Edgar Filing: WESTERN RESOURCES INC /KS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2000
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number 1-3523
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WESTERN RESOURCES, INC.
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(Exact name of registrant as specified in its charter)

KANSAS 48-0290150
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

818 KANSAS AVENUE, TOPEKA, KANSAS 66612
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(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code 785/575-6300
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Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $5.00 par value New York Stock Exchange
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(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
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(Title of Class)

Indicate 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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]

State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,682,196,624 of Common Stock and $10,181,490 of
Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there
is no readily ascertainable market value) at March 19, 2001.

Indicate the number of shares outstanding of each of the registrant's classes of
common stock.

Common Stock, $5.00 par value 84,460,817
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(Class) (Outstanding at March 19, 2001)

Documents Incorporated by Reference:

Part Document
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III The information required by Items 11-12 of this Form 10-K will be
included in an amendment to this Form 10-K to be filed with the
Commission.

WESTERN RESOURCES, INC.
TABLE OF CONTENTS

Page
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PART I
Item 1. Business 5

Item 2. Properties 23

Item 3. Legal Proceedings 25

Item 4. Submission of Matters to a Vote of
Security Holders 26

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 26

Item 6. Selected Financial Data 27

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 28

Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 51

Item 8. Financial Statements and Supplementary Data 52

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 96

PART III
Item 10. Directors and Executive Officers of the
Registrant 97

Item 11. Executive Compensation 98

Item 12. Security Ownership of Certain Beneficial
Owners and Management 98

Item 13. Certain Relationships and Related Transactions 98

PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 99

Signatures 104

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,
liquidity and capital resources, litigation, rate and other regulatory matters,
possible corporate restructurings, mergers, acquisitions, dispositions,
including the proposed separation of Westar Industries, Inc. from our electric
utility businesses and the consummation of the acquisition of our electric
operations by Public Service Company of New Mexico, compliance with debt
covenants, changes in accounting requirements and other accounting matters,
interest and dividends, Protection One's financial condition and its impact on
our consolidated results, environmental matters, changing weather, nuclear
operations, ability to enter new markets successfully and capitalize on growth
opportunities in non-regulated businesses, events in foreign markets in which
investments have been made, 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, ongoing municipal, state and federal
activities, such as the Wichita municipalization efforts; future economic
conditions; legislative and regulatory developments; competitive markets; and
other circumstances affecting anticipated operations, sales and costs. See Risk
Factors in Item 1. Business for additional information on these and other
matters.

PART I

ITEM 1. BUSINESS
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GENERAL

Western Resources, Inc. is a publicly traded consumer services company
incorporated in 1924. Unless the context otherwise indicates, all references in
this report on Form 10-K to the "company," "Western Resources," "we," "us" "our"
or similar words are to Western Resources, Inc. and its consolidated
subsidiaries. Our primary business activities are providing electric
generation, transmission and distribution services to approximately 636,000
customers in Kansas and providing monitored security services to over 1.5
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
security services are provided by Protection One, Inc., a publicly traded,
approximately 85%-owned subsidiary, and other wholly owned subsidiaries
collectively referred to as Protection One Europe. 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., natural gas transmission and distribution services are
provided to approximately 1.4 million customers in Oklahoma and Kansas. Westar
Industries, Inc., our wholly owned subsidiary, owns our interests in Protection
One, Protection One Europe, ONEOK, and other non-utility businesses. Our
corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas
66612.

Westar Industries has filed a registration statement with the Securities
and Exchange Commission (SEC) which covers the proposed sale of a portion of its
common stock through the exercise of non-transferable rights proposed to be
distributed by Westar Industries to our shareholders.

We can give no assurance as to whether or when the rights offering will be
consummated or whether or when the separation of our electric and non-electric
utility businesses, or the consummation of the acquisition of the company by PNM
may occur.

ELECTRIC UTILITY OPERATIONS

General

We supply electric energy at retail to approximately 636,000 customers in
Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina
and Hutchinson. We also supply electric energy at wholesale to the electric
distribution systems of 65 communities and 4 rural electric cooperatives. We
have contracts for the sale, purchase or exchange of wholesale electricity with
other utilities. In addition, we have power marketing

operations in which electric purchases and sales are made in areas outside of
our historical marketing territory.

Our electric sales for the last three years ended December 31 are as
follows:

2000 1999 1998
---------- ---------- ----------
(In Thousands)
Residential................... $ 452,674 $ 407,371 $ 428,680
Commercial.................... 367,367 356,314 356,610
Industrial.................... 252,243 251,391 257,186
Wholesale and
Interchange.................. 214,721 174,895 145,320
Power Marketing............... 457,178 190,101 382,601
System Hedging................ 35,321 3,320 -
Other......................... 49,628 46,306 41,288
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Total........................ $1,829,132 $1,429,698 $1,611,685

Our electric sales volumes for the last three years ended December 31 are
as follows:
2000 1999 1998
---------- ---------- ----------
(Thousands of MWH)
Residential................... 6,222 5,551 5,815
Commercial.................... 6,485 6,202 6,199
Industrial.................... 5,820 5,743 5,808
Wholesale and
Interchange.................. 6,892 5,617 4,826
Other......................... 108 108 108
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Total........................ 25,527 23,221 22,756

Power marketing and system hedging sales do not have any physical sales
volumes associated with them.

Fossil Fuel Generation

Capacity: The aggregate net generating capacity of our system is presently
5,604 megawatts (MW). The system has interests in 21 fossil-fuel steam
generating units, one nuclear generating unit (47% interest), nine combustion
peaking turbines, two diesel generators, and two wind generators. A fossil
fueled unit at Lawrence Energy Center (31 MW of capacity) was retired in 2000.

Our aggregate 2000 peak system net load, which was also our all time peak
system net load, occurred on September 11, 2000 and amounted to 4,531 MW. Our
net generating capacity combined with firm capacity purchases and sales provided
a capacity margin of approximately 11.7% above system peak responsibility at the
time of the peak.

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 energy transactions, unit commitment service, firm capacity, 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 generating capacity to other utilities for
certain periods as set forth below:

Utility Capacity (MW) Period Ending
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Oklahoma Municipal Power
Authority (OMPA) 60 December 2013

Midwest Energy, Inc. 60 May 2008
125 May 2010

Empire District Electric
Company (Empire) 80 May 2001
162 May 2010

McPherson Board of Public
Utilities (McPherson) (a) May 2027

(a) We provide base capacity to McPherson and McPherson provides peaking
capacity to us. During 2000, we provided approximately 73 MW to and
received approximately 185 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 a new combustion turbine generator with
a capacity of approximately 154 MW. The unit is scheduled to be placed in
operation in mid-2001. We estimate that completion of the project will require
approximately $20 million in capital resources during 2001. We forecast that we
will need additional capacity of approximately 150 MW by 2005 to serve our
customers' expected electricity needs. The methods for supplying this estimated
additional energy will be determined at a future date.

In July 1999, we and Empire agreed to jointly construct a 500-MW combined
cycle generating plant, which Empire will operate. We will own a 40% interest in
the plant through a subsidiary, Westar Generating, Inc. We estimate that our
share of the cost of completing the project will require approximately $31
million in capital resources during 2001. Commercial operation is expected to
begin in mid-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: Coal-fired units comprise 3,366 MW of our total 5,604 MW of
generating capacity and the nuclear unit provides 550 MW of capacity. Of the
remaining 1,688 MW of generating capacity, units that can burn either natural
gas or oil account for 1,603 MW, units that burn only diesel fuel account for 84
MW, and units which are powered by wind account for 1 MW (See Item 2.
Properties).

During 2000, coal was used to produce 78% of our electricity. Nuclear fuel
produced 16% and the remainder was produced from natural gas, oil, or diesel
fuel.

Our fuel mix fluctuates with the operation of nuclear powered Wolf Creek as
discussed below under Nuclear Generation, fuel costs, plant availability and
power available on the wholesale market.

Coal: The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 1,870 MW (our 84% share). We have a long-term coal supply
contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company
(RAG), to supply coal to JEC from mines located in the Powder River Basin in
Wyoming. The contract expires December 31, 2020. The contract contains a
schedule of minimum annual MMBtu delivery quantities. The coal to be supplied
is surface mined and has an average Btu content of approximately 8,397 Btu per
pound and an average sulfur content of .43 lbs/MMBtu (See Environmental
Matters). The average cost of coal burned at JEC during 2000 was approximately
$1.14 per MMBtu, or $19.09 per ton.

Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP)
railroads with a term continuing through December 31, 2013. This contract is
currently the subject of litigation.

The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 681 MW (KGE's 50% share). La Cygne 1 uses a blended fuel mix
containing approximately 85% Powder River Basin coal and 15% Kansas/Missouri
coal. La Cygne 2 uses Powder River Basin coal. The operator of La Cygne Station,
Kansas City Power & Light Company (KCPL), administers the coal and coal
transportation contracts. A portion of the La Cygne 1 and La Cygne 2 Powder
River Basin coal is supplied through several fixed price and spot market
contracts which expire at various times through 2003 and is transported under
KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern
Railroad through December 31, 2010. Additional coal may be acquired on the spot
market. The La Cygne 1 Kansas/Missouri coal is purchased from time to time from
local Kansas and Missouri producers.

The Powder River Basin coal supplied during 2000 had an average Btu content
of approximately 8,800 Btu per pound and an average sulfur content of .45
lbs/MMBtu. During 2000, the average cost of all coal burned at La Cygne 1 was
approximately $0.81 per MMBtu, or $13.92 per ton. The average cost of coal
burned at La Cygne 2 was approximately $0.72 per MMBtu, or $12.30 per ton.

The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 815 MW. In 2000, we obtained coal from
Montana and Colorado. The Montana coal supplied in 2000 had an average Btu
content of approximately 9,750 Btu per pound and an average sulfur content of
.80 lbs/MMBtu. The Colorado coal supplied in 2000 had an average Btu content of
approximately 10,568 Btu per pound and an average sulfur content of .45
lbs/MMBtu. During 2000, the average cost of all coal burned in the Lawrence
units was approximately $1.14 per MMBtu, or $22.50 per ton. The average cost of
all coal burned in the Tecumseh units was approximately $1.08 per MMBtu, or
$20.92 per ton.

During the first quarter of 2001, the Lawrence and Tecumseh Energy Centers
switched from Montana Coal to Wyoming Powder River Basin Coal transported by
BNSF railroad. Fuel switching is done in an effort to find alternative
economical supplies of coal that meet our generation needs. Colorado coal will
supplement the Wyoming coal and will be transported by BNSF and UP railroads.
We have enough Wyoming and Colorado coal under contract to support the
anticipated operation of these units through the end of 2001. We have a portion
of our Colorado coal needs under a contract that expires in 2004. We intend to
negotiate contracts for Wyoming and Colorado coal for these facilities for
future operations. We may also purchase coal on the spot market.

We have entered into all of our coal contracts in the ordinary course of
business and do not believe we are substantially dependent upon these contracts.
We believe there are other suppliers with plentiful sources of coal available at
spot market prices to replace, if necessary, fuel to be supplied pursuant to
these contracts. In the event that we were required to replace our coal
agreements, we would not anticipate a substantial disruption of our business
although the cost of purchasing coal could increase.

We have entered into all of our coal transportation contracts in the
ordinary course of business. Several rail carriers are capable of serving our
origin coal mines, but several of our generating stations can be served by only
one rail carrier. In the event the rail carrier to one of our generating
stations fails to provide reliable service, we could experience a short-term
disruption of our business. However, due to the obligation of the rail carriers
to provide service under the Interstate Commerce Act, we do not anticipate any
substantial long-term disruption of our business although the cost of
transporting coal could increase.

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 supplies the system with a flexible natural gas supply
necessary to meet operational needs. For Abilene and Hutchinson Energy Centers,
we have maintained interruptible natural gas transportation with Kansas Gas
Service under a contract which expires March 31, 2001. We are in the process of
replacing the current contract.

For Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy
Centers, we meet a portion of our natural gas transportation requirements
through firm natural gas transportation capacity agreements with Williams Gas
Pipelines Central. The firm transportation agreements that serve Gordon Evans,
Murray Gill, Lawrence and Tecumseh extend through April 1, 2010 and the
agreement for the Neosho facility extends through June 1, 2016.

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 some
of our generating stations and as a primary fuel in the Hutchinson Unit 4
combustion turbine and in the diesel generators. Oil is obtained by spot market
purchases and year-long contracts. We maintain quantities in inventory to meet
emergency requirements and protect against reduced availability of natural gas
for limited periods or when the primary fuel becomes uneconomical to burn.

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. We use financial instruments to hedge
a portion of our anticipated fossil fuel needs in an attempt to offset the
volatility of the spot market. Due to the volatility of these markets, we are
unable to determine what the value will be when the agreements are actually
settled. See the Market Risk Disclosure for further information.

Natural gas and oil prices increased significantly during 2000 throughout
the nation. During 2000, our region experienced a price range of $2.09 per
MMBtu to $11.53 per MMBtu for natural gas. We experienced a 45% increase in our
average cost for natural gas purchased, or an increase of $1.07 per MMBtu. See
the Market Risk Disclosure for further discussion.

During the first quarter of 2001, spot market prices for western coal
markets increased significantly. This increase will impact the fuel contracts
currently in place for the portion of our 2001 anticipated coal which is indexed
to or purchased on the spot market for our La Cygne Generating Station,
increasing our coal commodity price market risk. We do not believe that 2001
spot market purchases will be at rates as favorable as those experienced during
2000.

Set forth in the table below is information relating to the weighted
average cost of fuel that we have used (which includes the commodity cost,
transportation cost to our facilities and any other associated costs).

KPL Plants 2000 1999 1998
---------- ---- ---- ----
Per Million Btu:

Coal............... $1.13 $1.09 $1.15
Gas................ 3.84 2.66 2.29
Oil................ 3.45 4.17 4.40

Per MWH Generation.... 1.36 1.26 1.31

KGE Plants 2000 1999 1998
---------- ---- ---- ----
Per Million Btu:
Nuclear............ $0.44 $0.45 $0.48
Coal............... 0.91 0.87 0.86
Gas................ 3.34 2.31 2.28
Oil................ 3.12 2.11 4.05

Per MWH Generation.... 1.11 0.98 0.94

Nuclear Generation

Fuel Supply: The owners of Wolf Creek have on hand or under contract 100%
of their uranium needs for 2001 and 65% of the uranium required for operation of
Wolf Creek through March 2005. The balance is expected to be obtained through
spot market and contract purchases.

Contractual arrangements are in place for 100% of Wolf Creek's uranium
conversion needs for 2001 and 65% of the uranium conversion required for
operation of Wolf Creek through March 2005. The owners have under contract 100%
of Wolf Creek's uranium enrichment needs for 2001 and 77% of the uranium
enrichment required to operate Wolf Creek through March 2005. The balance of
Wolf Creek's conversion and enrichment needs are expected to be obtained through
term contract and spot market purchases.

All uranium, uranium hexaflouride and uranium enrichment arrangements have
been entered into in the ordinary course of business and Wolf Creek is not
substantially dependent upon these agreements. Wolf Creek's management believes
there are other supplies available at reasonable prices to replace, if
necessary, these contracts. In the event that these contracts were required to
be replaced, Wolf Creek's management does not anticipate a substantial
disruption of Wolf Creek's operations.

Nuclear fuel is amortized to cost of sales based on the quantity of heat
produced for the generation of electricity.

Fuel Disposal: 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 for the future
disposal of spent nuclear fuel. These disposal costs are charged to cost of
sales.

In 1996 and 1997, a U.S. Court of Appeals 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
indicated 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 nuclear 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. In early 2000, Wolf Creek completed 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.

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that
the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate
Low-Level Radioactive Waste Compact and selected a site in 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 net investment in the Compact through December 31, 2000, 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 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.

Scheduled Outages: Wolf Creek has an 18-month refueling and maintenance
schedule which permits uninterrupted operation every third calendar year. The
next outage is scheduled in the spring of 2002. During the outage, electric
demand is expected to be met primarily by our other fossil-fueled generating
units and by purchased power.

Insurance: Information with respect to insurance coverage applicable to
the operations of our nuclear generating facility is set forth in Note 14 of the
Notes to Consolidated Financial Statements.

Power Delivery

Our Power Delivery segment transports electricity from the generating
stations to approximately 636,000 customers in Kansas. It also transports
electric energy to the electric distribution systems of 65 communities and 4
rural electric cooperatives. Power Delivery properties include substations,
poles, wire, underground cable systems, and customer meters. Power Delivery's
objective is to provide low-cost electricity transportation while maintaining a
high level of system reliability and customer service.

We are a member of the Southwest Power Pool (SPP). SPP's responsibility is
to maintain transmission system reliability on a regional basis. SPP is working
to become a regional transmission organization (RTO) for the region encompassing
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 ten 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 also includes the customer service portion of
our electric utility business. Customer service includes, among other things,
operating our phone center, handling credit and collections, billing, meter
reading, and field service.

Competition and Deregulation

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 have initiated steps that were expected
to result in a more competitive environment for utility services. However,
during 2000 and early 2001, extensive problems in the deregulated California
market have caused many states to reconsider deregulation efforts. The Kansas
Legislature took no action on deregulation in 2000.

In a deregulated environment, utility companies that are not responsive to
a competitive energy marketplace may suffer erosion in market share, revenues
and profits as recently experienced in the California energy market. Increased
competition for retail electricity sales may in the future reduce our earnings
which could impact our ability to pay dividends and could have a material
adverse impact on our operations and our financial condition. A material non-
cash charge to earnings may be required should we discontinue accounting under
Statement of Financial Accounting Standard No. 71, "Accounting for the Effects
of Certain Types of Regulation."

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. 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. We anticipate that FERC Order 2000 will not have a material
effect on us or our operations.

For further discussion regarding competition and its potential impact on
us, 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, the transmission of electric
power and the issuance of certain securities. We are subject to the
jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations
and safety. We are also 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).

On November 27, 2000, we and KGE filed applications with the KCC for a
change in retail rates which included a cost allocation study and separate cost
of service studies for our KPL division and KGE. We and KGE also provided
revenue requirements on a combined company basis on December 28, 2000. If
approved as proposed, the impact of these rate requests will be an annual
increase of $93.0 million for our KPL division and $58.0 million for KGE for a
total of $151.0 million. The proposal also contains a mechanism for adjusting
these rate requests up or down if projected natural gas fuel prices are
different from the prices utilized in the November 27, 2000 filings. We
anticipate a ruling by the KCC in July 2001 but are unable to predict the
outcome. We can give no assurance that these rate requests will be approved as
proposed.

Additional information with respect to Rate Matters and Regulation is set
forth in Notes 1 and 3 of Notes to Consolidated Financial Statements and Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.

Environmental Matters

We currently hold all Federal and State environmental approvals required
for the operation of our generating units. We believe we are presently in
substantial compliance with all air quality regulations (including those
pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx))
promulgated by the State of Kansas and the Environmental Protection Agency, or
EPA.

The JEC and La Cygne 2 units have met: (1) the Federal sulfur dioxide
standards through the use of low sulfur 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 meet these
standards through the use of low sulfur coal and by all facilities burning coal
being 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 have not had to make any material capital expenditures 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 14 of the Notes to Consolidated Financial Statements.

MONITORED SERVICES

General: We provide property monitoring services through Protection One
and Protection One Europe to over 1.5 million customers. Security services are
provided to residential (both single family and multifamily residences),
commercial and wholesale customers. Revenues are generated primarily from
recurring monthly payments for monitoring and maintaining the alarm systems
installed in customer's homes and businesses.

Protection One and Protection One Europe are owned by Westar Industries and
will therefore cease to be part of Western Resources upon consummation of a
separation of our electric utility and non-electric utility businesses.

Operations: 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. Products range
from basic intrusion and fire detection equipment to fully integrated systems
with card access, closed circuit television and voice/video monitoring.

Alarm monitoring customer contracts generally have initial terms ranging
from two to ten years in duration, and provide for automatic renewals for a
fixed period (typically one year) unless one of the parties elects to cancel the
contract at the end of its term.

Protection One maintains nine major service centers in North America to
provide monitoring services to the majority of its customer base. In the United
Kingdom, Protection One Europe's service centers are based in the metropolitan
London area. The service centers in continental Europe are based in Paris and
in metropolitan Marseilles, France.

Protection One Europe has a significant number of customers in the United
Kingdom whose security systems are not monitored. Systems for these customers
are designed to detect unauthorized entry and emit an audible alarm. Protection
One Europe provides maintenance service for these customers.

Branch Operations: Protection One maintains 69 service branches in North
America from which Protection One provides field repair, customer care, alarm
response and sales services and 11 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. Protection One Europe maintains approximately 44 sales
branch offices in the United Kingdom and continental Europe.

Sales and Marketing: Protection One relies on a diverse customer
acquisition strategy including a mix of internal sales efforts, "tuck-in"
acquisitions and a dealer program. Protection One Europe relies on an internal
sales force. In February 2000, Protection One initiated a commission only
internal sales team, now operating in all Protection One markets, with a goal of
producing accounts at a cost lower than its external sales efforts. This program
utilizes Protection One's existing branch infrastructure in all its markets.
Protection One is also pursuing alliances with strategic partners in an effort
to further diversify its marketing distribution channels. Protection One's
dealer marketing program provides support services to dealers as they grow their
independent businesses. On behalf of 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.

Competition: The security alarm industry is highly competitive. 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.;
- SecurityLink from Cambridge Securities (previously from Ameritech
Inc., a subsidiary of Ameritech Corporation);
- Protection One;
- Brinks Home Security Inc., a subsidiary of The Pittston Services
Group of North America; and
- Honeywell Inc.

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 and Protection One Europe
believe that they compete effectively with other national, regional and local
security alarm companies due to their reputation for reliable equipment and
services, their prominent presence in the areas surrounding their branch offices
and dealers, and their ability to offer combined monitoring, repair and enhanced
services.

