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, 1999
[ ] 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. ()
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,140,411,389 of Common Stock and $11,682,772 of
Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there
is no readily ascertainable market value) at March 24, 2000.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock.
Common Stock, $5.00 par value 68,084,715
(Class) (Outstanding at March 28, 2000)
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 15, 2000.
<PAGE>
WESTERN RESOURCES, INC.
TABLE OF CONTENTS
Page
PART I
Item 1. Business 3
Item 2. Properties 23
Item 3. Legal Proceedings 25
Item 4. Submission of Matters to a Vote of
Security Holders 27
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 27
Item 6. Selected Financial Data 28
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 29
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 54
Item 8. Financial Statements and Supplementary Data 55
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 110
<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 628,000
customers in Kansas and providing monitored services to approximately 1.6
million customers in North America, the United Kingdom and continental Europe.
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). 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. Our investments in
Protection One and ONEOK are owned by Westar Capital, Inc. (Westar Capital), a
wholly-owned subsidiary. The consolidated entities of Western Resources are
referred to herein as "we." Our corporate headquarters are located at 818
Kansas Avenue, Topeka, Kansas 66612.
On March 28, 2000, our board of directors approved the separation of our
electric and non-electric utility businesses. The separation is currently
expected to be effected through an exchange offer to be made to our shareholders
in the third quarter of 2000. The exchange ratio will be described in materials
furnished to shareholders upon commencement of the exchange offer. The impact
on our financial position and operating results cannot be known until the
exchange ratio is determined. We expect to complete the separation in the
fourth quarter of 2000, but no assurance can be given that the separation will
be completed.
On March 18, 1998, we signed an Amended and Restated Plan of Agreement and
Plan of Merger with the Kansas City Power & Light Company (KCPL) under which
KGE, KPL and KCPL would have been combined into a new company called Westar
Energy, Inc. KCPL has notified us that it has terminated the contemplated
transaction. We expensed costs related to the KCPL merger of approximately
$17.6 million at December 31, 1999.
On February 29, 2000, Westar Capital purchased the continental European
and United Kingdom operations of Protection One, and certain investments held by
a subsidiary of Protection One for an aggregate purchase price of $244 million.
Westar Capital paid approximately $183 million in cash and transferred
Protection One debt securities with a market value of approximately $61 million
to Protection One.
<PAGE>
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, the outcome of Protection One
accounting issues reviewed by the SEC staff as disclosed in previous filings,
possible corporate restructurings, mergers, acquisitions, dispositions,
liquidity and capital resources, compliance with debt covenants, interest and
dividends, the impact of Protection One's financial condition on our
consolidated results, 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,
accounting matters, and the overall economy of our service area. What happens
in each case could vary materially from what we expect because of such things as
electric utility deregulation, including ongoing municipal, state and federal
activities; future economic conditions; legislative and regulatory developments;
our regulatory and competitive markets; and other circumstances affecting
anticipated operations, sales and costs.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 22 of the Notes to Consolidated Financial Statements.
ELECTRIC UTILITY OPERATIONS
General
We supply electric energy at retail to approximately 628,000 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.
<PAGE>
Our electric sales volumes (excluding power marketing) for the last three
years are as follows:
1999 1998 1997
(Thousands of MWH)
Residential. . . . 5,551 5,815 5,310
Commercial . . . . 6,202 6,199 5,803
Industrial . . . . 5,743 5,808 5,714
Wholesale and
Interchange. . . 5,617 4,826 5,334
Other. . . . . . . 108 108 107
Total. . . . . . 23,221 22,756 22,268
Our electric sales for the last three years are as follows:
1999 1998 1997
(Dollars in Thousands)
Residential. . . . $ 407,371 $ 428,680 $ 392,751
Commercial . . . . 356,314 356,610 339,167
Power Marketing. . 193,421 382,601 69,827
Industrial . . . . 251,391 257,186 254,076
Wholesale and
Interchange. . . 174,895 145,320 142,506
Other. . . . . . . 46,306 41,288 31,721
Total. . . . . . $1,429,698 $1,611,685 $1,230,048
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 market for generation. The Energy
Policy Act permitted the Federal Energy Regulatory Commission (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. In 1992, 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 ourselves. In December 1999, FERC issued an order (FERC Order 2000)
encouraging formation of regional transmission organizations (RTOs), whose
purpose is to facilitate greater competition at the wholesale level. Due to our
participation in the formation of the Southwest Power Pool RTO, we anticipate
that FERC Order 2000 will not have a material effect on us or our operations.
In December 1999, the Wichita, Kansas, City Council authorized the hiring
of an outside consultant to determine the feasibility of creating a municipal
electric utility to replace KGE as the supplier of electricity in Wichita.
KGE's rates are currently 7% below the national average for retail customers.
The average rates charged to retail customers in territories served by our KPL
division are 19% lower than KGE's rates. Customers within the Wichita
metropolitan area account for approximately 25% of our total energy sales. KGE
has an exclusive franchise with the City of Wichita to provide retail electric
service that expires March 2002. Under Kansas law, KGE will continue to have
the exclusive right to serve the customers in Wichita following the expiration
of the franchise, assuming the system is not municipalized. See also
Regulation and Rates below regarding a complaint filed with the FERC against KGE
by the City of Wichita.
<PAGE>
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.
Regulation and Rates: As a Kansas electric utility, we are subject to the
jurisdiction of the Kansas Corporation Commission (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 also subject to the jurisdiction of the KCC with respect
to the issuance of certain securities.
Additionally, we are subject to the jurisdiction of the FERC, which has
authority over wholesale sales of electricity and the issuance of certain
securities. We are also subject to the jurisdiction of the Nuclear Regulatory
Commission for nuclear plant operations and safety.
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
jurisdiction of the FERC, which has authority over wholesale sales of
electricity and the issuance of certain securities. KGE is also subject to the
jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations
and safety.
In September 1999, the City of Wichita filed a complaint with the FERC
against KGE, alleging improper affiliate transactions between KGE and KPL, a
division of Western Resources. The City of Wichita requests the FERC to
equalize the generation costs between KGE and KPL, in addition to other matters.
FERC has issued an order setting this matter for hearing and has referred the
case to a settlement judge. The hearing has been suspended pending settlement
discussions between the parties. We believe that the City of Wichita's
complaint is without merit and intend to defend against it vigorously.
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization
of commercial and industrial users of electricity in Kansas, filed a complaint
with the KCC requesting an investigation of Western Resources' and KGE's rates.
The KIC alleges that these rates are not based on current costs. We will oppose
this request vigorously but are unable to predict whether the KCC will open an
investigation.
Additional information with respect to Rate Matters and Regulation is set
forth in Notes 1 and 14 of Notes to Consolidated Financial Statements and Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.
<PAGE>
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 Jeffrey Energy Center (JEC) and La Cygne 2 units have met: (1) the
Federal sulfur dioxide standards through the use of low sulfur coal (See Coal);
(2) the Federal particulate matter standards through the use of electrostatic
precipitators; and (3) the Federal 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. We have
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 12 of the Notes to Consolidated Financial Statements.
Fossil Fuel Generation
Capacity: The aggregate net generating capacity of our system is presently
5,458 megawatts (MW). The system has interests in 22 fossil fueled steam
generating units, one nuclear generating unit (47% interest), seven combustion
peaking turbines, two diesel generators, and two wind generators. One unit of
the 22 fossil fueled units (31 MW of capacity) that had been previously
"mothballed" for future use, will be retired in 2000 (See Item 2. Properties).
Our 1999 peak system net load occurred July 29, 1999, and amounted to 4,372
MW. Our net generating capacity together with power available from firm
interchange and purchase contracts, provided a capacity margin of approximately
12.1% above system peak responsibility at the time of the peak.
<PAGE>
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. We are also a member of the Southwest
Power Pool as discussed under Power Delivery.
We have agreed to provide 42 MW of capacity and transmission service
through May, 2013 to Oklahoma Municipal Power Authority (OMPA). We have another
agreement to provide capacity to OMPA of 18 MW through May, 2013.
We have agreed to provide Midwest Energy, Inc. (MWE) with capacity of 125
MW through May 2005, and another 61 MW through May 2007. We have agreed to
provide Empire District Electric Company (Empire) with peaking and base load
capacity of 80 MW through May 2000, and another 162 MW through May 2009.
We also have agreed with the McPherson, Kansas Board of Public Utilities
(McPherson) to provide base capacity to McPherson and McPherson to provide
peaking capacity to us through May 2027. During 1999, we provided approximately
70 MW to and received approximately 187 MW from McPherson. The amount of base
capacity provided to McPherson is based on a fixed percentage of McPherson's
annual peak system load.
Future Capacity: We are installing three new combustion turbine generators
which will have installed capacity of approximately 300 MW. The first two units
are scheduled to be placed in operation in June 2000, and the third is scheduled
to be placed in operation in mid-2001. We estimate that the project will
require $126 million in capital resources through the completion of the projects
in 2001.
In July 1999, we and Empire agreed to construct jointly a 500-megawatt
combined cycle generating plant, which Empire will operate. We will own 40% of
the generating plant and estimate that the project will require $86 million in
capital resources. Construction of the plant began in the fall of 1999 with
operation expected to begin in the second quarter of 2001.
For further discussion regarding future capacity and cash requirements,
see Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Fuel Mix: Our coal-fired units comprise 3,366 MW of the total 5,458 MW of
generating capacity and our nuclear unit provides 550 MW of capacity. Of the
remaining 1,542 MW of generating capacity, units that can burn either natural
gas or oil account for 1,452 MW, units that burn only diesel fuel account for
89 MW, and the remaining units which are powered by wind account for 1 MW
(See Item 2. Properties).
<PAGE>
During 1999, low sulfur coal was used to produce 76% of our electricity.
Nuclear produced 18% and the remainder was produced from natural gas, oil, or
diesel fuel. During 2000, based on our estimate of the availability of fuel,
coal will be used to produce approximately 75% of our electricity and nuclear
will be used to produce approximately 17%.
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
1,870 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 RAG America
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 $1.11 per MMBtu, or
$18.69, per ton during 1999.
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.
The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 681 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 83% 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 2003. This low
sulfur coal had an average Btu content of approximately 8,458 Btu per pound and
a maximum sulfur content of .80 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. KCPL is currently negotiating an extension of rail
service beyond December 31, 2000. We anticipate that the negotiation of the
transportation agreements will not have a material effect on our operations.
During 1999, the average delivered cost of all local and Powder River Basin
coal procured for La Cygne 1 was approximately $0.78 per MMBtu, or $13.00 per
ton, and the average delivered cost of Powder River Basin coal for La Cygne 2
was approximately $0.68 per MMBtu, or $11.55 per ton.
<PAGE>
The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 815 MW (See Item 2. Properties). The
company sources low sulfur coal from Montana and Colorado under contracts
through December 31, 2000. The Montana coal is transported by BNSF railroad
and the Colorado coal is transported by the UP and BNSF railroads under
contracts expiring December 31, 2000. Any supplemental coal required during
2000 will be purchased in the short-term market. We are currently evaluating
our coal and transportation options for 2001 and will begin negotiations for new
contracts during third quarter 2000. We anticipate that the negotiation of
these contracts will not have a material affect on our operations.
The Montana coal supplied in 1999 had an average Btu content of
approximately 9,359 Btu per pound and an average sulfur content of
.34 lbs./MMBtu (See Environmental Matters). During 1999, the average delivered
cost of Montana coal for the Lawrence units was approximately $0.92 per MMBtu,
or $17.00 per ton, and the average delivered cost of Montana coal for the
Tecumseh units was approximately $0.91 per MMBtu, or $17.23 per ton. The
Colorado coal supplied in 1999 had an average Btu content of approximately
10,957 Btu per pound and an average sulfur content of .44 lbs/MMBtu
(See Environmental Matters). During 1999, the average delivered cost of
Colorado coal for the Lawrence units was approximately $1.41 per MMBtu, or
$30.86 per ton, and the average delivered cost of Colorado coal for the
Tecumseh units was approximately $1.39 per MMBtu, or $30.44 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. We are not substantially dependent upon these contracts due
to the availability of competitive rail options. There are 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 carrier to provide service under the Interstate
Commerce Act, we do not anticipate any substantial long-term disruption of our
business.
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 purchased in the short-
term spot market which we believe supplies 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, 1999, we
had approximately 3 million gallons of No. 2 oil and 18 million gallons of No. 6
oil in inventory 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 our weighted-
average cost of fuel.
KPL Plants 1999 1998 1997
Per Million Btu:
Coal. . . . . . . . . . $1.09 $1.15 $1.17
Gas . . . . . . . . . . 2.66 2.29 2.88
Oil . . . . . . . . . . 4.17 4.40 3.72
Per KWH Generation . . . . 1.26 1.31 1.32
KGE Plants 1999 1998 1997
Per Million Btu:
Nuclear . . . . . . . . $0.45 $0.48 $0.51
Coal. . . . . . . . . . 0.87 0.86 0.89
Gas . . . . . . . . . . 2.31 2.28 2.56
Oil . . . . . . . . . . 2.11 4.05 3.32
Per KWH Generation . . . . 0.98 0.94 1.00
Nuclear Generation
The owners of Wolf Creek have on hand or under contract 100% of their
uranium needs for 2000 and 77% of the uranium required to operate Wolf Creek
through March 2005. 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 March 2005.
<PAGE>
Wolf Creek has active contracts for uranium enrichment with Urenco and
USEC. Contracted arrangements cover 85% 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.
Wolf Creek has entered into all of its uranium, uranium hexaflouride and
uranium enrichment arrangements during the ordinary course of business and is
not substantially dependent upon these agreements. Wolf Creek believes there
are other supplies 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
operations.
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
of 1982 (NWPA), 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 the future disposal of spent nuclear fuel. These disposal costs are
charged to cost of sales and are currently recovered through rates.
In 1996 and 1997, a U.S. Court of Appeals (the Court) issued decisions that
(1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998, and (2) precluded 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.
In May 1998, the Court issued an order in response to the utilities'
petitions for remedies for DOE's failure to begin accepting spent fuel for
disposal. 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 its claims
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 begun replacement of
spent fuel storage racks to increase its on-site storage capacity for all spent
fuel expected to be generated by Wolf Creek through the end of its licensed life
in 2025.
<PAGE>
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 (the Compact) and selected a site in
Nebraska to locate a disposal facility. WCNOC and the owners of the other five
nuclear units in the Compact have provided most of the pre-construction
financing for this project. Our share of Wolf Creek's net investment at
December 31, 1999, was approximately $7.4 million.
On December 18, 1998, the application for a license to construct this
project was denied. The license applicant has sought a hearing on the license
denial, but a U.S. District Court has delayed indefinitely proceedings related
to the hearing. In late December 1998, the utilities filed a federal court
lawsuit contending Nebraska officials acted in bad faith while handling the
license application and seeking damages related to the utilities' costs incurred
because of the delay in processing the application. In May 1999, the Nebraska
legislature passed a bill withdrawing Nebraska from the Compact. In August
1999, the Nebraska governor gave official notice of the withdrawal to the other
member states. Withdrawal will not be effective for five years and will not, of
itself, nullify the site license proceeding.
Wolf Creek disposes of all classes of its low-level radioactive waste at
existing third-party repositories. Should disposal capability become
unavailable, Wolf Creek is able to store its low-level radioactive waste in an
on-site facility for up to five years under current regulations. Wolf Creek
believes that a temporary loss of low-level radioactive waste disposal
capability will not affect continued operation of the power plant.
Wolf Creek has an 18-month refueling and maintenance schedule which permits
uninterrupted operation every third calendar year. Wolf Creek is scheduled to
be taken off-line in September 2000, for its eleventh refueling and maintenance
outage. During the outage, electric demand is expected to be met primarily by
our 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 12 of the
Notes to Financial Statements.
Power Delivery
Our Power Delivery segment transports electricity from the generating
stations to approximately 628,000 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.
<PAGE>
We are a member of the Southwest Power Pool (SPP). SPP's responsibility
is to maintain system reliability on a regional basis and is working with us and
other members to become an RTO. The region encompasses areas within the eight
states of Kansas, Missouri, Oklahoma, New Mexico, Texas, 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.
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,
day-to-day operational interface with the KCC staff, and theft, diversion, and
claims.
MONITORED SERVICES
General: Protection One is one of the leading providers of life safety and
property monitoring services, providing electronic monitoring and maintenance of
its alarm systems in 1999 to nearly 1.6 million customers in North America and
Europe. Protection One also provides its customers with enhanced services that
include:
- Extended service protection
- Patrol and alarm response
- Two-way voice communication
- Medical information service
- Cellular back-up
Approximately 85% of Protection One's revenues are contractually recurring
for monitoring alarm security systems and other related services. Protection One
has grown rapidly by participating in the organic growth in the alarm industry
and by acquiring other alarm companies.
Protection One's principal activity is responding to the security and
safety needs of its customers. Protection One's sales are generated primarily
from recurring monthly payments for monitoring and maintaining the alarm systems
that are installed in its customers' homes and businesses. Security systems are
designed to detect burglaries, fires and other events. Through a network of 57
service branches and 13 satellite offices in North America and 65 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 sold its
European operations to Westar Capital on February 29, 2000. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
Protection One provides its services to residential (both single family and
multifamily residences), commercial and wholesale customers. At December 31,
1999, Protection One's customer base composition was as follows:
<PAGE>
Market Segment % Total
Single family and commercial. . . 72%
Multifamily/Apartment . . . . . . 18%
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.
Operations: Protection One's operations consist principally of alarm
monitoring, customer service functions and branch operations. Security alarm
systems include many different types of devices installed at customers' premises
designed to detect or react to various occurrences or conditions, such as
intrusion or the presence of fire or smoke.
Protection One's alarm monitoring customer contracts generally have initial
terms ranging from one to five years in duration, and provide for automatic
renewals for a fixed period (typically one year) unless Protection One or the
customer elect 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. In the United
Kingdom, Protection One's service center was based in metropolitan London and in
continental Europe, its service centers were based in Paris and in metropolitan
Marseilles, France. The European operations are now owned by Westar Capital.
Branch Operations: Protection One maintains approximately 57 service
branches in North America from which Protection One provides field repair,
customer care, alarm response and sales services and approximately 13 satellite
locations from which Protection One provides field repair services. Protection
One's branch infrastructure plays an important role in enhancing customer
satisfaction, reducing customer loss and building brand awareness.
Customer Acquisition Strategy: From November 1997 through December 1998,
Protection One completed in excess of 30 transactions, adding approximately one
million new customers and establishing its market position. In 1998, Protection
One also expanded the dealer program for the North American single family
residential market. While Protection One relied primarily on the dealer program
for its growth in 1999, Protection One shifted its focus to a more diverse
customer acquisition strategy including a more balanced mix of dealers, internal
sales, "tuck-in" acquisitions, and direct marketing, thereby placing less
reliance on account generation through the dealer program.
<PAGE>
In February 2000, Protection One commenced a commission only internal sales
program, with a goal of acquiring accounts at a cost lower than its external
programs. Protection One is also pursuing alignments with other strategic
partners in an effort to further diversify its marketing distribution channels.
This program utilizes Protection One's existing branch infrastructure in 11
markets.
To enhance Protection One's direct marketing efforts, Protection One
entered into an agreement with Paradigm Direct LLC (Paradigm). As part of this
agreement, Protection One's marketing department moved to Paradigm with the goal
to improve the return on investment of marketing dollars. Westar Capital owns
an approximate 40% interest in Paradigm.
Network Multifamily, Inc. (Multifamily) markets its services and products
primarily to developers, owners and managers of apartment complexes and other
multifamily dwellings. Multifamily grows its business through national and
regional advertising, a nationwide professional field sales force and
affiliations with professional industry-related associations. Protection One
believes this targeted internal sales effort is an effective means of generating
sales in the multifamily market, which is comprised primarily of developers and
professionals that can be identified and contacted with relative ease.
Dealer Marketing: The dealer marketing program provides support services
to dealers as they grow their independent businesses. On behalf of the dealer
program participants, Protection One obtains purchase discounts on security
systems, coordinates cooperative dealer advertising and provides assistance in
marketing and employee training support services.
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.
Competition: The security alarm industry is highly competitive and highly
fragmented. In North America, there are only five alarm companies that offer
services across the U.S. and Canada with the remainder being either large
regional or small, privately held alarm companies. Based on number of
residential customers, Protection One believes the top five alarm companies in
North America are:
- ADT Security Services, a subsidiary of Tyco International, Inc. (ADT)
- Protection One
- SecurityLink from Ameritech, Inc., a subsidiary of Ameritech
Corporation
- Brinks Home Security Inc., a subsidiary of The Pittston Services
Group of North America
- Honeywell Inc.
Other alarm service companies have adopted a strategy similar to Protection
One 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 its rate of growth, or
to increase the price paid by Protection One for customer accounts, which would
adversely affect its return on investment in such accounts and Protection One's
results of operations.
<PAGE>
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 to 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 and dealers, its ability to offer
combined monitoring, repair and enhanced services, its low cost structure and
its marketing alliance with Paradigm.
Intellectual Property: Protection One owns trademarks related to the name
and logo for each of Protection One, Network Multifamily Security 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
it 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.
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.
<PAGE>
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 Federal
Communications Commission and state public utilities commissions regulate the
operation and utilization of radio frequencies. In addition, the laws of certain
of the 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 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 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 the loss experiences at other security service companies, may
affect the availability and cost of such insurance. Certain of Protection One's
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.
<PAGE>
GEOGRAPHIC INFORMATION
Geographic information is set forth in Note 22 of the Notes to Consolidated
Financial Statements.
EMPLOYEES
As of December 31, 1999, we had 7,049 employees, of which 4,659 are
monitored service employees. We did not experience any strikes or work
stoppages during 1999. Our current contract with the International Brotherhood
of Electrical Workers extends through June 30, 2002. The contract covers
approximately 1,475 employees. Approximately 970 monitored services employees
in France are covered by a collective bargaining agreement.
RISK FACTORS
The following risk factors highlight factors that may affect our financial
condition and results of operation:
Efforts by Wichita to Equalize Rates May Affect Operations and Results: The
average rates charged to retail customers in territories served by our KPL
division are 19% lower than KGE's rates. As a result of this rate disparity,
the City of Wichita, Kansas has taken preliminary steps toward the creation of
a municipal electric utility to replace KGE as the supplier of electricity in
Wichita, including authorizing the hiring of an outside consultant to determine
the feasibility of creating a municipal electric utility. The City of Wichita
has also filed a complaint with the FERC against KGE seeking to equalize the
generation costs between KGE and KPL, in addition to other matters. We are
unable to predict whether the City of Wichita will proceed with efforts to
create a municipal electric utility and, if so, whether these efforts would be
successful. We are also unable to predict whether settlement discussions
between the parties in the FERC proceeding will be successful. Given the
current status of these matters, the potential impact on our operations and
financial condition is unclear. We can give no assurance that the impact will
not be material and adverse.
