWER AND LIGHT COMPANY
We, John E. Hayes, Jr., Chairman of the Board, President and Chief
Executive Officer and John K. Rosenberg, Secretary of the above named
corporation, a corporation organized and existing under the laws of the State of
Kansas, do hereby certify that at a meeting of the Board of Directors of said
corporation, the board adopted a resolution setting forth the following
amendment to the Restated Articles of Incorporation and declaring their
advisability:
FURTHER RESOLVED, That the following amendment of Article IV of the
Company's Restated Articles of Incorporation be, and it hereby is proposed
and declared advisable:
The first paragraph of said Article VI to be amended and read as
follows:
The amount of capital stock of this Corporation shall be 95,600,000
shares of which 85,000,000 shares is Common Stock of the par value of Five
Dollars ($5.00) each, 4,000,000 shares is Preference Stock without par
value, 600,000 shares is preferred stock of the par value of One Hundred
Dollars ($100) each and 6,000,000 shares is preferred stock without par
value, all such preferred stock being termed "Preferred Stock";
and
FURTHER RESOLVED, That the following amendment of Article XI of the
Company's Restated Articles of Incorporation be, and it hereby is proposed
and declared advisable:
Article XI be amended and read as follows:
The number of directors shall not be less than seven nor more than
fifteen and the precise number shall be determined from time-to-time by the
Board of Directors at any annual or special meeting within such minimum and
maximum number, provided, that unless approved by a majority of the
stockholders entitled to vote, the number of directors shall not be reduced
to terminate the office of a director during the term for which he was
elected.
We further certify that thereafter, pursuant to said resolution, and in
accordance with the by-laws of the corporation and the laws of the State of
Kansas, the Board of Directors called a special meeting of shareholders for
consideration of the proposed amendments, and thereafter, pursuant to notice and
in accordance with the statutes of the State of Kansas, the shareholders
convened and considered the proposed amendments.
We further certify that at the meeting a majority of the shares of common
stock entitled to vote and a majority of common and preferred shares together
entitled to vote, voted in favor of the proposed amendments.
We further certify that the amendments were duly adopted in accordance with
the provisions of K.S.A. 17-6602, as amended.
We further certify that the capital of said corporation will not be reduced
under or by reason of said amendments.
IN WITNESS WHEREOF, we have hereunto set our hands and affixed the seal of
said corporation the 29th day of March, 1991.
/s/John E. Hayes, Jr.
John E. Hayes, Jr.
Chairman of the Board,
President and Chief Executive Officer
/s/John K. Rosenberg
John K. Rosenberg
Secretary
State of Kansas )
) ss.
County of Shawnee )
Be it remembered that before me, a Notary Public in and for the aforesaid
county and state, personally appeared John E. Hayes, Jr., Chairman of the Board,
President and Chief Executive Officer, and John K. Rosenberg, Secretary of the
corporation named in this document, who are known to me to be the same persons
who executed the foregoing certificate and duly acknowledge that execution of
the same this 29th day of March, 1991
/s/Regina I. DeGarmo
Notary Public
[stamp of Notary Public]
Exhibit 12
WESTERN RESOURCES, INC.
Computations of Ratio of Earnings to Fixed Charges and
Computations of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend Requirements
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
Net Income . . . . . . . . . . . $ 47,756 $ 494,094 $168,950 $181,676 $187,447
Taxes on Income. . . . . . . . . 14,557 378,645 86,102 83,392 99,951
Net Income Plus Taxes. . . . 62,313 872,739 255,052 265,068 287,398
Fixed Charges:
Interest on Long-Term Debt . . 170,855 119,389 105,741 95,962 98,483
Interest on Other Indebtedness 37,190 55,761 34,685 27,487 20,139
Interest on Other Mandatorily
Redeemable Securities. . . . 18,075 18,075 12,125 372 -
Interest on Corporate-owned
Life Insurance Borrowings. . 38,236 36,167 35,151 32,325 26,932
Interest Applicable to
Rentals. . . . . . . . . . . 32,796 34,514 32,965 31,650 29,003
Total Fixed Charges. . . . 297,152 263,906 220,667 187,796 174,557
Preferred and Preference Dividend
Requirements:
Preferred and Preference
Dividends. . . . . . . . . . 3,591 4,919 14,839 13,419 13,418
Income Tax Required. . . . . . 1,095 3,770 7,562 6,160 7,155
Total Preferred and
Preference Dividend
Requirements . . . . . . 4,686 8,689 22,401 19,579 20,573
Total Fixed Charges and Preferred
and Preference Dividend
Requirements. . . . . . . . . 301,838 272,595 243,068 207,375 195,130
Earnings (1) . . . . . . . . . . $359,465 $1,136,645 $475,719 $452,864 $461,955
Ratio of Earnings to Fixed
Charges . . . . . . . . . . . . 1.21 4.31 2.16 2.41 2.65
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements. . . . . 1.19 4.17 1.96 2.18 2.37
(1) Earnings are deemed to consist of net income to which has been added income taxes (including
net deferred investment tax credit) and fixed charges. Fixed charges consist of all interest
on indebtedness, amortization of debt discount and expense, and the portion of rental expense
which represents an interest factor. Preferred and preference dividend requirements consist
of an amount equal to the pre-tax earnings which would be required to meet dividend
requirements on preferred and preference stock.
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report included in this Form 10-K, into the previously filed
Registration Statements File Nos. 333-59673, 33-49467, 33-49553, 333-02023,
33-50069, 333-26115, and 33-62375 of Western Resources, Inc. on Form S-3;
Nos. 333-02711 and 333-56369 of Western Resources, Inc. on Form S-4; Nos. 333-
70891, 33-57435, 333-13229, 333-06887, 333-20393, 333-20413 and 333-75395 of
Western Resources, Inc. on Form S-8; and No. 33-50075 of Kansas Gas and
Electric Company on Form S-3.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
April 13, 1999
Exhibit 21
WESTERN RESOURCES, INC.
Subsidiaries of the Registrant
State of Date
Subsidiary Incorporation Incorporated
1) Kansas Gas and Electric Company Kansas October 9, 1990
2) Westar Capital, Inc. Kansas October 8, 1990
3) Protection One, Inc. Delaware June 21, 1991
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
BALANCE SHEET AT DECEMBER 31, 1998 AND THE STATEMENT OF INCOME AND THE
STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 16394
<SECURITIES> 288077
<RECEIVABLES> 252259
<ALLOWANCES> 29544
<INVENTORY> 95590
<CURRENT-ASSETS> 57225
<PP&E> 5825925
<DEPRECIATION> 2030782
<TOTAL-ASSETS> 7951428
<CURRENT-LIABILITIES> 1034846
<BONDS> 3063064
220000
24858
<COMMON> 329548
<OTHER-SE> 1608435
<TOTAL-LIABILITY-AND-EQUITY> 7951428
<SALES> 2034054
<TOTAL-REVENUES> 2034054
<CGS> 823259
<TOTAL-COSTS> 1803540
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 226120
<INCOME-PRETAX> 60722
<INCOME-TAX> 14557
<INCOME-CONTINUING> 46165
<DISCONTINUED> 0
<EXTRAORDINARY> 1591
<CHANGES> 0
<NET-INCOME> 47756
<EPS-PRIMARY> 0.67
<EPS-DILUTED> 0.67
</TABLE>