Intellectual Property: Protection One owns trademarks related to the name
and logo for each of Protection One, Network Multifamily Security, and PowerCall
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. While
Protection One believes its trademarks, service marks and proprietary
information are important to its business, other than the trademarks Protection
One owns in its own name and logo, Protection One does not believe its inability
to use any of its trademarks and service marks would have a material adverse
effect on its business as a whole.

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:

- 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; and
- Subjecting alarm monitoring companies to fines or penalties for
transmitting false alarms.

Protection One's and Protection One Europe'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 and Protection One Europe are required to obtain licenses or
permits, to comply with standards governing employee selection and training, and
to meet certain standards in the conduct of its business. Many jurisdictions
also require certain employees to obtain licenses or permits. Those employees
who serve as patrol officers are often subject to additional licensing
requirements, including firearm licensing and training requirements in
jurisdictions in which they carry firearms.

The alarm industry is also subject to requirements imposed by various
insurance, approval, listing, and standards organizations. Depending upon the
type of customer served, the type of security service provided, and the
requirements of the applicable local governmental jurisdiction, adherence to the
requirements and standards of such organizations is mandatory in some instances
and voluntary in others.

Protection One's advertising and sales practices are regulated in the
United States by both the Federal Trade Commission and state consumer protection
laws. In addition, certain administrative requirements and laws of the
jurisdictions in which Protection One and Protection One Europe operate also
regulate such practices. Such laws and regulations include restrictions on the
promotion of the sale of 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 foreign jurisdictions in which Protection One and Protection One Europe
operate regulate the telephone communications with the local authorities.

Risk Management: The nature of the services provided by Protection One and
Protection One Europe potentially exposes them 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 and Protection One Europe's
alarm monitoring agreements, and other agreements, pursuant to which their
products and services are sold, contain provisions limiting liability to
customers in an attempt to reduce this risk.

Protection One and Protection One Europe carry insurance of various types,
including general liability and errors and omissions insurance in amounts
considered adequate and customary for the industry and business. Loss
experience, and the loss experiences at other security service companies, may
affect the availability and cost of such insurance. Certain insurance policies,
and the laws of some states, may limit or prohibit insurance coverage for
punitive or certain other types of damages, or liability arising from gross
negligence.

SEGMENT INFORMATION

Financial information with respect to business segments is set forth in
Note 22 of the Notes to Consolidated Financial Statements.

GEOGRAPHIC INFORMATION

Geographic information is set forth in Note 22 of the Notes to Consolidated
Financial Statements.

EMPLOYEES

As of December 31, 2000, we had approximately 8,300 employees, of which
approximately 5,800 were monitored service employees. We did not experience any
strikes or work stoppages during 2000. Our current contract with the
International Brotherhood of Electrical Workers extends through June 30, 2002.
The contract covers approximately 1,400 employees.

RISK FACTORS

Cautionary Statements Regarding Future Results of Operations

You should read the following risk factors in conjunction with discussions
of factors discussed elsewhere in this and other of our filings with the SEC.
These cautionary statements are intended to highlight certain factors that may
affect our financial condition and results of operations and are not meant to be
an exhaustive discussion of risks that apply to public companies with broad
operations, such as us. Like other businesses, we are susceptible to
macroeconomic downturns in the United States or abroad that may affect the
general economic climate and our performance or that of our customers.
Similarly, the price of our securities is subject to volatility due to
fluctuations in general market conditions, differences in our results of
operations from estimates and projections generated by the investment community
and other factors beyond our control.

Efforts by Wichita to Equalize Rates May Affect Operations and Results: In
September 1999, the City of Wichita filed a complaint with FERC against KGE,
alleging improper affiliate transactions between KGE and Western Resources' KPL
division. The City of Wichita asked that FERC equalize the generation costs
between KGE and KPL, in addition to other matters. On November 9, 2000, a FERC
administrative law judge ruled in our favor that no change in rates was
required. On December 13, 2000, the City of Wichita filed a brief with

FERC asking that the Commission overturn the judge's decision. We anticipate a
decision by FERC in the second quarter of 2001. A decision requiring
equalization of rates could have a material adverse effect on our business and
financial condition.

Municipalization Efforts by Wichita May Affect Operations and Results: In
December 1999, the City Council of Wichita, Kansas, 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. The
feasibility study was released in February 2001 and estimates that the City of
Wichita would be required to pay us $145 million for our stranded costs if it
were to municipalize. However, we estimate the amount to be substantially
greater. 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 and arrange for its own power supply. These costs are in
addition to the stranded costs for which the city would be required to reimburse
us. On February 2, 2001, the City of Wichita announced its intention to proceed
with its attempt to municipalize KGE's retail electric utility business in
Wichita. KGE will oppose municipalization efforts by the City of Wichita.
Should the city be successful in its municipalization efforts without providing
us adequate compensation for our assets and lost revenues, the adverse effect on
our business and financial condition could be material.

KGE's franchise with the City of Wichita to provide retail electric service
expires in March 2002. There can be no assurance that we can successfully
renegotiate the franchise with terms similar, or as favorable, as those in the
current franchise. Under Kansas law, KGE will continue to have the right to
serve the customers in Wichita following the expiration of the franchise,
assuming the system is not municipalized. Customers within the Wichita
metropolitan area account for approximately 25% of our total energy sales.

Electric Fuel Costs and Purchased Power are Included in Base Rates and are
not Recovered Automatically: Electric fuel costs and purchased power are
included in base rates. Therefore, if we wish to recover an increase in fuel
and purchased power costs, we 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 and purchased power costs from the projected average which we did not
recover through rates would reduce our earnings.

Purchased Power and Fossil-Fuel Commodity Prices are Volatile: In 2000 and
1999, 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, if available, or implement curtailment or interruption
procedures. To the extent open positions exist in our power marketing
portfolio, we are exposed to fluctuating market prices that may adversely impact
our financial position and results of operations. The increased expenses or
loss of revenues associated with this could be material and adverse to our
consolidated results of operations and financial condition. Over the last few
years, purchased power prices have increased above historical levels and are not
expected to decrease.

We use a mix of various fuel types, including coal and natural gas, to
operate our system. Natural gas prices increased significantly during 2000
throughout the nation. This increase impacted the cost of gas we used for
generation as well as our cost of purchased power. The higher natural gas prices
increased our total cost of gas purchased during 2000 although we decreased the
quantity burned.

During the first quarter of 2001, spot market prices for western coal
markets increased significantly. This increase will impact the portion of our
anticipated cost of coal which is indexed to or purchased on the spot market.

In an effort to mitigate fuel commodity price market risk, we use hedging
arrangements to minimize our exposure to increased coal, natural gas and oil
prices. Our future exposure to changes in fossil fuel prices will be dependent
upon the market prices and the extent and effectiveness of any hedging
arrangements we may have. Increases in purchased power and fossil fuel prices
could have a material adverse effect on our results of operation.

Hedging and Trading Activities Involve Risks: We are involved in hedging
and trading activities primarily to minimize risk from commodity market
fluctuations, capitalize on market knowledge and enhance system reliability. In
these activities, we utilize a variety of financial instruments, including
forward contracts involving cash settlements or physical delivery of an energy
commodity, options, swaps requiring payments (or receipt of payments) from
counter-parties based on the differential between specified prices for the
related commodity, and futures traded on electricity and natural gas.

Our hedging and trading activities involve risks, including the risk that
market prices will move against the prices reflected in our contracts, credit
risks associated with the financial condition of our counter-parties, and the
risk of increased earnings volatility from period to period. See Market Risk
Disclosure in Item 7. Management's Discussion and Analysis for further
discussion.

Strategic Transactions May Not Be Completed and the Separation of Westar
Industries Would Impact Results of Operation: Our strategic plans contemplate
acquisition of our electric utility business by PNM and the split-off of Westar
Industries to our shareholders. Prior to the completion of these transactions,
Westar Industries intends to sell a portion of its common stock in a rights
offering to our shareholders. The completion of these transactions is subject to
the satisfaction of various conditions, including the receipt of shareholder and
regulatory approvals in the case of the PNM transaction. We can give no
assurance that the conditions to closing will be satisfied and that the
transactions will be consummated as contemplated. Furthermore, if the Westar
Industries rights offering is completed, we would record a non-cash charge
against income equal to the difference between the book value of the portion of
our investment in Westar Industries sold in the rights offering and the offering
proceeds received by Westar Industries. Similarly, if the split-off of Westar
Industries is completed, we would record a non-cash charge against income equal
to the difference between the book value of our remaining investment in Westar
Industries and the fair market value of the shares of Westar Industries common
stock distributed to our shareholders. We are unable to determine the amount of
the charges at this time because the subscription price in the rights offering
has not been determined and the fair market value of the common stock of Westar
Industries distributed in the split-off will be determined at the time of the
split-off. However, the charges would be material and would have a material
adverse effect on our operating results in the period recorded.

Monitored Services Has Had a History of Losses Which are Likely to
Continue: Monitored services incurred net losses of $77.8 million in 2000 (a
net loss of $127.1 million excluding extraordinary gains of $49.3 million, net
of tax), $80.7 million in 1999 (a net loss of $91.9 million excluding the effect
of the Mobile Services Group gain, net of tax) and $17.8 million in 1998. These
losses reflect, among other factors:

- lower revenue and higher costs per customer due to a smaller customer
base;
- substantial charges incurred for amortization of purchased customer
accounts;
- interest incurred on indebtedness;
- other charges required to manage operations; and
- costs associated with the integration of acquisitions.

Substantial charges for amortization of purchased customer accounts will
continue on monitored services' existing customer base and customer accounts
acquired in the future. We anticipate that Protection One will also continue to
incur substantial interest expense because of its substantial debt. We do not
expect monitored services to attain profitable operations in the forseeable
future.

The Impact of Recently Proposed Accounting Changes Requiring the Write Off
of Goodwill Could Be Significant: The Financial Accounting Standards Board
issued an exposure draft on February 14, 2001 which, if adopted as proposed,
would establish a new accounting standard for the treatment of goodwill in a
business combination. The new standard would continue to

require recognition of goodwill as an asset in a business combination but would
not permit amortization as currently required by APB Opinion No. 17, "Intangible
Assets." The new standard would require that goodwill be separately tested for
impairment using a fair-value based approach as opposed to an undiscounted cash
flow approach which is required under current accounting standards. If goodwill
is found to be impaired, we would be required to record a non-cash charge
against income. The impairment charge would be equal to the amount by which the
carrying amount of the goodwill exceeds the fair value. Goodwill would no longer
be amortized on a current basis as is required under current accounting
standards. The exposure draft contemplates this standard to become effective on
July 1, 2001, although this effective date is not certain. Furthermore, the
proposed standard could be modified prior to its adoption.

If the new standard is adopted as proposed, any subsequent impairment test
on our customer accounts would be performed on the customer accounts alone
rather than in conjunction with goodwill utilizing an undiscounted cash flow
test pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of."

At December 31, 2000, we had $976 million in goodwill attributable to
acquisitions of businesses and $1,006 million for monitored services' customer
accounts. These intangible assets together represented 25.5% of the book value
of our total assets. We recorded approximately $61.4 million in goodwill
amortization expense in 2000. If the new standard becomes effective July 1, 2001
as proposed, we believe it is probable that we would be required to record a
non-cash impairment charge. We cannot determine the amount at this time, but we
believe the amount would be material and could be a substantial portion of our
intangible assets. This impairment charge would have a material adverse effect
on our operating results in the period recorded.

The Impact of Protection One Class Action Litigation May Be Material: We,
our subsidiary Westar Industries, Protection One, its subsidiary Protection One
Alarm Monitoring, Inc., 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 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, 1998,
1999 and the first three quarters of 2000 were false and misleading. We and
Protection One cannot predict the impact of this litigation which could be
material. (See Item 3. Legal Proceedings and Note 15 of the Notes to
Consolidated Financial Statements for more information.)

For additional risk factors relating to Protection One, see its December
31, 2000 Annual Report on Form 10-K.

EXECUTIVE OFFICERS OF THE COMPANY

Other Offices or Positions
Name Age Present Office Held During Past Five Years
---- --- -------------- ---------------------------

David C. Wittig 45 Chairman of the Board
(since January 1999)
Chief Executive Officer
(since July 1998)
and President
(since March 1996)

Thomas L. Grennan 49 Executive Vice President, Senior Vice President, Electric
Electric Operations Operations (September 1998 to
(since November 1998) November 1998)
Vice President, Generation Services
(May 1995 to August 1998)

Carl M. Koupal, Jr. 47 Executive Vice President
and Chief Administrative
Officer

Douglas T. Lake 50 Director Bear Stearns & Co., Inc. -
(since October 2000) Senior Managing Director
Executive Vice President, (1995 to August 1998)
Chief Strategic Officer
(since September 1998)

James A. Martin 43 Senior Vice President, Vice President (July 1995 to
and Treasurer August 2000)
(since August 2000)

Richard D. Terrill 46 Executive Vice President, Executive Vice President, General
General Counsel Counsel, Corporate Secretary
(since May 1999) (May 1999 to May 2000)
Vice President, Law and Corporate
Secretary (July 1998 to May 1999)
Secretary and Associate General
Counsel (April 1992 to June 1998)

Rita A. Sharpe 42 Executive Vice President, Western Resources, Inc. -
Shared Services (since Vice President, Shared Services
May 2000) (October 1998 to May 2000)
Westar Energy, Inc., -
Chairman and President (February
1997 to October 1998)
Vice President and Assistant
Secretary (May 1995 to February
1997)

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.

ITEM 2. PROPERTIES
-------------------

ELECTRIC GENERATING FACILITIES

Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW)
----------------------------- ---- --------- --------- -------------

Abilene Energy Center:
Combustion Turbine 1 1973 Gas 66.0

Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 151.0
2 1967 Gas--Oil 383.0
Combustion Turbines 1 2000 Gas--Oil 74.0
2 2000 Gas--Oil 74.0
Diesel Generator 1 1969 Diesel 3.0

Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18.0
2 1950 Gas 18.0
3 1951 Gas 31.0
4 1965 Gas 191.0
Combustion Turbines 1 1974 Gas 52.0
2 1974 Gas 50.0
3 1974 Gas 52.0
4 1975 Oil--Diesel 78.0
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 - 0.6
2 1999 - 0.6
La Cygne Station (50%):
Steam Turbines 1 (a) 1973 Coal 344.0
2 (b) 1977 Coal 337.0

Lawrence Energy Center:
Steam Turbines 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 43.0
2 1954 Gas--Oil 74.0
3 1956 Gas--Oil 112.0
4 1959 Gas--Oil 106.0

Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 67.0

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
Wolf Creek Generating
Station (47%):
Nuclear 1 (a) 1985 Uranium 550.0
-------
Total 5,604.2
=======

(a) We jointly own 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% interest in the La Cygne 2 generating unit.

We own approximately 6,300 miles of transmission lines, approximately
21,000 miles of overhead distribution lines, and approximately 2,800 miles of
underground distribution lines.

Substantially all of our utility properties are encumbered by first
priority mortgages pursuant to which bonds have been issued and are outstanding.

MONITORED SERVICES FACILITIES

Protection One:

Size
Location (Sq. ft.) Lease/Own Principal Purpose
-------- --------- --------- -------------------------------------

United States:
Addison, TX...................... 28,512 Lease Service Center/Multifamily
Administrative Headquarters
Beaverton, OR.................... 44,600 Lease Service Center
Hagerstown, MD (1)............... 21,370 Lease Service Center
Irving, TX....................... 53,750 Lease Service Center
Irving, TX....................... 27,197 Lease Administrative Functions
Orlando, FL...................... 11,020 Lease Wholesale Service Center
Topeka, KS....................... 17,703 Lease Financial/Administrative Headquarters
Wichita, KS...................... 50,000 Own Service Center/Administrative
Functions
Canada:
Ottawa, ON....................... 7,937 Lease Service Center/Administrative
Headquarters
Vancouver, BC.................... 5,177 Lease Service Center

(1) In March 2001, this facility was closed.

Protection One Europe:

Size
Location (Sq. ft.) Lease/Own Principal Purpose
-------- --------- --------- ------------------------------------

Europe:
London, UK....................... 8,900 Lease Administrative/Service Center
Basingstoke (London), UK......... 4,600 Lease Financial/Administrative
Offices/Service Center
Paris, FR........................ 3,498 Lease Financial/Administrative
Offices/Service Center
Vitrolles........................
(Marseilles), FR................. 13,003 Lease Administrative/Service Center

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 us with respect to securities of
ADT Ltd. We are cooperating with the SEC staff in this investigation.

The company, its subsidiary Westar Industries, 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, "Alec Garbini, 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. On February 27, 2001, plaintiffs filed a Third Consolidated Amended
Class Action Complaint ("Amended Complaint"). Plaintiffs purported 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 February 2, 2001. 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, 1998, 1999 and the first three quarters of 2000
were false and misleading and not in compliance with generally accepted
accounting principles. 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 Industries 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. Defendants have until
April 9, 2001 to respond to the Amended Complaint. The company and Protection
One intend to vigorously defend against all the claims asserted in the Amended
Complaint. The company and Protection One cannot predict the impact of this
litigation which could be material.

Additional information on legal proceedings involving the company is set
forth in Notes 3 and 15 of Notes to Consolidated Financial Statements. See also
Item 1. Business, Environmental Matters and Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------------------------------------------------------------

No matter was submitted to a vote of our security holders through the
solicitation of proxies or otherwise during the fourth quarter of 2000.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
------------------------------------------------------------------------------

Stock Trading

Our common stock is listed on the New York Stock Exchange and traded under
the ticker symbol WR. As of March 19, 2001, there were 39,546 common
shareholders of record. For information regarding quarterly common stock price
ranges for 2000 and 1999, see Note 23 of Notes to Consolidated Financial
Statements.

Dividends

Holders of our common stock are entitled to dividends when and as declared
by the Board of Directors. 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 and our obligations with respect to
mandatorily redeemable preferred securities issued by subsidiary trusts must be
met.

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 ninth day of the preceding month. The company's board of directors reviews
its dividend policy from time to time. Among the factors the board of directors
considers in determining its dividend policy are earnings, cash flows,
capitalization ratios, competition and financial loan covenants. In March 2000,
the company announced a quarterly dividend of $0.30 per share (an indicated
dividend rate of $1.20 per share on an annual basis). In February 2001, the
company's board of directors declared a first-quarter 2001 dividend of 30 cents
per share. Our agreement with PNM prohibits an increase in the dividend paid on
our common stock without the consent of PNM.

Our Articles of Incorporation contain restrictions on the payment of
dividends or the making of other distributions on our common stock while any
preferred shares remain outstanding unless certain capitalization ratios and
other conditions are met. At December 31, 2000, under these provisions, the
company's paid-in capital and retained earnings were restricted by $857,600
against the payment of dividends on common stock.

For information regarding quarterly dividend declarations for 2000 and
1999, 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.

ITEM 6. SELECTED FINANCIAL DATA
--------------------------------

For the Year Ended December 31,
-------------------------------------------------------------------
2000 1999(a) 1998(b) 1997(c) 1996
---------- ----------- ----------- ----------- ----------
(In Thousands)

Income Statement Data:
Sales.............................. $2,368,476 $2,030,087 $2,034,054 $2,151,765 $2,046,827

Net income before extraordinary
gain and accounting change........ 91,050 2,554 34,058 498,652 168,950

Earnings available for common
stock............................. 135,352 13,167 32,058 493,733 154,111

Balance Sheet Data:
Total assets....................... $7,767,208 $7,989,892 $7,929,776 $6,945,350 $6,647,781
Long-term debt (net) and
other mandatorily
redeemable securities............. 3,457,849 3,103,066 3,283,064 2,391,889 1,951,583

For the Year Ended December 31,
-------------------------------------------------------------------
2000 1999(a) 1998(b) 1997(c) 1996
---------- ----------- ----------- ----------- ----------

Common Stock Data:
Basic and diluted earnings per
share available for common
stock before extraordinary
gain and accounting change........ $ 1.30 $ 0.02 $ 0.46 $ 7.58 $ 2.41
Basic and diluted earnings per
share available for common
stock............................. $ 1.96 $ 0.20 $ 0.48 $ 7.58 $ 2.41
Dividends per share (d)............ $ 1.44 $ 2.14 $ 2.14 $ 2.10 $ 2.06
Book value per share............... $ 27.20 $ 27.66 $ 29.21 $ 30.86 $ 25.15
Average shares outstanding(000's) 68,962 67,080 65,634 65,128 63,834

(a) Information reflects the impairment of marketable securities and the change
to an accelerated amortization method for Monitored Services customer
accounts.
(b) Information reflects exit costs associated with international power
development activities.
(c) Information reflects the gain on the sale of Tyco common shares, our
strategic alliance with ONEOK and the acquisition of Protection One.
(d) In March 2000, the company announced a new dividend policy. See Item 5.
Dividends.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
------------------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------

INTRODUCTION

Unless the context otherwise indicates, all references in this report on
Form 10-K to the "company," "Western Resources," "we," "us," "our" or similar
words are to Western Resources, Inc. and its consolidated subsidiaries.

In Management's Discussion and Analysis we explain the general financial
condition, significant annual changes and the operating results for Western
Resources and its subsidiaries. We explain:

- What factors impact our business
- What our earnings and costs were in 2000 and 1999
- Why these earnings and costs differ from year to year
- How our earnings and costs affect our overall financial condition
- What our capital expenditures were for 2000
- What we expect our capital expenditures to be for the years 2001
through 2003
- 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 Financial Statements which show our operating results.