Deregulation May Reduce Our Earnings: Electric utilities have historically
operated in a rate regulated environment. Federal and state regulatory agencies
having jurisdiction over our rates and services and other utilities are
initiating steps that are expected to result in a more competitive environment
for utility 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 our earnings which could
impact our ability to pay dividends and have a material adverse impact on our
operations and our financial condition. A material non-cash charge to earnings
would be required should we discontinue accounting under Statement of Financial
Accounting Standard No. 71 "Accounting for the Effects of Certain Types of
Regulation."
<PAGE>
Downgrade in Credit Ratings Would Increase Cost of Borrowing and Reduce
Earnings: Credit rating agencies are applying more stringent guidelines when
rating utility companies due to increasing competition and utility investment in
non-utility businesses. Moody's has announced that our ratings are on review
for possible downgrade. Both Standard & Poor's Rating Group and Fitch Investors
Service have given our credit ratings a negative outlook. A downgrade in our
credit ratings will likely increase our cost of borrowing and decrease earnings.
Electric Fuel Costs are Included in Base Rates: 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 which 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, including the amount by which fuel costs increased, and thus cannot
be predicted.
Purchased Power Prices are Volatile: In 1999 and 1998, the wholesale power
market experienced extreme volatility in prices and supply. This volatility
impacts our costs of power purchased and our participation in power trades. If
we were unable to generate an adequate supply of electricity for our customers,
we would have to purchase power in the wholesale market or implement curtailment
or interruption procedures. To the extent open positions exist in our power
marketing activity, we are exposed to fluctuating market prices that may
adversely impact our financial position and results of operations. The
increased expenses associated with this could be material and adverse to our
consolidated results of operations and financial condition.
Protection One Losses Are Likely to Continue: Protection One has a history
of significant net losses which are expected to continue. These losses
increased in 1999, and are likely to be larger in the near future, due to
accelerated amortization of customer accounts, a shorter period for amortizing
goodwill, and potentially higher borrowing costs since Protection One's credit
ratings have recently been downgraded. The ratings downgrade may also make it
more difficult for Protection One to refinance its credit facility with Westar
Capital which matures on January 2, 2001, or to obtain other capital.
There can be no assurance that Protection One will attain profitable operations.
The Impact of Protection One Class Action Litigation May Be Material: We,
Protection One and certain of its officers are defendants in a class action
litigation pending in the U.S. District Court for the Central District of
Californian brought on behalf of shareholders of Protection One. The plaintiffs
are seeking unspecified compensatory damages based on allegations that various
statements concerning Protection One's financial results and operations for 1997
and 1998 were false and misleading. We and Protection One cannot currently
predict the impact of this litigation which could be material to Protection One.
See "Legal Proceedings."
For additional risk factors relating to Protection One, see its December
31, 1999 Annual Report on Form 10-K.
<PAGE>
<TABLE>
EXECUTIVE OFFICERS OF THE COMPANY
<CAPTION>
Other Offices or Positions
Name Age Present Office Held During Past Five Years
<S> <C> <C> <C>
David C. Wittig 44 Chairman of the Board Executive Vice President,
(since January 1999) Corporate Strategy
Chief Executive Officer (May 1995 to March 1996)
(since July 1998) Salomon Brothers Inc. - Managing Director,
and President Co-Head of Mergers and Acquisitions
(since March 1996) (1989 to 1995)
Thomas L. Grennan 47 Executive Vice President, Senior Vice President, Electric Operations
Electric Operations (September 1998 to November 1998)
(since November 1998) Vice President, Generation Services
(May 1995 to August 1998)
Vice President, Electric Production
(February 1994 to May 1995)
Carl M. Koupal, Jr. 46 Executive Vice President Executive Vice President
and Chief Administrative Corporate Communications,
Officer (since July 1995) Marketing, and Economic Development
(January 1995 to June 1995)
Vice President, Corporate Communications,
Marketing, and Economic Development
(March 1992 to January 1995)
Douglas T. Lake 49 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 47 Executive Vice President, Acting Executive Vice President,
Chief Financial Officer Chief Financial Officer and
and Treasurer Treasurer (October 1998 - May 1999)
(since May 1999) Kansas Gas and Electric Company -
Chairman of the Board
(June 1995 to January 1999)
President (June 1995 to October 1998)
Western Resources, Inc. -
Vice President, Electric Division (1996)
Vice President, Finance
(April 1992 to June 1995)
Richard D. Terrill 45 Executive Vice President, Vice President, Law and Corporate
General Counsel and Secretary (July 1998-May 1999)
Corporate Secretary Secretary and Associate General
(since May 1999) Counsel (April 1992 to June 1998)
Rita A. Sharpe 41 Vice President, Shared Westar Energy, Inc, -
Services (since October Chairman and President (Feb. 1997-
1998) October 1998)
Vice President and Assistant Secretary
(May 1995-February 1997)
Western Resources, Inc. -
Manager, Interchange Sales and
Accounting (1992-May 1995)
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 or
she was appointed as an executive officer.
</TABLE>
<PAGE>
ITEM 2. PROPERTIES
ELECTRIC UTILITY OPERATIONS
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 70.0
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 151.0
2 1967 Gas--Oil 376.0
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18.0
2 1950 Gas 18.0
3 1951 Gas 28.0
4 1965 Gas 191.0
Combustion Turbines 1 1974 Gas 53.0
2 1974 Gas 52.0
3 1974 Gas 55.0
4 1975 Oil--Diesel 83.0
Diesel Generator 1 1983 Diesel 3.0
Jeffrey Energy Center (84%)(a):
Steam Turbines 1 1978 Coal 625.0
2 1980 Coal 622.0
3 1983 Coal 623.0
Wind Turbines 1 1999 - 0.5
2 1999 - 0.5
La Cygne Station (50%):
Steam Turbines 1 (a) 1973 Coal 344.0
2 (b) 1977 Coal 337.0
Lawrence Energy Center:
Steam Turbines 2 (c) 1952 Gas 0.0
3 1954 Coal 59.0
4 1960 Coal 119.0
5 1971 Coal 394.0
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 44.0
2 1954 Gas--Oil 74.0
3 1956 Gas--Oil 108.0
4 1959 Gas--Oil 106.0
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 67.0
<PAGE>
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 85.0
8 1962 Coal 158.0
Combustion Turbines 1 1972 Gas 20.0
2 1972 Gas 21.0
Wichita Plant:
Diesel Generator 5 1969 Diesel 3.0
Wolf Creek Generating Station (47%)(a):
Nuclear 1 1985 Uranium 550.0
Total 5,458.0
(a) The company jointly owns Jeffrey Energy Center (84%), La Cygne 1 generating
unit, (50%) and Wolf Creek Generating Station (47%).
(b) In 1987, KGE entered into a sale leaseback transaction involving its 50%
individual interest in the La Cygne 2 generating unit.
(c) Unit was previously "mothballed" for future use and will be retired in 2000.
We own approximately 6,300 miles of transmission lines, approximately
20,800 miles of overhead distribution lines, and approximately 4,200 miles of
underground distribution lines.
Substantially all of our utility properties are encumbered by first
priority mortgages pursuant to which bonds have been issued.
MONITORED SERVICES
Protection One maintains its executive offices at 6011 Bristol Parkway,
Culver City, California 90230 and its main financial and administrative offices
at 818 South Kansas Avenue, Topeka Kansas 66612. Protection One operates
primarily from the following facilities, although Protection One leases office
space for its approximate 57 service branch offices and 13 satellite branches in
North America.
<PAGE>
<TABLE>
<CAPTION>
Size
Location (Sq. ft.) Lease/Own Principal Purpose
<S> <C> <C> <C>
United States:
Addison, TX. . . . 28,512 Lease Service Center/Administrative
Headquarters
Beaverton, OR. . . 44,600 Lease Service Center
Chatsworth, CA . . 43,472 Lease Marketing Call Center
Culver City, CA. . 23,520 Lease Former Corporate Headquarters (1)
Culver City, CA. . 8,029 Lease Current Corporate Headquarters
Hagerstown, MD . . 21,370 Lease Service Center
Irving, TX . . . . 53,750 Lease Service Center
Irving, TX . . . . 54,394 Lease Administrative Functions
Orlando, FL. . . . 11,020 Lease Wholesale Service Center
Topeka, KS . . . . 6,996 Lease Financial/Administrative Headquarters
Wichita, KS. . . . 50,000 Own Service Center/Administrative Functions
</TABLE>
<TABLE>
<CAPTION>
Size
Location (Sq. ft.) Lease/Own Principal Purpose
<S> <C> <C> <C>
Canada:
Ottawa, ON . . . . 7,937 Lease Service Center/Administrative
Headquarters
Vancouver, BC. . . 5,177 Lease Service Center
Europe (2):
Basingstoke (London),
UK . . . . . . . 3,500 Lease Financial/Administrative
Headquarters/Service Center
Paris, FR. . . . . 3,498 Lease Financial/Administrative
Headquarters/Service Center
Vitrolles
(Marseilles) FR. . 13,003 Lease Administrative/Service
Center
(1) In March 2000, the lease for Protection One's former corporate headquarters
was terminated.
(2) On February 29, 2000, Westar Capital purchased Protection One's European operations.
</TABLE>
ITEM 3. LEGAL PROCEEDINGS
The Securities and Exchange Commission (SEC) commenced a private
investigation in 1997 relating to, among other things, 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, Westar Capital, Protection One, its subsidiary Protection One
Alarm Monitoring, Inc. (Monitoring), and certain present and former officers and
directors of Protection One are defendants in a purported class action
litigation pending in the United States District Court for the Central District
of California, "Ronald Cats, et al., v. Protection One, Inc., et. al.",
No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four
pending purported class actions were consolidated into a single action. In
March 2000, plaintiffs filed a Second Consolidated Amended Class Action
Complaint (the Amended Complaint). Plaintiffs purport to bring the action on
behalf of a class consisting of all purchasers of publicly traded securities of
Protection One, including common stock and notes, during the period of
February 10, 1998, through November 12, 1999. The Amended Complaint asserts
claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the
Securities Exchange Act of 1934 against Protection One, Monitoring, and certain
present and former officers and directors of Protection One based on allegations
that various statements concerning Protection One's financial results and
operations for 1997 and 1998 were false and misleading and not in compliance
with Generally Accepted Accounting Principals (GAAP). Plaintiffs allege,
among other things, that former employees of Protection One have reported that
Protection One lacked adequate internal accounting controls and that certain
accounting information was unsupported or manipulated by management in order to
avoid disclosure of accurate
<PAGE>
information. The Amended Complaint further asserts claims against the company
and Westar as controlling persons under Sections 11 and 15 of the Securities Act
of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A
claim is also asserted under Section 11 of the Securities Act of 1933 against
Protection One's auditor, Arthur Andersen LLP. The Amended Complaint seeks an
unspecified amount of compensatory damages and an award of fees and expenses,
including attorneys' fees. The company and Protection One believe that all the
claims asserted in the Amended Complaint are without merit and intend to defend
against them vigorously. The company and Protection One cannot currently
predict the impact of this litigation which could be material to Protection One.
Additional information on legal proceedings involving the company is set
forth in Notes 13 and 14 of Notes to Consolidated Financial Statements herein.
See also Item 1. Business, Environmental Matters and Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of fiscal 1999 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 March 24, 2000, there were
50,680 common shareholders of record. For information regarding quarterly
common stock price ranges for 1999 and 1998, see Note 23 of Notes to
Consolidated Financial Statements.
Dividends
Holders of Western Resources common stock are entitled to dividends when
and as declared by the Board of Directors. At December 31, 1999, 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.
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. The company's board of directors reviews
its dividend policy on an annual basis. Among the factors typically considered
in determining its dividend policy are earnings, cash flows, capitalization
ratios, competition and regulatory conditions. In January 2000, the company's
board of directors declared a first-quarter 2000 dividend of 53 1/2 cents per
share. In March 2000, the company announced a new dividend policy. See Note 24
of Notes to Consolidated Financial Statements for further discussion.
For information regarding quarterly dividend declarations for 1999 and
1998, see Note 23 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, 1999(1) 1998(2) 1997(3) 1996 1995
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Sales. . . . . . . . . . . . . . . $2,036,158 $2,034,054 $2,151,765 $2,046,827 $1,744,274
Net income before
extraordinary gain. . . . . . . . 717 46,165 499,518 168,950 181,676
Earnings available for common
stock . . . . . . . . . . . . . . 11,330 44,165 494,599 154,111 168,257
December 31, 1999(1) 1998(2) 1997(3) 1996 1995
(Dollars in Thousands)
Balance Sheet Data:
Total assets . . . . . . . . . . . $8,008,206 $7,951,428 $6,959,550 $6,647,781 $5,490,677
Long-term debt, preference
stock, and other mandatorily
redeemable securities . . . . . . 3,103,066 3,283,064 2,458,034 1,951,583 1,641,263
Year Ended December 31, 1999(1) 1998(2) 1997(3) 1996 1995
Common Stock Data:
Earnings per share available for
common stock before extraordinary
gain. . . . . . . . . . . . . . . $(0.01) $ 0.65 $ 7.59 $ 2.41 $ 2.71
Earnings per share available for
common stock. . . . . . . . . . . $ 0.17 $ 0.67 $ 7.59 $ 2.41 $ 2.71
Dividends per share (4). . . . . . $ 2.14 $ 2.14 $ 2.10 $ 2.06 $ 2.02
Book value per share . . . . . . . $27.83 $29.40 $30.88 $25.15 $24.71
Average shares outstanding(000's). 67,080 65,634 65,128 63,834 62,157
(1) Information reflects the impairment of marketable securities and a change to an accelerated
amortization method for Protection One customer accounts.
(2) Information reflects exit costs associated with international power development activities.
(3) Information reflects the gain on the sale of Tyco common shares, our strategic alliance
with ONEOK and the acquisition of Protection One.
(4) In March 2000, the company announced a new dividend policy. See Note 24 of Notes to Consolidated
Financial Statements for further discussion.
</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 1999 and 1998
- 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 1999
- What we expect our capital expenditures to be for the years 2000
through 2002
- 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 __. These statements show our
operating results for 1999, 1998 and 1997. In Management's Discussion and
Analysis, we analyze and explain the significant annual changes of specific line
items in the Consolidated Statements of Income.
SUMMARY OF SIGNIFICANT ITEMS
Extraordinary Gain on Retirement of Protection One Bonds
In the fourth quarter 1999, Westar Capital purchased Protection One bonds
in the open market. We have recognized an extraordinary gain of $13.4 million,
net of tax, at December 31, 1999 related to the retirement of this debt. These
bonds were transferred to Protection One on February 29, 2000, when Westar
Capital purchased the continental European and United Kingdom operations of
Protection One, and certain investments held by a subsidiary of Protection One.
Marketable Securities
During the fourth quarter of 1999, we decided to sell our remaining
marketable security investments in paging industry companies. These securities
have been classified as available-for-sale; therefore, changes in market value
have been historically reported as a component of other comprehensive income.
The market value for these securities declined during the last six to nine
months of 1999. We determined that the decline in value of these securities was
other than temporary and a charge to earnings for the decline in value was
required at December 31, 1999. Therefore, we recorded a non-cash charge of
$76.2
<PAGE>
million in the fourth quarter of 1999. This charge to earnings has been
presented separately in the accompanying Consolidated Statements of Income.
In February 2000, Metrocall, Inc. (Metrocall), a paging company whose
securities were included in our investment portfolio at December 31, 1999, made
an announcement that significantly increased the market value of paging company
securities in the public markets. During the first quarter of 2000, we sold
these paging securities and realized a gain of $24.9 million.
Termination of Merger Agreement with Kansas City Power & Light Company
On March 18, 1998, we signed an Amended and Restated Plan of Agreement and
Plan of Merger with the Kansas City Power & Light Company (KCPL) under which
KGE, KPL, and KCPL would have been combined into a new company called Westar
Energy, Inc. KCPL has notified us that it has terminated the contemplated
transaction. We expensed costs related to the KCPL merger of approximately
$17.6 million at December 31, 1999.
Protection One Accounting Change
Protection One performed a review of its amortization policy relating to
customer accounts and identified three distinct pools, each of which has
distinct attributes that effect differing attrition characteristics. The pools
correspond to its North America and Multifamily business segments and its former
European business segment. For the North America and Europe pools, the analyzed
data indicated that a change from a straight-line to a declining balance
(accelerated) method would more closely match future amortization cost with the
estimated revenue stream from these assets. Protection One elected to change to
that method for its North America and Europe pools of customers. No change was
made in the method used for the Multifamily pool. See Note _ of Notes to
Consolidated Financial Statements for further discussion.
Protection One Impairment Test
Protection One also performed an impairment test of its customer accounts
and related goodwill under the guidance of the Statement of Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (SFAS 121). Paragraph 6 of SFAS 121
indicates that an impairment loss should be recognized only if the sum of the
expected future cash flows (undiscounted and without interest charges) is less
than the carrying amount of the asset(s) grouped at the lowest level of
identifiable cash flows. After performing the test, Protection One determined
that the customer accounts are not currently impaired.
Protection One Change in Estimate of Useful Life of Goodwill
In conjunction with the impairment test for customer accounts, Protection
One also re-evaluated the original assumptions and rationale utilized in the
establishment of its carrying value and estimated useful life of goodwill.
Protection One concluded that due to continued losses and increased
<PAGE>
levels of attrition experienced in 1999, the estimated useful life of goodwill
should be reduced from 40 years to 20 years. As of January 1, 2000, the
remaining goodwill, net of accumulated amortization, will be amortized over its
remaining useful life based on a 20-year life. On Protection One's existing
account base, Protection One anticipates that this will result in an increase
in annual goodwill amortization of approximately $34 million prospectively.
OPERATING RESULTS
Western Resources Consolidated
1999 Compared to 1998: Basic earnings per share were $0.17 compared to
$0.67 in 1998. The company's 1999 results of operations benefited from the
strong performance of the regulated electric utility operations. However, this
strong performance was not sufficient to compensate for the changes to earnings
discussed above or the performance of our monitored services business. The
impact of the monitored services business on basic earning per share was
$(1.05), compared to $(0.03) in 1998.
1998 Compared to 1997: Basic earnings per share were $0.67 compared to
$7.59. Operating results for 1998 are difficult to compare to 1997 due
primarily to 1998 charges to income and the 1997 pre-tax gain on the sale of
Tyco International Ltd. (Tyco) common stock of $864.2 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 $24.3 million to reflect the impairment of assets and the closing
of business activities.
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 energy sales, related cost of sales and operating expenses in 1997
for our natural gas business have been replaced by investment earnings in ONEOK.
The following discussion explains significant changes from prior year
results in sales, costs of sales, operating expenses, other income (expense),
interest expense, income taxes, and preferred and preference dividends.
Electric Utility
Electric sales include sales from fossil generation, nuclear generation,
power marketing and power delivery operations. The KCC and the FERC authorize
rates for our electric sales. Power marketing is only regulated by the FERC. We
expanded into both the marketing of electricity and risk management services to
wholesale electric customers and the purchase of electricity for retail
customers. Changing weather affects the amount of electricity our customers
use. Very hot summers and very cold winters prompt more demand, especially
among our
<PAGE>
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
- The City of Wichita's attempt to create a municipal electric utility
- The cost of fuel included in base rates
The following tables reflect the changes in electric sales volumes
(excluding power marketing), for the years ended December 31, 1999, 1998 and
1997:
1999 1998 % Change
(Thousands of MWH)
Residential . . . . 5,551 5,815 (4.5)%
Commercial . . . . 6,202 6,199 0.1 %
Industrial . . . . 5,743 5,808 (1.1)%
Other . . . . . . . 108 108 (0.2)%
Total retail. . . 17,604 17,930 (1.8)%
Wholesale . . . . . 5,617 4,826 16.4 %
Total . . . . . . 23,221 22,756 2.0 %
1998 1997 % Change
(Thousands of MWH)
Residential . . . . 5,815 5,310 9.5 %
Commercial . . . . 6,199 5,803 6.8 %
Industrial . . . . 5,808 5,714 1.6 %
Other . . . . . . . 108 107 1.0 %
Total retail. . . 17,930 16,934 5.9 %
Wholesale . . . . . 4,826 5,334 (9.5)%
Total . . . . . . 22,756 22,268 2.2 %
1999 compared to 1998: Electric utility gross profit increased 3%, or $30.5
million. Gross profit as a percentage of sales improved to 67% from 57%. These
improvements are due primarily to increased power marketing profit and increased
wholesale sales. In the summer of 1999, we had increased power plant
availability during hot weather when demand was high which allowed increased
wholesale sales. Power plant availability impacts both gross profit and gross
profit percentage, as it is more profitable for us to generate electricity for
resale than to purchase power for resale. Partially offsetting these increases
were lower retail sales due to weather which was milder in 1999.
1998 compared to 1997: Electric utility gross profit increased 8%, or $68.3
million. This improvement occurred because our retail sales volumes increased
<PAGE>
$66 million as a result of warmer summer temperatures but electric cost of sales
only increased $4.6 million because Wolf Creek operated the entire year without
any outages. Our retail sales would have been higher had we not implemented an
electric rate decrease on June 1, 1998. See Note 14 of Notes to Consolidated
Financial Statements for further information on our electric rate decreases.
Gross profit as a percentage of sales decreased to 57% from 69%. In 1997,
we made a strategic decision to expand our power marketing business to better
utilize our generating assets and to reduce risk associated with energy prices.
In 1997, our power marketing activity had an insignificant effect on gross
profit. In 1998, we had power marketing sales of $382.6 million, but our net
profit on power marketing transactions was significantly less than our net
profit on our traditional electric sales.
Items included in energy cost of sales are fuel expense, purchased power
expense (electricity we purchase from others for resale) and power marketing
expense.
BUSINESS SEGMENTS
We have defined four business segments: fossil generation, nuclear
generation, power delivery and monitored services, based on how management
currently evaluates our business. Our business segments are 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.
The following discussion identifies key factors affecting our electric
business segments.
<PAGE>
1999 1998 1997
Fossil Generation: (Dollars in Thousands)
External sales . . . . . . . . . . $ 365,311 $ 525,974 $ 208,836
Internal sales . . . . . . . . . . 546,683 517,363 517,167
Depreciation and amortization . . 55,320 53,132 53,831
EBIT . . . . . . . . . . . . . . . 219,087 144,357 149,825
Nuclear Generation:
Internal sales . . . . . . . . . . $ 108,445 $ 117,517 $ 102,330
Depreciation and amortization. . . 39,629 39,583 65,902
EBIT . . . . . . . . . . . . . . . (25,214) (20,920) (60,968)
Power Delivery:
External sales . . . . . . . . . . $1,064,385 $1,085,711 $1,021,212
Internal sales . . . . . . . . . . 293,522 66,492 66,492
Depreciation and amortization. . . 71,717 68,297 63,590
EBIT . . . . . . . . . . . . . . . 145,603 196,398 173,809
Fossil Generation
Fossil Generation's external sales include power produced for sale to
external wholesale customers located outside our historical marketing territory.
Internal sales include power produced for sale to Power Delivery. Internal
sales are made at an internal transfer price which is based upon an assumed
competitive market price for capacity and energy.
1999 compared to 1998: External sales decreased $160.7 million, or 31%,
primarily due to lower power marketing sales. Power marketing sales decreased
$192.5 million, or 50%, due to milder weather compared to last year. In 1999
and 1998, the wholesale power market experienced extreme volatility in prices
and supply. This volatility impacts our cost of power purchased and our
participation in power trades.
The decrease in power marketing sales was partially offset by higher
wholesale sales of $29.6 million. Due to warmer than normal weather throughout
the Midwest in July and increased availability of our coal-fired generation
stations, we were able to sell more electricity to wholesale customers in 1999
than in 1998. During the summer of 1998, one of our coal-fired generation units
was unavailable for an extended period of time, reducing our wholesale sales
capacity.
The internal transfer price Fossil Generation charged Power Delivery was
higher due to a higher forecasted peak demand. Therefore, internal sales and
EBIT of Fossil Generation were higher. EBIT was also higher due to improved
net profit on power marketing transactions.
1998 compared to 1997: External sales increased $317.1 million, mostly
because of increased power marketing sales of $312.8 million.
EBIT for 1998 decreased from 1997 because we had higher cost of sales of
$4.6 million due primarily to a coal-fired generation station being
unavailable for the summer. The availability of our generating units and
purchased power from other companies also impact power marketing sales.
<PAGE>
Nuclear Generation
Nuclear generation has no external sales because it provides all of its
power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc.
Internal sales include the internal transfer price that Nuclear Generation
charges to Power Delivery. The amounts in the table above are our 47% share of
Wolf Creek's operating results. EBIT is negative because internal sales are
less than Wolf Creek's costs.
Wolf Creek has a scheduled refueling and maintenance outage approximately
every 18 months. The next outage is scheduled in September 2000. During an
outage Wolf Creek produces no power for its co-owners; therefore internal sales
and EBIT decrease and nuclear fuel expense decreases.
1999 compared to 1998: Internal sales and EBIT decreased primarily due to
the scheduled 36-day refueling and maintenance outage at Wolf Creek in 1999. In
1998, Wolf Creek operated the entire year without any outages.
1998 compared to 1997: Internal sales and EBIT were higher in 1998 than in
1997 because the Wolf Creek facility was off-line for 58 days in 1997 for a
scheduled maintenance outage.
Depreciation and amortization expense decreased $26.3 million because we
had fully amortized a regulatory asset during 1997. This decrease in
amortization expense increased EBIT for 1998.
Power Delivery
Power Delivery's external sales consist of the transmission and
distribution of power to our Kansas electric customers and the customer service
provided to them. Internal sales include an intra-segment transfer price for
charges for the use of the distribution lines and transformers.
1999 compared to 1998: External sales decreased $21.3 million due
primarily to 2% lower retail electric sales volume. Retail sales volumes
decreased primarily as a result of milder temperatures in 1999. Our service
territories averaged 22% fewer cooling degree days in 1999. The cumulative
effect of the electric rate decreases implemented on June 1, 1998, and June 1,
1999, reduced sales by approximately $10 million.
Internal sales were $227 million higher due to a change in the internal
transfer price charged for the use of the distribution lines and transformers.
EBIT decreased $50.8 million primarily due to $21.3 million lower external
sales, a $16.1 million higher internal transfer price charged by Fossil
Generation and $8.3 million in ancillary service fees charged by Fossil
Generation. The increased internal transfer price was due to higher peak demand
to accommodate air conditioning load. No ancillary service fees were charged by
Fossil Generation in 1998.
1998 compared to 1997: External sales and EBIT increased. In addition to
our normal customer growth, we experienced warmer weather during the summer
<PAGE>
months in 1998 than we did in 1997 which improved external sales approximately
$41.9 million. The effect of our electric rate decrease lowered 1998 external
sales approximately $11 million.
Monitored Services
Protection One operates and manages our monitored services interest. The
results discussed below reflect Protection One on a stand-alone basis and do not
take into consideration the minority interest of approximately 15% at December
31, 1999 and 1998.
1999 1998 1997
(Dollars in Thousands)
External sales. . . . . . . . . $605,176 $421,095 $152,347
Depreciation and amortization . 238,803 117,651 41,179
EBIT. . . . . . . . . . . . . . (24,013) 56,727 (38,517)
1999 compared to 1998: Protection One had a net increase of 8,595
customers in 1999 as compared to a net increase of 445,156 customers in 1998.
Accordingly, results for 1999 include a full year of operations with the
customers added throughout 1998. The increase in customers is the primary
reason for the $184.1 million increase in external sales.
EBIT decreased $80.7 million due to higher cost of sales as a result of
increased customers, higher depreciation and amortization expense and higher
selling general and administrative expenses.
Depreciation and amortization expense increased $121.2 million. As
discussed above in SUMMARY OF SIGNIFICANT ITEMS, Protection One changed its
customer amortization method from a 10-year straight line method to a 10-year
declining balance method which resulted in an increase in amortization expense
of approximately $50 million. The balance of the increase is primarily
attributed to a full year of amortization expense on customers acquired during
1998.
Selling, general and administrative expenses increased $71.5 million
primarily due to costs associated with the overall increase in the average
number of customers billed, additional bad debt expense of approximately
$10.5 million resulting from higher attrition, costs associated with Year 2000
compliance, professional fees and salary increases.
1998 compared to 1997: Monitored services sales increased $268.7 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 which 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 $37.9 million.
Protection One added
<PAGE>
approximately $16.6 million of monthly recurring revenue from acquisitions and
approximately $5.3 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 $21.9 million of acquired monthly recurring
revenue is reflected in 1998 results. Offsetting these revenue increases was
Protection One's net monthly recurring revenue losses of 9%.
Cost of sales increased $93.4 million. Monitoring and related services
expenses increased by $70.9 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.
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 sales 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 $117.7 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.
EBIT increased $95.2 million. Included in 1998 EBIT is a non-recurring
gain approximating $16.3 million on the repurchase of customer contracts covered
by a financing arrangement. A charge of approximately $24.3 million adversely
affected 1997 EBIT. The charge was needed to reflect the impairment of certain
assets and the closing of business activities.
Western Resources Consolidated
Other Operating Expenses
In 1999, we recorded a charge of $17.6 million for deferred KCPL merger
costs related to the termination of the KCPL merger.
In 1998, we recorded a $98.9 million charge to income associated with our
decision to exit the international power project development business.
Activities associated with the exit plan were substantially complete at December
31, 1999. See Note 16 of Notes to Consolidated Financial Statements for further
discussion.
<PAGE>
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 $24.3 million to reflect the impairment of
certain assets and the closing of business activities.
Other Income (Expense)
Compared to 1998, other income for 1999 decreased $69.5 million primarily
due to the other than temporary decline in the value on marketable securities
recorded in 1999. Compared to 1997, other income for 1998 decreased $865.4
million primarily due to the gain recognized in 1997 on the sale of our Tyco
common stock.
Interest Expense
1999 compared to 1998: Interest expense represents the interest we paid on
outstanding debt. Interest expense increased 30% because Protection One
borrowed additional long-term debt primarily to fund purchases of customer
accounts. Western Resources also had higher long-term debt interest expense
because of the 6.25% and 6.8% unsecured senior notes due 2018 that we issued in
third quarter of 1998. Short-term debt interest expense was $2.4 million higher
due to higher average balances of short-term debt in 1999.
1998 compared to 1997: 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.
Income Taxes
1999 compared to 1998: We have recorded an income tax benefit in 1999 of
$33 million and income tax expense in 1998 of $15 million. This change is
primarily due to lower earnings before income taxes in 1999. Earnings before
income taxes decreased primarily due to operating results at Protection One, an
impairment of the marketable securities discussed above and the charge related
to the termination of the KCPL merger.
We also had tax expense of $7.2 million related to Westar Capital's
extraordinary gain on the purchase of Protection One bonds, which is presented
separately on the consolidated statement of income after income from continuing
operations.
Our effective income tax rates are affected by the receipt of non-taxable
proceeds from our corporate owned life insurance policies, the tax benefit from
excluding 70% of the dividends received from ONEOK, the generation and
<PAGE>
utilization of tax credits from Affordable Housing investments, the amortization
of prior years' investment tax credits, and the amortization of non-deductible
goodwill.
1998 compared to 1997: Income tax expense declined significantly due to the
decline in taxable net income. Tax expense for 1997 included taxes related to
the gain on the sale of Tyco common stock. Our effective tax rate also declined
from 1997.
Preferred and Preference Dividends
On April 1, 1998, we redeemed the 7.58% preference stock due 2007. This
redemption has resulted in a significant decline in preferred and preference
dividends since 1997.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and
maintenance costs associated with the electric utility business, cash needs of
our monitored services business for customer account growth and infrastructure,
debt service and cash payments of common stock dividends. Our ability to
attract necessary financial capital on reasonable terms is critical to our
verall business plan. Historically, we have paid for these items with cash on
hand, 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.
We had $15.8 million in cash and cash equivalents at December 31, 1999.
We consider highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. At December 31, 1999, we had
approximately $705.4 million of short-term debt outstanding, of which $535.4
million was commercial paper. Current maturities of long-term debt were $111.7
million at December 31, 1999.
As of December 31, 1999, we had arrangements with certain banks to provide
unsecured short-term lines of credit on a committed basis totaling approximately
$1.1 billion. The unused portion of these lines of credit was used to provide
support for commercial paper.
The unsecured short-term lines of credit included three revolving credit
facilities with various banks as follows:
Amount Facility Termination Date
$300 million 364-day March 15, 2000
500 million 5-year March 17, 2003
250 million 6 1/2-month June 30, 2000
<PAGE>
In March 2000, we amended the $300 million facility to reduce the
commitment to $242 million and to extend the maturity date to June 30, 2000. We
also amended all of these credit facilities to reflect the possibility of
borrowing from them rather than using them to provide support for commercial
paper borrowings. As a result of these amendments our cost of borrowing will be
higher. A one percent increase in our interest rate on our outstanding
short-term debt balance as of December 31, 1999, would have increased our annual
interest expense by $7 million. We cannot predict the market conditions or our
credit ratings at the time we may borrow from these facilities; and therefore,
cannot predict how much higher our interest expense might be.
Amendments to the credit facilities include increased pricing to reflect
credit quality and the potential drawn nature of credit facilities rather than
support for commercial paper, redefinition of the total debt to capital
financial covenant, limitation on use of proceeds from sale of first mortgage
bonds requiring repayment of debt outstanding under the credit facilities before
proceeds may be used for other purposes, and a commitment to use our "best
efforts" to pledge first mortgage bonds to support our credit facilities if our
senior unsecured credit rating drops below "investment grade" (bonds rated below
BBB by Standard & Poor's (S&P) and Fitch and below Baa by Moody's Investors
Service (Moody's)).
In order to maintain adequate short-term borrowing capacity, we expect to
replace or further amend these credit facilities prior to their termination.
In January 2000, we reached an agreement with our banks under our current
credit facilities to eliminate a cross-default provision relating to Protection
One and its subsidiaries, provided we do not increase our investment in
Protection One by more than $225 million or $125 million if our senior unsecured
credit ratings drop below investment grade as determined by S&P and Moody's. We
borrowed $225 million in short-term debt in 1999 to fund Westar Capital's
revolving credit agreement to Protection One. We may borrow additional short-
term debt from time-to-time to fund Protection One's revolving credit agreement.
We have registered securities for sale with the Securities and Exchange
Commission (SEC). As of December 31, 1999, these included $400 million of
unsecured senior notes, $50 million of KGE first mortgage bonds and
approximately 11.2 million Western Resources common shares.
Our ability to issue additional debt and equity securities is restricted
under limitations imposed by the charters and the Mortgage and Deed of Trusts of
Western Resources and KGE.
Our mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless our unconsolidated 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
<PAGE>
the proposed issuance. Based on our results for the 12 months ended
December 31, 1999, $410 million of first mortgage bonds could be issued
(8.25% interest rate assumed).
Our 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, 1999, we had approximately $365 million of net bondable property
additions not subject to an unfunded prior lien entitling us to issue up to
219 million principal amount of additional bonds. As of December 31, 1999,
$125 million in additional first mortgage bonds could be issued on the basis
of retired bonds.
KGE's mortgage prohibits additional 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 either 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. In addition, the issuance of
bonds is subject to limitations based upon the amount of bondable property
additions. Based on KGE's results for the 12 months ended December 31, 1999,
approximately $1.0 billion principal amount of additional KGE first mortgage
bonds could be issued (8.25% interest rate assumed) under the most restrictive
tests in the mortgage. As of December 31, 1999, $17 million in additional bonds
could be issued on the basis of retired bonds.
We plan to sell, subject to market and other conditions, up to $500 million
of first mortgage bonds in 2000.
S&P, Fitch Investors Service (Fitch) and Moody's are independent credit-
rating agencies that rate our debt securities. These ratings indicate the
agencies' assessment of our ability to pay interest and principal on these
securities.
<TABLE>
As of March 24, 2000, ratings with these agencies were as follows:
<CAPTION>
Western Western KGE's Protection Protection
Resources' Western Resources' KGE's Senior One One
Mortgage Resources' Short-term Mortgage Unsecured Senior Senior
Bond Unsecured Debt Bond Debt Unsecured Subordinated
Rating Agency Rating Debt Rating Rating Rating Debt Unsecured Debt
<S> <C> <C> <C> <C> <C> <C> <C>
S&P A- BBB A-2 BBB+ BBB BB- B
Fitch A- BBB+ F-2 A- - BB B+
Moody's A3 Baa1 P-2 A3 Baa3 B2 Caa1
</TABLE>
<PAGE>
Credit rating agencies are applying more stringent guidelines when rating
utility companies due to increasing competition and utility investment in non-
utility businesses. In January 2000,in response to the terminated KCP&L merger
and unprofitable operations and liquidity issues at Protection One, Moody's
announced they were placing Western Resources and KGE ratings on review for
possible downgrade, S&P affirmed its ratings of Western Resources and KGE, but
said the outlook is negative, and Fitch placed the ratings of Western Resources
and KGE on RatingAlert - Negative. We anticipate that these rating agencies
will complete their reviews and lower our credit ratings in the near future,
but we cannot predict our new ratings.
In response to liquidity and operational issues and the announcement by
Western Resources that it is exploring strategic alternatives for Protection
One, in November 1999, Moody's, S&P and Fitch downgraded their ratings on
Protection One's credit facility and outstanding securities. On March 24, 2000,
Moody's further downgraded their ratings on Protection One's outstanding
securities with outlook remaining negative.
Should our short-term debt ratings be lowered, access to the commercial
paper market, when available, would be more costly and may require borrowing
from our existing revolving credit facilities.
Cash Flows from Operating Activities
Cash from operations decreased 7% in 1999 compared to 1998. This decrease
was primarily due to lower net income in 1999 and higher amortization expense
recorded by Protection One.
Cash Flows Used In Investing Activities
Cash used in investing activities decreased 62% primarily due to fewer
acquisitions of monitored services companies and customer accounts and fewer
purchases of marketable securities than in 1998. This decrease was offset by
higher capital expenditures in 1999.
Cash Flows from Financing Activities
Cash from financing activities decreased 86% because we issued less debt
as a result of fewer acquisitions by Protection One in 1999 compared to 1998.
The decrease in long-term debt proceeds was offset by increased short-term
borrowings used to fund Westar Capital's revolving credit agreement to
Protection One.
In July 1999, we announced a stock repurchase program for up to $25 million
of our common stock. In 1999, we purchased 900,000 shares of common stock at an
average price of $17.55 per share. In January 2000, we purchased another
540,000 shares of common stock at an average price of $17.01 per share to
complete our repurchase of approximately $25 million in common stock. All
of these purchased shares will be held in treasury and will be available for
general corporate purposes or resale at a future date. We may make additional
repurchases of shares from time-to-time in the open market or in private
transactions. We may
<PAGE>
also make additional purchases of Protection One bonds from time to time in the
open market.
Future Cash Requirements
We believe that internally generated funds and access to capital markets
will be sufficient to meet our operating and capital expenditure requirements,
debt service and dividend payments through the year 2002. Uncertainties
affecting our ability to meet these requirements with internally generated funds
include the factors affecting sales described above, the impact of inflation on
operating expenses, regulatory actions, and compliance with future environmental
regulations, and the impact of Protection One's operations and financial
condition.
Additionally, our ability to access capital markets will affect the new and
existing credit agreements we have available to meet our operating and capital
expenditure requirements, debt service and dividend payments.
We plan to install three new combustion turbine generators with an
installed capacity of approximately 300 MW. The first two units are scheduled
to be placed in operation in June 2000, and the third is scheduled to be placed
in operation in mid-2001. We estimate that the project will require
$126 million in capital resources through the completion of the projects in
2001.
In July 1999, we agreed with Empire to construct jointly a 500-megawatt
combined cycle generating plant, which Empire will operate. We estimate that
our share of the project will require an estimated $86 million in capital
resources and that we will own 40% of the generating plant. Construction of
the plant began in the fall of 1999 with operation expected to begin in the
second quarter of 2001.
Our business requires a significant capital investment. We currently
expect that through the year 2002, we will need cash mostly for:
- Ongoing utility construction and maintenance programs designed
to maintain and improve facilities providing electric service.
- Improving operations within the monitored services business and
the acquisition of customer accounts.
Capital expenditures for 1999 and anticipated capital expenditures for 2000
through 2002 are as follows:
Fossil Nuclear Power Monitored
Generation Generation Delivery Services Other Total
(Dollars in Thousands)
1999. . . $ 57,300 $ 10,000 $ 89,200 $274,000 $106,800 $537,300
2000. . . 163,400 31,600 86,100 85,000 94,600 460,700
2001. . . 83,900 19,600 86,700 123,000 29,500 342,700
2002. . . 54,800 20,300 85,500 123,000 - 283,600
<PAGE>
Monitored services capital expenditures include purchases of customer
accounts. Other capital expenditures primarily represents our commitments to
install three combustion turbine generators, to jointly construct a combined
cycle generating plant and to fund 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 12 of Notes to Consolidated Financial Statements). Actual expenditures may
differ from our estimates.
Maturities of long-term debt through 2004 are as follows:
Principal
Year Amount
(Dollars in Thousands)
2000 . . . . . . . . $111,667
2001 . . . . . . . . 32,246
2002 . . . . . . . . 106,472
2003 . . . . . . . . 240,568
2004 . . . . . . . . 370,457
Capital Structure
Our capital structures at December 31, 1999, and 1998 were as follows:
1999 1998
Shareholders' Equity . . . . . . . . . . . 37% 37%
Preferred stock. . . . . . . . . . . . . . 1% 1%
Western Resources obligated
mandatorily redeemable preferred
securities of subsidiary trust holding
solely company subordinated debentures . 4% 4%
Long-term debt . . . . . . . . . . . . . . 58% 58%
Total. . . . . . . . . . . . . . . . . . . 100% 100%
Dividend Policy
Our board of directors reviews our dividend policy on an annual basis.
Among the factors the board of directors considers in determining our dividend
policy are earnings, cash flows, capitalization ratios, competition and
regulatory conditions. In January 2000, our board of directors declared a
first- quarter 2000 dividend of 53 1/2 cents per share. In March 2000, we
announced a new dividend policy. See Note 24 of Notes to Consolidated
Financial Statements for further discussion.
OTHER INFORMATION
Electric Utility
City of Wichita Proceeding: In December 1999, the Wichita, Kansas, City
<PAGE>
Council authorized the hiring of an outside consultant to determine the
feasibility of creating a municipal electric utility to replace KGE as the
supplier of electricity in Wichita. KGE's rates are currently 7% below the
national average for retail customers. The average rates charged to retail
customers in territories served by our KPL division are 19% lower than KGE's
rates. The City of Wichita has filed a complaint with the FERC requesting the
FERC to equalize the generation costs between KGE and KPL, in addition to other
matters (see also FERC Proceeding below). Customers within the Wichita
metropolitan area account for approximately 25% of our total energy sales.
KGE has an exclusive franchise with the City of Wichita to provide retail
electric service that expires March 2002. Under Kansas law, KGE will continue
to have the exclusive right to serve the customers in Wichita following the
expiration of the franchise, assuming the system is not municipalized.
KGE will oppose any attempt by the City of Wichita to eliminate it as the
electric provider to Wichita customers. In order to municipalize KGE's Wichita
electric facilities, the City of Wichita would be required to purchase KGE's
facilities or build a separate independent system.
KCC Proceeding: On March 16, 2000, the Kansas Industrial Consumers (KIC),
an organization of commercial and industrial users of electricity in Kansas,
filed a complaint with the KCC requesting an investigation of Western Resources'
and KGE's rates. The KIC alleges that these rates are not based on current
costs. We will oppose this request vigorously but are unable to predict whether
the KCC will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with the FERC against us, alleging improper affiliate transactions between KPL,
one of our divisions, and KGE, our wholly-owned subsidiary. The City of Wichita
requests the FERC to equalize the generation costs between KPL and KGE, in
addition to other matters. FERC has issued an order setting this matter for
hearing and has referred the case to a settlement judge. The hearing has been
suspended pending settlement discussions between the parties. We believe that
the City of Wichita's complaint is without merit and intend to defend against it
vigorously.
Competition and Deregulation: 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 market for
generation. 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. During 1999, wholesale electric
sales represented approximately 14% of total electric sales, excluding power
marketing sales. In 1992, 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 ourselves.
In December 1999, FERC issued an order (FERC Order 2000) encouraging formation
of regional
<PAGE>
transmission organizations (RTOs), whose purpose is to facilitate greater
competition at the wholesale level. Due to our participation in the formation
of the Southwest Power Pool RTO, we anticipate that FERC Order 2000 will not
have a material effect on us or our operations.
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 1999 and 2000 legislative sessions, but none passed
in 1999 and none are expected to pass in 2000. When retail wheeling will be
implemented by the legislature in Kansas remains uncertain.
If retail wheeling is implemented in Kansas, increased competition for
retail electricity sales may reduce our future electric utility earnings
compared to our historical electric utility earnings. 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. Our rates range from approximately 75% to 93% of the
national average for retail customers. Because of these reduced rates, we
expect to retain a substantial part of our current volume of sales volumes in a
competitive environment. We also expect we can maintain profitable prices in a
competitive environment, given how our current rates compare to the national
average rates. We offer competitive electric rates for industrial improvement
projects and economic development projects in an effort to maintain and increase
electric load.