SUMMARY OF SIGNIFICANT ITEMS

PNM Merger and Split-off of Westar Industries

On November 8, 2000, we entered into an agreement under which Public
Service Company of New Mexico (PNM) will acquire our electric utility businesses
in a stock-for-stock transaction. Under the terms of the agreement, both we and
PNM will become subsidiaries of a new holding company. Immediately prior to the
consummation of this combination, we will split-off our remaining interest in
Westar Industries to our shareholders. Westar Industries, our wholly owned
subsidiary, owns our interests in Protection One, Inc., Protection One Europe,
ONEOK, Inc., and other non-utility businesses. In connection with this
transaction, in February 2001 Westar Industries converted a portion of a
receivable owed by us into approximately 14.4 million shares of our common
stock. See Note 2 of the Notes to Consolidated Financial Statements.

Westar Industries has filed a registration statement with the Securities
and Exchange Commission (SEC) covering the proposed sale of a portion of its
common stock through the exercise of non-transferable rights proposed to be
distributed by Westar Industries to our shareholders. We anticipate that the
rights offering will be completed in 2001.

Extraordinary Gain on Extinguishment of Debt

During 2000, Westar Industries purchased $170.0 million face value of
Protection One bonds on the open market. In exchange for cash and the
settlement of certain intercompany payables and receivables, $103.9 million of
these debt securities were transferred to Protection One. Protection One also
purchased $30.5 million face value of its bonds on the open market during 2000.
An extraordinary gain of $49.2 million, net of tax of $26.5 million, was
recognized at December 31, 2000, on these retirements.

Exposure Draft for Goodwill Accounting

The Financial Accounting Standards Board (FASB) issued an exposure draft on
February 14, 2001 which, if adopted as proposed, would establish a new
accounting standard for the treatment of goodwill in a business combination.
The new standard would continue to require recognition of goodwill as an asset
in a business combination but would not permit amortization as currently
required by APB Opinion No. 17, "Intangible Assets." The new standard would
require that goodwill be separately tested for impairment using a fair-value
based approach as opposed to an undiscounted cash flow approach which is
required under current accounting standards. If goodwill is found to be
impaired, we would be required to record a non-cash charge against income. The
impairment charge would be equal to the amount by which the carrying amount of
the goodwill exceeds the fair value. Goodwill would no longer be amortized on a
current basis as is required under current accounting standards. The exposure
draft contemplates this standard to become effective on July 1, 2001, although
this effective date is not certain. Furthermore, the proposed standard could be
modified prior to its adoption.

At December 31, 2000, we had $976 million in goodwill attributable to
acquisitions of businesses and $1,006 million for monitored services' customer
accounts. These intangible assets together represented 25.5% of the book value
of our total assets. We recorded approximately $61.4 million in goodwill
amortization expense in 2000. If the new standard becomes effective July 1,
2001 as proposed, we believe it is probable that we would be required to record
a non-cash impairment charge. We cannot determine the amount at this time, but
we believe the amount would be material and could be a substantial portion of
our intangible assets. This impairment charge would have a material adverse
effect on our operating results in the period recorded.

Strategic Transaction and the Separation of Westar Industries

Our strategic plans contemplate the acquisition of our electric utility
businesses by PNM and the split-off of Westar Industries to our shareholders.
Prior to the completion of these transactions, Westar Industries intends to sell
a portion of its common stock in a rights offering to our shareholders. The
completion of these transactions is subject to the satisfaction of various
conditions, including the receipt of shareholder and regulatory approvals in the
case of the PNM transaction. We can give no assurance that the conditions to
closing will be satisfied and that the transactions will be consummated as
contemplated. Futhermore, if the Westar Industries rights offering is completed,
we would record a non-cash charge against income equal to the difference between
the book value of the portion of our investment in Westar Industries sold in the
rights offering and the offering proceeds received by Westar Industries.
Similarly, if the split-off of Westar Industries is completed, we would record a
non-cash charge against income equal to the difference between the book value of
our remaining investment in Westar Industries and the fair market value of the
shares of Westar Industries common stock distributed to our shareholders. We are
unable to determine the amount of the charges at this time because the
subscription price in the rights offering has not been determined and the fair
market value of the common stock of Westar Industries distributed in the split-
off will be determined at the time of the split-off. However, the charges would
be material and would have a material adverse effect on our operating results in
the period recorded.

Monitored Services Change in Estimate of Useful Life of Goodwill

In January 2000, 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,
increased levels of attrition experienced in 1999 and other factors, the
estimated useful life of goodwill should be reduced from 40 years to 20 years as
of January 1, 2000. After that date, remaining

goodwill, net of accumulated amortization, is being amortized over its remaining
useful life based on a 20-year life. Protection One Europe made a similar
change. Based on Protection One's and Protection One Europe's existing account
bases at January 1, 2000, this resulted in an increase in aggregate annual
goodwill amortization of approximately $33.0 million in 2000.

Marketable Securities

During the fourth quarter of 1999, we decided to sell our remaining
marketable security investments in paging industry companies. These securities
were classified as available-for-sale; therefore, changes in market value were
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, a non-cash charge of $76.2 million
was recorded in the fourth quarter of 1999 and is presented separately in the
accompanying Consolidated Statements of Income.

During the first quarter of 2000, we sold the remainder of our portfolio of
paging company securities. We realized a gain of $24.9 million on these sales.
This gain was largely attributable to a general increase in the market value of
paging companies triggered by an announcement made by one paging company in
February 2000 which had a favorable impact on the market value of public paging
company securities.

During 2000, we sold our equity investment in a gas compression company and
realized a pre-tax gain of $91.1 million.

OPERATING RESULTS

Western Resources Consolidated

2000 Compared to 1999: Basic earnings per share was $1.96 compared to $0.20
in 1999. This increase is primarily attributable to increased investment
earnings from the sale of certain investments and the extraordinary gain on the
retirement of Protection One bonds. This increase was partially offset by a
change in the estimated life of goodwill and operating losses from our monitored
services segment.

1999 Compared to 1998: Basic earnings per share was $0.20 compared to
$0.48 in 1998. Our 1999 results of operations benefited from the performance of
the regulated electric utility operations. However, this performance was not
sufficient to offset the impairment recorded on marketable securities in the
fourth quarter of 1999 or the losses from our monitored services segment.

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 dividends.

Electric Utility

We supply electric energy at retail to approximately 636,000 customers in
Kansas. We also supply electric energy at wholesale to the electric
distribution systems of 65 communities and 4 rural electric cooperatives. We
have contracts for the sale, purchase or exchange of electricity with other
utilities.

In addition, we have power marketing operations and we engage in system
hedging transactions. Power marketing transactions are electric purchases and
sales made in areas outside of our historical marketing territory. System
hedging transactions are entered into at certain times to reduce exposure
relative to the volatility of market prices for purchased power. The settlement
of system hedging transactions affects both our sales and our cost of sales
although the net effect in 2000 was insignificant. If the cost of settling the
hedging transactions exceeds the premiums from the related sales, the net effect
will be a loss just as there would be a net gain if the premiums from the sales
exceed the corresponding cost of the sales.

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 and purchased power included in base rates
- The results of our power marketing and system hedging transactions

Our electric sales for the last three years are as follows:

2000 1999 1998
---------- ---------- ----------
(In Thousands)

Residential....... $ 452,674 $ 407,371 $ 428,680
Commercial........ 367,367 356,314 356,610
Industrial........ 252,243 251,391 257,186
Wholesale and
Interchange..... 214,721 174,895 145,320
Power Marketing... 457,178 190,101 382,601
System Hedging.... 35,321 3,320 -
Other............. 49,628 46,306 41,288
---------- ---------- ----------
Total........... $1,829,132 $1,429,698 $1,611,685
========== ========== ==========

The following tables reflect the changes in electric sales volumes, as
measured by megawatt hours, for the years ended December 31, 2000, 1999 and
1998:

2000 1999 % Change
------ ------ --------
(Thousands of MWH)

Residential................ 6,222 5,551 12.1%
Commercial................. 6,485 6,202 4.6
Industrial................. 5,820 5,743 1.4
Other...................... 108 108 -
------ ------ -----
Total retail.............. 18,635 17,604 5.9
Wholesale.................. 6,892 5,617 22.7
------ ------ -----
Total..................... 25,527 23,221 9.9%
====== ====== =====

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 -
------ ------ -----
Total retail.............. 17,604 17,930 (1.8)
Wholesale.................. 5,617 4,826 16.4
------ ------ -----
Total..................... 23,221 22,756 2.0%
====== ====== =====

Power marketing and system hedging sales do not have any physical sales
volumes associated with them.

2000 compared to 1999: Electric operations gross profit increased $28.3
million, or 3%. The increase is due primarily to increased power marketing
sales. Electric operations gross profit as a percentage of sales decreased to
54% from 67% primarily due to higher fuel and purchased power prices. (See
Market Risk Disclosure for further discussion.)

Additionally, we experienced a 12% increase in residential sales volumes
and a 23% increase in wholesale sales volumes. The increase in residential
sales is primarily due to increased demand caused by warm weather. Cooling-
degree days increased by 27%. The increase in wholesale sales volumes was
primarily due to increased wholesale market opportunities because of our larger
trading operation.

Items included in energy cost of sales are fuel expense, purchased power
expense (electricity we purchase from others for resale) and power marketing
expense.

Partially offsetting the higher sales was an increase of $371.3 million in
cost of sales primarily due to higher power marketing expense of $263.0 million
and increased fuel and purchased power expenses of approximately $71.0 million.
Fuel and purchased power expenses were higher primarily due to increased
commodity prices, increased demand from retail customers because of warmer
weather and higher wholesale sales volumes.

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 were 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.

BUSINESS SEGMENTS

Our business is segmented based on differences in products and services,
production processes, and management responsibility. Based on this approach, we
have identified four reportable segments: Fossil Generation, Nuclear Generation,
Power Delivery and Monitored Services. We also have other non-utility operations
and our ONEOK investment.

Fossil Generation produces power for sale internally to the Power Delivery
segment and externally to wholesale customers. Power marketing and system
hedging are components of our Fossil Generation segment. Nuclear Generation
represents our 47% ownership in the Wolf Creek nuclear generating facility.
This segment has only internal sales because it provides all of its power to its
co-owners. The Power Delivery segment consists of the transmission and
distribution of power to our retail customers in Kansas and the customer service
provided to these customers and the transmission of wholesale energy. Monitored
Services represents our security alarm monitoring business in North America and
Europe.

We manage our 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 tables reflect key information for our three electric utility
business segments:

For the years ended December 31,
------------------------------------
2000 1999 1998
---------- ---------- ----------

Fossil Generation: (In Thousands)
External sales................. $ 705,536 $ 365,311 $ 525,974
Internal sales................. 572,533 546,683 517,363
Depreciation and amortization.. 60,331 55,320 53,132
EBIT........................... 202,744 219,087 144,357

Nuclear Generation (a):
Internal sales................. $ 107,770 $ 108,445 $ 117,517
Depreciation and amortization.. 40,052 39,629 39,583
EBIT........................... (24,323) (25,214) (20,920)

Power Delivery:
External sales................. $1,123,590 $1,064,385 $1,085,711
Internal sales................. 291,927 293,522 66,492
Depreciation and amortization.. 75,419 71,717 68,297
EBIT........................... 171,872 145,603 196,398

(a) Our 47% share of Wolf Creek's operating results.

Fossil Generation

Fossil Generation's external sales include power produced for sale to
external wholesale customers located outside our historical marketing territory
and the amounts associated with the system hedging transactions discussed above.
Internal sales include power produced for sale to Power Delivery which delivers
the power to our retail and wholesale customers. The internal transfer price
for these sales is set by us based upon what we believe would be competitive
market prices for capacity and energy at the time of sale.

2000 compared to 1999: External sales increased $340.2 million primarily
due to power marketing sales which increased by $267.1 million, wholesale sales
which increased by $39.8 million and system hedging sales which increased by
$32.0 million. Since 1997, we have gradually increased the size of our power
trading operation in an effort to better utilize our market knowledge and to
mitigate the risk associated with energy prices.

While sales increased significantly, EBIT was $16.3 million lower because
of higher cost of sales. Cost of sales was $371.3 million higher primarily due
to higher power marketing expense of $263.0 million, increased fuel and
purchased power expenses of approximately $71.0 million and system hedging
transaction costs of approximately $33.1 million.

Fuel and purchased power expenses were higher primarily due to increased
commodity prices, increased demand from retail customers because of warmer
weather and higher wholesale sales volumes.

The cost of fuel was significantly affected by increased gas costs of $13.3
million (despite a 9% reduction in MMBtu of gas burned). Our average natural
gas price increased 45% during the year compared to 1999. Additionally, coal
costs increased by $35.1 million primarily due to increasing the quantities of
coal burned in our efforts to minimize gas costs and cost of oil increased $7.2
million primarily due to increased price and increasing the quantities of oil
burned. See the Market Risk Disclosure in Item 7. Management's Discussion and
Analysis for further discussion.

1999 compared to 1998: External sales decreased $160.7 million, or 31%,
primarily due to lower power marketing sales. Power marketing sales decreased
$189.2 million, or 50%, due to milder weather compared to 1998. 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.

Nuclear Generation

Nuclear generation has only internal sales because it provides all of its
power to its co-owners: KGE, Kansas City Power and Light Company, and Kansas
Electric Power Cooperative, Inc. KGE owns 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), the operating company for Wolf Creek Generating Station
(Wolf Creek). Internal sales are priced at the internal transfer price that
Nuclear Generation charges to Power Delivery.

Wolf Creek has a scheduled refueling and maintenance outage approximately
every 18 months. The next outage is scheduled in the spring of 2002. During an
outage, Wolf Creek produces no power for its co-owners; therefore internal
sales, EBIT and nuclear fuel expense decrease.

2000 compared to 1999: Wolf Creek shut down on September 29, 2000, for its
eleventh scheduled refueling and maintenance outage. Internal sales and EBIT
declined immaterially because both periods had scheduled refueling and
maintenance outages.

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 refueling outages.

Power Delivery

The Power Delivery segment's external sales consist of the transmission and
distribution of power to our electric retail and wholesale customers and the
customer service provided to them. Internal sales consist of the intra-segment
transfer price charged to Fossil Generation and Nuclear Generation for the use
of the distribution lines and transformers.

2000 compared to 1999: External sales increased $59.2 million, or 6% and
EBIT increased $26.3 million, or 18%. We experienced a 12% increase in
residential sales volumes primarily due to a 27% increase in cooling degree days
and a 15% increase in heating degree days which increased the demand for power
on our system.

1999 compared to 1998: External sales decreased $21.3 million due
primarily to 2% lower retail electric sales volumes. Retail sales volumes
decreased primarily as a result of milder temperatures in 1999 than in 1998.
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. Ancillary services include such items as voltage stabilization and
spinning reserve. No ancillary service fees were charged by Fossil Generation
in 1998. The increased internal transfer price was due to higher peak demand to
accommodate air conditioning load.

Monitored Services

Protection One and Protection One Europe comprise our monitored services
business. The results discussed below reflect monitored services on a stand-
alone basis. These results do not take into consideration Protection One's
minority interest of approximately 15% at December 31, 2000, 1999 and 1998.

2000 1999 1998
-------- -------- --------
(In Thousands)

External sales................... $537,859 $599,105 $421,095
Depreciation and amortization.... 248,414 235,465 125,103
EBIT............................. (91,370) (20,675) 34,438

2000 compared to 1999: Sales decreased $61.2 million primarily due to a
decline in customer base and the effect of the adoption of Staff Accounting
Bulletin No. 101, "Revenue Recognition" (SAB 101). Adoption of SAB 101 reduced
revenue by $10.9 million. In North America, Protection One had a net decrease of
141,527 customers in 2000 as compared to a net increase of 8,595 customers in
1999. The decrease in customers is primarily attributable to the fact that
Protection One's present customer acquisition strategies were not able to
generate accounts in a sufficient volume at acceptable costs to replace accounts
lost through attrition. Protection One expects this trend will continue until
the efforts it is making to acquire new accounts and reduce attrition become
more successful than they have been to date. Until Protection One is able to
reverse this trend, net losses of customer accounts will materially and
adversely affect its business, financial condition and results of operations.
Protection One's focus remains on the completion of its current infrastructure
projects, the development of cost effective marketing programs, the development
of its commercial business and the generation of positive cash flow. Protection
One Europe had a net increase of 9,115 customers. The increase is primarily due
to internal marketing efforts.

EBIT decreased $70.7 million due to lower sales, higher cost of sales and
lower other income. Cost of sales increased $5.6 million due to increased
compensation costs for additional personnel hired at Protection One's monitoring
centers, an increase in the cost of parts and materials, and increased vehicle
costs. Other income decreased because Protection One recorded a $17.2 million
gain on the sale of the Mobile Services Group in the third quarter of 1999.

Depreciation and amortization expense increased by $12.9 million primarily
due to the change in the estimated life of goodwill which was reduced from 40
years to 20 years.

Operating and maintenance expense decreased $13.6 million primarily due to
declines in third party monitoring costs, signs and decals, printing and
compensation expenses. These decreases are a direct result of the significant
decline in the number of new accounts acquired during 2000 primarily due to the
restructuring of Protection One's dealer program.

1999 compared to 1998: Monitored services had a net increase of 63,611
customers in 1999 as compared to a net increase of 544,521 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 $178.0 million increase in external sales.

EBIT decreased $53.6 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 $108.8 million. In 1999,
Protection One and Protection One Europe changed their customer amortization
method from a 10-year straight line method to a 10-year declining balance method
for most of the North American and European customers. This change increased
amortization expense by approximately $39.2 million. The balance of the increase
is primarily attributed to a full year of amortization expense on customers
acquired during 1998. See Note 1 of Notes to Consolidated Financial Statements
for further discussion.

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.

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. See Note
17 of Notes to Consolidated Financial Statements for further discussion.

Other Income (Expense)

2000 compared to 1999: Other income increased $214.4 million primarily due
to a $91.1 million gain on the sale of our remaining investment in a gas
compression company and a $24.5 million gain on the sale of marketable
securities. Other income also improved in 2000 because of a special charge of
$76.2 million we recorded in 1999 related to our paging securities portfolio.
These increases were partially offset by a decrease in other income due to the
$17.2 million gain on the sale of Protection One's Mobile Services Group
recorded in the third quarter of 1999.

1999 compared to 1998: Other income for 1999 decreased $57.3 million
primarily due to the impairment charge for an other than temporary decline in
the value of marketable securities recorded in 1999 as discussed above.

Interest Expense

2000 compared to 1999: Interest expense represents the interest we paid on
outstanding debt. We retired long-term debt during 1999 and 2000, causing long-
term debt interest expense to decrease by $10.0 million for the year ended
December 31, 2000. The retirements included $125 million of Western Resources'
first mortgage bonds in 1999 and $75 million in 2000. We also retired
Protection One bonds in the fourth quarter of 1999 and during 2000 with an
aggregate face value of $290.4 million. For more information, see the Liquidity
and Capital Resources section below.

Short-term debt interest expense was $5.5 million higher due to increased
short-term borrowings under our credit facilities. The majority of this short-
term debt was repaid in the third quarter of 2000 with proceeds from the $600
million term loan.

1999 compared to 1998: Interest expense increased 30% primarily due to
Protection One incurring additional long-term debt to fund purchases of customer
accounts. We also had higher long-term debt interest expense because of the
6.25% and 6.8% unsecured senior notes due in 2018 that we issued in the 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.

Income Taxes

2000 compared to 1999: We had income tax expense of $46.1 million in 2000
compared to an income tax benefit of $32.2 million in 1999. Our effective
income tax rates were 33.6% for December 31, 2000 and (108.6%) for December 31,
1999. This change is primarily due to earnings before income taxes in 2000
compared to a loss before income taxes in 1999. Earnings before income taxes
increased primarily due to the $115.6 million gain on the sale of investments.

In 1999, our loss before income taxes included an impairment charge for
marketable securities and the charge related to the termination of the KCPL
merger.

In 2000, we also had tax expense of $26.5 million related to our
extraordinary gain on the purchase of Protection One bonds.

The difference between our effective tax rate and the statutory rate is
primarily attributable to the tax benefit of excluding from taxable income, in
accordance with IRS rules, 70% of the dividends received from ONEOK, the
generation and utilization of tax credits from affordable housing investments,
the amortization of prior years' investment tax credits, the amortization of
non-deductible goodwill, the tax benefits from corporate-owned life insurance
and the deduction for state income taxes.

1999 compared to 1998: We have recorded an income tax benefit in 1999 of
$32.2 million and income tax expense in 1998 of $6.8 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, the
impairment of 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 Industries'
extraordinary gain on the purchase of Protection One bonds, which is presented
on the consolidated statement of income after income from continuing operations.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion explains significant factors in liquidity and
capital resources at December 31, 2000.

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, debt service and cash payments of common stock
dividends. Our ability to attract necessary financial capital on reasonable
terms is critical to our overall business plan. Historically, we have paid for
these items with cash on hand and the issuance of stock or long- 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 $8.8 million in cash and cash equivalents at December 31, 2000. We
consider cash equivalents to be highly liquid debt instruments when purchased
with a maturity of three months or less. We also had $22.2 million of
restricted cash classified as a current asset. The current asset portion of our
restricted cash consists primarily of cash held in escrow as required by certain
letters of credit. In addition, we had $35.9 million of restricted cash
classified as a long-term asset which consists primarily of cash held in escrow
required by the terms of a pre-paid capacity and transmission agreement.

At December 31, 2000, current maturities of long-term debt were $41.8
million and short-term debt outstanding was $35.0 million. At March 19, 2001,
our short-term debt outstanding was $72.0 million.

On June 28, 2000, we entered into a $600 million, multi-year term loan that
replaced two revolving credit facilities which matured on June 30, 2000. The net
proceeds of the term loan were used to retire short-term debt. The term loan is
secured by first mortgage bonds of the company and KGE and has a final maturity
date of March 17, 2003.

Maturities of the term loan through March 17, 2003, are as follows:

Principal
Year Amount
---- ---------
(In Thousands)
2001.................... $ 9,000
2002.................... 6,000
2003.................... 585,000
---------
$ 600,000

The terms of the loan contain requirements for maintaining certain
consolidated leverage ratios, interest coverage ratios and consolidated debt to
capital ratios. We are in compliance with all of these requirements.

Interest on the term loan is payable on the expiration date of each
borrowing under the facility or quarterly if the term of the borrowing is
greater than three months. The weighted average interest rate, including
amortization of fees, on the term loan for the year ending December 31, 2000 was
10.28%.

We also have an arrangement with certain banks to provide a revolving
credit facility on a committed basis totaling $500 million. The facility is
secured by first mortgage bonds of the company and KGE and matures on March 17,
2003. Borrowings on this facility were $35.0 million at December 31, 2000 and
$72.0 million at March 19, 2001. Under the terms of the agreement, we are
required, among other restrictions, to maintain a total debt to total
capitalization ratio of not greater than 65% at all times. We are in compliance
with this restriction.

We have registered securities for sale with the Securities and Exchange
Commission (SEC). As of December 31, 2000, these included $400 million of
unsecured senior notes, $500 million of our first mortgage bonds, $50 million of
KGE first mortgage bonds and approximately 11.2 million of our common shares.

Our ability to issue additional debt and equity securities is restricted
under limitations imposed by the Articles of Incorporation 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 (which as
defined, does not include earnings or losses attributable to the ownership of
securities of subsidiaries) for a period of 12 consecutive months within 15
months preceding the issuance are not less than the greater of twice the annual
interest charges on, or 10% of the principal amount of, all first mortgage bonds
outstanding after giving effect to the proposed issuance. In addition, the
issuance of bonds is subject to limitations based upon the amount of bondable
property additions. As of December 31, 2000, $39 million of first mortgage bonds
(at an assumed interest rate of 9.5%) could be issued under the most restrictive
provisions in the mortgage.

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 less than either 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.
As of December 31, 2000, approximately $242 million principal amount of
additional KGE first mortgage bonds could be issued under the most restrictive
provisions in the mortgage.

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.

As of March 15, 2001, ratings with these agencies are as follows:

Western Protection Protection
Resources' Western KGE's One's One's
Mortgage Resources Mortgage Senior Senior
Bond Unsecured Bond Unsecured Subordinated
Rating Agency Rating Debt Rating Debt Unsecured Debt
------------- --------- --------- --------- ---------- --------------
S&P BBB- BB- BB+ B+ B-
Fitch BB+ BB BB+ B+ B-
Moody's Ba1 Ba2 Ba1 B3 Caa2

Credit rating agencies are applying more stringent guidelines when rating
utility companies due to increasing competition and utility investment in non-
utility businesses.

Following the announcement on November 9, 2000, of an agreement under which
PNM will acquire our electric utility businesses, S&P revised its Credit Watch
for us from developing to positive. Moody's has also upgraded its outlook from
negative to positive. Fitch also revised our Rating Watch from negative to
evolving after the November 2000 announcement.

On March 24, 2000, Moody's downgraded its ratings on Protection One's
outstanding securities and on March 9, 2001, Moody's further downgraded these
ratings citing concerns regarding Protection One's operations, leverage and
liquidity over the intermediate term, with outlook remaining negative. S&P and
Fitch currently have Protection One's ratings on negative watch.

Sale of Accounts Receivable

On July 28, 2000, we and KGE entered into an agreement to sell, on an
ongoing basis, all of our accounts receivable arising from the sale of
electricity, to WR Receivables Corporation, a special purpose entity wholly
owned by the company. The agreement expires on July 26, 2001, and is annually
renewable upon agreement by both parties. The special purpose entity has sold
and, subject to certain conditions, may from time to time sell, up to $125
million (and upon request, subject to certain conditions, up to $175 million) of
an undivided fractional ownership interest in the pool of receivables to a
third-party, multi-seller receivables funding entity affiliated with a lender.
Our retained interests in the receivables sold are recorded at cost which
approximates fair value. We have received net proceeds of $115.0 million as of
December 31, 2000.

Cash Flows from Operating Activities

Cash from operations decreased to $286.1 million for the year ended
December 31, 2000, from $368.4 million for the same period of 1999. The primary
reasons for this decrease are income taxes paid on the sale of marketable
securities in 2000 and cash required to be escrowed in 2000 for certain
contractual agreements as discussed in Liquidity and Capital Resources. Changes
in working capital also contributed to this decrease in cash flow from
operations.

Cash Flows (used in) Investing Activities

Investing activities used net cash flow of $86.0 million in 2000. The
proceeds from the sale of marketable securities of approximately $218.6 million
were offset by $308.1 million of capital additions which included costs
associated with two new combustion turbine generators which were placed in
service in June 2000.

Investing activities used net cash flow of $467.1 million in 1999 primarily
due to net additions to property, plant and equipment of approximately $275.7
million and Protection One's use of approximately $268.4 million for customer
account and security alarm business acquisitions.

Cash Flows (used in) from Financing Activities

We had a net use of cash for financing activities totaling $202.4 million
during 2000 due primarily to net payments on short-term and long-term debt and
dividend payments. In June 2000, we received $600 million of proceeds on a
multi-year term loan, which was used to replace two revolving credit facilities,
which matured at the end of the second quarter. The proceeds from the sale of
marketable securities and accounts receivable were also used to reduce short-
term debt and to retire long-term debt.

We had net cash provided from financing activities totaling $93.3 million
during 1999 due primarily to proceeds of short-term and long-term debt of $408.9
million offset by payments on long-term debt totaling $198.0 million and
dividend payments of $145.0 million.

Debt and Equity Repurchase Plans

We and Protection One may from time to time purchase our and Protection
One's debt and equity securities in the open market or through negotiated
transactions. The timing and terms of purchases, and the amount of debt or
equity actually purchased, will be determined by the company and Protection One
based on market conditions and other factors.

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 2003. Uncertainties
affecting our ability to meet these requirements include the factors affecting
sales described above, the impact of inflation on operating expenses, regulatory
actions, the proposed change in accounting for goodwill, the rights offering,
compliance with future environmental regulations, municipalization efforts by
the City of Wichita, the pending rate applications and the impact of our
monitored services' 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 have $747
million of long-term debt and a $500 million revolving credit facility that will
mature in 2003. Additionally, we have $400 million of putable/callable bonds
that may either mature in August 2003 or be remarketed and repriced at our
current credit spread and mature in 2018. We believe we will be successful in
refinancing these obligations but can make no assurance that these financings
will be completed at similar costs to maturing debt or at all.

We are constructing a new combustion turbine generator with an installed
capacity of approximately 154 MW. The unit is scheduled to be placed in
operation in mid-2001. We estimate that completion of the project will require
approximately $20 million in capital resources during 2001.

We forecast that we will need additional capacity of approximately 150 MW
by 2005 to serve our customer's expected electricity needs. The methods for
supplying this additional energy will be determined at a future date.

In July 1999, we and Empire District Electric Company (Empire) agreed to
jointly construct a 500-MW combined cycle generating plant, which Empire will
operate. We will own a 40% interest in the plant through a subsidiary, Westar
Generating, Inc. which will be entitled to 40% of the plant's capacity. We
estimate that our share of the cost of completing the project will require
approximately $31 million in capital resources during 2001. Commercial operation
is expected to begin in mid-2001.

Our business requires significant capital investments. We currently expect
that through the year 2003, 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 2000 and anticipated capital expenditures for 2001
through 2003 are as follows:

Fossil Nuclear Power Monitored
Generation Generation Delivery Services Other Total
---------- ---------- -------- --------- ------- --------
(In Thousands)
2000. . . $162,600 $25,900 $97,000 $ 69,500 $ 2,900 $357,900
2001. . . 110,700 16,700 89,300 92,900 200 309,800
2002. . . 76,600 19,900 97,100 101,300 - 294,900
2003. . . 70,400 29,400 96,000 134,900 - 330,700

Monitored Services includes capital expenditures for Protection One and
Protection One Europe, including purchases of customer accounts. Other
represents our commitment to fund our affordable housing tax credit program.

These estimates are prepared for planning purposes and will be revised from
time to time. See Note 6 of Notes to Consolidated Financial Statements.
Actual expenditures are likely to differ from our estimates.

Maturities of long-term debt as of December 31, 2000 are as follows:

Principal
Year Amount
-------------------------------
(In Thousands)
2001 . . . . . . . . $ 41,825
2002 . . . . . . . . 116,705
2003 . . . . . . . . 747,207
2004 . . . . . . . . 370,617
2005 . . . . . . . . 313,007
Thereafter . . . . . 1,683,819
----------
$3,273,180

Capital Structure

Our capital structure at December 31, 2000 and 1999 was as follows:

2000 1999
---- ----
Shareholders' Equity........................ 35% 38%
Preferred stock............................. 1 1
Western Resources obligated
mandatorily redeemable preferred
securities of subsidiary trust holding
solely company subordinated debentures.... 4 4
Long-term debt.............................. 60 57
---- ----
Total..................................... 100% 100%

Dividend Policy

Our board of directors reviews our dividend policy from time to time. Among
the factors the board of directors considers in determining our dividend policy
are earnings, cash flows, capitalization ratios, competition and financial loan
covenants. Provisions in our Articles of Incorporation contain restrictions on
the payment of dividends or the making of other distributions on our common
stock while any preferred shares remain outstanding unless certain
capitalization ratios and other conditions are met. Our agreement with PNM
prohibits an increase in the dividend paid on our common stock without the
consent of PNM.

OTHER INFORMATION

Electric Utility

City of Wichita Municipalization Efforts: In December 1999, the City
Council of Wichita, Kansas, 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. The feasibility study was
released in February 2001 and estimates that the City of Wichita would be
required to pay us $145 million for our stranded costs if it were to
municipalize. However, we estimate the amount to be substantially greater. 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 and arrange for its own power supply. These costs are in addition to the
stranded costs for which the city would be required to reimburse us. On February
2, 2001, the City of Wichita announced its intention to proceed with its attempt
to municipalize KGE's retail electric utility business in Wichita. KGE will
oppose municipalization efforts by the City of Wichita. Should the city be
successful in its municipalization efforts without providing us adequate
compensation for our assets and lost revenues, the adverse effect on our
business and financial condition could be material.

KCC Rate Proceedings: On November 27, 2000, we and KGE filed applications
with the KCC for a change in retail rates which included a cost allocation study
and separate cost of service studies for our KPL division and KGE. We and KGE
also provided revenue requirements on a combined company basis on December 28,
2000. If approved as proposed, the impact of these rate requests will be an
annual increase of $93.0 million for our KPL division and $58.0 million for KGE
for a total of $151.0 million. The proposal also contains a mechanism for
adjusting these rate requests up or down if projected natural gas fuel prices
are different from the prices utilized in the November 27, 2000 filings. We
anticipate a ruling by the KCC in July 2001 but are unable to predict its
outcome. We can give no assurance that these rate requests will be approved as
proposed.

FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with FERC against us alleging improper affiliate transactions between our KPL
division and KGE, our wholly owned subsidiary. The City of Wichita asked that
FERC equalize the generation costs between KPL and KGE, in addition to other
matters. A hearing on the case was held at FERC on October 11 and 12, 2000 and
on November 9, 2000, a FERC administrative law judge ruled in our favor that no
change in rates was required. On December 13, 2000, the City of Wichita filed a
brief with FERC asking that the Commission overturn the judge's decision. On
January 5, 2001, we filed a brief opposing the city's position. We anticipate a
decision by FERC in the second quarter of 2001. A decision requiring
equalization of rates could have a material adverse effect on our business and
financial condition.

Competition and Deregulation: The United States electric utility industry
is evolving from a regulated monopolistic market to a competitive marketplace.
During 2000 and early 2001, extensive problems in the deregulated California
market have made many states reconsider deregulation efforts. Various states
have taken steps to allow retail customers to purchase electric power from
providers other than their local utility company. Several bills promoting
deregulation were introduced to the Kansas Legislature in the 1999 legislative
session, but none passed. No bills were considered in the legislature during the
2000 legislative session. Based on these events, we do not anticipate
deregulation to occur in Kansas in the near term.

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. During 2000, traditional wholesale electric sales,
excluding power marketing sales, represented approximately 12% of total electric
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
transmission organizations (RTOs), whose purpose is to facilitate greater
competition at the wholesale level. We are a member of the Southwest Power Pool
(SPP) which filed a second request with FERC in October 2000 to seek RTO
recognition which reflects FERC comments to the SPP's first request.
We anticipate that FERC Order 2000 will not have a material effect on us or our
operations.

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 5% to 24% below the
national average for retail customers. Because of these rates, we expect to
retain a substantial part of our current volume of sales volumes in a
competitive environment.

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
earnings. 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 and the impact
should the City of Wichita municipalization efforts be successful. We
periodically review SFAS 71 criteria and believe our net regulatory assets,
including those related to generation, are probable of future recovery. If we
discontinue SFAS 71 accounting treatment based upon competitive or other events,
such as the successful municipalization efforts by areas we serve, we may
significantly impact the value of our net regulatory assets and our utility
plant investments, particularly Wolf Creek.

Regulatory changes, including competition or successful municipalization
efforts by the City of Wichita, could adversely impact our ability to recover
our investment in these assets. As of December 31, 2000, we have recorded
regulatory assets which are currently subject to recovery in future rates of
approximately $327.4 million. Of this amount, $187.3 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 or because of such successful municipalization
efforts, we may not be able to fully recover our entire investment in Wolf
Creek. KGE presently owns 47% of Wolf Creek. We may also have stranded costs
from an inability to recover our environmental remediation costs and long-term
fuel contract costs in a competitive environment. If we 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 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.

On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, our share of Wolf Creek's
decommissioning costs, under the immediate dismantlement method, is estimated to
be approximately $631 million during the period 2025 through 2034, or
approximately $221 million in 1999 dollars. These costs include decontamination,
dismantling and site restoration and were calculated using an assumed inflation
rate of 3.6% over the remaining service life from 1999 of 26 years. The actual
decommissioning costs may vary from the estimates because of changes in the
assumed dates of decommissioning, changes in regulatory requirements, changes in
technology and changes in costs of labor, materials and equipment. On May 26,
2000, we filed an application with the KCC requesting approval of the funding of
our decommissioning trust on this basis. Approval was granted by the KCC on
September 20, 2000.

The 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 FASB expects to issue a final statement of financial
accounting standard in the second quarter of 2001. The proposed Exposure Draft
contains an effective date of fiscal years beginning after June 15, 2001.
However, the ultimate effective date has not been finalized. If current
accounting practices for nuclear power plant decommissioning are changed, the
following could occur:

- Our annual decommissioning expense could be higher than in 2000
- The estimated cost for decommissioning could be recorded as a liability
(rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the Wolf
Creek plant

We do not believe that such changes, if required, would adversely affect
our operating results due to our current ability to recover decommissioning
costs through rates. See Note 14 of the Notes to Consolidated Financial
Statements.

Monitored Services

Attrition: Customer attrition has a direct impact on Protection One's and
Protection One Europe's results of operations since it affects revenues,
amortization expense and cash flow. Any significant change in the pattern of
their historical attrition experience would have a material effect on the
results of operations.

Customer attrition for the years ended December 31, 2000 and 1999 is
summarized below:

Customer Account Attrition
--------------------------------------------
December 31, 2000 December 31, 1999
--------------------- ---------------------
Annualized Trailing Annualized Trailing
Fourth Twelve Fourth Twelve
Quarter Month Quarter Month
---------- -------- ---------- --------
Protection One 15.0% 14.0% 14.7% 14.3%
Protection One Europe 11.4% 12.2% 10.7% 9.5%

Our monitored services segment had a net decrease of 119,415 customers from
December 31, 1999 to December 31, 2000. The number of customers decreased
primarily because monitored services' customer acquisition strategies were not
able to generate accounts in a sufficient volume at acceptable costs to replace
accounts lost through attrition. We expect that this trend will continue until
the efforts being made to acquire new accounts at acceptable costs and reduce
attrition become more successful than they have been to date. Until this trend
has been reversed, net losses of customer accounts will materially and adversely
affect monitored services' business, financial condition, results of operation
and prospects.

Related Party Transactions

We and ONEOK have shared services agreements in which we provide and bill
one another for facilities, utility field work, information technology, customer
support, bill processing and human resources services. Payments for these
services are based on various hourly charges, negotiated fees and out-of-pocket
expenses. In 2000 and 1999, ONEOK paid us $5.0 million and $5.6 million, net of
what we owed ONEOK, for services.

At December 31, 2000, $44.0 million was outstanding under Protection One's
senior credit facility with Westar Industries. In February 2001, the facility
maturity date was extended to January 2, 2002 and in March 2001, Protection One
requested a $40 million increase in the commitment under the facility pursuant
to the terms of the facility.

We have a tax sharing agreement with Protection One. This pro rata tax
sharing agreement allows Protection One to be reimbursed for current tax
benefits utilized in our consolidated tax return. Upon consummation of the PNM
merger and the split-off, we will no longer consolidate Protection One's tax
return with ours.

During 2000, Westar Industries purchased $170.0 million face value of
Protection One bonds on the open market. In exchange for cash and the settlement
of certain intercompany payables and receivables, $103.9 million of these debt
securities were transferred to Protection One. The balance of the bonds were
sold to Protection One in March 2001. No gain or loss was recognized on these
transactions.

On February 29, 2000, Westar Industries purchased the European operations
of Protection One, and certain investments held by a subsidiary of Protection
One for an aggregate purchase price of $244 million. Westar Industries paid
approximately $183 million in cash and transferred Protection One debt
securities with a market value of approximately $61 million to Protection One.
Westar Industries 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 Industries on Protection
One's revolving credit 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 future purchases.

On February 28, 2001, Westar Industries converted a portion of a receivable
owed by us into approximately 14.4 million shares of our common stock. See Note
2 of the Notes to Consolidated Financial Statements.

Market Risk Disclosure

Market Price Risks: We are exposed to market risk, including market
changes, changes in commodity prices, equity instrument investment prices and
interest rates.

Commodity Price Exposure: In 2000, we engaged in both trading and non-
trading activities in our commodity price risk management activities. We traded
electricity, gas and oil. We utilized a variety of financial instruments,
including forward contracts involving cash settlements or physical delivery of
an energy commodity, options, swaps requiring payments (or receipt of payments)
from counter-parties based on the differential between specified prices for the
related commodity and futures traded on electricity, natural gas and oil.

We are involved in trading activities primarily to minimize risk from
market fluctuations, capitalize on our market knowledge and 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 2001, we
expect to trade coal, natural gas and oil fossil fuel types as well as
electricity.

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, 2000, were
$725,403, $36,559 and $269,217. 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 2001.

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 counter-parties, product
location (basis) differentials and other risks which management policy dictates.
The counter-parties in our portfolio are primarily large energy marketers and
major utility companies. The creditworthiness of our counter-parties could
positively or negatively impact our overall exposure to credit risk. We maintain
credit policies with regard to our counter-parties 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 market prices. From 1999 to 2000, we
experienced a 13% increase in the average price per MW of electricity purchased
for utility operations. Actual purchased power market volatility was
significantly greater than the average price increase indicates. If we were to
have a similar increase from 2000 to 2001, given the amount of power purchased
for utility operations during 2000, we would have an exposure of approximately
$5.4 million of operating income. Due to the volatility of the power market,
past prices can not be used to predict future prices.

We use a mix of various fuel types, including coal and natural gas, to
operate our system which helps lessen our risk associated with any one fuel
type. Natural gas prices increased significantly during 2000 throughout the
nation. This increase impacted the cost of gas we used for generation as well as
our cost of purchased power. From December 31, 1999 to December 31, 2000, we
experienced a 45% increase in our average cost for natural gas purchased for
utility operations, or an increase of $1.07 per MMBtu. The higher natural gas
prices increased our total cost of gas purchased during 2000 by approximately
$16.9 million although we decreased the quantity burned by 1.5 million MMBtu. If
we were to have a similar increase from 2000 to 2001, we would have an exposure
of approximately $24.4 million of operating income.

Based on MMBtu's of natural gas and fuel oil burned during 2000, we had
exposure of approximately $6.8 million of operating income for a 10% change in
average price paid per MMBtu. Actual natural gas market volatility was
significantly greater than that indicated by the average price increase. Due to
the volatility of natural gas prices, past prices can not be used to predict
future prices.

During the first quarter of 2001, spot market prices for western coal
markets increased significantly. This increase will impact the fuel contracts
currently in place for a portion of our 2001 anticipated coal needs at our La
Cygne Generating Station, increasing our coal commodity price market risk. We
believe that 2001 spot market purchases will be at higher rates than those
experienced during 2000.

Additional factors that affect our commodity price exposure are the
quantity and availability of fuel used for generation and the quantity of
electricity customers will consume. Quantities of fossil fuel used for
generation could vary dramatically year to year based on the individual fuel's
availability, price, deliverability, unit outages and nuclear refueling. Our
customer's electricity usage could also vary dramatically year to year based on
the weather or other factors.

Financial Hedging Exposure: We also use financial instruments to hedge a
portion of our anticipated fossil fuel needs. At the time we enter into these
transactions, we are unable to determine what the value will be when the
agreements are actually settled.

Decline in Equity Price Risk: During 2000, our balance in marketable
securities declined approximately $173.2 million from December 31, 1999, due to
the sale of a significant portion of our marketable security portfolio. We do
not expect to be materially impacted by changes in the market prices of our
remaining investments.

Interest Rate Exposure: We have approximately $156.9 million of variable
rate debt and current maturities of fixed rate debt as of December 31, 2000. Our
weighted average interest rate increased from 6.96% at December 31, 1999 to
8.11% at December 31, 2000. A 100 basis point change in each debt series'
benchmark rate used to set the rate for such series would impact net income on
an annual basis by approximately $1.6 million after tax.