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
iscontinue 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 the Wolf Creek nuclear generation
facility.
Regulatory changes, including competition, could adversely impact our
ability to recover our investment in these assets. As of December 31, 1999, we
<PAGE>
have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $366 million. Of this amount, $218.2 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 debt issuance costs, deferred employee benefit costs, deferred
plant costs, and coal contract settlement costs.
In a competitive environment, we may not be able to fully recover our
entire investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. 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.
Nuclear Decommissioning: Decommissioning is a nuclear industry term for
the permanent shut-down of a nuclear power plant. 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 to fund decommissioning.
These plans are designed so that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
The Financial Accounting Standards Board (FASB) is reviewing the accounting
for closure and removal costs, including decommissioning of nuclear power
plants. The FASB has issued an Exposure Draft "Accounting for Obligations
Associated with the Retirement of Long-Lived Assets." The proposed Statement is
to be effective for fiscal years beginning after June 15, 2001. If current
accounting practices for nuclear power plant decommissioning are changed, the
following could occur:
- Our annual decommissioning expense could be higher than in 1999
- 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 change, if required, would adversely affect our
operating results due to our current ability to recover decommissioning costs
through rates (See Note 12 of Notes to Consolidated Financial Statements).
Collective Bargaining Agreement: Our contract with the International
Brotherhood of Electrical Workers (IBEW) was renewed on January 20, 2000, and
will be due for renewal July 1, 2002. The contract covers approximately 1,475
employees. As of December 31, 1999, we had 7,049 employees.
<PAGE>
Year 2OOO Issue: Our electric utility operations experienced no business
disruptions as a result of the transition from December 31, 1999, to January 1,
2000, or as a result of "leap day" on February 29, 2000. We estimated that
total costs to update all of our electric utility operating systems for Year
2000 readiness, excluding costs associated with WCNOC, would be approximately
$6.3 million. As of December 31, 1999, we expensed $6.3 million for these
purposes. We expect to incur minimal cost in 2000 to complete remediation of
less important systems. We expect no Year 2000 issues to arise in 2000.
WCNOC experienced no business disruptions as a result of the transition
from December 31, 1999, to January 1, 2000, or as a result of "leap day" on
February 29, 2000. WCNOC has estimated the costs to complete the Year 2000
project at $3.5 million ($1.7 million, our share). As of December 31, 1999,
WCNOC expensed $3.2 million ($1.5 million our share), to complete remediation
and testing of mission critical systems necessary to continue to provide
electrical service to our customers. WCNOC expects to incur $0.2 million
(our share) in 2000 to complete remediation of less important systems. WCNOC
expects no Year 2000 issues to arise in 2000.
Monitored Services
Attrition: During 1999, Protection One experienced an increase in customer
attrition. Total attrition for the twelve months ended December 31, 1999 was
14.0% compared to 9.4% for the same period ended December 31, 1998. Annualized
total attrition for the quarter ended December 31, 1999, was 14.7% compared to
16.0% for the quarter ended September 30, 1999.
Customer attrition by Protection One's business segments is summarized
below for the period ended December 31.
Trailing Twelve Month
December 31,
1999_ 1998
North America . . . . . . 16.0% 11.0%
Multifamily . . . . . . . 7.6% 4.6%
Europe (1). . . . . . . . 9.6% -
Total Protection One. . 14.0% 9.4%
(1) Protection One acquired the European operations in 1998.
Sale of Mobile Services Group: On August 25, 1999, Protection One sold its
Mobile Services Group to ATX Technologies (ATX). The sales price was
approximately $20 million in cash plus a note and a preferred stock investment
in ATX. In August, Protection One recorded a gain on the sale of approximately
$11 million, net of tax.
Year 2OOO Issue: Protection One experienced no business disruptions as a
result of the transition from December 31, 1999 to January 1, 2000, or as a
result of "leap day" on February 29, 2000. As of December 31, 1999, Protection
One expensed $4.3 million to complete remediation and testing of mission
critical
<PAGE>
systems necessary to continue to provide monitored services to its customers.
Protection One expects to incur minimal costs in 2000 to complete remediation of
less important systems. Protection One expects no Year 2000 issues to arise in
2000.
Related Party Transactions
We and ONEOK have shared services agreements in which we provide and bill
for facilities, utility field work, information technology, customer support,
bill processing and human resources services to one another. Payments for these
services are based upon various hourly charges, negotiated fees and
out-of-pocket expenses. In 1999 and 1998, ONEOK paid us $5.6 million and
$4.9 million, net of what we owed ONEOK, for services.
As a result of Protection One not meeting its debt covenants, in December
1999, Westar Capital, acquired the debt and assumed the lenders' obligations
under Protection One's revolving credit facility. We loaned Westar Capital
approximately $225 million for this purpose.
As of February 29, 2000, we had spent $42.4 million to acquire Protection
One non-convertible debt securities through open market transactions. In the
first quarter of 2000, Westar Capital transferred to Protection One certain
outstanding Protection One debt securities for partial payment of certain
outstanding intercompany amounts owed to Protection One.
On February 29, 2000, Westar Capital purchased the continental European and
United Kingdom operations of Protection One, and certain investments held by a
subsidiary of Protection One for an aggregate purchase price of $244 million.
Westar Capital paid approximately $183 million in cash and transferred
Protection One debt securities with a market value of approximately $61 million
to Protection One. Westar Capital has agreed to pay Protection One a portion of
the net gain, if any, on a subsequent sale of the European businesses on a
declining basis over the four years following the closing. Cash proceeds from
the transaction were used to reduce the outstanding balance owed to Westar
Capital on Protection One's revolving credit facility. Concurrently, Westar
apital and Protection One amended the revolving credit agreement to reduce the
facility from $250 million to $115 million and to change the maturity date to
January 2, 2001. For approved acquisitions, an additional $40 million could be
made available under the facility. No gain or loss was recorded on this
intercompany transaction and the net book value of the assets was unaffected.
We may acquire additional Protection One debt securities. The timing and
terms of purchases, and the amount of debt actually purchased, will be based on
market conditions and other factors. Purchases are expected to be made in the
open market or through negotiated transactions. Because Protection One's debt
currently trades at less than its carrying value, we would expect to realize an
extraordinary gain on extinguishment of debt on any purchases.
<PAGE>
Investment in Gas Compression Company
As of December 31, 1999, we owned less than 10% of the outstanding common
stock of a gas compression company through our Westar Capital subsidiary. We
have determined that this investment is not strategic to our ongoing business
and are selling the common stock. During 1999, we recorded a $9.3 million gain
on the sale of a portion of this investment. During the first quarter of 2000,
we sold a significant portion of this investment and realized a gain of $72.6
million through March 16, 2000.
Market Risk Disclosure
Market Price Risks: We are exposed to market risk, including changes in
commodity prices, equity instrument investment prices and interest rates.
Commodity Price Exposure: In 1999, we engaged in both trading and non-
trading activities in our commodity price risk management activities. We
primarily traded electricity commodities. We utilized 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 were involved in trading activities primarily to minimize risk from
market fluctuations, to maintain a market presence and to enhance system
reliability. We attempted to balance our physical and financial purchase and
sale contracts in terms of quantities and contract terms. Net open positions
existed or were established due to the origination of new transactions and our
assessment of, and response to, changing market conditions. To the extent we
had open positions, we were exposed to the risk that fluctuating market prices
could adversely impact our financial position or results from operations. In
2000, we expect to operate our trading activities in a similar manner as 1999.
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 the VAR 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. Our Risk Oversight Committee sets the VAR limit. The
high, low and average VAR amounts for the year ended December 31, 1999, were
$395,115, $26,039 and $68,832. We employ additional risk control mechanisms
such as stress testing, daily loss limits, and commodity position limits.
We expect to use the same VAR model and VAR limits in 2000.
<PAGE>
We have considered a number of risks and costs associated with the future
contractual commitments included in our energy portfolio. These risks include
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 are primarily large energy
marketers and major utility companies. The creditworthiness of our
counterparties could positively or negatively impact our overall exposure to
credit risk. We maintain credit policies with regard to our counterparties
that, in 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. From 1998 to 1999,
we experienced a 27% increase in price per MW of electricity purchased for
utility operations. If we were to have a similar increase from 1999 to 2000,
given the amount of power purchased for utility operations during 1999, we would
have an exposure of approximately $6.3 million of net income. Due to the
volatility of the power market, there are no indications that past performance
can be used to predict the future.
We use a mix of various fuel types to operate our system. From 1998 to
1999, we experienced a 4% increase in the average price per MMBtu of natural gas
purchased for utility operations. From 1998 to 1999, we experienced less than
a 1% change in price per MMBtu for all fuel types purchased for our system.
Based on MMBtu's of natural gas and fuel oil burned during 1999, we would have
exposure in 2000 of approximately $4.7 million of net income for a 10% change in
average price paid per MMBtu. Due to the volatility of natural gas prices,
there are no indications that past performance can be used to predict the
future.
Quantities of natural gas and electricity could vary dramatically year to
year based on weather, unit outages and nuclear refueling.
Equity Price Risk: We had approximately $111.9 million of equity
securities as of December 31, 1999. Through March 16, 2000, we sold a material
portion of these equity securities and recognized a $72.6 million gain.
Following the sale of these equity securities, we have $29.9 million of equity
securities. 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 as an adjustment to shareholders' equity. Declines in market value
which are other than temporary are recognized in income. The market price of
equity securities still owned at December 31, 1999, increased by 34% from 1998
to 1999. During the first quarter of 2000, the market price of these equity
securities increased 5%. An immediate 10% change in the market price of our
remaining equity securities would have a $3.0 million effect on fair value.
Interest Rate Exposure: We have approximately $827.4 million of variable
rate debt, including current maturities of fixed rate debt, as of December 31,
1999. Our weighted average interest rate increased from 5.94% at December 31,
1998 to 6.96% at December 31, 1999. A 100 basis point change in each debt
series benchmark rate would impact net income on an annual basis by
approximately $9.2 million.
<PAGE>
In response to the terminated KCP&L merger and unprofitable operations and
liquidity issues at Protection One, Moody's, S&P, and Fitch are reviewing our
securities ratings. Should our short-term debt ratings be lowered, access to
the commercial paper market, when available, would be more costly and may
require borrowing from our existing revolving credit facilities. We cannot
redict the market conditions or our credit ratings at the time we may borrow
from these facilities; and therefore, cannot predict how much higher our
interest expense might be.
Due to Protection One's liquidity and operational issues and our
announcement that we are exploring strategic alternatives for Protection One, in
November 1999, Moody's, S&P and Fitch downgraded their ratings on Protection
One's credit facility and outstanding securities. On March 24, 2000, Moody's
further downgraded their ratings on Protection One's our outstanding securities
with outlook remaining negative.
During the first quarter of 2000, we sold our remaining portfolio of
marketable debt securities and realized a gain of approximately $24.9 million.
Therefore, we have no further interest rate exposure related to marketable debt
securities.
Foreign Currency Exchange Rates: We have overseas operations with
functional currencies other than the United States dollar. As of December 31,
1999, the unrealized loss on currency translation, presented as a separate
component of stockholders' equity and reported within other comprehensive income
was approximately $1.3 million pretax. A 10% change in the currency exchange
rates would have an immaterial effect on other comprehensive income.
Pronouncements Issued but Not Yet Effective
In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133). In June 1999, the FASB issued Statement No. 137 "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133." SFAS 133 establishes accounting and reporting
standards requiring that every derivative instrument, including certain
derivative instruments embedded in hybrid contracts, be recorded in the balance
sheet as either an asset or liability measured at its fair value. With respect
to hybrid contracts, a company may elect to apply SFAS 133, as amended, to (1)
all hybrid contracts, (2) only those hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997, or (3) only those
hybrid contracts that were issued, acquired, or substantively modified after
December 31, 1998.
SFAS 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met and that
a company must formally document, designate and assess the effectiveness of
transactions that receive hedge accounting. SFAS 133, in part, allows special
hedge accounting for fair value and cash flow hedges. We have no fair value
<PAGE>
hedges as of December 31, 1999. SFAS 133 provides that the effective portion of
the gain or loss on a derivative instrument designated and qualifying as a cash
flow hedging instrument be reported as a component of other comprehensive income
and be reclassified into earnings in the same period or periods during which the
hedged forecasted transaction affects earnings. The remaining gain or loss on
the derivative instrument, if any, must be recognized currently in earnings. If
SFAS 133 were required to be applied to cash flow hedges in place at
December 31, 1999, changes in the fair value of options and forwards would
contribute approximately $1.3 million of additional loss to other comprehensive
income for the twelve months ended December 31, 1999, if these hedges were
100% effective. We are still in the process of evaluating the effectiveness of
these hedges.
We use derivatives for non-trading purposes primarily to reduce exposure
relative to the volatility of cash market prices. Specifically, anticipated
purchases of electricity are being hedged using options and forwards. We
currently record our cash flow hedges as assets and liabilities on our
Consolidated Balance Sheet. We mark the hedges to market on the Consolidated
Balance Sheet at the end of each period. We recognize the realized gains and
losses in net income in the period the options and forwards are settled.
SFAS 133, as amended, is effective for fiscal years beginning after June
15, 2000. SFAS 133 cannot be applied retroactively. We are currently evaluating
commodity contracts and financial instruments to determine what, if any, effect
of adopting SFAS 133 might have on our financial statements. We have not yet
quantified all effects of adopting SFAS 133 on our financial statements;
however, SFAS 133 could increase volatility in earnings and other comprehensive
income. We plan to adopt SFAS 133 as of January 1, 2001.
<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 56
Financial Statements:
Consolidated Balance Sheets, December 31, 1999 and 1998 57
Consolidated Statements of Income for the years ended
December 31, 1999, 1998 and 1997 58
Consolidated Statements of Comprehensive Income for the
years ended December 31, 1999, 1998 and 1997 59
Consolidated Statements of Cash Flows for the years ended
1999, 1998 and 1997 60
Consolidated Statements of Cumulative Preferred Stock
December 31, 1999 and 1998 61
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 1999, 1998 and 1997 62
Notes to Consolidated Financial Statements 63
Financial Schedules:
Schedule II - Valuation and Qualifying Accounts 109
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 stock of Western Resources, Inc., as of
December 31, 1999 and 1998, 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, 1999. These 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 financial statements and
this schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 financial position of Western Resources, Inc., as
of December 31, 1999 and 1998, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the Financial Statements, effective September 1,
1999, the company changed its method of amortization for customer accounts for
its North American and European customers from the straight-line method to a
declining balance (accelerated) method.
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,
March 16, 2000
(except with respect to the Dividend Policy and Corporate Restructuring
discussed in Note 24, as to which the date is March 28, 2000)
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<CAPTION>
December 31,
1999 1998
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 15,827 $ 16,394
Accounts receivable (net) . . . . . . . . . . . . . . . . 229,200 218,243
Inventories and supplies (net). . . . . . . . . . . . . . 112,392 95,590
Marketable securities . . . . . . . . . . . . . . . . . . 177,128 288,077
Prepaid expenses and other. . . . . . . . . . . . . . . . 68,421 57,225
Total Current Assets. . . . . . . . . . . . . . . . . . 602,968 675,529
PROPERTY, PLANT AND EQUIPMENT (NET) . . . . . . . . . . . . 3,889,444 3,799,916
OTHER ASSETS:
Investment in ONEOK . . . . . . . . . . . . . . . . . . . 590,109 615,094
Customer accounts (net) . . . . . . . . . . . . . . . . . 1,138,902 1,014,428
Goodwill (net). . . . . . . . . . . . . . . . . . . . . . 1,102,157 1,188,253
Regulatory assets . . . . . . . . . . . . . . . . . . . . 366,004 364,213
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 318,622 293,995
Total Other Assets. . . . . . . . . . . . . . . . . . . 3,515,794 3,475,983
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . $8,008,206 $7,951,428
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt. . . . . . . . . . . $ 111,667 $ 165,838
Short-term debt . . . . . . . . . . . . . . . . . . . . . 705,421 312,472
Accounts payable. . . . . . . . . . . . . . . . . . . . . 132,834 127,834
Accrued liabilities . . . . . . . . . . . . . . . . . . . 226,786 252,367
Accrued income taxes. . . . . . . . . . . . . . . . . . . 40,328 32,942
Deferred security revenues. . . . . . . . . . . . . . . . 61,148 57,703
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 73,011 85,690
Total Current Liabilities . . . . . . . . . . . . . . . 1,351,195 1,034,846
LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . . . . . . . . . . . . 2,883,066 3,063,064
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. . . . . 982,548 938,659
Minority interests. . . . . . . . . . . . . . . . . . . . 193,499 205,822
Deferred gain from sale-leaseback . . . . . . . . . . . . 198,123 209,951
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 279,451 316,245
Total Long-Term Liabilities . . . . . . . . . . . . . . 4,756,687 4,953,741
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Cumulative preferred stock. . . . . . . . . . . . . . . . 24,858 24,858
Common stock, par value $5 per share, authorized
150,000,000 shares, outstanding 67,401,657 and
65,909,442 shares, respectively . . . . . . . . . . . . 341,508 329,548
Paid-in capital . . . . . . . . . . . . . . . . . . . . . 820,945 775,337
Retained earnings . . . . . . . . . . . . . . . . . . . . 691,016 823,590
Accumulated other comprehensive income. . . . . . . . . . 37,788 9,508
Treasury stock, at cost, 900,000 and 0 shares,
respectively . . . . . . . . . . . . . . . . . . . . . (15,791) -
Total Shareholders' Equity. . . . . . . . . . . . . . . 1,900,324 1,962,841
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY. . . . . . . . . . $8,008,206 $7,951,428
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,
1999 1998 1997
<S> <C> <C> <C>
SALES:
Energy. . . . . . . . . . . . . . . . . . . . . . . $1,430,982 $1,612,959 $1,999,418
Security. . . . . . . . . . . . . . . . . . . . . . 605,176 421,095 152,347
Total Sales . . . . . . . . . . . . . . . . . . . 2,036,158 2,034,054 2,151,765
COST OF SALES:
Energy. . . . . . . . . . . . . . . . . . . . . . . 478,982 691,468 928,723
Security. . . . . . . . . . . . . . . . . . . . . . 184,005 131,791 38,800
Total Cost of Sales . . . . . . . . . . . . . . . 662,987 823,259 967,523
GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . 1,373,171 1,210,795 1,184,242
OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . 337,068 337,507 384,313
Depreciation and amortization . . . . . . . . . . . 407,007 280,673 256,725
Selling, general and administrative expense . . . . 342,652 263,310 316,479
International power development costs . . . . . . . (5,632) 98,916 -
Deferred merger costs . . . . . . . . . . . . . . . 17,600 - 48,008
Monitored services special charge . . . . . . . . . - - 24,292
Total Operating Expenses. . . . . . . . . . . . . 1,098,695 980,406 1,029,817
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . 274,476 230,389 154,425
OTHER INCOME (EXPENSE):
Impairment of marketable securities . . . . . . . . (76,166) - -
Investment earnings . . . . . . . . . . . . . . . . 35,979 49,797 44,978
Gain on sale of Tyco securities . . . . . . . . . . - - 864,253
Minority interests. . . . . . . . . . . . . . . . . 12,934 382 3,586
Other . . . . . . . . . . . . . . . . . . . . . . . 14,234 6,274 9,071
Total Other Income (Expense). . . . . . . . . . . (13,019) 56,453 921,888
EARNINGS BEFORE INTEREST AND TAXES. . . . . . . . . . 261,457 286,842 1,076,313
INTEREST EXPENSE. . . . . . . . . . . . . . . . . . . 294,104 226,120 193,808
(LOSS) EARNINGS BEFORE INCOME TAXES . . . . . . . . . (32,647) 60,722 882,505
INCOME TAX (BENEFIT) EXPENSE. . . . . . . . . . . . . (33,364) 14,557 382,987
NET INCOME BEFORE EXTRAORDINARY GAIN. . . . . . . . . 717 46,165 499,518
EXTRAORDINARY GAIN, NET OF TAX. . . . . . . . . . . . 11,742 1,591 -
NET INCOME. . . . . . . . . . . . . . . . . . . . . . 12,459 47,756 499,518
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . 1,129 3,591 4,919
EARNINGS AVAILABLE FOR COMMON STOCK . . . . . . . . . $ 11,330 $ 44,165 $ 494,599
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . 67,080,281 65,633,743 65,127,803
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING:
Earnings available for common stock before
extraordinary gain. . . . . . . . . . . . . . . . $ (0.01) $ 0.65 $ 7.59
Extraordinary gain. . . . . . . . . . . . . . . . . 0.18 .02 -
EARNINGS AVAILABLE FOR COMMON STOCK . . . . . . . . . $ 0.17 $ 0.67 $ 7.59
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . $ 2.14 $ 2.14 $ 2.10
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,
1999 1998 1997
<S> <C> <C> <C>
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . $ 12,459 $ 47,756 $499,518
OTHER COMPREHENSIVE INCOME (LOSS), BEFORE TAX:
Unrealized holding (losses) gains on marketable
securities arising during the year . . . . . . . . . . (55,420) (17,244) 25,248
Less: Reclassification adjustment for losses
included in net income. . . . . . . . . . . . . . . . . 102,417 14,029 -
Unrealized gain (loss) on marketable securities (net) . . 46,997 (3,215) 25,248
Unrealized loss on currency translation . . . . . . . . . (115) (1,026) -
Other comprehensive income (loss), before tax . . . . . 46,882 (4,241) 25,248
INCOME TAX (BENEFIT) EXPENSE. . . . . . . . . . . . . . . . 18,602 (1,630) 13,129
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX . . . . . . . 28,280 (2,611) 12,119
COMPREHENSIVE INC0ME. . . . . . . . . . . . . . . . . . . . $ 40,739 $ 45,145 $511,637
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<CAPTION>
Year ended December 31,
1999 1998 1997
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 12,459 $ 47,756 $ 499,518
Adjustments to reconcile net income to net cash
provided by operating activities:
Extraordinary gain. . . . . . . . . . . . . . . . . . . . (11,742) (1,591) -
Depreciation and amortization . . . . . . . . . . . . . . 407,007 280,673 256,725
Amortization of gain on sale-leaseback. . . . . . . . . . (11,828) (11,828) (11,281)
Equity in earnings from investments . . . . . . . . . . . (8,199) (6,064) (25,405)
Gain on sale of Mobile Services . . . . . . . . . . . . . (17,249) - -
Minority interests. . . . . . . . . . . . . . . . . . . . (12,934) 382 3,586
(Gain)/loss on sale of securities . . . . . . . . . . . . 26,251 14,029 (864,253)
Impairment of marketable securities . . . . . . . . . . . 76,166 - -
Accretion of debt premium . . . . . . . . . . . . . . . . (6,799) 3,034 1,026
International development costs . . . . . . . . . . . . . (5,632) 98,916 -
Net deferred taxes. . . . . . . . . . . . . . . . . . . . (16,992) (49,317) (25,306)
Deferred merger costs . . . . . . . . . . . . . . . . . . 17,600 - 48,008
Monitored services special charge . . . . . . . . . . . . - - 24,292
Changes in working capital items (net of effects
from acquisitions):
Accounts receivable (net) . . . . . . . . . . . . . . . (3,824) 118,844 14,156
Inventories and supplies (net). . . . . . . . . . . . . (15,024) (8,000) 3,249
Prepaid expenses and other. . . . . . . . . . . . . . . (17,742) (26,988) 9,230
Accounts payable. . . . . . . . . . . . . . . . . . . . 5,000 (33,613) (48,298)
Accrued liabilities . . . . . . . . . . . . . . . . . . (20,152) (42,411) 68,623
Accrued income taxes. . . . . . . . . . . . . . . . . . 7,386 5,582 9,869
Deferred Revenue. . . . . . . . . . . . . . . . . . . . 3,479 (2,237) 670
Other . . . . . . . . . . . . . . . . . . . . . . . . . (3,518) 58,519 (9,254)
Changes in other assets and liabilities . . . . . . . . (30,485) (45,474) (33,251)
Net cash flows from (used in) operating activities. . . 373,228 400,212 (78,096)
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment (net). . . . . (275,744) (182,885) (207,989)
Customer account acquisitions . . . . . . . . . . . . . . (241,000) (277,667) (45,163)
Monitored services acquisitions,
net of cash acquired. . . . . . . . . . . . . . . . . . (27,409) (549,196) (438,717)
Divestiture of Mobile Services. . . . . . . . . . . . . . 19,087 - -
Proceeds from issuance of stock by subsidiary (net) . . . - 45,565 -
Purchases of marketable securities . . . .. . . . . . . . (12,003) (261,036) (10,461)
Proceeds from sale of marketable securities . . . . . . . 73,456 27,895 1,533,530
Investment in Paradigm. . . . . . . . . . . . . . . . . . (35,883) - -
Sale of ONEOK Stock . . . . . . . . . . . . . . . . . . . 28,101 - -
Purchase of Protection One bonds. . . . . . . . . . . . . (19,671) - -
Other investments (net) . . . . . . . . . . . . . . . . . 4,251 (91,451) (45,318)
Net cash flows (used in) from investing activities. . . (486,815) (1,288,775) 785,882
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 392,949 75,972 (744,240)
Proceeds of long-term debt. . . . . . . . . . . . . . . . 16,000 1,096,238 520,000
Retirements of long-term debt . . . . . . . . . . . . . . (178,350) (167,068) (293,977)
Issuance of common stock (net). . . . . . . . . . . . . . 43,245 17,284 25,042
Redemption of preference stock. . . . . . . . . . . . . . - (50,000) -
Cash dividends paid . . . . . . . . . . . . . . . . . . . (145,033) (144,077) (141,727)
Acquisition of treasury stock . . . . . . . . . . . . . . (15,791) - -
Net cash flows from (used in) financing activities. . . 113,020 828,349 (634,902)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (567) (60,214) 72,884
CASH AND CASH EQUIVALENTS:
Beginning of the period . . . . . . . . . . . . . . . . . 16,394 76,608 3,724
End of the period . . . . . . . . . . . . . . . . . . . . $ 15,827 $ 16,394 $ 76,608
The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CUMULATIVE PREFERRED STOCK
(Dollars in Thousands)
<CAPTION>
December 31,
1999 1998
<S> <C> <C>
CUMULATIVE PREFERRED 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
TOTAL CUMULATIVE PREFERRED STOCK. . . . . . . . . . . . . . . . $ 24,858 $ 24,858
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,
1999 1998 1997
<S> <C> <C> <C>
CUMULATIVE PREFERRED AND PREFERENCE STOCK:
Beginning balance. . . . . . . . . . . . . . . $ 24,858 $ 74,858 $ 74,858
Redemption of preference stock . . . . . . . . - (50,000) -
Ending balance . . . . . . . . . . . . . . . . 24,858 24,858 74,858
COMMON STOCK:
Beginning balance. . . . . . . . . . . . . . . 329,548 327,048 323,126
Issuance of common stock . . . . . . . . . . . 11,960 2,500 3,922
Ending balance . . . . . . . . . . . . . . . . 341,508 329,548 327,048
PAID-IN CAPITAL:
Beginning balance. . . . . . . . . . . . . . . 775,337 760,553 739,433
Expenses on common stock . . . . . . . . . . . - - (5)
Issuance of common stock . . . . . . . . . . . 45,608 14,784 21,125
Ending balance . . . . . . . . . . . . . . . . 820,945 775,337 760,553
RETAINED EARNINGS:
Beginning balance. . . . . . . . . . . . . . . 823,590 919,911 562,121
Net income . . . . . . . . . . . . . . . . . . 12,459 47,756 499,518
Dividends on preferred and preference stock. . (1,129) (3,591) (4,919)
Dividends on common stock. . . . . . . . . . . (143,904) (140,486) (136,809)
Ending balance . . . . . . . . . . . . . . . . 691,016 823,590 919,911
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Beginning balance. . . . . . . . . . . . . . . 9,508 12,119 -
Unrealized (loss) gain on marketable
securities . . . . . . . . . . . . . . . . 46,997 (3,215) 25,248
Unrealized loss on currency translation. . . . (115) (1,026) -
Income tax benefit (expense) . . . . . . . . . (18,602) 1,630 (13,129)
Ending balance . . . . . . . . . . . . . . . . 37,788 9,508 12,119
TREASURY STOCK:
Beginning balance. . . . . . . . . . . . . . . - - -
Acquisition of treasury stock. . . . . . . . . (15,791) - -
Ending balance . . . . . . . . . . . . . . . . (15,791) - -
TOTAL SHAREHOLDERS' EQUITY . . . . . . . . . . . $1,900,324 $1,962,841 $2,094,489
The Notes to Consolidated Financial Statements are an integral part of this statement.