Foreign Currency Exchange Rates: We have foreign operations with functional
currencies other than the United States dollar. As of December 31, 2000, the
unrealized loss on currency translation, presented as a separate component of
shareholders' equity and reported within other comprehensive income was
approximately $9.4 million pretax. A 10% change in the currency exchange rates
would have an immaterial effect on other comprehensive income.

New Accounting Pronouncements

In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133). SFAS 133, as amended, is effective for fiscal years beginning after June
15, 2000. SFAS 133 establishes accounting and reporting standards requiring that
every derivative instrument, including certain derivative instruments embedded
in other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires that changes in the
derivatives' fair value be recognized currently in earnings unless specific
hedge accounting criteria are met.

We adopted SFAS 133 on January 1, 2001. We have evaluated our commodity
contracts, financial instruments and other contracts and have determined that we
have derivative instruments which will be marked to market through earnings in
accordance with SFAS 133. We will not designate any derivatives as hedges. We
estimate that the effect on our financial statements of adopting SFAS 133 on
January 1, 2001, will be to increase pre-tax earnings for the first quarter of
2001 by approximately $31 million. Accounting for derivatives under SFAS 133 may
increase volatility in future earnings.

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
----------------------------------------------------

TABLE OF CONTENTS PAGE

Report of Independent Public Accountants 53

Financial Statements:

Consolidated Balance Sheets, December 31, 2000 and 1999 54
Consolidated Statements of Income for the years ended
December 31, 2000, 1999 and 1998 55
Consolidated Statements of Comprehensive Income for the
years ended December 31, 2000, 1999 and 1998 56
Consolidated Statements of Cash Flows for the years ended
2000, 1999 and 1998 57
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 2000, 1999 and 1998 58
Notes to Consolidated Financial Statements 59

Financial Schedules:

Schedule II - Valuation and Qualifying Accounts 103

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.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors
of Western Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Western
Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, 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, 2000. 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. and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.

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 9, 2001

WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands)

December 31,
------------------------
2000 1999
---------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents............................ $ 8,762 $ 11,040
Restricted cash...................................... 22,205 15,962
Accounts receivable (net)............................ 152,165 229,200
Inventories and supplies (net)....................... 101,303 112,392
Marketable securities................................ 3,946 177,128
Energy trading contracts............................. 185,364 16,370
Prepaid expenses and other........................... 40,503 40,876
---------- ----------
Total Current Assets................................ 514,248 602,968
---------- ----------

PROPERTY, PLANT AND EQUIPMENT (NET)................... 3,993,438 3,889,444
---------- ----------

OTHER ASSETS:
Restricted cash...................................... 35,878 -
Investment in ONEOK.................................. 591,173 590,109
Customer accounts (net).............................. 1,005,505 1,122,585
Goodwill (net)....................................... 976,102 1,057,041
Regulatory assets.................................... 327,350 366,004
Other................................................ 323,514 361,741
---------- ----------
Total Other Assets.................................. 3,259,522 3,497,480
---------- ----------

TOTAL ASSETS.......................................... $7,767,208 $7,989,892
========== ==========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt................. $ 41,825 $ 111,667
Short-term debt...................................... 35,000 705,421
Accounts payable..................................... 177,067 132,834
Accrued liabilities.................................. 207,329 226,786
Accrued income taxes................................. 53,834 40,328
Deferred security revenues........................... 73,585 61,148
Energy trading contracts............................. 191,673 15,182
Other................................................ 34,187 57,829
---------- ----------
Total Current Liabilities........................... 814,500 1,351,195
---------- ----------

LONG-TERM LIABILITIES:
Long-term debt (net)................................. 3,237,849 2,883,066
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..... 919,807 976,135
Minority interests................................... 184,591 192,734
Deferred gain from sale-leaseback.................... 186,294 198,123
Other................................................ 272,747 279,451
---------- ----------
Total Long-term Liabilities......................... 5,021,288 4,749,509
---------- ----------

COMMITMENTS AND CONTINGENCIES (Note 14)

SHAREHOLDERS' EQUITY:
Cumulative preferred stock........................... 24,858 24,858
Common stock, par value $5 per share, authorized
150,000,000 shares, outstanding 70,082,314 and
67,401,657 shares, respectively..................... 350,412 341,508
Paid-in capital...................................... 850,100 820,945
Retained earnings.................................... 714,454 679,880
Accumulated other comprehensive income (loss) (net).. (8,404) 37,788
Treasury stock, at cost, 0 and 900,000 shares,
respectively....................................... - (15,791)
---------- ----------
Total Shareholders' Equity.......................... 1,931,420 1,889,188
---------- ----------

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY.............. $7,767,208 $7,989,892
========== ==========

The Notes to Consolidated Financial Statements are an integral part of these
statements.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)

Year Ended December 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------

SALES:
Energy............................................................. $ 1,830,617 $1,430,982 $1,612,959
Monitored services................................................. 537,859 599,105 421,095
----------- ---------- ----------
Total Sales....................................................... 2,368,476 2,030,087 2,034,054
----------- ---------- ----------
COST OF SALES:
Energy............................................................. 850,277 478,982 691,468
Monitored services................................................. 185,555 179,964 131,791
----------- ---------- ----------
Total Cost of Sales............................................... 1,035,832 658,946 823,259
----------- ---------- ----------

Gross profit........................................................ 1,332,644 1,371,141 1,210,795
----------- ---------- ----------
OPERATING EXPENSES:
Operating and maintenance expense.................................. 337,481 337,081 337,507
Depreciation and amortization...................................... 426,369 403,669 288,125
Selling, general and administrative expense........................ 343,163 340,609 263,310
International power development costs.............................. - (5,632) 98,916
Deferred merger costs.............................................. - 17,600 -
----------- ---------- ----------
Total Operating Expenses.......................................... 1,107,013 1,093,327 987,858
----------- ---------- ----------

INCOME FROM OPERATIONS.............................................. 225,631 277,814 222,937
----------- ---------- ----------
OTHER INCOME (EXPENSE):
Investment earnings................................................ 192,423 35,979 49,797
Impairment of marketable securities................................ - (76,166) -
Minority interests................................................. 8,625 12,600 2,762
Other.............................................................. - 14,234 (8,563)
----------- ---------- ----------
Total Other Income (Expense)...................................... 201,048 (13,353) 43,996
----------- ---------- ----------

EARNINGS BEFORE INTEREST AND TAXES.................................. 426,679 264,461 266,933
----------- ---------- ----------
INTEREST EXPENSE:
Interest expense on long-term debt................................. 226,419 236,417 170,855
Interest expense on short-term debt and other...................... 63,149 57,687 55,265
----------- ---------- ----------
Total Interest Expense.......................................... 289,568 294,104 226,120
----------- ---------- ----------

EARNINGS (LOSS) BEFORE INCOME TAXES................................. 137,111 (29,643) 40,813

Income tax expense (benefit)........................................ 46,061 (32,197) 6,755
----------- ---------- ----------

NET INCOME BEFORE EXTRAORDINARY GAIN AND ACCOUNTING CHANGE.......... 91,050 2,554 34,058

Extraordinary gain, net of tax of $26,514, $6,322 and $2,730........ 49,241 11,742 1,591

Cumulative effect of accounting change, net of tax of $1,097........ (3,810) - -
----------- ---------- ----------

NET INCOME.......................................................... 136,481 14,296 35,649

Preferred dividends................................................. 1,129 1,129 3,591
----------- ---------- ----------

EARNINGS AVAILABLE FOR COMMON STOCK................................. $ 135,352 $ 13,167 $ 32,058
=========== ========== ==========

Average common shares outstanding................................... 68,962,245 67,080,281 65,633,743

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING:
Before extraordinary gain and accounting change.................... $ 1.30 $ 0.02 $0.46
Extraordinary gain................................................. 0.71 0.18 0.02
Accounting change.................................................. (0.05) - -
----------- ---------- ----------
After extraordinary gain and accounting change..................... $ 1.96 $ 0.20 $ 0.48
=========== ========== ==========

DIVIDENDS DECLARED PER COMMON SHARE................................. $ 1.435 $ 2.14 $ 2.14

The Notes to Consolidated Financial Statements are an integral part of these
statements.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)

Year Ended December 31,
--------------------------------------
2000 1999 1998
---------- ----------- -----------

NET INCOME........................................................... $ 136,481 $ 14,296 $ 35,649
---------- ----------- -----------
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Unrealized holding gains/(losses) on marketable securities
arising during the year........................................... 43,174 (55,420) (17,244)
Adjustment for (gains)/losses included in net income................ (114,948) 102,417 14,029
---------- ----------- -----------
Net change in unrealized gain/(loss) on marketable securities....... (71,774) 46,997 (3,215)
Foreign currency translation adjustment............................. (9,376) (115) (1,026)
Income tax (expense)/benefit........................................ 34,958 (18,602) 1,630
---------- ----------- -----------
Total other comprehensive income (loss), net of tax................ (46,192) 28,280 (2,611)
---------- ----------- -----------

COMPREHENSIVE INC0ME................................................. $ 90,289 $ 42,576 $ 33,038
========== =========== ===========

The Notes to Consolidated Financial Statements are an integral part of these
statements.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)

Year Ended December 31,
------------------------------------------
2000 1999 1998
---------- ---------- ----------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................... $ 136,481 $ 14,296 $ 35,649
Adjustments to reconcile net income to net cash
provided by operating activities:
Extraordinary gain................................................... (49,241) (11,742) (1,591)
Cumulative effect of accounting change............................... 3,810 - -
Depreciation and amortization........................................ 426,369 403,669 288,125
Amortization of gain on sale-leaseback............................... (11,828) (11,828) (11,828)
Equity in earnings from investments.................................. (11,219) (8,199) (6,064)
Minority interests................................................... (8,625) (12,600) (2,762)
(Gain)/loss on sale of marketable securities......................... (114,948) 26,251 14,029
Impairment of marketable securities.................................. - 76,166 -
Gain on sale of investments.......................................... (9,562) (17,249) -
Accretion of debt premium............................................ (6,237) (6,799) 3,034
Write-off of international development activities.................... - (5,632) 98,916
Net deferred taxes................................................... (29,744) (15,825) (57,119)
Deferred merger costs................................................ - 17,600 -
Changes in working capital items (net of effects from acquisitions):
Restricted cash..................................................... (15,234) (18,689) (11,987)
Accounts receivable (net)........................................... (37,127) (3,824) 118,844
Inventories and supplies (net)...................................... 12,282 (15,024) (8,000)
Accounts payable.................................................... 44,172 5,000 (33,613)
Accrued liabilities................................................. (19,457) (20,152) (42,411)
Accrued income taxes................................................ 13,506 7,386 5,582
Deferred security revenues.......................................... (2,065) 3,479 (2,237)
Other............................................................... (10,314) (2,571) 43,518
Changes in other assets and liabilities.............................. (24,875) (35,272) (29,873)
---------- ---------- ----------
Net cash flows from operating activities............................ 286,144 368,441 400,212
---------- ---------- ----------

CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment (net)..................... (308,073) (275,744) (182,885)
Customer account acquisitions........................................ (35,513) (241,000) (277,667)
Security alarm monitoring acquisitions, net of cash acquired......... (11,748) (27,409) (549,196)
Purchases of marketable securities................................... - (12,003) (261,036)
Proceeds from sale of marketable securities.......................... 218,609 73,456 27,895
Other investments (net).............................................. 50,688 15,556 (91,451)
---------- ---------- ----------
Net cash flows used in investing activities......................... (86,037) (467,144) (1,334,340)
---------- ---------- ----------

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt (net)................................................ (670,421) 392,949 75,972
Proceeds of long-term debt........................................... 610,045 16,000 1,096,238
Retirements of long-term debt........................................ (208,952) (198,021) (167,068)
Proceeds from accounts receivable sale (net)......................... 115,000 - -
Proceeds from issuance of stock by subsidiary........................ - - 45,565
Issuance of common stock (net)....................................... 38,059 43,245 17,284
Redemption of preference stock....................................... - - (50,000)
Cash dividends paid.................................................. (98,827) (145,033) (144,077)
Acquisition of treasury stock........................................ (9,187) (15,791) -
Reissuance of treasury stock......................................... 21,898 - -
---------- ---------- ----------
Net cash flows from (used in) financing activities.................. (202,385) 93,349 873,914
---------- ---------- ----------

NET DECREASE IN CASH AND CASH EQUIVALENTS............................. (2,278) (5,354) (60,214)

CASH AND CASH EQUIVALENTS:
Beginning of year.................................................... 11,040 16,394 76,608
---------- ---------- ----------
End of year.......................................................... $ 8,762 $ 11,040 $ 16,394
========== ========== ==========

The Notes to Consolidated Financial Statements are an integral part of these
statements.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Dollars in Thousands)

Cumulative Accumulated
Preferred and Other
Preference Common Paid-in Retained Comprehensive Unearned Treasury
Stock Stock Capital Earnings Income Compensation Stock Total
------------- -------- -------- ------------- ------------- ------------ ---------- ----------

BALANCE, December 31, 1997....... $ 74,858 $327,048 $760,553 $ 919,045 $ 12,119 $ - $ - $2,093,623
Net income....................... - - - 35,649 - - - 35,649
Redemption of preference stock... (50,000) - - - - - - (50,000)
Dividends on preferred and
preference stock................ - - - (3,591) - - - (3,591)
Issuance of common stock......... - 2,500 12,711 - - - - 15,211
Dividends on common stock........ - - - (140,486) - - - (140,486)
Unrealized loss on marketable
securities...................... - - - - (3,215) - - (3,215)
Currency translation
adjustments..................... - - - - (1,026) - - (1,026)
Tax benefit...................... - - - - 1,630 - - 1,630
Grant of restricted stock........ - - 4,137 - - (4,137) - -
Amortization of restricted stock. - - - - - 2,073 - 2,073
--------------------------------------------------------------------------------------------------

BALANCE, December 31, 1998....... $ 24,858 $329,548 $777,401 $ 810,617 $ 9,508 $ (2,064) $ - $ 1,949,868
Net income....................... - - - 14,296 - - - 14,296
Dividends on preferred and
preference stock................ - - - (1,129) - - - (1,129)
Issuance of common stock......... - 11,960 44,906 - - - - 56,866
Dividends on common stock........ - - - (143,904) - - - (143,904)
Unrealized gain on marketable
securities...................... - - - - 46,997 - - 46,997
Currency translation
adjustments..................... - - - - (115) - - (115)
Tax benefit...................... - - - - (18,602) - - (18,602)
Acquisition of treasury stock.... - - - - - - (15,791) (15,791)
Grant of restricted stock........ - - 4,333 - - (4,333) - -
Amortization of restricted stock. - - - - - 702 - 702
--------------------------------------------------------------------------------------------------

BALANCE, December 31, 1999....... $ 24,858 $341,508 $826,640 $679,880 $ 37,788 $ (5,695) $(15,791) $1,889,188
Net income....................... - - - 136,481 - - - 136,481
Dividends on preferred and
preference stock............... - - - (1,129) - - - (1,129)
Issuance of common stock......... - 8,904 18,537 - - - - 27,441
Dividends on common stock........ - - - (97,698) - - - (97,698)
Unrealized loss on marketable
securities..................... - - - - (71,774) - - (71,774)
Currency translation adjustments. - - - - (9,376) - - (9,376)
Tax benefit...................... - - - - 34,958 - - 34,958
Acquisition of treasury stock.... - - - - - - (9,187) (9,187)
Issuance of treasury stock....... - - - (3,080) - - 24,978 21,898
Grant of restricted stock........ - - 22,989 - - (22,989) - -
Amortization of restricted stock. - - - - - 10,618 - 10,618
--------------------------------------------------------------------------------------------------

BALANCE, December 31, 2000....... $24,858 $350,412 $868,166 $714,454 $ (8,404) $ (18,066) $ - $1,931,420
==================================================================================================

The Notes to Consolidated Financial Statements are an integral part of these
statements.

WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business: Western Resources, Inc. (Western Resources, 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 636,000 customers in Kansas and providing
monitored security services to approximately 1.5 million customers in North
America and 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 security services are provided by Protection One,
Inc., a publicly traded, approximately 85%-owned subsidiary, and other wholly
owned subsidiaries collectively referred to as Protection One Europe. In
addition, through the company's 45% ownership interest in ONEOK, Inc., natural
gas transmission and distribution services are provided to approximately 1.4
million customers in Oklahoma and Kansas. Westar Industries, Inc., the company's
wholly owned subsidiary, owns the company's interests in Protection One,
Protection One Europe, ONEOK and other non-utility businesses.

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.

Regulatory Accounting: 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
requires 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.

Cash and Cash Equivalents: The company considers highly liquid
collateralized debt instruments purchased with a maturity of three months or
less to be cash equivalents.

Restricted Cash: Restricted cash consists of cash used to collateralize
letters of credit and cash held in escrow.

Accounts Receivable: Receivables, which consist primarily of trade accounts
receivable, were reduced by allowances for doubtful accounts of $45.8 million at
December 31, 2000 and $35.8 million at December 31, 1999.

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. Realized gains and losses are included in earnings
and are derived using the specific identification method.

The following table summarizes the company's investments in marketable
securities as of December 31:

Gross Unrealized
----------------
Cost Gains Losses Fair Value
-------- ------- --------- ----------
(In Thousands)
2000:
Equity securities............ $ 6,690 $ - $ (2,744) $ 3,946
Debt securities.............. - - - -
-------- ------- -------- --------
Total...................... $ 6,690 $ - $ (2,744) $ 3,946
======== ======= ======== ========

1999:
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
======== ======= ======== ========

Proceeds from the sales of equity and debt securities were $218.6 million
in 2000 and $73.5 million in 1999. The gross realized gains from sales of
equity and debt investments were $116.0 million in 2000 and $12.6 million in
1999. The gross realized losses from sales of equity and debt investments were
$1.0 million in 2000 and $38.8 million in 1999.

Energy Trading Contracts: The company is involved in system hedging and
trading activities primarily to minimize risk from commodity market
fluctuations, capitalize on its market knowledge and 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 requiring payments (or receipt of payments)
from counter-parties based on the differential between specified prices for the
related commodity, and futures traded on electricity and natural gas.

The company accounts for transactions on either a settlement basis or using
the mark-to-market method of accounting. On a settlement basis, the company
recognizes the gains or losses on system hedging transactions as the power is
delivered. Under the mark-to-market method of accounting, trading transactions
are shown at fair value in the consolidated balance sheets as energy trading
contracts assets - current and energy trading contracts liabilities-current.
Long term energy trading contract assets and liabilities are included in other
long term assets and other long term liabilities, respectively. The company
reflects changes in fair value resulting in unrealized gains and losses from
these transactions in energy sales. The company records the revenues and costs
for all transactions in its consolidated statements of income when the contracts
are settled. The company recognizes revenues in energy sales; costs are recorded
in energy cost of sales.

The company values contracts in the trading portfolio using end-of-the-
period market prices, utilizing the following factors (as applicable):

- closing exchange prices (that is, closing prices for standardized
electricity products traded on an organized exchange such as the New
York Mercantile Exchange);
- broker dealer and over-the-counter price quotations;

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). AFUDC represents the cost of borrowed funds used to finance
construction projects. The AFUDC rate was 7.39% in 2000, 6.00% in 1999 and 6.00%
in 1998. The cost of additions to utility plant and replacement units of
property are capitalized. Interest capitalized into construction in progress was
$9.4 million in 2000, $4.4 million in 1999 and $1.9 million in 1998.

Maintenance costs and replacement of minor items of property are charged to
expense as incurred. Incremental costs incurred during scheduled Wolf Creek
Generating Station refueling and maintenance outages are deferred and amortized
monthly over the unit's operating cycle, normally about 18 months. 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 $108.2 million as of December 31, 2000 and $88.1 million as
of December 31, 1999.

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 2.99% during
2000, 2.92% during 1999 and 2.88% during 1998. Nonutility property, plant and
equipment is depreciated on a straight-line basis over the estimated useful
lives of the related assets. The company periodically evaluates its depreciation
rates considering the past and expected future experience in the operation of
its facilities.

Inventories and Supplies: Inventories and supplies for the company's
utility business are stated at average cost. Monitored services' 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 cost of sales based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel in
the reactor was $18.6 million at December 31, 2000 and $29.3 million at December
31, 1999.

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 and Protection One Europe historically amortized most
customer accounts by using the straight-line method over a ten-year life. The
choice of an amortization life was based on estimates and judgments about the
amounts and timing of expected future revenues from these assets and average
customer account life. Selected periods were determined because, in Protection
One's and Protection One Europe's opinion, they would adequately match
amortization cost with anticipated revenue.

Protection One and Protection One Europe conducted a comprehensive review
of their 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
corresponded 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 elected to change to
that method, except for accounts acquired in the Westinghouse acquisition which
are utilizing an accelerated method. No change was made in the method used for
the Multifamily pool.

Protection One's and Protection One Europe's amortization rates consider
the average estimated remaining life and historical and projected attrition
rates. The amortization method for each customer pool is as follows:

Pool Method
------------------------------------------------------------------------
North America
Acquired Westinghouse customers Eight-year 120% declining balance
Other customers Ten-year 130% declining balance
Europe Ten-year 125% declining balance
Multifamily Ten-year straight-line

Adoption of the declining balance method effectively shortens the estimated
expected average customer life for these 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 for Europe
customers and the North America customers which had been amortized on a
straight-line basis. Accordingly, the effect of the change in accounting
principle increased Protection One's amortization expense reported in the third
quarter of 1999 by approximately $40 million. Accumulated amortization would
have been approximately $34 million higher through the end of the second quarter
of 1999 if the declining balance method had historically been used.

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 and Protection One Europe 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 related goodwill.

Goodwill has been recorded in business acquisitions where the principal
asset acquired was the recurring revenues from the acquired customer base. For
purposes of the impairment analysis, goodwill has been considered directly
related to the acquired customers.

Due to the high level of customer attrition experienced in 2000 and 1999,
the decline in market value of Protection One's publicly traded equity and debt
securities and because of recurring losses, Protection One and Protection One
Europe performed an impairment test on their customer account assets and
goodwill in both 2000 and 1999. These tests indicated that future estimated
undiscounted cash flows exceeded the sum of the recorded balances for customer
accounts and goodwill.

Goodwill: Goodwill represents the excess of the purchase price over the
fair value of net assets acquired by Protection One and Protection One Europe.
Protection One and Protection One Europe changed their estimates of goodwill
life from 40 years to 20 years as of January 1, 2000. After that date, remaining
goodwill, net of accumulated amortization, is being amortized over its remaining
useful life based on a 20-year life. As a result of this change in estimate,
goodwill amortization expense for the year ended December 31, 2000 increased by
approximately $33.0 million.

The carrying value of goodwill was included in the evaluations of
recoverability of customer accounts. No reduction in the carrying value was
necessary at December 31, 2000.

Amortization expense was $61.4 million, $31.6 million and $22.5 million for
the years ended December 31, 2000, 1999 and 1998. Accumulated amortization was
$118.6 million and $59.3 million at December 31, 2000 and 1999.

The Financial Accounting Standards Board (FASB) issued an exposure draft on
February 14, 2001 which, if adopted as proposed, would establish a new
accounting standard for the treatment of goodwill in a business combination. The
new standard would continue to require recognition of goodwill as an asset in a
business combination but would not permit amortization as currently required by
APB Opinion No. 17, "Intangible Assets." The new standard would require that
goodwill be separately tested for impairment using a fair-value based approach
as opposed to an undiscounted cash flow approach which is required under current
accounting standards. If goodwill is found to be impaired, the company would be
required to record a non-cash charge against income. The impairment charge would
be equal to the amount by which the carrying amount of the goodwill exceeds the
fair value. Goodwill would no longer be amortized on a current basis as is
required under current accounting standards. The exposure draft contemplates
this standard to become effective on July 1, 2001, although this effective date
is not certain. Furthermore, the proposed standard could be modified prior to
its adoption.

If the new standard is adopted, any subsequent impairment test on the
company's customer accounts would be performed on the customer accounts alone
rather than in conjunction with goodwill utilizing an undiscounted cash flow
test pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of."

At December 31, 2000, the company had $976 million in goodwill attributable
to acquisitions of businesses and $1,006 million for monitored services'
customer accounts. These intangible assets together represented 25.5% of the
book value of the company's total assets. The company recorded approximately
$61.4 million in goodwill amortization expense in 2000. If the new standard
becomes effective July 1, 2001 as proposed, the company believes it is probable
that it would be required to record a non-cash impairment charge. The company
cannot determine the amount at this time, but it believes the amount would be
material and could be a substantial portion of its intangible assets. This
impairment charge would have a material adverse effect on the company's
operating results in the period recorded.

Regulatory Assets and Liabilities: Regulatory assets represent probable
future revenue associated with certain costs that will be recovered from
customers through the rate-making 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:

As of December 31,
------------------
2000 1999
-------- --------
(In Thousands)
Recoverable income taxes............... $187,308 $218,239
Debt issuance costs.................... 63,263 68,239
Deferred employee benefit costs........ 36,251 36,251
Deferred plant costs................... 29,921 30,306
Other regulatory assets................ 10,607 12,969
-------- --------
Total regulatory assets.............. $327,350 $366,004
======== ========

- Recoverable income taxes: Recoverable income taxes represent amounts due
from customers for accelerated tax benefits which have been previously
flowed through to customers and are expected to be recovered in the
future as the accelerated tax benefits reverse.

- Debt issuance costs: Debt reacquisition expenses are amortized over the
remaining term of the reacquired debt or, if refinanced, the term of the
new debt. Debt issuance costs are amortized over the term of the
associated debt.

- Deferred employee benefit costs: Deferred employee benefit costs
represent costs to be recovered by income generated through the
company's Affordable Housing Tax Credit (AHTC) investment program as
authorized by the KCC.

- Deferred plant costs: Costs related to the Wolf Creek nuclear generating
facility.

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 $18.0 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.

Revenue Recognition

Energy Sales Recognition: 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 are recorded as a component of accounts
receivable (net) and amounted to $44 million at December 31, 1999. During 2000,
the company sold its energy related accounts receivable, including amounts
related to unbilled sales.

Monitored Services Sales Recognition: Monitored services sales are
recognized when security services are provided. Installation revenue, sales
revenues on equipment upgrades and direct costs of installations and sales are
deferred for residential customers with service contracts. For commercial
customers and national account customers, revenue recognition is dependent upon
each specific customer contract. In instances when the company sells the
equipment outright, revenues and costs are recognized in the period incurred. In
cases where there is no outright sale, revenues and direct costs are deferred
and amortized.

Deferred installation revenues and system sales revenues will be recognized
over the expected useful life of the customer, utilizing a 130% declining
balance. Deferred costs in excess of deferred revenues will be recognized over
the contract life. To the extent deferred costs are less than deferred
revenues, such costs are recognized over the customers' estimated useful life,
utilizing a 130% declining balance.

Deferred revenues also result from customers who are billed for monitoring,
extended service protection and patrol and response services in advance of the
period in which such services are provided, on a monthly, quarterly or annual
basis.

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.

Foreign Currency Translation: The assets and liabilities of the company's
foreign operations are generally translated into U.S. dollars at current
exchange rates and revenues and expenses are translated at average exchange
rates for the year.

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:

2000 1999
------- -------
(In Millions)
Cash surrender value of policies (a).... $ 705.4 $ 642.4
Borrowings against policies............. (665.9) (608.3)
------- -------
COLI (net).............................. $ 39.5 $ 34.1
======= =======

(a) 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, 2000 and 1999.

Income is 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 $0.9 million in 2000,
$1.4 million in 1999 and $13.7 million in 1998.

Cumulative Effect of Accounting Change: The company adopted Staff
Accounting Bulletin No. 101, "Revenue Recognition" (SAB 101) in the fourth
quarter of 2000 which had a retroactive effective date of January 1, 2000. The
impact of this accounting change generally requires deferral of certain
monitored services sales for installation revenues and direct sales-related
expenses. Deferral of these revenues and costs is generally necessary when
installation revenues have been received and a monitoring contract to provide
future service is obtained. Historically, Protection One acquired a majority of
its customers by acquisition or through an independent dealer program for its
North American operations. Dealers billed and retained any installation
revenues. In 2000, Protection One began an internal sales program. Because of
these factors the impact of adopting SAB 101 for Protection One was not
significant. Protection One Europe has a larger concentration of commercial
customers where installation revenues and related costs had previously been
recognized.

The cumulative effect of the change in accounting principle was
approximately $3.8 million, net of tax benefits of $1.1 million and is related
to changes in revenue recognition at Protection One Europe. Prior to the
adoption of SAB 101, Protection One Europe recognized installation revenues and
related expenses upon completion of the installation. Pro forma amounts and
amounts per share, assuming the change in accounting principle was applied
retroactively are as follows:

2000 1999 1998
---------------- ------------------ -----------------
Per Share Per Share Per Share
Amount Amount Amount Amount Amount Amount
------ ------ ------ ------ -------- -------
(In Thousands, Except Per Share Amounts)

Earnings available for
common stock before
extraordinary gain and
accounting change:
As reported.............................. $ 89,921 $1.30 $ 1,425 $ 0.02 $30,467 $ 0.46
Pro forma effect of
accounting change....................... - - (2,800) (0.04) (1,010) (0.01)
-------- ----- ------- ------ ------- ------
Pro forma................................ $ 89,921 $1.30 $(1,375) $(0.02) $29,457 $ 0.45

Earnings available for
common stock:
As reported.............................. $135,352 $1.96 $13,167 $ 0.20 $32,058 $ 0.48
Pro forma effect of
accounting change....................... 3,810 0.05 (2,800) (0.04) (1,010) (0.01)
-------- ----- ------- ------ ------- ------
Pro forma................................ $139,162 $2.01 $10,367 $ 0.16 $31,048 $ 0.47

New Accounting Pronouncements: In June 1998, the FASB issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133, as amended, is effective for
fiscal years beginning after June 15, 2000. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivatives' fair value be recognized currently
in earnings unless specific hedge accounting criteria are met.

The company adopted SFAS 133 on January 1, 2001. The company has evaluated
its commodity contracts, financial instruments and other contracts and
determined that certain commodity contracts are derivative instruments. Under
current GAAP, these contracts qualify as hedges. However, under SFAS 133, these
contracts will not qualify as hedges. Accordingly, the instruments will be
marked to market through earnings. The company estimates that the effect on its
financial statements of adopting SFAS 133 on January 1, 2001, will be to
increase pre-tax earnings for the first quarter of 2001 by approximately $31
million. Accounting for derivatives under SFAS 133 may increase volatility in
future earnings.

Supplemental Cash Flow Information: Cash paid for interest and income
taxes for each of the years ended December 31, are as follows:

2000 1999 1998
-------- -------- --------
(In Thousands)
Interest on financing activities
(net of amount capitalized)......... $310,345 $298,802 $220,848
Income taxes.......................... 28,751 784 47,196

Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.

2. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES

On November 8, 2000, the company entered into an agreement under which
Public Service Company of New Mexico (PNM) will acquire the electric utility
businesses of the company in a stock-for-stock transaction. Under the terms of
the agreement, both the company and PNM will become subsidiaries of a new
holding company. Immediately prior to the consummation of this combination, the
company will split-off its remaining interest in Westar Industries to its
shareholders.

The company and Westar Industries entered into an Asset Allocation and
Separation Agreement at the same time the company entered into the merger
agreement with PNM. Among other things, this agreement permits a receivable owed
by the company to Westar Industries to be converted into certain securities of
the company. At the closing of the merger, any of these securities then owned by
Westar Industries will be converted into securities of PNM or the holding
company to be formed by PNM.

On February 28, 2001, Westar Industries converted $350 million of the
receivable into approximately 14.4 million shares of the company's common stock
pursuant to the Asset Allocation and Separation Agreement. These shares
represent approximately 16.9% of the company's outstanding common stock
including these shares in outstanding shares. There are no voting rights with
respect to these shares as long as Westar Industries is a majority owned
subsidiary of the company.

3. RATE MATTERS AND REGULATION

KCC Rate Proceedings: On November 27, 2000, the company and KGE filed
applications with the KCC for a change in retail rates which included a cost
allocation study and separate cost of service studies for the company's KPL
division and KGE. The company requested an annual rate increase totaling
approximately $151 million. The company and KGE also provided revenue
requirements on a combined company basis on December 28, 2000. The company
anticipates a ruling by the KCC in July 2001 but is unable to predict its
outcome.

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 the company's KPL division and
KGE, a wholly owned subsidiary of the company. The City of Wichita asked that
FERC equalize the generation costs between KPL and KGE, in addition to other
matters. A hearing on the case was held at FERC on October 11 and 12, 2000 and
on November 9, 2000 a FERC administrative law judge ruled in favor of the
company that no change in rates was required. On December 13, 2000, the City of
Wichita filed a brief with FERC asking that the Commission overturn the judge's
decision. On January 5, 2001, the company filed a brief opposing the City's
position. The company anticipates a decision by FERC in the second quarter of
2001.

4. SALE OF ACCOUNTS RECEIVABLE

On July 28, 2000, the company and KGE entered into an agreement to sell, on
an ongoing basis, all of their accounts receivable arising from the sale of
electricity, to WR Receivables Corporation, a special purpose entity wholly
owned by the company. The agreement expires on July 26, 2001, and is annually
renewable upon agreement by both parties. The special purpose entity has sold
and, subject to certain conditions, may from time to time sell, up to $125
million (and upon request, subject to certain conditions, up to $175 million) of
an undivided fractional ownership interest in the pool of receivables to a
third-party, multi-seller receivables funding entity affiliated with a lender.
The company's retained interests in the receivables sold are recorded at cost
which approximates fair value. The company has received net proceeds of $115.0
million as of December 31, 2000.

5. SHORT-TERM DEBT

The company has an arrangement with certain banks to provide a revolving
credit facility on a committed basis totaling $500 million. The facility is
secured by first mortgage bonds of the company and KGE and matures on March 17,
2003. The company also has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling approximately $12.0
million. As of December 31, 2000, borrowings on these facilities were $35.0
million.

The agreements provide the company with the ability to borrow at different
market-based interest rates. The company pays commitment or facility fees in
support of these lines of credit. Under the terms of the agreements, the company
is required, among other restrictions, to maintain a total debt to total
capitalization ratio of not greater than 65% at all times. The company is in
compliance with all restrictions.

Information regarding the company's short-term borrowings, comprised of
borrowings under the credit agreements, bank loans and commercial paper, is as
follows:

As of December 31,
----------------------
2000 1999
--------- -----------
(Dollars in Thousands)
Borrowings outstanding at year end:
Credit agreement.................... $ 35,000 $ 50,000
Bank loans.......................... - 120,000
Commercial paper notes.............. - 535,421
-------- ----------
Total.............................. $ 35,000 $ 705,421
======== ==========

Weighted average interest rate on
debt outstanding at year end
(including fees).................... 8.11% 6.96%

Weighted average short-term debt
outstanding during the year......... $402,845 $ 455,184

Weighted daily average interest
rates during the year
(including fees).................... 7.92% 5.76%

Unused lines of credit supporting
commercial paper notes.................. $ - $1,021,000

The company's interest expense on short-term debt and other was $63.1
million in 2000, $57.7 million in 1999 and $55.3 million in 1998.

6. LONG-TERM DEBT

Long-term debt outstanding is as follows at December 31:

2000 1999
---------- ----------
(In Thousands)
Western Resources
-----------------
First mortgage bond series:
8 7/8% due 2000.................................. $ - $ 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
---------- ----------
325,000 400,000
---------- ----------

Pollution control bond series:
Variable due 2032, 4.70% at December 31, 2000.... 45,000 45,000
Variable due 2032, 4.62% at December 31, 2000.... 30,500 30,500
6% due 2033...................................... 58,410 58,420
---------- ----------
133,910 133,920
---------- ----------

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............ 28,977 29,783
6.25% unsecured senior notes due 2018,
putable/callable 2003.......................... 400,000 400,000
Senior secured term loan......................... 600,000 -
Other long-term agreements....................... 16,889 21,895
---------- ----------
1,565,866 971,678
---------- ----------

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................................... 13,623 13,653
Variable due 2027, 4.60% at December 31, 2000.... 21,940 21,940
7.0% due 2031.................................... 327,500 327,500
Variable due 2032, 4.60% at December 31, 2000.... 14,500 14,500
Variable due 2032, 4.60% at December 31, 2000.... 10,000 10,000
---------- ----------
387,563 387,593
---------- ----------

Protection One
--------------
Convertible senior subordinated notes
due 2003, fixed rate 6.75%..................... 23,785 53,950
Senior subordinated discount notes due 2005,
effective rate of 11.8%........................ 42,887 87,038
Senior unsecured notes due 2005,
fixed rate 7.375%.............................. 204,650 250,000
Senior subordinated notes due 2009,
fixed rate 8.125% (1).......................... 255,740 341,415
Other............................................ 267 2,033
---------- ----------
527,329 734,436
---------- ----------
Protection One Europe
---------------------
CET recourse financing agreements, average
effective rate 15%............................. 33,512 60,838

Unamortized debt premium........................... 13,541 13,726

Less:
Unamortized debt discount........................ (7,047) (7,458)
Long-term debt due within one year............... (41,825) (111,667)
---------- ----------
Long-term debt (net)............................. $3,237,849 $2,883,066
========== ==========

(1) The rate is currently 8.625% and will continue at that rate until an
exchange offer related to the offering is completed.

Debt discount and expenses are being amortized over the remaining lives
of each issue.

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. First mortgage bonds are secured by the utility assets of the company
and KGE. 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.

On June 28, 2000, the company entered into a $600 million, multi-year
term loan that replaced two revolving credit facilities which matured on June
30, 2000. The net proceeds of the term loan were used to retire short-term debt.
The term loan is secured by first mortgage bonds of the company and KGE and has
a maturity date of March 17, 2003.

Maturities of the term loan through March 17, 2003, are as follows:

Principal
Amount
Year (In Thousands)
-------------------------------------
2001...................... $ 9,000
2002...................... 6,000
2003...................... 585,000
--------
$600,000

The terms of the loan contain requirements for maintaining certain
consolidated leverage ratios, interest coverage ratios and consolidated debt to
capital ratios. The company is in compliance with all of these requirements.

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 these
notes has been 8.625% since June 1999. If the exchange offer is completed, the
interest rate will revert back to 8.125%. Interest on these notes 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 13.625%. 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%
through June 30, 2000, the first full call date of the notes. Since the notes
were not called on that date the current market yield was adjusted to 11.8% as
of July 1, 2000. The 1997 revaluation 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. This revaluation had no impact on the
expected cash flow to existing noteholders. As of June 30, 2000, the notes
became redeemable at Protection One's option, at a specified redemption price.

In 1998, Protection One redeemed unsecured senior subordinated discount
notes with a book value of $69.4 million and recorded an extraordinary gain on
the extinguishment of $1.6 million, net of tax.

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
redemption price, beginning September 19, 1999.

In 1999, Westar Industries purchased Protection One bonds on the open
market at amounts less than the carrying amount of the debt. The company
recognized an extraordinary gain of $13.4 million, net of tax, at December 31,
1999, related to the retirement of this debt.

During 2000, Westar Industries purchased various issues of Protection One
bonds on the open market at amounts less than the carrying amount of the debt.
The company recognized an extraordinary gain of $49.2 million, net of tax, at
December 31, 2000, related to the retirement of this debt.

Protection One Europe 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.

Maturities of long-term debt through 2005 are as follows:

Principal
Amount
Year (In Thousands)
---------------------------------
2001................ $ 41,825
2002................ 116,705
2003................ 747,207
2004................ 370,617
2005................ 313,007
Thereafter.......... 1,683,819
----------
$3,273,180

The company's interest expense on long-term debt was $226.4 million in
2000, $236.4 million in 1999 and $170.9 million in 1998.

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. At December 31, 2000, Protection One was in
compliance with all financial covenants governing its debt securities.

The indentures governing all of Protection One's debt securities require
that Protection One offer to repurchase the securities in certain circumstances
following a change of control.

7. 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 and are not included in the table
below. The decommissioning trust is recorded at fair value and is based on the
quoted market prices at December 31, 2000 and 1999. 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, 2000 and 1999. 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.

The carrying values and estimated fair values of the company's financial
instruments are as follows:

Carrying Value Fair Value
---------------------- ----------------------
As of December 31,
----------------------------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
(In Thousands)

Decommissioning trust.... $ 64,222 $ 58,286 $ 64,222 $ 58,286
Fixed-rate debt, net of
current maturities...... 3,109,415 2,743,057 2,809,711 2,350,880
Other mandatorily
redeemable securities... 220,000 220,000 182,232 187,950

The tables below present the estimated fair value of contracts not settled
at December 31, 2000.

The notional volumes and estimated fair values of the company's forward
contracts and options for electricity positions are as follows at December 31:

2000 1999
---------------------- ----------------------
Notional Notional
Volumes Estimated Volumes Estimated
(MWH's) Fair Value (MWH's) Fair Value
--------- ---------- --------- ----------
(Dollars in Thousands)
Forward contracts:
Purchased................ 3,581,500 $264,488 1,137,600 $33,021
Sold..................... 3,713,248 269,731 1,088,800 32,395

Options:
Purchased................ 647,600 $ 12,606 944,800 $ 5,524
Sold..................... 387,200 11,976 754,200 8,458

The notional volumes and estimated fair values of the company's forward
contract and options for gas positions are as follows at December 31:

2000 1999
----------------------- -----------------------
Notional Notional
Volumes Estimated Volumes Estimated
(MMBtu's) Fair Value (MMBtu's) Fair Value
---------- ---------- ---------- ----------
(Dollars in Thousands)
Forward contracts:
Purchased................ 73,859,179 $283,453 13,010,000 $31,002
Sold..................... 50,614,417 174,441 500,000 1,108

Options:
Purchased................ 39,171,500 $ 21,887 6,000,000 $ 971
Sold..................... 30,140,000 21,196 4,000,000 615

Under mark-to-market accounting, energy trading contracts with third
parties are reflected at fair market value, net of reserves, with resulting
unrealized gains and losses recorded as energy trading contract assets and
liabilities. These assets and liabilities are affected by the actual timing of
settlements related to these contracts and current period changes resulting
primarily from newly originated transactions and the impact of price movements.
These changes are recognized as revenues in the consolidated statements of
income in the period the changes occur. As of December 31, 2000, the company
had gross mark-to-market gains (asset position) and losses (liability position)
on these energy trading contracts as follows:

2000 1999
-------- -------
(In Thousands)
Current Assets - energy trading contracts...... $185,364 $16,370
Other Assets - other........................... 15,883 -
-------- -------
$201,247 $16,370
-------- -------

Current Liabilities - energy trading contracts. $191,673 $15,182
Long-term liabilities - other.................. 1,096 -
-------- -------
$192,769 $15,182
-------- -------
Net mark-to-market gains..................... $ 8,478 $ 1,188
======== =======

These net mark-to-market gains have been recognized in revenue. Included
within these assets and liabilities is an unrealized gain of $31 million which
will be recognized through revenue in 2001 as a cumulative effect of an
accounting change upon adoption of SFAS 133.

8. MONITORED SERVICES BUSINESS

In 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 million. This gain is reflected in
other income (expense) - other on the statement of income.

Protection One acquired a significant number of security companies in 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. The table
assumes acquisitions in 1998 occurred as of January 1, 1998.

Year Ended December 31, 1998
-----------
(Unaudited)
(In Thousands,
Except Per Share Data)
----------------------

Sales......................................... $2,175,089
Earnings available for common stock........... $21,449
Earnings per share............................ $0.33

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.