</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 628,000 customers in Kansas and providing monitored
services to approximately 1.6 million customers in North America, the United
Kingdom and continental Europe. 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.
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. Our investments in
Protection One and ONEOK are owned by Westar Capital, Inc. (Westar Capital),
a wholly-owned subsidiary.
Principles of Consolidation: The company prepares its financial statements
in conformity with accounting principles generally accepted in the United
States. 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.
Use of Management's Estimates: The preparation of financial statements
require management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
Consolidated Statements of Cash Flows: For purposes of the Consolidated
Statements of Cash Flows, the company considers highly liquid collateralized
debt instruments purchased with a maturity of three months or less to be cash
equivalents. Cash paid for interest and income taxes for each of the years
ended
<PAGE>
December 31, are as follows:
1999 1998 1997
(Dollars in Thousands)
Interest on financing activities
(net of amount capitalized) . . . . $298,802 $220,848 $193,468
Income taxes. . . . . . . . . . . . . 784 47,196 404,548
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.
Available-for-sale Securities: The company classifies marketable equity and
debt securities accounted for under the cost method as available-for-sale.
These securities are reported at fair value based on quoted market prices.
Cumulative, temporary unrealized gains and losses, net of the related tax
effect, are reported as a separate component of shareholders' equity until
realized. Current temporary changes in unrealized gains and losses are reported
as a component of other comprehensive income.
The following table summarizes the company's investments in marketable
securities as of December 31:
Gross Unrealized
Cost Gains Losses Fair Value
1999: (Dollars in Thousands)
Equity securities. . . . . . $ 43,124 $70,407 $ (1,628) $111,903
Debt securities. . . . . . . 65,225 - - 65,225
Total. . . . . . . . . . . $108,349 $70,407 $ (1,628) $177,128
1998:
Equity securities. . . . . . $ 94,369 $45,685 $(10,182) $129,872
Debt securities. . . . . . . 172,129 - (13,924) 158,205
Total. . . . . . . . . . . $266,498 $45,685 $(24,106) $288,077
Proceeds from the sales of equity and debt securities were $73.5 million
in 1999 and $27.9 million in 1998. In 1997, the only available-for-sale
security sold was an investment in Tyco International common stock
(See Note 18). The gross realized gains from sales of equity and debt
investments were $12.6 million in 1999 and $2.0 million in 1998. The gross
realized losses from sales of equity and debt investments were $38.8 million in
1999 and $16.1 million in 1998.
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).
<PAGE>
The AFUDC rate was 6.00% in 1999, 6.00% in 1998 and 5.80% in 1997. 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, the
original cost and removal cost, less salvage value, are charged to accumulated
depreciation.
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 totaled $88.1 million as of December 31, 1999, and $68 million as
of December 31, 1998.
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 2.92% during
1999, 2.88% during 1998 and 2.89% during 1997. Nonutility property, plant and
equipment is depreciated on a straight-line basis over the estimated useful
lives of the related assets.
Inventories and Supplies: Inventories and supplies for the company's
utility business are stated at average cost. Inventories, comprised of alarm
systems and parts, are stated at the lower of average cost or market.
Nuclear Fuel: 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 was $29.3 million at December 31, 1999, and $39.5 million at
December 31, 1998.
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.
Protection One historically amortized the costs it allocated to its
customer accounts by using the straight-line method over a ten-year life. The
straight-line method, indicated in Accounting Principles Board Opinion No. 17 as
the appropriate method for such assets, has been the predominant method used to
amortize customer accounts in the monitored services industry. Protection One's
management is not aware of whether the economic life or the rate of realization
for Protection One's customer accounts differ materially from other monitored
services companies.
The choice of a ten-year life was based on Protection One's estimates and
judgments about the amounts and timing of expected future revenues from these
assets, the rate of attrition of such revenue over customer life, and average
<PAGE>
customer account life. Ten years was used because, in Protection One's opinion,
it would adequately match amortization cost with anticipated revenue from those
assets even though many accounts were expected to produce revenue over periods
substantially longer than ten years. Effectively, it expensed the asset ratably
over an "expected average customer life" that was shorter than the expected life
of the revenue stream, thus implicitly giving recognition to projected revenues
for a period beyond ten years.
Protection One conducted a comprehensive review of its amortization policy
during the third quarter of 1999. This review was performed specifically to
evaluate the historic amortization policy in light of the inherent declining
revenue curve over the life of a pool of customer accounts and Protection One's
historical attrition experience. After completing the review, Protection One
identified three distinct pools, each of which has distinct attributes that
effect differing attrition characteristics. The pools correspond to Protection
One's North America, Multifamily and Europe business segments. For the North
America and Europe pools, the analyzed data indicated that Protection One can
expect attrition to be greatest in years one through five of asset life and that
a change from a straight-line to a declining balance (accelerated) method would
more closely match future amortization cost with the estimated revenue stream
from these assets. Protection One has elected to change to that method. No
change was made in the method used for the Multifamily pool.
Protection One's amortization rates for the North America and Europe
customer pools consider the average estimated remaining life and historical and
projected attrition rates. The average estimated remaining life for each
customer pool is as follows:
Average
Estimated
Remaining Life
Pool (Years) Method
North America 8-10 Ten-year 130% declining balance
Europe 10 Ten-year 125% declining balance
Multifamily 12 Ten-year straight-line
Adoption of the declining balance method effectively shortens the estimated
expected average customer life for these two customer pools, and does so in a
way that does not make it possible to distinguish the effect of a change in
method (straight-line to declining balance) from the change in estimated lives.
In such cases, generally accepted accounting principles require that the effect
of such a change be recognized in operations in the period of the change, rather
than as a cumulative effect of a change in accounting principle. Protection One
changed to the declining balance method in the third quarter of 1999.
Accordingly, the effect of the change in accounting principle increased
Protection One's amortization expense reported in the third quarter of 1999 by
$47 million.
Protection One's accumulated amortization recorded on its balance sheet would
have been approximately $41 million higher, through the end of the second
quarter of 1999, if it had historically used the declining balance method.
<PAGE>
In accordance with SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of", long-lived
assets held and used by Protection One are evaluated for recoverability on a
periodic basis or as circumstances warrant. An impairment would be recognized
when the undiscounted expected future operating cash flows by customer pool
derived from customer accounts is less than the carrying value of capitalized
customer accounts and goodwill.
Due to the high level of customer attrition experienced in 1999 and the
decline in market value of Protection One's publicly traded equity and debt
securities, Protection One performed an impairment test on its customer account
asset in the fourth quarter and concluded that no impairment has occurred.
Protection One also reevaluated its amortization estimates and concluded no
change was needed.
Goodwill: Goodwill represents the excess of the purchase price over the
fair value of net assets acquired by Protection One. Protection One has
historically amortized goodwill on a straight-line basis over 40 years. The
carrying value of goodwill was included in Protection One's evaluation of
recoverability of customer accounts. No reduction in the carrying value was
necessary at December 31, 1999.
In conjunction with the impairment test for customer accounts, Protection
One re-evaluated the original assumptions and rationale utilized in the
establishment of the carrying value and estimated useful life of goodwill.
Protection One concluded that due to continued losses and increased levels of
attrition experienced in 1999, the estimated useful life of goodwill should be
reduced from 40 years to 20 years. As of January 1, 2000, the remaining
goodwill, net of accumulated amortization, will be amortized over its remaining
useful life based on a 20-year life. On Protection One's existing account base,
Protection One anticipates that this will result in an increase in annual
goodwill amortization of approximately $34 million prospectively. Accumulated
amortization was $62.7 million and $31.1 million at December 31, 1999 and
December 31, 1998.
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, 1999 1998
(Dollars in Thousands)
Recoverable taxes. . . . . . . . . . . $218,239 $205,416
Debt issuance costs. . . . . . . . . . 68,239 73,635
Deferred employee benefit costs. . . . 36,251 36,128
Deferred plant costs . . . . . . . . . 30,306 30,657
Coal contract settlement costs . . . . 7,957 12,259
Other regulatory assets. . . . . . . . 5,012 6,118
Total regulatory assets. . . . . . . $366,004 $364,213
Recoverable income taxes: Recoverable income taxes represent amounts
due from customers for accelerated tax benefits which have been
<PAGE>
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.
The company expects to recover all of the above regulatory assets in rates
charged to customers. A return is allowed on deferred plant costs and coal
contract settlement costs and approximately $49.1 million of debt issuance
costs.
Minority Interests: Minority interests represent the minority
shareholders' proportionate share of the shareholders' equity and net loss 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 $44 million at December 31, 1999, and $38.8 million at
December 31, 1998, are recorded as a component of accounts receivable (net) on
the Consolidated Balance Sheets.
Monitored services sales are recognized when monitoring, extended service
protection, patrol, repair and other services are provided. Deferred revenues
result from customers who are billed for monitoring, extended service protection
and patrol and alarm response services in advance of the period in which such
services are provided, on a monthly, quarterly or annual basis.
The company's allowance for doubtful accounts receivable totaled $35.8
million at December 31, 1999, and $29.5 million at December 31, 1998.
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.
The company has a tax sharing agreement with Protection One. This pro rata
tax sharing agreement allows Protection One to be reimbursed for tax benefits
<PAGE>
utilized in the company's consolidated tax return.
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. The change in market value of these energy trading
contracts is recorded on the Consolidated Balance Sheet, and included in
earnings.
The company is also exposed to commodity price changes outside of trading
activities. The company uses derivatives for non-trading purposes primarily to
reduce exposure relative to the volatility of cash market prices. The company
currently records the change in market value of these cash flow hedges on its
Consolidated Balance Sheet. The company does not recognize gains and losses in
net income until the period these options and forwards are settled.
The company has considered a number of risks and costs associated with the
future contractual commitments included in the company's energy portfolio.
These risks include credit risks associated with the financial condition of
counterparties, product location (basis) differentials and other risks which
management policy dictates. The counterparties in the company's portfolio are
primarily large energy marketers and major utility companies. The
creditworthiness of the company's counterparties could positively or negatively
impact the company's overall exposure to credit risk. The company maintains
credit policies with regard to its counterparties that, in management's view,
minimize overall credit risk.
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:
1999 1998
(Dollars in Millions)
Cash surrender value of policies (1). . $642.4 $587.5
Borrowings against policies . . . . . . (608.3) (558.5)
COLI (net). . . . . . . . . . . . . . . $ 34.1 $ 29.0
(1) Cash surrender value of policies as presented represents the value
of the policies as of the end of the respective policy years and not as of
December 31, 1999 and 1998.
Income was recorded for increases in cash surrender value and net death
proceeds. 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 $1.4 million in
1999,
<PAGE>
$13.7 million in 1998 and $0.6 in 1997.
New Pronouncements: In June 1998, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133). In June 1999,
the FASB issued Statement No. 137 "Accounting for Derivative Instruments and
Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133."
SFAS 133 establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
hybrid contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. With respect to hybrid contracts, a
company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts,
(2) only those hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997, or (3) only those hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1998.
SFAS 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met and that
a company must formally document, designate and assess the effectiveness of
transactions that receive hedge accounting. SFAS 133, in part, allows special
hedge accounting for fair value and cash flow hedges. The company had no fair
value hedges as of December 31, 1999. SFAS 133 provides that the effective
portion of the gain or loss on a derivative instrument designated and qualifying
as a cash flow hedging instrument be reported as a component of other
comprehensive income and be reclassified into earnings in the same period or
periods during which the hedged forecasted transaction affects earnings. The
remaining gain or loss on the derivative instrument, if any, must be recognized
currently in earnings. If SFAS 133 were required to be applied to cash flow
hedges in place at December 31, 1999, changes in the fair value of options and
forwards would contribute approximately $1.3 million of additional loss to other
comprehensive income for the twelve months ended December 31, 1999, if these
hedges were 100% effective. The company is still in the process of evaluating
the effectiveness of these hedges.
SFAS 133, as amended, is effective for fiscal years beginning after June
15, 2000. SFAS 133 cannot be applied retroactively. The company is currently
evaluating commodity contracts and financial instruments to determine what, if
any, effect of adopting SFAS 133 might have on its financial statements. The
company has not yet quantified all effects of adopting SFAS 133 on its financial
statements; however, SFAS 133 could increase volatility in earnings and other
comprehensive income. The company plans to adopt SFAS 133 as of January 1, 2001.
On January 1, 1999, the company adopted Emerging Issues Task Force Issue
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF Issue 98-10). 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.
<PAGE>
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
2. MONITORED SERVICES BUSINESS
Protection One acquired a significant number of security companies in 1998
and 1997. The largest acquisitions included Protection One in November 1997,
Network Multifamily, Inc. (Multifamily) in January 1998, Multimedia Security
Services, Inc. in March 1998, and Compagnie Europeenne de Telesecurite (CET) in
October 1998. All companies acquired have been accounted for using the purchase
method. The principal assets acquired in the acquisitions are customer
accounts. The excess of the purchase price over the estimated fair value of the
net assets acquired is recorded as goodwill. The results of operations of each
acquisition have been included in the consolidated results of operations of
Protection One from the date of the acquisition.
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 and 1997 occurred as of January 1, 1997.
Year Ended December 31, 1998 1997
(Unaudited)
(Dollars in Thousands,
Except Per Share Data)
Sales $2,175,089 $2,462,849
Earnings available for common stock 33,556 463,264
Earnings per share $0.51 $7.11
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.
During 1999, Protection One completed four acquisitions, all in the United
Kingdom, for a combined purchase price of approximately $32 million. Protection
One's purchase price allocations for the 1999 acquisitions are preliminary and
may be adjusted as additional information is obtained.
During the third quarter of 1999, Protection One sold the assets which
comprised its Mobile Services Group. Cash proceeds of this sale approximated
$20 million and Protection One recorded a pre-tax gain of approximately $17.3
million.
In December 1997, Protection One incurred charges of $12.8 million to write
down the value of the customer account base due to excessive losses associated
with a specific acquisition and $11.5 million to reflect the closing of
business
<PAGE>
activities that were no longer of continuing value to the combined operations.
3. MARKETABLE SECURITIES
During the fourth quarter of 1999, the company decided to sell its
remaining marketable security investments in paging industry companies. These
securities have been classified as available-for-sale; therefore, changes in
market value have been historically reported as a component of other
comprehensive income.
The market value for these securities declined during the last six to nine
months of 1999. The company determined that the decline in value of these
securities was other than temporary and a charge to earnings for the decline in
value was required at December 31, 1999. Therefore, the company recorded a non-
cash charge of $76.2 million in the fourth quarter of 1999. This charge to
earnings has been presented separately in the accompanying Consolidated
Statements of Income. See also Note 24 for subsequent events.
4. CUSTOMER ACCOUNTS
The following is a rollforward of the investment in customer accounts (at
cost) at December 31:
1999 1998
Beginning customer accounts, net. . . . . $1,031,956 $ 530,312
Acquisition of customer accounts. . . . . 333,195 601,063
Amortization of customer accounts . . . . (189,214) (89,893)
Non-cash charges against
purchase holdbacks. . . . . . . . . . . (37,035) (9,526)
Ending customer accounts, net . . . . . . $1,138,902 $1,031,956
Accumulated amortization of the investment in customer accounts at December
31, 1999 and 1998 was $307.6 million and $118.4 million.
In conjunction with certain purchases of customer accounts, Protection One
withholds a portion of the purchase price as a reserve to offset qualifying
losses of the acquired customer accounts for a specified period as provided for
in the purchase agreements, and as a reserve for purchase price settlements of
assets acquired and liabilities assumed. The estimated expected amount to be
paid at the end of the holdback period is capitalized and an equivalent current
liability established at the time of purchase.
<PAGE>
The following is a rollforward of purchase holdbacks at December 31:
1999 1998
Balance, beginning of year. . . . . $42,303 $11,444
Additions . . . . . . . . . . . . . 26,663 72,673
Non-cash charges against
customer accounts . . . . . . . . (37,035) (9,526)
Cash payments to sellers. . . . . . (11,718) (32,288)
Balance, end of year. . . . . . . . $20,213 $42,303
Purchase holdback periods are negotiated between Protection One and sellers
or dealers, but typically range from zero to 12 months. At the end of the period
prescribed by the purchase holdback, Protection One verifies customer losses
experienced during the period and calculates a final payment to the seller or
dealer. The purchase holdback is extinguished at the time of final payment and
a corresponding adjustment is made in the customer intangible to the extent the
final payment varies from the estimated liability established at the time of
purchase.
5. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
1999 1998
(Dollars in Thousands)
Electric plant in service. . . . . . . $5,769,401 $5,646,176
Less - accumulated depreciation. . . . 2,141,037 2,015,880
3,628,364 3,630,296
Construction work in progress. . . . . 170,061 82,700
Nuclear fuel (net) . . . . . . . . . . 28,013 39,497
Net utility plant. . . . . . . . . . 3,826,438 3,752,493
Non-utility plant in service . . . . . 92,872 62,324
Less - accumulated depreciation. . . . 29,866 14,901
Net property, plant and equipment. . $3,889,444 $3,799,916
6. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1999
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 174,450 $ 113,415 344.0 50
Jeffrey 1 (b) Jul 1978 302,452 138,934 625.0 84
Jeffrey 2 (b) May 1980 294,502 128,865 622.0 84
Jeffrey 3 (b) May 1983 407,864 166,298 623.0 84
Jeffrey wind 1 (b) May 1999 855 17 0.5 84
Jeffrey wind 2 (b) May 1999 854 16 0.5 84
Wolf Creek (c) Sep 1985 1,378,238 460,880 550.0 47
(a) Jointly owned with KCPL
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
<PAGE>
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 337 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.
7. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD
<TABLE>
The company's investments which are accounted for by the equity method are
as follows:
<CAPTION>
Equity Earnings,
Ownership at Investment at Year Ended
December 31, December 31, December 31
1999 1999 1998 1999 1998
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
ONEOK, Inc. (1). . . . . . 45% $590,109 $615,094 $6,945 $6,064
Affordable Housing Tax
Credit limited
partnerships (2). . . . . 13% to 29% 79,460 85,461 - -
Paradigm Direct. . . . . . 40% 35,385 - 1,254 -
International companies
and joint ventures (3). . 9% to 50% 18,724 10,500 - -
(1) The company also received approximately $41 million of preferred and common dividends in
1999.
(2) Investment is aggregated. Individual investments are not material. 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 material. During 1998, the
company recognized an other than temporary decline in value of its foreign equity
investments as discussed in Note 16.
</TABLE>
The following summarized financial information for the company's investment
in ONEOK is presented as of and for the periods ended December 31, 1999, and
November 30, 1998, the most recent periods for which public information is
available.
December 31, November 30,
1999 1998
(Dollars in Thousands)
Balance Sheet:
Current assets . . . . . $ 593,721 $ 404,358
Non-current assets . . . 2,645,854 2,091,797
Current liabilities. . . 786,713 338,466
Non-current liabilities. 1,301,338 993,668
Equity . . . . . . . . . 1,151,524 1,164,021
December 31, November 30,
Twelve Months Ended 1999 1998
(Dollars in Thousands)
<PAGE>
Income Statement:
Revenues . . . . . . . . $2,070,983 $1,896,178
Gross profit. . . . . . 760,209 645,606
Net income . . . . . . . 106,873 103,525
At December 31, 1999, the company's ownership interest in ONEOK is
comprised of approximately 2.3 million common shares and approximately 19.9
million convertible preferred shares. If all the preferred shares were
converted, the company would own approximately 45% of ONEOK's common shares
presently outstanding.
8. SHORT-TERM DEBT
The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling approximately $1.1
billion. 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, which is used to fund its short-term borrowing requirements.
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, 1999 1998
(Dollars in Thousands)
Borrowings outstanding at year end:
Credit agreement. . . . . . . . . $ 50,000 $ -
Bank loans. . . . . . . . . . . . 120,000 164,700
Commercial paper notes. . . . . . 535,421 147,772
Total . . . . . . . . . . . . . $ 705,421 $312,472
Weighted average interest rate on
debt outstanding at year end
(including fees). . . . . . . . . 6.96% 5.94%
Weighted average short-term debt
outstanding during the year . . . $ 455,184 $529,255
Weighted daily average interest
rates during the year
(including fees). . . . . . . . . 5.76% 5.93%
Unused lines of credit supporting
commercial paper notes. . . . . . $1,021,000 $820,900
<PAGE>
The company borrowed $225 million in short-term debt in 1999 to fund Westar
Capital's revolving credit agreement to Protection One.
The company's interest expense on short-term debt was $57.7 million in
1999, $55.3 million in 1998 and $73.8 million in 1997.
The unsecured short-term lines of credit included three revolving credit
facilities with various banks as follows:
Amount Facility Termination Date
$300 million 364-day March 15, 2000
500 million 5-year March 17, 2003
250 million 6 1/2-month June 30, 2000
In March 2000, the company amended the $300 million facility to reduce the
commitment to $242 million and to extend the maturity date to June 30, 2000.
The company also amended all of these credit facilities to reflect the
possibility of borrowing from them rather than using them to provide support for
commercial paper borrowings.
Amendments to the credit facilities include increased pricing to reflect
credit quality and the potential drawn nature of credit facilities rather than
support for commercial paper, redefinition of the total debt to capital
financial covenant, limitation on use of proceeds from sale of first mortgage
bonds to pay off debt outstanding under the credit facilities before proceeds
may be used for other purposes, and a commitment to use the company's "best
efforts" to pledge first mortgage bonds to support its credit facilities if our
senior unsecured credit rating drops below "investment grade" (bonds rated
below BBB by S&P and Fitch and below Baa by Moody's as determined by Standard &
Poor's Ratings Group (S&P) and Moody's Investors Service (Moody's).
9. LONG-TERM DEBT
Long-term debt outstanding is as follows at December 31:
1999 1998
(Dollars in Thousands)
Western Resources
First mortgage bond series:
7 1/4% due 1999 . . . . . . . . . . . . . . . . $ - $ 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
400,000 525,000
Pollution control bond series:
Variable due 2032, 4.80% at December 31, 1999 . 45,000 45,000
Variable due 2032, 4.54% at December 31, 1999 . 30,500 30,500
6% due 2033 . . . . . . . . . . . . . . . . . . 58,420 58,420
133,920 133,920
<PAGE>
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
Pollution control bond series:
5.10% due 2023. . . . . . . . . . . . . . . . . 13,653 13,673
Variable due 2027, 4.25% at December 31, 1999 . 21,940 21,940
7.0% due 2031 . . . . . . . . . . . . . . . . . 327,500 327,500
Variable due 2032, 4.199% at December 31, 1999. 14,500 14,500
Variable due 2032, 4.30% at December 31, 1999 . 10,000 10,000
387,593 387,613
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 . . . . . 29,783 29,985
6.25% unsecured senior notes due 2018,
putable/callable 2003 . . . . . . . . . . . . 400,000 400,000
949,783 949,985
Protection One
Senior credit facility due 2001, 6.8%
at December 31, 1998. . . . . . . . . . . . . - 42,417
Convertible senior subordinated notes
due 2003, fixed rate 6.75%. . . . . . . . . . 53,950 53,950
Senior subordinated discount notes due 2005,
effective rate of 6.4%. . . . . . . . . . . . 87,038 125,590
Senior unsecured notes due 2005,
fixed rate 7.375% . . . . . . . . . . . . . . 250,000 250,000
Senior subordinated notes due 2009,
fixed rate 8.125% . . . . . . . . . . . . . . 341,415 350,000
CET recourse financing agreements, average
effective rate 18% and 15%, respectively. . . 60,838 93,541
Other . . . . . . . . . . . . . . . . . . . . . 2,033 2,574
795,274 918,072
Other long-term agreements. . . . . . . . . . . . 21,895 8,325
Unamortized debt premium. . . . . . . . . . . . . 13,726 13,918
Less:
Unamortized debt discount . . . . . . . . . . . . (7,458) (7,931)
Long-term debt due within one year. . . . . . . . (111,667) (165,838)
Long-term debt (net). . . . . . . . . . . . . . . $2,883,066 $3,063,064
Debt discount and expenses are being amortized over the remaining lives of
each issue.
<PAGE>
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.
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 the first mortgage
bonds. The notes are structurally subordinated to all secured and unsecured
debt of the company's subsidiaries.
In December 1998, Protection One entered into a revolving credit facility
which provided for borrowings of up to $500 million, subsequently decreased to
$250 million, and was to expire in December 2001. As a result of Protection One
not meeting its debt covenants under this facility, in December 1999, Westar
Capital acquired the debt and assumed the lenders' obligations.
In 1998, Protection One issued $350 million of Unsecured Senior
Subordinated Notes. The notes are redeemable at Protection One's option, in
whole or in part, at a predefined price.
Protection One did not complete a required exchange offer during 1999. As
a result, the interest rate on this facility increased to 8.625% in June 1999.
If the exchange offer is completed, the interest rate will revert back to
8.125%. Interest on this facility is payable semi-annually on January 15 and
July 15.
In 1998, Protection One issued $250 million of Senior Unsecured Notes.
Interest is payable semi-annually on February 15 and August 15. The notes are
redeemable at Protection One's option, in whole or in part, at a predefined
price.
In 1995, Protection One issued $166 million of Unsecured Senior
Subordinated Discount Notes with a fixed interest rate of 13 5/8%. Interest
payments began in 1999 and are payable semi-annually on June 30 and December 31.
In connection with the acquisition of Protection One in 1997, these notes were
restated to fair value reflecting a current market yield of approximately 6.4%.
This resulted in bond premium being recorded to reflect the increase in value of
the notes as a result of the decline in interest rates since the note issuance.
The revaluation has no impact on the expected cash flow to existing noteholders.
In 1998, Protection One redeemed notes with a book value of $69.4 million
and recorded an extraordinary gain on the extinguishment of $1.6 million, net of
tax. The remaining notes are redeemable at Protection One's option in whole or
in part, at anytime on or after June 30, 2000, at a predefined price.
In 1996, Protection One issued $103.5 million of Convertible Senior
Subordinated Notes. Interest is payable semi-annually on March 15 and September
15. The notes are convertible at any time at a conversion price of $11.19 per
share. The notes are redeemable, at Protection One's option, at a specified
<PAGE>
redemption price, beginning September 19, 1999.
Protection One's subsidiary CET has recognized as a financing transaction
cash received through the sale of security equipment and future cash flows to be
received under security equipment operating lease agreements with customers to
a third-party financing company. A liability has been recorded for the proceeds
of these sales as the finance company has recourse to CET in the event of
nonpayment by customers of their equipment rental obligations. The average
implicit interest rate in the financing is 18% at December 31, 1999.
Accordingly, the liability is reduced, rental revenue is recognized, and
interest expense is being recorded as these recourse obligations are reduced
through the cash receipts paid to the financing company over the term of the
related equipment rental agreements which averages four years. The liability
is increased as new security monitoring equipment and equipment rental
agreements are sold to the finance company that have recourse provisions.
Protection One's debt instruments contain financial and operating covenants
which may restrict its ability to incur additional debt, pay dividends, make
loans or advances and sell assets. From September 30, 1999 through December 31,
1999, Protection One received waivers from compliance with the then-applicable
leverage and interest coverage ratio covenants under the senior credit facility.
At December 31, 1999 Protection One was in compliance with all financial
covenants governing its debt securities.
The indentures governing Protection One's debt securities require that
Protection One offer to repurchase the securities in certain circumstances
following a change of control.
In the fourth quarter 1999, Westar Capital purchased Protection One bonds
on the open market at amounts less than the carrying amount of the debt. The
company has recognized an extraordinary gain of $13.4 million, net of tax, at
December 31, 1999 related to the retirement of this debt.
Maturities of long-term debt through 2004 are as follows:
Principal
Year Amount
(Dollars in Thousands)
2000 . . . . . . . . $111,667
2001 . . . . . . . . 32,246
2002 . . . . . . . . 106,472
2003 . . . . . . . . 240,568
2004 . . . . . . . . 370,457
The company's interest expense on long-term debt was $236.4 million in
1999, $170.9 million in 1998 and $120 million in 1997.
1O. 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
<PAGE>
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.
<TABLE>
The following tables summarize the status of the company's pension and
other postretirement benefit plans:
<CAPTION>
Pension Benefits Postretirement Benefits
December 31, 1999 1998 1999 1998
(Dollars in Thousands)
<S> <C> <C> <C> <C>
Change in Benefit Obligation:
Benefit obligation, beginning of year. $392,057 $462,964 $ 87,519 $ 83,673
Service cost . . . . . . . . . . . . . 8,949 7,952 1,609 1,405
Interest cost. . . . . . . . . . . . . 26,487 31,278 5,854 5,763
Plan participants' contributions . . . - - 784 858
Benefits paid. . . . . . . . . . . . . (21,961) (24,682) (6,990) (5,630)
Assumption changes . . . . . . . . . . (49,499) 36,268 (9,458) 6,801
Actuarial losses (gains) . . . . . . . (4,608) 10,095 (31) (5,351)
Acquisitions . . . . . . . . . . . . . (676) - - -
Plan amendments. . . . . . . . . . . . - - - -
Curtailments, settlements and special
term benefits (1) . . . . . . . . . . - (131,818) - -
Benefit obligation, end of year. . . . $350,749 $392,057 $ 79,287 $ 87,519
Change in Plan Assets:
Fair value of plan assets,
beginning of year . . . . . . . . . . $441,531 $584,792 $ 173 $ 118
Actual return on plan assets . . . . . 85,079 66,106 10 6
Acquisitions . . . . . . . . . . . . . - - - -
Employer contribution. . . . . . . . . 2,882 2,197 6,284 5,679
Plan participants' contributions . . . - - 784 -
Benefits paid. . . . . . . . . . . . . (22,497) (23,910) (6,990) (5,630)
Settlements (1). . . . . . . . . . . . - (187,654) - -
Fair value of plan assets,
end of year . . . . . . . . . . . . . $506,995 $441,531 $ 261 $ 173
Funded status. . . . . . . . . . . . . $156,246 $ 49,474 $(79,026) $(87,346)
Unrecognized net (gain)/loss . . . . . (205,338) (104,023) (7,733) 1,814
Unrecognized transition
obligation, net . . . . . . . . . . 209 244 52,171 56,159
Unrecognized prior service cost. . . . 32,854 36,309 (3,730) (4,131)
Accrued postretirement benefit costs . $(16,029) $(17,996) $(38,318) $(33,504)
Actuarial Assumptions:
Discount rate. . . . . . . . . . . . . 7.75% 6.75% 7.75% 6.75%
Expected rate of return. . . . . . . . 9.0% 9.0% 9.0% 9.0%
Compensation increase rate . . . . . . 4.5% 4.75% 4.5% 4.75%
Components of net periodic benefit cost:
Service cost . . . . . . . . . . . . . $ 8,949 $ 7,952 $ 1,610 $ 1,405
Interest cost. . . . . . . . . . . . . 26,487 31,278 5,854 5,763
Expected return on plan assets . . . . (34,393) (39,069) (16) (11)
Amortization of unrecognized
transition obligation, net. . . . . . 34 (32) 3,987 3,988
Amortization of unrecognized prior
service costs . . . . . . . . . . . . 3,455 3,455 (466) (461)
Amortization of (gain)/loss, net . . . (3,477) (5,885) 129 (396)
Other. . . . . . . . . . . . . . . . . - - - -
Net periodic benefit cost. . . . . . . $ 1,055 $ (2,301) $ 11,098 $ 10,288
(1) In July 1998, pension plan assets were transferred to ONEOK resulting in a settlement loss.
</TABLE>
<PAGE>
For measurement purposes, an annual health care cost growth rate of 7.0%
was assumed for 1999, 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 $2.0 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 in the company
stock fund. The company's contributions were $3.7 million for 1999, $3.8
million for 1998, and $5.0 million for 1997.
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 cash or in a combination of both stock and
cash. Protection One's matching contribution to the plan was $802,251 for 1999
and $992,000 for 1998.
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 as a means to attract, retain
and motivate employees and board members (Plan Participants). 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 five million shares of common stock may be granted under the LTISA Plan.
<PAGE>
<TABLE>
Stock options and restricted shares under the LTISA plan are as follows:
<CAPTION>
December 31, 1999 1998 1997
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 1,590,700 $ 36.106 665,400 $30.282 205,700 $29.250
Granted. . . . . . . . . . . . 981,625 30.613 925,300 40.293 459,700 30.750
Exercised. . . . . . . . . . . - - - - - -
Forfeited. . . . . . . . . . . (153,690) 31.985 - - - -
Outstanding, end of year . . . 2,418,635 $34.139 1,590,700 $36.106 665,400 $30.282
Weighted-average fair value
of options granted during
the year . . . . . . . . . . $ 8.22 $ 9.12 $ 3.00
</TABLE>
<TABLE>
Stock options and restricted shares issued and outstanding at December 31,
1999, are as follows:
<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:
1999. . . . . . . . . . $27.813-32.125 800,995 10.0 $30.815
1998. . . . . . . . . . 38.625-43.125 763,000 9.0 40.538
1997. . . . . . . . . . 30.750 414,520 8.0 30.750
1996. . . . . . . . . . 29.250 138,620 6.7 29.250
2,117,135
Restricted shares:
1999. . . . . . . . . . 27.813-32.125 165,000 9.0 29.616
1998. . . . . . . . . . 38.625 136,500 8.0 38.625
Total issued. . . . . 301,500
</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 $3.28 in 1999, and $6.88 in 1998. The value of each dividend equivalent is
calculated by accumulating dividends that would have been paid or payable on a
share of company common stock. The dividend equivalents expire after nine years
from date of grant.
<PAGE>
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:
1999 1998
Dividend yield. . . . . . . . . . 6.25% 6.32%
Expected stock price volatility . 16.56% 15.95%
Risk-free interest rate . . . . . 6.05% 5.67%
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.
A summary of options issued under the Plan by fiscal year is as follows:
Shares Granted Total Shares
to Officers Granted
1998 . . . 690,000 1,246,500
1999 . . . 399,700 1,092,908
Each option has a term of 10 years and vests ratably over three years. 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.
<TABLE>
A summary of warrant and option activity for Protection One from November
1997 through December 31, 1999, is as follows:
<CAPTION>
December 31, 1999 1998 1997
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(1) . . . . . . . . . 3,422,739 $ 7.494 2,366,435 $ 5.805 2,366,741 $5.805
Granted. . . . . . . . . . . . 1,092,908 7.905 1,246,500 11.033 - -
Exercised. . . . . . . . . . . - - (109,595) 5.564 (306) 0.050
Forfeited. . . . . . . . . . . (956,511) 10.124 (117,438) 10.770 - -
Adjustment to May 1995
warrants . . . . . . . . . . - - 36,837 - - -
Outstanding, end of year . . . 3,559,136 $12.252 3,422,739 $ 7.494 2,366,435 $5.805
(1) There was no outstanding stock or options prior to November 24, 1997.
</TABLE>
<PAGE>
Stock options and warrants issued and outstanding at December 31, 1999, are
as follows:
Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Contractual Exercise
Price Outstanding Life in Years Price
Exercisable:
Fiscal 1995 $ 6.375-$ 9.125 64,800 5.0 $ 6.491
Fiscal 1996 8.000- 10.313 178,400 6.0 8.031
Fiscal 1996 13.750- 15.500 69,000 6.0 14.924
Fiscal 1997 9.500 136,000 7.0 9.500
Fiscal 1997 15.000 25,000 7.0 15.000
Fiscal 1997 14.268 50,000 2.0 14.268
Fiscal 1998 11.000 367,499 8.0 11.000
Fiscal 1998 8.563 16,331 8.0 8.563
Fiscal 1999 8.928 87,600 9.0 8.928
KOP Warrants 3.633 103,697 1.0 3.633
1993 Warrants 0.167 428,400 4.0 0.167
1995 Note Warrants 3.890 786,277 5.0 3.890
Other 0.050 305 7.0 0.050
2,313,309
Not Exercisable:
1998 options $ 11.000 333,001 8.0 $11.000
1998 options 8.563 32,660 8.0 8.563
1999 options 8.928 686,500 9.0 8.928
1999 options 3.875- 6.125 193,666 9.0 5.855
1,245,827
Total outstanding 3,559,136
The weighted average fair value of options granted during 1999 and 1998 and
estimated on the date of grant were $6.87 and $5.41. The fair value was
calculated using the following assumptions:
Year ended December 31,
1999 1998
Dividend yield. . . . . . . . . 0.00% 0.00%
Expected stock price volatility 64.06% 61.72%
Risk free interest rate . . . . 6.76% 5.50%
Expected option life. . . . . . 6 years 6 years
Effect of Stock-Based Compensation on Earnings Per Share: 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 1999, 1998 and 1997 as shown in the table below.
<PAGE>
Year Ended December 31, 1999 1998 1997
(Dollars in Thousands, Except Per Share Amounts)
Earnings available for common stock:
As reported . . . . . . . . . . $11,330 $44,165 $494,599
Pro forma . . . . . . . . . . . 8,204 42,640 494,436
Earnings per common share
(basic and diluted):
As reported . . . . . . . . . . $0.17 $0.67 $7.59
Pro forma . . . . . . . . . . . 0.12 0.65 7.59
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 life insurance
policies on which 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 certain conditions, each executive may transfer to the company
their interest in the death benefit based on a predetermined formula, beginning
no earlier than the first day of the calendar year following retirement or three
years from the date of the policy. The liability associated with this program
was $31.9 million as of December 31, 1999, and $57.9 million as of December 31,
1998. The obligations under this program can increase and decrease based on the
company's total return to shareholders. This liability decreased approximately
$10.5 million in 1999 based on the company's total return to shareholders.
There was no change in the liability in 1998. Under current tax rules,
payments to active employees in exchange for their interest in the death
benefits may not be fully deductible by the company for income tax purposes.
11. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK, AND OTHER MANDATORILY
REDEEMABLE SECURITIES
The company's Restated Articles of Incorporation, as amended, provide for
150,000,000 authorized shares of common stock. At December 31, 1999, 67,401,657
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. During 1999, a total of 1,819,856 original issue shares were
purchased from the company. At December 31, 1999, 2,771,191 shares were
available under the DSPP registration statement.
<PAGE>
In 1999, the company purchased 900,000 shares of common stock at an average
price of $17.55 per share. The purchased shares were purchased with short-term
debt and available funds. The purchased shares are held in treasury and are
available for general corporate purposes, resale or retirement. These purchased
shares are shown as $15.8 million in treasury stock on the accompanying
Consolidated Balance Sheet.
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. At December 31, 1999, and 1998, the company had no
preference stock outstanding.
Other Mandatorily Redeemable Securities: On December 14, 1995, Western
Resources Capital I, a wholly-owned trust, issued 4.0 million preferred
securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A,
for $100 million. The trust interests 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 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 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 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 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.
<PAGE>
12. COMMITMENTS AND CONTINGENCIES
Purchase Orders and Contracts: 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 $190 million at
December 31, 1999.
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, 1999, the costs
incurred for preliminary site investigation and risk assessment have been
inimal. 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.
Superfund Sites: In December 1999, the company was identified as one of
more than 1,000 potentially responsible parties at an EPA Superfund site in
Kansas City, Kansas (Kansas City site). The company has previously been
associated with other Superfund sites for which the company's liability has been
classified as de minimis and any potential obligations have been settled at
minimal cost. Since 1993, the company has settled Superfund obligations at
three sites for a total of $141,300. No Superfund obligations have been settled
since 1994. The company's obligation, if any, at the Kansas City site is
expected to be limited based upon previous experience and the limited nature of
the company's business transactions with the previous owners of the site. In
the opinion of the company's management, the resolution of this matter is not
expected to have a material impact on the company's financial position or
results of operations.