9. MARKETABLE SECURITIES

During the fourth quarter of 1999, the company decided to sell its
remaining marketable security investments in paging industry companies. These
securities were classified as available-for-sale; therefore, changes in market
value were 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, a non-cash charge of $76.2
million was recorded in the fourth quarter of 1999 and is presented separately
in the accompanying Consolidated Statements of Income.

In February 2000, a paging company whose securities were included in the
securities discussed in the paragraph above at December 31, 1999, made an
announcement that significantly increased the market value of paging company
securities generally 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.

During 2000, the company sold its equity investment in a gas compression
company and realized a pre-tax gain of $91.1 million.

1O. CUSTOMER ACCOUNTS

The following is a rollforward of the investment in customer accounts (at
cost) for the following years:

December 31,
-----------------------
2000 1999
--------- ---------
(In Thousands)
Beginning customer accounts, net.............. $1,122,585 $1,009,084
Acquisition of customer accounts.............. 54,993 337,464
Amortization of customer accounts............. (163,297) (185,974)
Non-cash charges against
purchase holdbacks...................... (8,776) (37,989)
---------- ----------
Ending customer accounts, net................. $1,005,505 $1,122,585
========== ==========

Accumulated amortization of the investment in customer accounts at
December 31, 2000 and 1999 was $493.4 million and $330.7 million.

11. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

The company's investments which are accounted for by the equity method are
as follows:

Equity Earnings,
Investment at Year Ended
Ownership at December 31, December 31
December 31, --------------------- ------------------
2000 2000 1999 2000 1999
------------- -------- -------- -------- -------
(Dollars in Thousands)

ONEOK (a).................. 45% $591,173 $590,109 $ 8,213 $6,945
Affordable Housing Tax
Credit limited
partnerships (b).......... 13% to 29% 69,364 79,460 10,066 5,615
Paradigm Direct (c)........ - - 35,385 3,006 1,254
International companies
and joint ventures (d).... 9% to 50% 13,514 18,724 4,799 -

(a) The company also received approximately $40 million and $41 million of
preferred and common dividends in 2000 and 1999.
(b) 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 post-retirement and post-
employment benefits offered to the company's employees.
(c) The company sold this investment on December 15, 2000.
(d) Investment is aggregated. Individual investments are not material.

The following summarized unaudited financial information for the company's
investment in ONEOK is as follows:

As of December 31,
----------------------
2000 1999
---------- ----------
(In Thousands)
Balance Sheet:
Current assets.................... $3,324,959 $ 595,386
Non-current assets................ 4,044,177 2,645,854
Current liabilities............... 3,535,352 786,713
Non-current liabilities. 2,608,827 1,303,003
Equity............................ 1,224,957 1,151,524

For the Year Ended December 31,
-------------------------------
2000 1999
---------- ----------
(In Thousands)
Income Statement:
Revenues.......................... $6,642,858 $2,064,726
Gross profit...................... 797,132 632,350
Net income........................ 145,607 106,873

At December 31, 2000, the company's ownership interest in ONEOK is
comprised of approximately 2.2 million common shares and approximately 19.9
million convertible preferred shares. If all the preferred shares were
converted, the company would then own approximately 45% of ONEOK's common shares
outstanding.

12. EMPLOYEE BENEFIT PLANS

Pension: The company maintains qualified noncontributory defined benefit
pension plans covering substantially all utility employees. Pension benefits
are based on years of service and the employee's compensation during the five
highest paid consecutive years out of ten before retirement. The company's
policy is to fund pension costs accrued, subject to limitations set by the
Employee Retirement Income Security Act of 1974 and the Internal Revenue Code.
The company also maintains a non-qualified Executive Salary Continuation Program
for the benefit of certain management employees, including executive officers.

Postretirement Benefits: The company accrues the cost of postretirement
benefits, primarily medical benefit costs, during the years an employee provides
service.

The following tables summarize the status of the company's pension and
other postretirement benefit plans:

Pension Benefits Postretirement Benefits
----------------------- -------------------------
December 31, 2000 1999 2000 1999
-------------------------------------------- ---------- --------- ---------- --------
(Dollars in Thousands)

Change in Benefit Obligation:
Benefit obligation, beginning of year...... $ 350,749 $ 392,057 $ 79,287 $ 87,519
Service cost............................... 7,964 8,949 1,344 1,609
Interest cost.............................. 26,901 26,487 7,158 5,854
Plan participants' contributions........... - - 1,130 784
Benefits paid.............................. (20,337) (21,961) (6,476) (6,990)
Assumption changes......................... 19,350 (49,499) 5,038 (9,458)
Actuarial losses (gains)................... (2,491) (4,608) 15,049 (31)
Acquisitions............................... - (676) - -
Curtailments, settlements and special
term benefits............................. 1,267 - - -
---------- --------- ---------- --------
Benefit obligation, end of year............ $ 383,403 $ 350,749 $ 102,530 $ 79,287
========== ========= ========== ========

Change in Plan Assets:
Fair value of plan assets,
beginning of year......................... $ 506,995 $ 441,531 $ 261 $ 173
Actual return on plan assets............... 1,448 85,079 17 10
Acquisitions............................... - - - -
Employer contribution...................... 1,927 2,882 5,177 6,284
Plan participants' contributions........... - - 1,109 784
Benefits paid.............................. (20,197) (22,497) (6,170) (6,990)
---------- --------- ---------- --------
Fair value of plan assets,
end of year............................... $ 490,173 $ 506,995 $ 394 $ 261
========== ========= ========== ========

Funded status.............................. $ 106,770 $ 156,246 $ (102,136) $(79,026)
Unrecognized net (gain)/loss............... (141,443) (205,338) 11,904 (7,733)
Unrecognized transition
obligation, net........................... 174 209 48,183 52,171
Unrecognized prior service cost............ 29,538 32,854 (3,264) (3,730)
---------- --------- ---------- --------
Accrued postretirement benefit costs....... $ (4,961) $ (16,029) $ (45,313) $(38,318)
========== ========= ========== ========

Actuarial Assumptions:
Discount rate.............................. 7.25-7.75% 7.75% 7.25-7.75% 7.75%
Expected rate of return.................... 9.00-9.25% 9.00% 9.00-9.25% 9.00%
Compensation increase rate................. 4.25-5.00% 4.50% 4.50-5.00% 4.50%

Components of net periodic (benefit) cost:
Service cost............................... $ 7,972 $ 8,949 $ 1,344 $ 1,610
Interest cost.............................. 26,977 26,487 7,157 5,854
Expected return on plan assets............. (39,143) (34,393) (24) (16)
Amortization of unrecognized
transition obligation, net................ 35 34 3,988 3,987
Amortization of unrecognized prior
service costs............................. 3,316 3,455 (466) (466)
Amortization of (gain)/loss, net........... (9,427) (3,477) 457 129
Other...................................... 9 - - -
---------- --------- ---------- --------
Net periodic (benefit) cost................ $ (10,261) $ 1,055 $ 12,456 $ 11,098
========== ========= ========== ========

For measurement purposes, an annual health care cost growth rate of 6.0%
was assumed for 2000 decreasing 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 $2.5 million and the aggregate
of the service and interest cost components by $0.2 million. A 1% decrease in
the trend rate would decrease the present value of the accumulated projected
benefit obligation by $2.3 million and the aggregate of the service and interest
cost components by $0.2 million.

Savings Plans: The company maintains savings plans in which substantially
all employees participate, with the exception of Protection One and Protection
One Europe employees. The company matches employees' contributions up to
specified maximum limits. The company's contribution to the plans are deposited
with a trustee and are invested in one or more funds, including the company
stock fund. The company's contributions were $3.9 million for 2000, $3.7
million for 1999 and $3.8 million for 1998.

In 1999, the company established a qualified employee stock purchase plan,
the terms of which allow for full-time non-union employees to participate in the
purchase of designated shares of the company's common stock at no more than a
15% discounted price. Western Resources' employees purchased 249,050 shares in
2000, pursuant to this plan, at an average price per share of $13.9984. In 1999,
employees purchased 72,698 shares at an average price per share of

$14.4234. A total of 1,250,000 shares of common stock have been reserved for
issuance under this program.

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 cash contribution to the plan was approximately $0.7
million for 2000, $0.9 million for 1999 and $1.0 million for 1998.

Protection One maintains a qualified employee stock purchase plan that
allows eligible employees to acquire shares of Protection One common stock at
periodic intervals through their accumulated payroll deductions. A total of
2,650,000 shares of common stock have been reserved for issuance in this program
and a total of 422,133 shares have been issued including the issuance of 145,523
shares in January 2001.

Stock Based Compensation Plans: The company, excluding Protection One and
Protection One Europe, 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 (RSUs), performance shares and performance share
units to Plan Participants. Up to five million shares of common stock may be
granted under the LTISA Plan.

During 2000, 710,352 RSUs were granted to a broad-based group of over 900
non-union employees. Each RSU represents a right to receive one share of the
company's common stock at the end of the restricted period. In addition, in
2000, current non-union employees were offered the opportunity to exchange their
stock options for RSUs of approximately equal economic value. As a result,
2,246,865 stock options were canceled in 2000 in exchange for 614,741 RSUs. The
grant of restricted stock is shown as a separate component of shareholders'
equity. Unearned compensation is being amortized to expense over the vesting
period. This compensation expense is shown as a separate component of
shareholders' equity. The company granted a total of 152,000 restricted shares
in 1999 and 136,500 in 1998.

Another component of the LTISA Plan is the Executive Stock for Compensation
program where eligible employees are entitled to receive RSUs in lieu of cash
compensation at the end of a deferral period. In 2000, 95,000 RSUs were
deferred, representing $1.3 million in cash compensation. In 1999, 35,000 RSUs
were deferred, representing $0.7 million of cash compensation. Dividend
equivalents accrue on the deferred RSUs. Dividend equivalents are the right to
receive cash equal to the value of dividends paid on the company's common stock.

Stock options and restricted shares under the LTISA plan are as follows:

As of December 31,
-------------------------------------------------------------------------
2000 1999 1998
-------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Shares Exercise Shares Exercise
(Thousands) Price (Thousands) Price (Thousands) Price
---------- -------- ---------- ------------- ---------- ---------

Outstanding,
beginning of year............................. 2,418.6 $ 34.139 1,590.7 $36.106 665.4 $30.282
Granted........................................ 1,953.1 15.513 981.6 30.613 925.3 40.293
Exercised...................................... (0.5) 15.625 - - - -
Forfeited...................................... (2,265.6) 28.827 (153.7) 31.985 - -
---------- ---------- ----------
Outstanding, end of year....................... 2,105.6 $ 22.583 2,418.6 $34.139 1,590.7 $36.106
========== ========== ==========
Weighted-average fair value
of awards granted during
the year...................................... $ 11.28 $ 8.22 $ 9.12

Stock options and restricted shares issued and outstanding at December 31,
2000 are as follows:

Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Contractual Exercie
Price Outstanding Life in Years Price
------------------ ----------- ------------- -------

Options:
2000...................................................... $ 15.3125 17,690 10.0 $15.3125
1999...................................................... 27.8125-32.125 51,305 9.0 29.7357
1998...................................................... 38.625-43.125 222,720 8.0 40.986
1997...................................................... 30.750 137,740 7.0 30.750
1996...................................................... 29.250 68,870 5.7 29.250
---------
498,325
---------
Restricted shares:
2000...................................................... 15.3125-19.875 1,319,083 6.3 15.6079
1999...................................................... 27.813-32.125 151,783 8.0 29.7587
1998...................................................... 38.625 136,500 7.0 38.625
---------
1,607,366
---------

Total issued............................................ 2,105,691
=========

An equal amount of dividend equivalents is issued to recipients of stock
options and RSUs. The weighted-average grant-date fair value of the dividend
equivalent was $4.62 in 2000 and $3.28 in 1999. 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, with
respect to stock options, expire after nine years from date of grant.

The fair value of stock options and dividend equivalents were estimated on
the date of grant using the Black-Scholes option-pricing model. The model
assumed the following at December 31:

2000 1999
----- -----
Dividend yield..................... 6.32% 6.25%
Expected stock price volatility.... 16.42% 16.56%
Risk-free interest rate............ 5.79% 6.05%

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 employees. Under the LTIP, 4.2 million shares are
reserved for issuance. 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.

Options issued since 1997 have a term of 10 years and vest ratably over 3
years.

A summary of warrant and option activity for Protection One from December
31, 1998, through December 31, 2000, is as follows:

As of December 31,
----------------------------=---------------------------------------------
2000 1999 1998
--------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Shares Exercise Shares Exercise
(Thousands) Price (Thousands) Price (Thousands) Price
---------- -------- ---------- ------------ ---------- --------

Outstanding, beginning of year....................... 3,788.1 $ 7.232 3,422.7 $ 7.494 2,366.4 $ 5.805
Granted.............................................. 922.5 1.436 1,092.9 7.905 1,246.5 11.033
Exercised............................................ (5.4) 3.89 - - (109.6) 5.564
Forfeited............................................ (300.6) 6.698 (727.5) 10.125 (117.4) 10.770
Adjustment to May 1995 warrants...................... - - - - 36.8 -
-------- ------- -------
Outstanding, end of year............................. 4,404.6 $ 6.058 3,788.1 $ 7.232 3,422.7 $ 7.494
======== ======= =======

Exercisable, end of year............................. - - 2,313.3 $ 6.358 2,263.2 $ 5.681
======== ======= =======

(1) There were no outstanding stock or options prior to November 24, 1997.

Stock options and warrants of Protection One issued and outstanding at
December 31, 2000, 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-$ 6.500 100,800 4.0 $ 6.491
Fiscal 1996..................... 8.000- 10.313 248,400 5.0 8.022
Fiscal 1996..................... 13.750- 15.500 99,000 5.0 14.947
Fiscal 1997..................... 9.500 110,500 6.0 9.500
Fiscal 1997..................... 15.000 37,500 6.0 15.000
Fiscal 1997..................... 14.268 50,000 1.0 14.268
Fiscal 1998..................... 11.000 671,835 7.0 11.000
Fiscal 1998..................... 8.5625 23,833 7.0 8.5625
Fiscal 1999..................... 8.9275 248,297 8.0 8.9275
Fiscal 1999..................... 5.250- 6.125 56,222 8.0 6.028
Fiscal 2000..................... 1.438 5,000 9.0 1.438
1993 Warrants................... 0.167 428,400 3.0 0.167
1995 Note Warrants.............. 3.890 780,837 4.0 3.890
---------
2,860,624
---------
Not Exercisable:
1998 options.................... $ 11.000 112,165 7.0 $ 11.000
1998 options.................... 8.5625 11,917 7.0 8.5625
1999 options.................... 8.9275 410,403 8.0 8.9275
1999 options.................... 5.250- 6.125 112,444 8.0 6.028
2000 options.................... 1.313- 1.438 896,980 9.0 1.436
---------
1,543,909
---------
Total outstanding 4,404,533
=========

The weighted average fair value of options granted by Protection One during
2000, 1999 and 1998 estimated on the date of grant were $1.13, $5.41 and $6.87.
The fair value was calculated using the following assumptions:

Year Ended December 31,
-------------------------
2000 1999 1998
----- ----- -----
Dividend yield................... - % - % - %
Expected stock price volatility.. 92.97% 64.06% 61.72%
Risk free interest rate.......... 4.87% 6.76% 5.50%
Expected option life............ 6 years 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 2000, 1999 and 1998 as shown in the table below.

Year Ended December 31, 2000 1999 1998
--------------------------------------------------------------------------
(In Thousands, Except Per Share Amounts)

Earnings available for common stock:
As reported.................................. $135,352 $13,167 $32,058
Pro forma.................................... 134,274 10,699 42,640

Basic and diluted earnings per common share:
As reported.................................. $ 1.96 $ 0.20 $ 0.48
Pro forma.................................... 1.95 0.16 0.65

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 $19.1 million as of December 31, 2000, and $31.9 million as of December 31,
1999. The obligations under this program can increase and decrease based on the
company's total return to shareholders and payments to plan participants. This
liability decreased approximately $12.8 million in 2000 due primarily to
payments to plan participants and $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.

13. COMMON STOCK, PREFERRED 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, 2000, 70,082,314
shares were issued and 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. During 2000, a total of 3,220,657 shares were purchased from the company
made up of 1,440,000 treasury and 1,780,657 original issue shares. These shares
were for DSPP, ESPP, 401K match and other stock based plans operated under the
1996 Long-term Incentive and Share Award Plan. Of the total shares purchased
from the company in 2000, 2,750,457 were for the DSPP made up of 1,021,443
treasury and 1,729,014 original issue shares. During 2000 an additional
6,000,000 shares were registered to the DSPP. At December 31, 2000, 6,020,734
shares were available under the DSPP registration statement.

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. These purchased shares are shown as $15.8 million in
treasury stock on the accompanying Consolidated Balance Sheet. In 2000, the
company purchased 540,000 shares of common stock at an average price of $17.01.
All of these shares were reissued during the year.

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.

Total
Principal Call Amount
Rate Outstanding Price Premium to Redeem
---- ----------- -------- ----------- -----------

4.500% $13,857,600 108.00% $1,108,608 $14,966,208
4.250% 6,000,000 101.50% 90,000 6,090,000
5.000% 5,000,000 102.00% 100,000 5,100,000
----------- ---------- -----------
$24,857,600 $1,298,608 $26,156,208

The provisions in the company's Articles of Incorporation contain
restrictions on the payment of dividends or the making of other distributions on
the company's common stock while any preferred shares remain outstanding unless
certain capitalization ratios and other conditions are met.

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.

14. COMMITMENTS AND CONTINGENCIES

Efforts by Wichita to Equalize Electric Rates: In September 1999, the City
of Wichita filed a complaint with FERC against KGE, alleging improper affiliate
transactions between KGE and Western Resources' KPL division. The City of
Wichita asked that FERC equalize the generation costs between KGE and KPL, in
addition to other matters. On November 9, 2000, a FERC administrative law judge
ruled in the company's favor that no change in rates was required. On December
13, 2000, the City of Wichita filed a brief with FERC asking that the Commission
overturn the judge's decision. The company anticipates a decision by FERC in
the second quarter of 2001. A decision requiring equalization of rates could
have a material adverse effect on the company's operations and financial
position.

Municipalization Efforts by Wichita: In December 1999, the City Council of
Wichita, Kansas, 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. The feasibility study was released in
February 2001 and estimates that the City of Wichita would be required to pay
KGE $145 million for its stranded costs if the City were to municipalize.
However, the company estimates the amount to be substantially greater. 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 and
arrange for its own power supply. These costs are in addition to the stranded
costs for which the city would be required to reimburse the company. On February
2, 2001, the City of Wichita announced its intention to proceed with its attempt
to municipalize KGE's retail electric utility business in Wichita. KGE will
oppose municipalization efforts by the City of Wichita. Should the city be
successful in its municipalization efforts without providing the company
adequate compensation for its assets and lost revenues, the adverse effect on
the operations and financial position of the company could be material.

KGE's franchise with the City of Wichita to provide retail electric service
expires in March 2002. There can be no assurance that this franchise can be
successfully renegotiated with terms similar, or as favorable, as those in the
current franchise. Under Kansas law, KGE will continue to have the right to
serve the customers in Wichita following the expiration of the franchise,
assuming the system is not municipalized. Customers within the Wichita
metropolitan area account for approximately 25% of the company's total energy
sales .

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 $154.2 million at
December 31, 2000.

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 on the results
of the investigations and risk analysis. At December 31, 2000, the costs
incurred for preliminary site investigation and risk assessment have been
minimal. In accordance with the terms of the strategic alliance with ONEOK,
ownership of twelve of these sites and the responsibility for clean-up of these
sites were transferred to ONEOK. The ONEOK agreement limits the company's
future liability associated with these sites to an immaterial amount. The
company's investment earnings from ONEOK could be impacted by these costs.

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. Material capital expenditures
have not been 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.

On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, the company's share of Wolf
Creek's decommissioning costs, under the immediate dismantlement method, is
estimated to be approximately $631 million during the period 2025 through 2034,
or approximately $221 million in 1999 dollars. These costs include
decontamination, dismantling and site restoration and were calculated using an
assumed inflation rate of 3.6% over the remaining service life from 1999 of 26
years. The actual decommissioning costs may vary from the estimates because of
changes in the assumed dates of decommissioning, changes in regulatory
requirements, changes in technology and changes in costs of labor, materials and
equipment. On May 26, 2000, the company filed an application with the KCC
requesting approval of the funding of the company's decommissioning trust on
this basis. Approval was granted by the KCC on September 20, 2000.

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 $4.0 million in 2000 and will increase annually to
$5.5 million in 2024. These amounts are deposited in an external trust fund.
The average after-tax expected return on trust assets is 5.8%.

The company's investment in the decommissioning fund, including reinvested
earnings approximated $64.2 million at December 31, 2000 and $58.3 million at
December 31, 1999. Trust fund earnings accumulate in the fund balance and
increase the recorded decommissioning liability.

- The company's annual decommissioning expense could be higher than in
2000
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in
the Wolf Creek plant

The company does not believe that such changes, if required, would
adversely affect its operating results due to its current ability to recover
decommissioning costs through rates.

Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.5 billion for a single
nuclear incident. If this liability limitation is insufficient, the United
States 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 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 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 $5.3 million per year.

Although the company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or an
extended outage, the company's insurance coverage may not be adequate to cover
the costs that could result from a catastrophic accident or extended outage at
Wolf Creek. Any substantial losses not covered by insurance, to the extent not
recoverable through rates, would have a material adverse effect on the company's
financial condition and results of operations.

Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the company has entered into various commitments to obtain
nuclear fuel and coal. Some of these contracts contain provisions for price
escalation and minimum purchase commitments. At December 31, 2000, WCNOC's
nuclear fuel commitments (company's share) were approximately $7.3 million for
uranium concentrates expiring in 2003, $1.1 million for conversion expiring in
2003, $16.1 million for enrichment expiring at various times through 2003 and
$61.3 million for fabrication through 2025.

At December 31, 2000, the company's coal and transportation contract
commitments in 2000 dollars under the remaining terms of the contracts were
approximately $1.52 billion. The largest contract expires in 2020, with the
remaining contracts expiring at various times through 2013.

At December 31, 2000, the company's natural gas transportation commitments
in 2000 dollars under the remaining terms of the contracts were approximately
$61.5 million. The natural gas transportation contracts provide firm service to
several of the company's gas burning facilities and expire at various times
through 2010, except for one contract which expires in 2016.

Energy Act: As part of the 1992 Energy Policy Act, a special assessment is
being collected from utilities for an uranium enrichment decontamination and
decommissioning fund. The company's portion of the assessment for Wolf Creek is
approximately $9.6 million, payable over 15 years. Such costs are recovered
through the ratemaking process.

15. 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.

The company, its subsidiary Westar Industries, 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, "Alec Garbini, 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. On
February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action
Complaint ("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 February 2, 2001. 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, 1998, 1999 and the first three quarters of 2000 were false and
misleading and not in compliance with generally accepted accounting principles.
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 Industries 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. Defendants have until April 9, 2001 to respond to the Amended Complaint.
The company and Protection One intend to vigorously defend against all the
claims asserted in the Amended Complaint. The company and Protection One cannot
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 3 for
discussion of regulatory proceedings and FERC proceedings including the City of
Wichita and Note 14 for discussion of the City of Wichita municipalization
efforts.

16. LEASES

At December 31, 2000, the company had leases covering various property and
equipment.

Rental payments for operating leases and estimated rental commitments are
as follows:

Year Ended December 31, Leases
-------------------------------------------
(In Thousands)
Rental payments:
1998......................... $70,796
1999......................... 71,771
2000......................... 71,232

Future commitments:
2001......................... $71,280
2002......................... 67,033
2003......................... 62,270
2004......................... 54,647
2005......................... 55,931
Thereafter................... 558,754
--------
Total future commitments... $869,915
========

In 1987, KGE sold and leased back its 50% undivided interest in the La
Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29 years,
with various options to renew the lease or repurchase the 50% undivided
interest. KGE remains responsible for its share of operation and maintenance
costs and other related operating costs of La Cygne 2. The lease is an operating
lease for financial reporting purposes. The company recognized a gain on the
sale which was deferred and is being amortized over the initial lease term.

In 1992, the company deferred costs associated with the refinancing of the
secured facility bonds of the Trustee and owner of La Cygne 2. These costs are
being amortized over the life of the lease and are included in operating
expense.

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, $38.0 million
in 2005, and $464.6 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 annually for 2000, 1999 and 1998.

17. 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. 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 The Wing Group 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.

18. INCOME TAXES

Income tax expense (benefit) is composed of the following components at
December 31:

2000 1999 1998
------- -------- --------
(In Thousands)
Currently payable:
Federal................... $18,600 $ 13,907 $ 52,993
State..................... 10,131 9,622 10,881
Deferred:
Federal................... 13,790 (43,090) (46,869)
State..................... 9,585 (6,582) (4,185)
Amortization of investment
tax credits................ (6,045) (6,054) (6,065)
------- -------- --------
Total income tax expense
(benefit).................. $46,061 $(32,197) $ 6,755
====== ======== ========

Under SFAS No. 109, "Accounting for Income Taxes," temporary differences
gave rise to deferred tax assets and deferred tax liabilities as follows at
December 31:

2000 1999
---------- ----------
(In Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback....... $ 82,013 $ 87,220
Monitored services deferred tax assets 101,101 59,171
Other................................. 119,344 131,976
---------- ----------
Total deferred tax assets............ $ 302,458 $ 278,367
========== ==========

Deferred tax liabilities:
Accelerated depreciation and other.... $ 609,396 $ 614,309
Acquisition premium................... 275,159 283,157
Deferred future income taxes.......... 188,006 218,937
Other................................. 58,158 40,508
---------- ----------
Total deferred tax liabilities....... $1,130,719 $1,156,911
========== ==========

Investment tax credits................. $ 91,546 $ 97,591
========== ==========
Accumulated deferred income taxes, net. $ 919,807 $ 976,135
========== ==========

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
regulatory asset for these amounts. These assets also are a temporary difference
for which deferred income tax liabilities have been provided. This liability is
classified above as deferred future income taxes.

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:

For the Year Ended December 31,
-------------------------------
2000 1999 1998
------ ------ ------

Effective income tax rate................... 33.6% (108.6%) 16.6%
Effect of:
State income taxes......................... (9.4) (7.1) (7.3)
Amortization of investment tax credits..... 4.4 20.4 14.9
Corporate-owned life insurance policies.... 8.4 28.0 22.4
Affordable housing tax credits............. 7.8 31.3 3.1
Accelerated depreciation flow through
and amortization, net..................... (4.9) (12.2) (4.4)
Adjustment to tax provision................ - 4.3 (16.9)
Dividends received deduction............... 7.1 34.3 23.9
Amortization of goodwill................... (13.0) (19.3) (17.0)
Other...................................... 1.0 (6.1) (0.3)
----- ------ -----
Statutory federal income tax rate........... 35.0% (35.0%) 35.0%
===== ====== =====

19. RELATED PARTY TRANSACTIONS

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 on various hourly charges,
negotiated fees and out-of-pocket expenses. ONEOK paid the company $5.0 million
in 2000 and $5.6 million in 1999, 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% as of
December 31, 2000.

2O. PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at December 31:

2000 1999
---------- ----------
(In Thousands)

Electric plant in service........... $5,987,920 $5,769,401
Less - accumulated depreciation..... 2,274,940 2,141,037
---------- ----------
3,712,980 3,628,364
Construction work in progress....... 189,853 170,061
Nuclear fuel (net).................. 30,791 28,013
---------- ----------
Net utility plant.................. 3,933,624 3,826,438
Non-utility plant in service........ 113,040 92,872
Less - accumulated depreciation..... 53,226 29,866
---------- ----------
Net property, plant and equipment.. $3,993,438 $3,889,444
========== ==========

The company's depreciation expense on property, plant and equipment was
$201.7 million in 2000, $186.1 million in 1999 and $168.9 million in 1998.

21. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 2000
---------------------------------------------------
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
---------- ---------- ------------ ----- ----
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 182,794 $ 115,903 344.0 50
Jeffrey 1 (b) Jul 1978 305,838 144,009 625.0 84
Jeffrey 2 (b) May 1980 297,979 133,701 622.0 84
Jeffrey 3 (b) May 1983 410,926 175,482 623.0 84
Jeffrey wind 1 (b) May 1999 828 58 0.6 84
Jeffrey wind 2 (b) May 1999 828 57 0.6 84
Wolf Creek (c) Sep 1985 1,381,656 491,978 550.0 47

(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

Amounts and capacity 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 KGE 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.

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.

The first three segments comprise the company's electric utility business.
Fossil Generation produces power for sale internally to the Power Delivery
segment and externally to wholesale customers. A component of the company's
Fossil Generation segment is power marketing which attempts to minimize market
fluctuation risk associated with fuel and purchased power requirements and
enhance system reliability. Nuclear Generation represents the company's 47%
ownership in the Wolf Creek nuclear generating facility. This segment has only
internal sales because it provides all of its power to its co-owners. The Power
Delivery segment consists of the transmission and distribution of power to the
company's retail customers in Kansas and the customer service provided to these
customers and the transportation of wholesale energy. Monitored Services
represents the company's security alarm monitoring business in North America,
the United Kingdom and continental Europe. Other represents the company's non-
utility operations and natural gas investment.

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
(EBIT). 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.

Year Ended December 31, 2000:
-----------------------------
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services Other(a) Items (b) Total
---------- ---------- --------- ----------- ---------- ---------- ----------
(In Thousands)

External sales.................. $ 705,536 $ - $1,123,590 $ 537,859 $ 1,484 $ 7 $2,368,476
Internal sales.................. 572,533 107,770 291,927 - - (972,230) -
Depreciation and amortization... 60,331 40,052 75,419 248,414 2,116 37 426,369
Earnings before interest and
taxes.......................... 202,744 (24,323) 171,872 (91,370) 189,289 (21,533) 426,679
Interest expense................ 289,568
Earnings before income taxes.... 137,111
Identifiable assets............. 1,664,300 1,068,228 1,899,951 2,139,748 994,983 (2) 7,767,208

Year Ended December 31, 1999:
--------------------------------
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services Other(a) Items (b) Total
---------- ---------- --------- ----------- ---------- ---------- ----------
(In Thousands)

External sales.................. $ 365,311 $ - $1,064,385 $ 599,105 $ 1,284 $ 2 $2,030,087
Internal sales.................. 546,683 108,445 293,522 - - (948,650) -
Depreciation and amortization... 55,320 39,629 71,717 235,465 1,448 90 403,669
Earnings before interest and
taxes.......................... 219,087 (25,214) 145,603 (20,675) (28,088) (26,252) 264,461
Interest expense................ 294,104
Earnings/(loss) before income
taxes.......................... (29,643)
Identifiable assets............. 1,476,716 1,083,344 1,783,937 2,539,921 1,165,145 (59,171) 7,989,892

Year Ended December 31, 1998:
----------------------------
Eliminating/
Fossil Nuclear Power Monitored Reconciling
Generation Generation Delivery Services Other(a) Items (b) Total
---------- ---------- --------- ----------- ---------- ---------- ----------
(In Thousands)

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 68,297 125,103 2,010 - 288,125
Earnings before interest and
taxes.......................... 144,357 (20,920) 196,398 34,438 (99,608) 12,268 266,933
Interest expense................ 226,120
Earnings before income
taxes.......................... 40,813
Identifiable assets............. 1,360,102 1,121,509 1,788,943 2,489,667 1,269,013 (99,458) 7,929,776

(a) EBIT includes the gain on the sale of the company's investment in a gas
compression company of $91.1 million and the gain on the sale of other
marketable securities of $24.9 million.
(b) Identifiable assets includes eliminating and reclassing balances to
consolidate the monitored services business.
(c) 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.
(d) EBIT includes investment earnings of $21.7 million and the write-off of
international power development costs of $98.9 million.

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:

For the Year Ended December 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------
(In Thousands)
External sales:
North America operations........... $2,262,381 $1,867,081 $1,990,329
International operations........... 106,095 163,006 43,725
---------- ---------- ----------
Total............................ $2,368,476 $2,030,087 $2,034,054
========== ========== ==========

As of December 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------
(In Thousands)

Property, plant and equipment, net:
North America operations........... $3,985,331 $3,881,294 $3,792,645
International operations........... 8,107 8,150 7,271
---------- ---------- ----------
Total............................ $3,993,438 $3,889,444 $3,799,916
========== ========== ==========

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
------- -------- --------- ----------
(In Thousands, Except Per Share Amounts)
2000
----

Sales............................. $481,699 $546,607 $759,562 $580,608
Gross profit...................... 306,760 331,889 395,534 298,461
Net income before
extraordinary gain and
accounting change.............. 39,801 23,565 53,991 (26,307)
Net income........................ 54,483 40,912 60,707 (19,621)
Earnings per share available
for common stock before
extraordinary gain and
accounting change
Basic....................... $ 0.58 $ 0.34 $ 0.78 $ (0.40)
Diluted..................... $ 0.58 $ 0.34 $ 0.77 $ (0.39)
Cash dividend per common share. $ 0.535 $ 0.30 $ 0.30 $ 0.30
Market price per common share:
High............................ $ 18.313 $ 17.813 $ 21.953 $ 25.875
Low............................. $ 15.313 $ 14.688 $ 15.375 $ 20.438

1999
------------------------------------
Sales............................. $460,582 $476,142 $646,740 $446,623
Gross profit...................... 312,655 324,407 424,581 309,498
Net income before
extraordinary gain and
accounting change.............. 19,980 17,722 53,203 (88,351)
Net income........................ 19,980 17,722 53,203 (76,609)
Basic and fully diluted earnings
per share available
for common stock before
extraordinary gain.............. $ 0.30 $ 0.26 $ 0.78 $ (1.32)
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

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
-----------------------------------------------------------

Director (age), year first became a director: Description

Directors (Class I) - Term Expiring in 2OO3

Charles Q. Chandler, IV (47), 1999: Mr. Chandler is Chairman of the Board,
President, and Chief Executive Officer of INTRUST Bank, N.A. (since February
1996) and President of INTRUST Financial Corporation. Mr. Chandler was Executive
Vice President and Vice Chairman of INTRUST Bank, N.A. until 1996. Both
companies are located in Wichita, Kansas. Mr. Chandler is a director of INTRUST
Financial Corporation, the First National Bank of Pratt, Kansas, the Will Rogers
Bank in Oklahoma City, Oklahoma, and the Wesley Medical Center in Wichita,
Kansas, and a trustee for the Kansas State University Endowment Foundation.

John C. Dicus (67), 199O: Mr. Dicus is Chairman of the Board and Chief
Executive Officer of Capitol Federal Savings Bank. Mr. Dicus is also Chairman of
the Board and Chief Executive Officer of Capitol Federal Financial and Capitol
Federal Savings Bank MHC (since march 1999). These companies are located in
Topeka, Kansas. Mr. Dicus is a director for Security Benefit Life Insurance
Company and Columbian National Title Company, and a trustee of the Menniger
Foundation, Stormont-Vail HealthCare, Inc. and the Kansas University
Endowment Association.

Douglas T. Lake (5O), 2OOO: Mr. Lake is Executive Vice President and Chief
Strategic Officer of the company (since September 1998). Prior to that Mr. Lake
was Senior Managing Director at Bear, Stearns & Co. Inc., an investment banking
firm. Mr. Lake is also Chairman of the Board of Protection One, Inc., and a
director of ONEOK, Inc. and Guardian International, Inc.

Owen F. Leonard (6O), 2OOO: Mr. Leonard is President of KL Industries,
Saddle Brook, New Jersey. KL Industries is privately held investment company
which manufactures equipment for the electronics industry. Mr. Leonard is a
director for QuVIS, Inc., Fox Run Holdings, Inc. and Waco Instruments, Inc.

Directors (Class II) - Term Expiring in 2OO1

Gene A. Budig (61), 1999: Dr. Budig is Senior Advisor to the Commissioner
of Baseball in New York, New York (since March 2000). Prior to that time, Dr.
Budig was President of the American League of Professional Baseball Clubs. Dr.
Budig is a director of the Harry S. Truman Library Institute, the Ewing Marion
Kaufman Foundation, the Major League Baseball Hall of Fame and the Media Studies
Center-Freedom Forum.

John C. Nettels, Jr. (44), 2OOO: Mr. Nettels is a Partner with the law firm
of Morrison & Hecker, L.L.P. in Wichita, Kansas.

David C. Wittig (45), 1996: Mr. Wittig is Chairman of the Board, President,
and Chief Executive Officer of the Company (since January 1999, March 1996, and
July 1998, respectively). Prior to that time, Mr. Wittig was Executive Vice
President of Corporate Development. Mr. Wittig is a director of Waco
Instruments, Inc. and Fox Run Holdings, Inc. Mr. Wittig is a trustee of the
Kansas University Endowment Association and Boys Harbor, Inc.

Directors (Class III) - Term Expiring in 2OO2

Frank J. Becker (65), 1992: Mr. Becker is President of Becker Investments,
Inc. in Lawrence, Kansas. Mr. Becker is a director of the Douglas County Bank,
Martin K. Eby Construction Company, and IMA Insurance, Inc., and a trustee of
the Kansas University Endowment Association.

Louis W. Smith (58), 1991: Mr. Smith is President and Chief Executive
Officer (since July 1997) of the Ewing Marion Kauffman Foundation in Kansas
City, Missouri. Mr. Smith is a director of the Ewing Marion Kauffman Foundation,
Sprint Corporation, H & R Block, Inc., and Midwest Research Institute.

See "Executive Officers of the Company" in "Item 1. Business," for the
information relating to the company's Executive Officers as required by Item 10
which is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION
--------------------------------

The information required by Item 11 will be included in an amendment to
this Form 10-K to be filed by us with the SEC.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
------------------------------------------------------------------------

The information required by Item 12 will be included in an amendment to
this Form 10-K to be filed by us with the SEC.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
--------------------------------------------------------

None.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
--------------------------------------------------------------------------

The following financial statements are included herein.

FINANCIAL STATEMENTS
--------------------

Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 2000 and 1999
Consolidated Statements of Income, for the years ended December 31, 2000, 1999
and 1998
Consolidated Statements of Comprehensive Income, for the years ended December
31, 2000, 1999 and 1998
Consolidated Statements of Cash Flows, for the years ended December 31, 2000,
1999 and 1998
Consolidated Statements of Shareholders' Equity, for the years ended December
31, 2000, 1999, and 1998
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 17, 2000 - Announcement of merger agreement
between Public Service Company of New Mexico and Western Resources.

Form 8-K filed November 27, 2000 - Press release announcing that Western
Resources. and KGE filed separate requests with the KCC seeking recovery
of investments in new power plants and higher operating and maintenance
costs.

EXHIBIT INDEX

All exhibits marked "I" are incorporated herein by reference. All
exhibits marked by an asterisk are management contracts or compensatory plans or
arrangements required to be identified by Item 14(a)(3) of Form 10-K.

Description
-----------

2(a) -Agreement and Plan of Restructuring and Merger, dated as of November 8, I
2000 among the Company, Public Service Company of New Mexio, HVOLT
Enterprises, Inc., HVK, Inc. and HVNM, Inc. (filed as Exhibit 99.1 to
the November 17, 2000 Form 8-K)
3(a) -By-laws of the company, as amended March 16, 2000 (filed as
Exhibit 3(a) to December 1999 Form 10-K) 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)
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 (filed as exhibit
3(d) to December 1993 Form 10-K)
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)
3(f) -Certificate of Designations for Preference Stock, 7.58% Series, I
without par value, dated April 8, 1992 (filed as exhibit 3(e)
to December 1993 form 10-K)
3(g) -Certificate of Amendment to Restated Articles of Incorporation I
of the company dated May 8, 1992 (filed as exhibit 3(c) to
December 31, 1994 Form 10-K)
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)
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)
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)
3(k) -Form of Certificate of Designations for 7.5% Convertible Preference Stock I
(filed as Exhibit 99.4 to November 17, 2000 Form 8-K).
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)

100

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(v) -Thirty-Fourth Supplemental Indenture dated June 28, 2000
4(w) -Debt Securities Indenture dated August 1, 1998. I
(filed as Exhibit 4.1 to the June 30, 1998 Form 10-Q)
4(x) -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 Agreements with Messers. Grennan, Koupal, Lake, Terrill,
Wittig and Ms. Sharpe.*
10(c) -A Rail Transportation Agreement among Burlington Northern I
Railroad Company, the Union Pacific Railroad Company and the

101

Company. (filed as Exhibit 10 to the June 1994 Form 10-Q)
10(d) -Agreement between the Company and AMAX Coal West Inc. I
effective March 31, 1993. (filed as Exhibit 10(a) to the
December 31, 1993 Form 10-K)
10(e) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed as Exhibit 10(b) to the
December 31, 1993 Form 10-K)
10(f) -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 I
August 17, 1998.*
10(o) -Form of Change of Control Agreement with officers of the company*
10(p) -Amendment to Outside Directors' Deferred Compensation Plan dated May 17,
2001.*
10(q) -Asset Allocation and Separation Agreement, dated as of November 8, 2000, I
between the Company and Westar Industries, Inc. (filed as Exhibit 99.2
to the November 17, 2000 Form 8-K)
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
21 -Subsidiaries of the Registrant.
23 -Consent of Independent Public Accountants, Arthur Andersen LLP

102

WESTERN RESOURCES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)

Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts(a) Deductions of Period
----------- --------- -------- ----------- ---------- ---------

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 (a).......................... 3,856 - - (2,831) 1,025
Accrued exit fees, change in
estimate, shut-down and severance
costs (b)........................... - 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 (a).......................... 1,025 - - (1,025) -
Accrued exit fees, shut-down
and severance costs (b)............. 22,900 (5,632) - (16,888) 380

Year ended December 31, 2OOO
Allowances deducted from
assets for doubtful accounts........ 35,765 23,690 - (13,639) 45,816
Accrued exit fees, shut-down
and severance costs................. 380 - - - 380

(a) Consists of costs to close duplicate facilities and severance and
compensation benefits.
(b) See Note 17 of Notes to the Consolidated Financial Statements for further
information.

103

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 April 2, 2001 By /s/ DAVID C. WITTIG
------------------- ---------------------------------------
David C. Wittig, Chairman of the Board,
President and Chief Executive Officer

104

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
--------- ----- ----

DAVID C. WITTIG Chairman of the Board, April 2, 2001
---------------------------------- President and Chief
(David C. Wittig) Executive Officer
(Principal Executive Officer)

JAMES A. MARTIN Senior Vice President April 2, 2001
---------------------------------- and Treasurer
(James A. Martin) (Principal Financial and
Accounting Officer)

FRANK J. BECKER Director April 2, 2001
----------------------------------
(Frank J. Becker)

GENE A. BUDIG Director April 2, 2001
----------------------------------
(Gene A. Budig)

CHARLES Q. CHANDLER, IV Director April 2, 2001
----------------------------------
(Charles Q. Chandler, IV)

JOHN C. DICUS Director April 2, 2001
----------------------------------
(John C. Dicus)

DOUGLAS T. LAKE Director April 2, 2001
----------------------------------
(Douglas T. Lake)

OWEN F. LEONARD Director April 2, 2001
----------------------------------
(Owen F. Leonard)

JOHN C. NETTELS, JR. Director April 2, 2001
----------------------------------
(John C. Nettels, Jr.)

LOUIS W. SMITH Director April 2, 2001
----------------------------------
(Louis W. Smith)

105