Clean Air Act: The 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
<PAGE>
3.6% over the remaining service life from 1996 of 29 years. On September 1,
1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for
approval. Approval of this study by the KCC is pending. The company's share of
the cost for decommissioning in the 1999 study under the dismantlement method is
$221 million in 1999 dollars.
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 $3.9 million in 1999 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% per
year.
The company's investment in the decommissioning fund, including reinvested
earnings approximated $58.3 million at December 31, 1999, and $52.1 million at
December 31, 1998. Trust fund earnings accumulate in the fund balance and
increase the recorded decommissioning liability.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.5 billion for a single
nuclear incident. If this liability limitation is insufficient, the U.S.
Congress will consider taking whatever action is necessary to compensate the
public for valid claims. The Wolf Creek owners (Owners) have purchased the
maximum available private insurance of $200 million. 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 mandated by the NRC. The company's
share of any remaining proceeds can be used to pay for property damage or
decontamination expenses or, if certain requirements are met including
decommissioning the plant, toward 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 $6 million per year.
<PAGE>
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, 1999, Wolf Creek's
nuclear fuel commitments (company's share) were approximately $14 million for
uranium concentrates expiring at various times through 2003, $26 million for
enrichment expiring at various times through 2003 and $65.2 million for
fabrication through 2025.
At December 31, 1999, the company's coal contract commitments in 1999
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.
At December 31, 1999, the company's natural gas transportation commitments
in 1999 dollars under the remaining terms of the contracts were approximately
$29.1 million. The natural gas transportation contracts provide firm service to
the company's gas burning facilities expiring at various times through 2010.
Protection One SEC Matters: As previously disclosed, Protection One has been
advised by the Division of Corporation Finance of the SEC that, in the view of
the staff, there are errors in Protection One's financial statements which are
material and which have had the effect of inflating earnings commencing with the
year 1997. Protection One has had extensive discussions with the SEC staff
about the methodology used by Protection One to amortize customer accounts, the
purchase price allocation to customer accounts in the Multifamily acquisition
and other matters. The SEC staff has not indicated it concurs with, nor has
the SEC staff determined not to object to, the restatements made in 1999 or the
change in accounting principle for customer accounts. Protection One cannot
predict whether the SEC staff will make additional comments or take other action
that will further impact its financial statements or the effect or timing of any
such action.
13. LEGAL PROCEEDINGS
The SEC commenced a private investigation in 1997 relating to, among other
things, 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 in this investigation.
<PAGE>
The company, its subsidiary Westar Capital, Protection One, its subsidiary
Protection One Alarm Monitoring, Inc. (Monitoring), and certain present and
former officers and directors of Protection One are defendants in a purported
class action litigation pending in the United States District Court for the
Central District of California, "Ronald Cats, et al., v. Protection One, Inc.,
et. al.", No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999,
four pending purported class actions were consolidated into a single action. In
March 2000, plaintiffs filed a Second Consolidated Amended Class Action
Complaint (the Amended Complaint). Plaintiffs purport to bring the action on
behalf of a class consisting of all purchasers of publicly traded securities of
Protection One, including common stock and notes, during the period of
February 10, 1998, through November 12, 1999. The Amended Complaint asserts
claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the
Securities Exchange Act of 1934 against Protection One, Monitoring, and certain
present and former officers and directors of Protection One based on allegations
that various statements concerning Protection One's financial results and
operations for 1997 and 1998 were false and misleading and not in compliance
with Generally Accepted Accounting Principals (GAAP). Plaintiffs allege, among
other things, that former employees of Protection One have reported that
Protection One lacked adequate internal accounting controls and that certain
accounting information was unsupported or manipulated by management in order to
avoid disclosure of accurate information. The Amended Complaint further asserts
claims against the company and Westar as controlling persons under Sections 11
and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934. A claim is also asserted under Section 11 of
the Securities Act of 1933 against Protection One's auditor,
Arthur Andersen LLP. The Amended Complaint seeks an unspecified amount of
compensatory damages and an award of fees and expenses, including attorneys'
fees. The company and Protection One believe that all the claims asserted
in the Amended Complaint are without merit and intend to defend against them
vigorously. The company and Protection One cannot currently predict the
impact of this litigation which could be material.
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 disposition
of such matters will not have a material adverse effect upon the company's
overall financial position or results of operations. See also Note 14 for
discussion of the FERC proceeding regarding the City of Wichita complaint.
14. RATE MATTERS AND REGULATION
KCC Proceedings: In January 1997, the KCC entered an order reducing
electric rates for both KPL and KGE. The order required KGE to reduce electric
rates by $65 million cumulative, phased in over three years beginning in 1997.
The order required KPL to reduce electric rates by $10 million in 1997 and issue
two one-time rebates of $5 million in January 1998, and January 1999.
<PAGE>
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization
of commercial and industrial users of electricity in Kansas, filed a complaint
with the KCC requesting an investigation of Western Resources' and KGE's rates.
The KIC alleges that these rates are not based on current costs. The company
will oppose this request vigorously but is unable to predict whether the KCC
will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with the Federal Energy Regulatory Commission (FERC) against the company,
alleging improper affiliate transactions between KPL, a division of the company,
and KGE, a wholly-owned subsidiary of the company. The City of Wichita
requests the FERC to equalize the generation costs between KPL and KGE, in
addition to other matters. FERC has issued an order setting this matter for
hearing and has referred the case to a settlement judge. The hearing has been
suspended pending settlement discussions between the parties. The company
believes that the City of Wichita's complaint is without merit and intends to
defend against it vigorously.
15. LEASES
At December 31, 1999, 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:
Operating
Year Ended December 31, Leases
(Dollars in Thousands)
Rental payments:
1997 . . . . . . . . . . . . . . $ 71,126
1998 . . . . . . . . . . . . . . 70,796
1999 . . . . . . . . . . . . . . 71,771
Future commitments:
2000 . . . . . . . . . . . . . . 68,431
2001 . . . . . . . . . . . . . . 64,100
2002 . . . . . . . . . . . . . . 59,090
2003 . . . . . . . . . . . . . . 59,655
2004 . . . . . . . . . . . . . . 52,899
Thereafter . . . . . . . . . . . 610,925
Total future commitments . . . $915,100
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.
<PAGE>
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 $19.1 million of this deferral remained on the
Consolidated Balance Sheet at December 31, 1999.
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, $34.6 million in 2004, and $502.6
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 1999, $28.9 million for 1998, and $27.3 million for 1997.
16. INTERNATIONAL POWER DEVELOPMENT COSTS
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
recorded a $98.9 million charge to income in the fourth quarter of 1998 as a
result of exiting this business.
During 1999, the company terminated the employment of all employees, closed
offices, discontinued all development activities, and terminated all other
matters related to the activity of Wing in accordance with the terms of the exit
plan. These activities were substantially completed by December 31, 1999. The
actual costs incurred during 1999 to complete the exit plan approximated $16.9
million, which was $5.6 million less than the amount estimated at December 31,
1998. This was accounted for as a change in estimate in 1999.
At December 31, 1999, approximately $380,000 of accrued exit fees and shut-
down costs were included in other current liabilities on the accompanying
Consolidated Balance Sheet. This amount represents employee settlement and
severance costs expected to be paid in 2000.
The detailed components of the 1999 activity to exit this business are as
follows:
(Dollars in Thousands)
Accrued exit fees, shut-down and severance
costs, balance at December 31, 1998. . . . . . $22,900
Actual costs incurred. . . . . . . . . . . . . . (16,888)
Change in estimate . . . . . . . . . . . . . . . (5,632)
Accrued exit fees, change in estimate, shut-down and
severance costs, balance at December 31, 1999. . . .$ 380
17. MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY
On March 18, 1998, the company signed an Amended and Restated Plan of
Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL)
under which KGE, KPL, a division of Western Resources, and KCPL would have been
<PAGE>
combined into a new company called Westar Energy, Inc. KCPL has notified the
company that it has terminated the contemplated transaction.
The company expensed costs related to the KCPL merger of approximately
$17.6 million at December 31, 1999 and approximately $48 million at December 31,
1997 associated with the original merger agreement.
18. 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 $864.2 million on the sale and recorded tax expense
of approximately $345 million in connection with this gain.
19. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in Statement of Financial Accounting Standards No. 107
"Disclosures about Fair Value of Financial Instruments."
Cash and cash equivalents, 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,
1999 and 1998. The fair value of fixed-rate debt 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, 1999 and 1998. 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 would not have a material effect on
the company's
<PAGE>
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, 1999 1998 1999 1998
(Dollars in Thousands)
Decommissioning trust. . $ 58,286 $ 52,093 $ 58,286 $ 52,093
Fixed-rate debt, net of
current maturities . . 2,742,307 2,956,692 2,350,130 3,076,709
Other mandatorily
redeemable securities. 220,000 220,000 187,950 226,800
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, to maintain a market presence and to enhance system
reliability. The company attempts to balance its 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 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.
The notional volumes and estimated fair values of the company's trading
forward contracts and options are as follows at December 31:
1999 1998
Notional Notional
Volumes Estimated Volumes Estimated
(MWH's) Fair Value (MWH's) Fair Value
(Dollars in Thousands)
Forward contracts:
Purchased. . . . . 496,800 $14,800 1,535,600 $46,361
Sold . . . . . . . 478,400 14,404 1,535,600 46,141
Options:
Purchased. . . . . 659,200 $ 5,079 148,800 $ 361
Sold . . . . . . . 336,480 6,013 64,000 195
<PAGE>
Forward contracts and options had a net unrealized loss of $73,000 at
December 31, 1999, and a net unrealized gain of $40,000 at December 31, 1998.
The notional volumes and estimated fair values of the company's non-trading
forward contract and options for electric positions are as follows at December
31:
1999 1998
Notional Notional
Volumes Estimated Volumes Estimated
(MWH's) Fair Value (MWH's) Fair Value
(Dollars in Thousands)
Forward contracts:
Purchased. . . . . 640,800 $18,221 - -
Sold . . . . . . . 610,400 17,991 - -
Options:
Purchased. . . . . 285,600 $ 445 - -
Sold . . . . . . . 417,720 2,445 - -
Non-trading forward contracts and options for electric positions had a net
unrealized loss of $127,950 at December 31, 1999. No non-trading forward
contracts and options for electric positions were held at December 31, 1998.
The notional volumes and estimated fair values of the company's non-trading
forward contract and options for gas positions are as follows at December 31:
1999 1998
Notional Notional
Volumes Estimated Volumes Estimated
(MMBtu's) Fair Value (MMBtu's) Fair Value
(Dollars in Thousands)
Forward contracts:
Purchased. . . . . 13,010,000 $31,002 - -
Sold . . . . . . . 500,000 1,108 - -
Options:
Purchased. . . . . 6,000,000 $ 971 - -
Sold . . . . . . . 4,000,000 615 - -
Non-trading forward contracts and options for gas positions had a net
unrealized loss of $1,147,134 at December 31, 1999. No non-trading forward
contracts and options for gas positions were held at December 31, 1998.
<PAGE>
2O. INCOME TAXES
Income tax expense is composed of the following components at December 31:
1999 1998 1997
(Dollars in Thousands)
Currently payable:
Federal. . . . . . . . . . . $ 13,907 $52,993 $336,150
State. . . . . . . . . . . . 9,622 10,881 72,143
Deferred:
Federal. . . . . . . . . . . (44,257) (39,067) (15,945)
State. . . . . . . . . . . . (6,582) (4,185) (2,696)
Amortization of investment
tax credits . . . . . . . . . (6,054) (6,065) (6,665)
Total income tax expense
(benefit) . . . . . . . . . . $(33,364) $14,557 $382,987
Under Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes", temporary differences gave rise to deferred tax assets and
deferred tax liabilities as follows at December 31:
1999 1998
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . . . $ 87,220 $ 92,427
Monitored services deferred tax assets . . . 59,171 93,571
Other. . . . . . . . . . . . . . . . . . . . 125,563 138,506
Total deferred tax assets. . . . . . . . . $ 271,954 $ 324,504
Deferred tax liabilities:
Accelerated depreciation and other . . . . . $ 614,309 $ 613,730
Acquisition premium. . . . . . . . . . . . . 283,157 291,156
Deferred future income taxes . . . . . . . . 218,937 206,114
Other. . . . . . . . . . . . . . . . . . . . 40,508 48,518
Total deferred tax liabilities . . . . . . $1,156,911 $1,159,518
Investment tax credits . . . . . . . . . . . . $ 97,591 $ 103,645
Accumulated deferred income taxes, net . . . . $ 982,548 $ 938,659
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, 1999 1998 1997
Effective income tax rate. . . . . . . . . (102.2%) 24.0% 43.4%
Effect of:
State income taxes. . . . . . . . . . . . (6.0) (4.5) (5.0)
Amortization of investment tax credits. . 18.5 10.0 0.8
Corporate-owned life insurance policies . 25.4 15.0 0.9
Affordable housing tax credits. . . . . . 28.5 2.1 -
Accelerated depreciation flow through
and amortization, net . . . . . . . . . (11.1) (2.9) (0.4)
Adjustment to tax provision . . . . . . . 3.9 (11.3) (3.7)
Dividends received deduction. . . . . . . 31.1 16.0 -
Amortization of goodwill. . . . . . . . . (17.6) (11.4) -
Other . . . . . . . . . . . . . . . . . . (5.5) (2.0) (1.0)
Statutory federal income tax rate. . . . . (35.0%) 35.0% 35.0%
21. RELATED PARTY
The company and ONEOK have shared services agreements in which facilities,
utility field work, information technology, customer support, bill processing,
and human resources services are provided to and billed to one another.
Payments for these services are based upon various hourly charges, negotiated
fees and out-of-pocket expenses. ONEOK paid the company $5.6 million in 1999
and $4.9 million in 1998, net of what the company owed ONEOK, for services.
In 1999, the company sold 984,000 shares of ONEOK stock to ONEOK as a
result of ONEOK's repurchase program. The company reduced its investment in
ONEOK for proceeds received from this sale. All such shares were required to be
sold to ONEOK in accordance with a Shareholder Agreement between the company and
ONEOK. The company's ownership interest remains at approximately 45%.
22. 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.
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
<PAGE>
generating facility. This segment does not have any external sales. The power
delivery segment consists of the transmission and distribution of power to the
company's wholesale and retail customers in Kansas and the customer service
provided to these customers.
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 1.6 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>
Year Ended December 31, 1999:
<CAPTION>
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. . . $ 365,311 $ - $1,064,385 $ 605,176 $ 1,284 $ 2 $2,036,158
Internal sales. . . 546,683 108,445 293,522 - - (948,650) -
Depreciation and
amortization . . . 55,320 39,629 71,717 238,803 1,448 90 407,007
Earnings before
interest and taxes 219,087 (25,214) 145,603 (24,013) (27,754) (26,252) 261,457
Interest expense. . 294,104
Earnings before
income taxes . . . (32,647)
Identifiable assets 1,476,716 1,083,344 1,783,937 2,558,235 1,165,145 (59,171) 8,008,206
</TABLE>
<TABLE>
Year Ended December 31, 1998:
<CAPTION>
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services (3)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
Internal 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>
<TABLE>
Year Ended December 31, 1997:
<CAPTION>
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery (4)Services (5,6)Other (2,7)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
Internal 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
(1) Earnings before interest and taxes (EBIT) includes investment earnings of $36.0 million,
an impairment of marketable securities of $76.2 million and the write-off of deferred
costs of $17.6 million.
(2) Identifiable assets includes eliminating and reclassing balances to consolidate the monitored
services business.
(3) Earnings before interest and taxes (EBIT) includes investment earnings of $21.7 million and
the write-off of international power development costs of $98.9 million.
(4) EBIT includes monitored services special charge of $24.3 million.
(5) EBIT includes investment earnings of $37.8 million and gain on sale of Tyco securities of
$864.2 million.
(6) 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.
(7) EBIT includes write-off of deferred merger costs of $48 million.
</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 are as follows:
Year Ended December 31, 1999 1998
(Dollars in Thousands)
External sales:
North America operations. . . . . $1,873,152 $1,990,329
International operations. . . . . 163,006 43,725
Total . . . . . . . . . . . . . $2,036,158 $2,034,054
Property, plant and equipment, net:
North America operations. . . . . $3,881,294 $3,792,645
International operations. . . . . 8,150 7,271
Total . . . . . . . . . . . . . $3,889,444 $3,799,916
<PAGE>
23. 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)
1999
Sales . . . . . . . . . . . . . $460,582 $476,142 $648,998 $450,436
Gross profit. . . . . . . . . . 312,655 324,407 425,087 311,022
Net income before
extraordinary gain(1). . . . 20,747 18,489 49,010 (87,529)
Net income(1) . . . . . . . . . 20,747 18,489 49,010 (75,787)
Basic earnings per share available
for common stock before
extraordinary gain. . . . . . $ 0.31 $ 0.27 $ 0.72 $ (1.31)
Cash dividend per common share. $ 0.535 $ 0.535 $ 0.535 $ 0.535
Market price per common share:
High. . . . . . . . . . . . . $ 33.875 $ 29.375 $ 27.125 $ 23.8125
Low . . . . . . . . . . . . . $ 26.6875 $ 23.75 $ 20.375 $ 16.8125
1998
Sales . . . . . . . . . . . . . $382,343 $463,301 $701,402 $487,008
Gross profit. . . . . . . . . . 252,040 291,338 365,415 302,002
Net income before
extraordinary gain(2). . . . 29,813 29,415 71,421 (84,484)
Net income(2) . . . . . . . . . 29,813 31,006 71,421 (84,484)
Basic earnings per share available
for common stock before
extraordinary gain. . . . . . $ 0.44 $ 0.42 $ 1.08 $ (1.29)
Cash dividend per common share. $ 0.535 $ 0.535 $ 0.535 $ 0.535
Market price per common share:
High. . . . . . . . . . . . . $ 44.188 $ 42.688 $ 41.625 $ 43.250
Low . . . . . . . . . . . . . $ 40.000 $ 36.875 $ 37.688 $ 32.563
(1) The effect of Protection One's change in accounting principle effected
income in the third quarter of 1999 by increasing amortization expense
by $47 million.
(2) The loss in the fourth quarter of 1998, is primarily attributable to a
$98.9 million charge to income to exit the company's international power
development business.
24. SUBSEQUENT EVENTS
Marketable Securities: Through March 16, 2000, the company sold a
significant portion of an equity investment in a gas compression company and
realized a gain of $72.6 million.
<PAGE>
In February 2000, Metrocall, Inc., a paging company whose securities were
included in our investment portfolio at December 31, 1999, made an announcement
that significantly increased the market value of paging company securities in
the public markets. During the first quarter of 2000, the remainder of these
paging securities were sold and a gain of $24.9 million was realized.
Retirement of Protection One Debt: In the first quarter of 2000, Westar
Capital, purchased an additional $46.3 million of Protection One bonds in the
open market and recognized an extraordinary gain of $14.4 million, net of tax.
Protection One European Operations: On February 29, 2000, Westar Capital
purchased the continental European and United Kingdom operations of Protection
One, and certain investments held by a subsidiary of Protection One for an
aggregate purchase price of $244 million. The basis of the net assets sold did
not change and no gain or loss was recorded for this related party transaction.
Terms of the agreement were approved by a special committee of outside directors
of Protection One. The special committee obtained a fairness opinion from an
investment banker.
Dividend Policy: The company's board of directors reviews the company's
dividend policy on an annual basis. Among the factors the board of directors
considers in determining the company's dividend policy are earnings, cash flows,
capitalization ratios, competition and regulatory conditions. In January 2000,
the company's board of directors declared a first-quarter 2000 dividend of
53 1/2 cents per share. In March, the company announced a new dividend policy
that will result in quarterly dividends of $.30 per share or $1.20 per share on
an annual basis to be effective with the declaration of the July 2000 dividend.
Corporate Restructuring: On March 28, 2000, the company's board of
directors approved the separation of its electric and non-electric utility
businesses. The separation is currently expected to be effected through an
exchange offer to be made to shareholders in the third quarter of 2000. The
exchange ratio will be described in materials furnished to shareholders upon
commencement of the exchange offer. The impact on the company's financial
position and operating results cannot be known until the exchange ratio is
determined. The company expects to complete the separation in the fourth
quarter of 2000, but no assurance can be given that the separation will be
completed.
<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 2000 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 2000 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 2000 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, 1999 and 1998
Consolidated Statements of Income, for the years ended December 31, 1999,
1998 and 1997
Consolidated Statements of Comprehensive Income, for the years ended
December 31, 1999, 1998 and 1997
Consolidated Statements of Cash Flows, for the years ended December 31, 1999,
1998 and 1997
Consolidated Statements of Cumulative Preferred Stock, December 31, 1999 and
1998
Consolidated Statements of Shareholders' Equity, for the years ended
December 31, 1999, 1998 and 1997
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 November 15, 1999 - Press release regarding Western
Resources third-quarter earnings and plans to purchase Protection One
debt.
Form 8-K/A filed December 2, 1999 - Reporting a correction to attachment 2
of Western Resources third-quarter results reported on Form 8-K, dated
November 15, 1999.
Form 8-K filed December 3, 1999 - Press release reporting Western
Resources' and Protection One's receipt of extension on bank waiver.
Form 8-K filed December 8, 1999 - Presentation distributed by Western
Resources to financial analysts.
Form 8-K filed December 20, 1999 - Press release reporting Westar Capital,
a subsidiary of Western Resources, acquisition of the debt and
assumption of the lenders' obligations under Protection One's revolving
credit facility.
<PAGE>
Form 8-K filed January 3, 2000 - Press release reporting that Kansas City
Power & Light Company terminated the proposed merger with Western
Resources.
Form 8-K filed January 26, 2000 - Press release reporting that Western
Resources reached an agreement with its banks to eliminate the cross-
default provisions relating to Protection One, Inc.
Form 8-K filed January 27, 2000 - Press release reporting Western
Resources declaration of a first quarter dividend and that the Board of
Directors will consider a stock dividend for the balance of the current
annual dividend.
Form 8-K filed March 1, 2000 - Press release reporting Westar Capital's
purchase of Protection One, Inc.'s continental European and United
Kingdom operations, and certain other assets of Protection One.
<PAGE>
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -By-laws of the company, as amended March 16, 2000. (filed
electronically) I
3(b) -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(c) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated March 29, 1991.
3(d) -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(e) -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(f) -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(g) -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(h) -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(i) -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(j) -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)
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)
<PAGE>
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 June 30, 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 June 30, 1998 Form 10-Q)
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)
<PAGE>
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) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 31, 1993 Form 10-K)
10(g) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 31, 1993 Form 10-K)
10(h) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 31, 1993 Form 10-K)
10(i) -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(j) -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)
10(k) -Form of Shareholder Agreement between New ONEOK and the I
company. (filed as Exhibit 99.3 to the December 12, 1997
Form 8-K)
10(l) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 I
to the June 30, 1998 Form 10-Q)
10(m) -Amendment to Letter Agreement between the company and David C. I
Wittig, dated April 27, 1995 (filed as Exhibit 10 to the
June 30, 1998 Form 10-Q/A)
10(n) -Letter Agreement between the company and Douglas T. Lake, dated
August 17, 1998. (filed electronically)
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
21 -Subsidiaries of the Registrant. (filed electronically)
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
(filed electronically)
27 -Financial Data 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, 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, change in
estimate, shut-down and severance
costs (c) . . . . - 22,900 - - 22,900
Year ended December 31, 1999
Allowances deducted from
assets for doubtful accounts. . 29,544 24,302 - (18,081) 35,765
Monitored services special
charge (b). . . . . . . . . . . 1,025 - - (1,025) -
Accrued exit fees, shut-down
and severance costs (c) . . . . 22,900 (5,632) - (16,888) 380
(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 16 of Notes 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.
Date March 28, 2000 By 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,
DAVID C. WITTIG President and Chief March 28, 2000
(David C. Wittig) Executive Officer
(Principal Executive Officer)
Executive Vice President and
WILLIAM B. MOORE Chief Financial Officer March 28, 2000
(William B. Moore) (Principal Financial and
Accounting Officer)
FRANK J. BECKER Director March 28, 2000
(Frank J. Becker)
GENE A. BUDIG Director March 28, 2000
(Gene A. Budig)
CHARLES Q. CHANDLER, IV Director March 28, 2000
(Charles Q. Chandler, IV)
JOHN C. DICUS Director March 28, 2000
(John C. Dicus)
OWEN F. LEONARD Director March 28, 2000
(Owen F. Leonard)
RUSSELL W. MEYER, JR. Director March 28, 2000
(Russell W. Meyer, Jr.)
JOHN C. NETTELS, JR. Director March 28, 2000
(John C. Nettels, Jr.)
JANE DESNER SADAKA Director March 28, 2000
(Jane Desner Sadaka)
LOUIS W. SMITH Director March 28, 2000
(Louis W. Smith)
<PAGE>
Exhibit 3
WESTERN RESOURCES, INC.
BY-LAWS
(as amended March 16, 2000)
ARTICLE I
STOCKHOLDERS
Section 1. The annual meeting of the stockholders of the Company shall
be held on such day and at such time as the Board of Directors may deem
reasonable and appropriate, at the principal office of the Company in the City
of Topeka, Kansas, or such other place as the Board of Directors may designate
for the purpose of electing Directors and transacting such other business as
may properly be brought before the meeting.
Section 2. Special meetings of the stockholders may be held upon call
of the Board of Directors or the Chairman of the Board or the President, at
such time and at such place within or without the State of Kansas as may be
stated in the call and notice.
Section 3. Notice stating the place, day and hour of every meeting of
the stockholders, and in the case of a special meeting further stating the
purpose for which such meeting is called, shall be mailed at least ten days
before the meeting to each stockholder of record who shall be entitled to vote
thereat, at the last known post office address of each such stockholder as it
appears upon the books of the Company. Such further notice shall be given by
mail, publication or otherwise, as may be required by law.
Section 4. The holders of record of a majority of the shares of the
capital stock of the Company issued and outstanding, entitled to vote thereat,
present in person or represented by proxy, shall constitute a quorum at all
meetings of the stockholders, and the vote of a majority of such quorum shall
be necessary for the transaction of any business, unless otherwise provided by
law, by the Articles of Incorporation or by the By-laws. If at any meeting
there shall be no quorum, the holders of record, entitled to vote, of a
majority of such shares of stock so present or represented may adjourn the
meeting from time to time, without notice other than announcement at the
meeting, until a quorum shall have been obtained, when any business may be
transacted which might have been transacted at the meeting as first convened
had there been a quorum.
Section 5. Meetings of the stockholders shall be presided over by the
Chairman of the Board or, if he is not present, by the President or, in his
absence, by a Vice President. In the event that none of such officers be
present, then the meeting shall be presided over by a chairman to be chosen at
the meeting. The Secretary of the Company or, if he is not present, an
Assistant Secretary of the Company or, if neither the Secretary nor an
Assistant Secretary is present, a secretary to be chosen at the meeting shall
act as secretary of the meeting.
Section 6. At all meetings of the stockholders every holder of record
of the shares of the capital stock of the Company, entitled to vote thereat,
may vote thereat either in person or by proxy.
Section 7. At all elections of directors the voting shall be by written
ballot.
Section 8. The Board of Directors shall have power to close the stock
transfer books of the Company for a period not exceeding sixty days preceding
the date of - -
(a) Any meeting of the stockholders;
(b) Any payment of any dividends;
(c) Any allotment of rights;
(d) Any effective date of change or conversion or exchange of capital stock;
or, in lieu of closing the stock transfer books, the Board of Directors may fix
in advance a date not exceeding sixty days preceding the effective date of any
of the above enumerated transactions, and in such case only such stockholders as
shall be stockholders of record on the date so fixed shall be entitled to
receive notice of and to vote at such meeting, or to receive payment of such
dividend, or to receive allotment of rights, or to exercise rights of change,
conversion or exchange of capital stock, as the case may be, or to participate
in any of the above transactions, notwithstanding any transfer of any stock on
the books of the Company after such record date fixed as aforesaid.
ARTICLE II
DIRECTORS
Section 1. Subject to the provisions of the Articles of Incorporation, the
Directors shall be elected at the regular annual meeting of stockholders, but if
such election of Directors is not held on the day of the annual meeting, the
Directors shall cause the election to be held as soon thereafter as conveniently
may be. Also, subject to the provisions of the Articles of Incorporation, the
Directors shall be divided into three classes, which shall be as nearly equal in
number as possible, and no class shall include fewer than two Directors.
Directors shall hold office for a term of three years and until their successors
are elected and qualified. Each class of Directors shall be designated by the
year in which its term ends. The Board shall fill vacancies in any class in the
manner prescribed in this Article II, provided that any such newly elected
Director shall serve for the remainder of the term applicable to the vacancy
being filled. Notwithstanding the foregoing, whenever the holders of the
preferred stock or preference stock issued by the Company shall have the right,
voting separately by class, to elect Directors at an annual or special meeting
of the stockholders, the election, term of office, and filling of vacancies of
such Directors shall be governed by the terms of the Articles of Incorporation
applicable thereto, and such Directors so elected shall not be divided into
classes pursuant to this paragraph. Directors elected by a vote of the holders
of preferred stock or preference stock as provided in the Articles of
Incorporation shall hold office only so long as is required by the Articles of
Incorporation. Except as otherwise provided in the By-laws and Articles of
Incorporation, no Director shall be removed except for cause. This paragraph
shall not be amended or repealed, and no provision inconsistent herewith shall
be adopted, without the affirmative vote of the holders of at least 80% of the
outstanding shares of stock of the Company entitled to vote in any election.
Each director who is not a salaried full time officer or employee of the
Company shall be conclusively deemed to have resigned from the Board of
Directors of the Company if he retires, resigns, or is removed from the primary
business position which he held at the time of his election to the Board.
No director who is not a salaried full time officer or employee of the
Company shall be designated by the Board of Directors of the Company as a
nominee for re-election to the Board of Directors at an annual meeting of
stockholders if he shall have attained the age of seventy (70) at year-end prior
to such annual meeting.
No director who is a salaried full time officer or employee of the Company
shall be designated by the Board of Directors of the Company as a nominee for
re-election to the Board of Directors at an annual meeting of stockholders, if
he shall have attained the age of sixty-five (65) at year-end prior to such
annual meeting, or if he is no longer a full time officer or employee of the
Company, or if he has been removed, during the 12 month period prior to Board
action on nominees, from the position he previously held with the Company,
except that any chief executive officer serving on the Board may be re-nominated
for a maximum of two three-year terms after his retirement as chief executive
officer.
A majority of the members of the Board shall constitute a quorum for the
filling of vacancies of the Board of Directors and the transaction of business,
but if at any meeting of the Board there shall be less than a quorum present, a
majority of the Directors present may adjourn the meeting from time to time
without notice, other than announcement of the meeting, until a quorum shall
have been obtained, when any business may be transacted which might have been
transacted at the meeting as first convened had there been a quorum. The acts
of a majority of the Directors present at any meeting at which there is a quorum
shall, except as otherwise provided by law, by the Articles of Incorporation or
the By-Laws, be the acts of the Board.
Section 2. Vacancies in the Board of Directors, caused by death,
resignation or otherwise, may be filled at any meeting of the Board of Directors
and if the remaining directors constitute less than a quorum, by such remaining
directors, and the directors so elected shall hold office for the remainder of
the terms applicable to the class to which they were elected and until their
successors are elected and qualified.
Section 3. Meetings of the Board of Directors shall be held at such place
within or without the State of Kansas as may from time to time be fixed by
resolution of the Board or as may be specified in the call of any meeting.
Regular meetings of the Board shall be held at such time as may from time to
time be fixed by resolution of the Board, and notice of such meetings need not
be given. Special meetings of the Board may be held at any time upon call of
the Chairman of the Board or the President or a Vice President, by oral,
telegraphic or written notice, duly served on or sent or mailed to each director
not less than the day prior to any such meeting. Members of the Board may
participate in any meeting of such Board by means of conference telephone or
similar communications equipment by means of which all persons participating in
the meeting can hear each other, and participation in such meeting shall
constitute presence in person at the meeting. A meeting of the Board may be
held without notice immediately before or after the annual meeting of the
stockholders at the same place at which such meeting is held. Any meeting may
be held without notice if all of the directors are present at the meeting, or if
all of the directors sign a waiver thereof in writing. Any action required or
permitted to be taken at any meeting of the board of directors may be taken
without a meeting if all members of the board consent thereto in writing, and
the writing or writings are filed with the minutes of proceedings of the board.
Section 4. Meetings of the Board of Directors shall be presided over by
the Chairman of the Board, or, if he is not present, by the President or, if he
is absent, by a Vice President. In the event none of such officers are present,
then the meeting shall be presided over by a chairman to be chosen at the
meeting. The Secretary of the Company or, if he is not present, an Assistant
Secretary of the Company or, if neither the Secretary nor an Assistant Secretary
is present, a secretary to be chosen at the meeting shall act as secretary of
the meeting.
Section 5. Each director of the Company who is not a salaried officer or
salaried employee of the Company shall be entitled to receive such remuneration
for serving as a director and as a member of any committee of the Board as may
be fixed from time to time by the Board of Directors.
ARTICLE III
OFFICERS
Section 1. The Board of Directors shall choose one of its number President
of the Company and shall appoint one or more Vice Presidents, a Secretary and a
Treasurer of the Company and from time to time may appoint such Assistant
Secretaries, Assistant Treasurers, and other officers and agents of the Company
as it may deem proper. Any officer may hold more than one office.
Section 2. The term of office of all officers shall be one year or
until the respective successors are chosen or appointed, but any officer or
agent may be removed, with or without cause, at any time by the affirmative vote
of a majority of the members of the Board then in office.
Section 3. Subject to such limitations as the Board of Directors may
from time to time prescribe, the officers of the Company shall each have such
powers and duties as generally pertain to their respective offices, as well as
such powers and duties as from time to time may be conferred by the Board of
Directors.
Section 4. The salaries of all officers and agents of the Company shall
be fixed by the Board of Directors, or pursuant to such authority as the Board
may from time to time prescribe.
ARTICLE IV
CERTIFICATES OF STOCK
Section 1. The interest of each shareholder in the Company shall be
evidenced by a certificate or certificates for shares of stock of the Company in
such form as the Board of Directors may from time to time prescribe or by book
entry upon the books and records of the Company. Certificates for shares of
stock of the Company shall be signed by the Chairman of the Board or the
President or any Vice President and the Treasurer or any Assistant Treasurer of
this corporation and sealed with its corporate seal, or when the same bear the
facsimile signature of the Chairman of the Board or the President or any Vice
President and of the Treasurer or any Assistant Treasurer of the corporation and
its facsimile seal and shall be countersigned and registered in such manner, if
any, as the Board may by resolution, prescribe.
Section 2. The shares of stock of the Company shall be transferable only
on the books of the Company by the holders thereof in person or by duly
authorized attorney, upon surrender for cancellation of certificates, if
certificated, for a like number of shares of the same class of stock, with duly
executed assignment and power of transfer endorsed thereon or attached thereto,
or if uncertificated, with other appropriate evidence of transfer, with such
proof of the authenticity of the signatures as the Company or its agents may
reasonably require.
Section 3. No certificate for shares of stock of the Company shall be
issued in place of any certificate alleged to have been lost, stolen or
destroyed, except upon production of such evidence of the loss, theft, or
destruction, and upon indemnification of the Company and its agents to such
extent and in such manner as the Board of Directors may from time to time
prescribe.
ARTICLE V
CHECKS, NOTES, ETC.
All checks and drafts on the Company's bank accounts and all bills of
exchange and promissory notes, and all acceptances, obligations and other
instruments for the payment of money, shall be signed by such officer or
officers or agent or agents as shall be thereunto authorized from time to time
by the Board of Directors; provided that checks drawn on the Company's dividend,
general and special accounts may bear the facsimile signature, affixed thereto
by a mechanical device, of such officer or agent as the Board of Directors shall
authorize.
ARTICLE VI
FISCAL YEAR
The Fiscal year of the Company shall begin on the first day of January in
each year and shall end on the thirty-first day of December following.
ARTICLE VII
CORPORATE SEAL
The corporate seal shall have inscribed thereon the name of the Company and
the words "Corporate Seal Kansas".
Exhibit 10
August 17, 1998
Mr. Douglas T. Lake
29 Sturgis Road
Bronxville, New York 10708
Dear Doug,
In accordance with our recent discussions, I would like to outline for
you some terms for a position with Western Resources. Obviously, any
agreement is subject to approval of the Western Resources Board of Directors.
I am pleased to offer you the position of Executive Vice President,
Chief Strategic Officer for Western Resources. In addition, you would serve
as a member of the Company's Executive Council and participate with other
senior officers in the formation and implementation of corporate policy
regarding all aspects of the Company's operations.
In your position, you would be primarily responsible for leading our
efforts to grow our business as well as the businesses of our subsidiaries.
Where appropriate, you would be expected to serve on subsidiary boards. In
addition, we would expect you to open and manage an office in New York City to
be staffed with a sufficient number of financial analysts in order to provide
much of the analytical work for which we currently rely on bankers.
While we would expect you to spend at least half of your time in Topeka
and to establish your primary residence here, you would be expected to travel
extensively.
Your annual base compensation would be set at $325,000. You would
receive a $350,000 signing bonus if you begin your employment prior to
September 1, 1998. In addition to this base compensation, you would
participate in the Company's short- and long-term incentive plans for
officers. The short-term plan, while subject to change, would provide you an
opportunity for additional cash compensation of up to 60% of base pay. You
would also receive 30,000 stock options and 13,500 restricted shares in 1998,
under the long-term plan. In addition, you would be enrolled in Western
Resources' executive salary continuation plan.
If you are still an employee of Western Resources (or its successor or
one of its affiliates) as of September 1, 2000, you would receive a $500,000
payout. Likewise, if you are an employee on September 1, 2002, you would
receive $1,000,000. In the event your employment is terminated prior to these
respective dates by the Company without "Cause" or by you for "Good Reason,"
as those terms are defined in the Company's Change of Control Agreements, you
would receive $500,000 if such termination is prior to September 1, 2000 or
$1,000,000 if after September 1, 2000 but before September 1, 2002.
In addition to the above, you will receive all benefits which are
customarily offered to officers who serve on the Company's Executive Council.
These include a deferred compensation plan, a 401K savings plan, a qualified
retirement plan, medical/dental insurance, life insurance, accidental death
and dismemberment insurance, short- and long-term disability protection, sick
leave, vacation and holiday leave, up to $10,000 annually to cover financial
planning and tax preparation as well as $10,000 for legal assistance in that
regard, a car allowance, personal use of a cellular phone, a club membership,
a change of control agreement, matching gift, and relocation benefits. I have
enclosed a schedule that sets forth this information in greater detail.
<PAGE>
Doug, I look forward too hearing from you on this matter. Please call
if you would like to discuss any of these matters in more detail.
Sincerely,
David C. Wittig
<PAGE>
NAME: Douglas T. Lake
POSITION: Executive Vice President, Chief Strategic Officer
PAY GRADE: 5
COMPENSATION COMMENTS
Base Salary $325,000 Paid on the 15th and last day
of the month
Short Term Incentive Yes Performance related cash award
(target of 60% of Base Salary)
Payable in first quarter
following close of performance
period
Long Term Incentive Yes Non-qualified stock options and
dividend equivalents 30,000
stock options and 13,5000
restricted shares in 1998
BENEFITS
Medical/Dental Yes Noncontributory medical;
dental premium split 50/50
Life Insurance Yes 1X salary basic and AD&D -
noncontributory; Up to 4X
salary supplemental - employee
paid; premium fixed at age of
entry; supplemental fully
portable upon termination/
retirement
Qualified Retirement
Plan Elig. After
1 yr. Provides approx. 37% of final 5
year's average base pay with 20
years of service.
Savings Plan Elig. After
1 mo. 401(k) Plan allows 14% up to
$10,000 pre-tax and 4% after
tax Company matches first 6% of
base pay contributed at 50%
after 1 year of service.
Executive Salary
Continuation Plan Yes Full vesting with 15 years
service or age 65. Provides
61.7% of final 3 year's pay at
age 65. Lesser benefit payable
below age 65. Earliest
commencement is age 50,
actuarially reduced for age
below 60 and service less than
15 years. Benefit reduced by
Qualified Retirement Plan
benefit.
<PAGE>
Deferred Compensation Yes Maximum deferral 100% of Base
Salary; 100% of cash incentive
compensation. (Long term
Incentive comp. shares not
eligible for deferral).
Vacation Yes 4 weeks
Holidays Yes 10 days total; 9 fixed, 1
floating
Sick Leave Yes 7 days per year until 12
accumulated, then accrue 14
days per year; 180 days maximum
Short Term Disability Yes Performance related cash award
(target of 60% of Base
Salary)Payable in first quarter
following close of performance
period
Long Term Disability Yes Provides 60% Base Salary up to
$5,000 per month less Social
Security; payable to age 65.
Car Allowance Yes Monthly car allowance $571,
grossed up for anticipated
taxes ($935 includes taxes).
Financial Planning Yes Up to $10,000 annually for
financial planning and tax
related expenses, and up to
$10,000 for associated legal
fees and tax preparation
expenses.
Change of Control
Agreement Yes The Western Resources Change of
Control Agreement provides
specified benefits to a select
group of management and
executive employees of the
company in order that they may
advise the Board whether a
proposed change in control
would be in the best interests
of the company and its
shareowners without being
influenced by the uncertainties
of their own situation. In
your case, the applicable
severance multiple will be
2.99.
Club Membership Yes Company paid membership to
Topeka Country Club. Company
will reimburse for monthly
dues/capital expenses.
<PAGE>
Relocation Yes Company will pay for cost of
moving household goods and one
auto. Company will pay up to
90 days storage. You will
receive a cash payment in the
amount of 15% of the appraised
value of your Bronxville
residence (even if you choose
to keep such residence).
Matching Gift Yes The Company's matching gift
program provides matching
contributions to qualified
entities on a 2 for 1 basis of
up to $5,000 per year (maximum
match of $10,000 per year).
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,
1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
Earnings from
continuing operations(1) . . . $(48,798) $ 58,088 $ 872,739 $255,052 $265,068
Fixed Charges:
Interest expense . . . . . . . 294,104 226,120 193,225 152,551 123,821
Interest on Corporate-owned
Life Insurance Borrowings. . 36,908 38,236 36,167 35,151 32,325
Interest Applicable to
Rentals. . . . . . . . . . . 34,252 32,796 34,514 32,965 31,650
Total Fixed Charges. . . . 365,264 297,152 263,906 220,667 187,796
Distributed income of equity
investees . . . . . . . . . . . 3,728 3,812 - - -
Preferred and Preference Dividend
Requirements:
Preferred and Preference
Dividends. . . . . . . . . . 1,129 3,591 4,919 14,839 13,419
Income Tax Required. . . . . . 746 1,095 3,770 7,562 6,160
Total Preferred and
Preference Dividend
Requirements . . . . . . 1,875 4,686 8,689 22,401 19,579
Total Fixed Charges and Preferred
and Preference Dividend
Requirements. . . . . . . . . 367,139 301,838 272,595 243,068 207,375
Earnings (2) . . . . . . . . . . $320,194 $359,052 $1,136,645 $475,719 $452,864
Ratio of Earnings to Fixed
Charges (3) . . . . . . . . . . 0.88 1.21 4.31 2.16 2.41
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements. . . . . 0.87 1.19 4.17 1.96 2.18
(1) Earnings from continuing operations consists of loss or earnings before extraordinary gain and
income taxes adjusted for minority interest and undistributed earnings from equity investees.
(2) Earnings are deemed to consist of net income to which has been added income taxes (including net
deferred investment tax credit), fixed charges and distributed income of equity investees.
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.
(3) At December 31, 1999, the company's earnings were deficient by $45.1 million to cover fixed
charges.
</TABLE>
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
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. 333-9335, 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,
March 28, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AT DECEMBER 31, 1999 AND THE CONSOLIDATED STATEMENT
OF INCOME AND THE CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED
DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 15827
<SECURITIES> 177128
<RECEIVABLES> 264965
<ALLOWANCES> 35765
<INVENTORY> 112392
<CURRENT-ASSETS> 602968
<PP&E> 6060347
<DEPRECIATION> 2170903
<TOTAL-ASSETS> 8008206
<CURRENT-LIABILITIES> 1351195
<BONDS> 2883066
220000
24858
<COMMON> 341508
<OTHER-SE> 1533958
<TOTAL-LIABILITY-AND-EQUITY> 8008206
<SALES> 2036158
<TOTAL-REVENUES> 2036158
<CGS> 662987
<TOTAL-COSTS> 662987
<OTHER-EXPENSES> 1098695
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 294104
<INCOME-PRETAX> (32647)
<INCOME-TAX> (33364)
<INCOME-CONTINUING> 717
<DISCONTINUED> 0
<EXTRAORDINARY> 11742
<CHANGES> 0
<NET-INCOME> 12459
<EPS-BASIC> 0.17
<EPS-DILUTED> 0.17
</TABLE>
