Western Resources Form10-K

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2000

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-3523

WESTERN RESOURCES, INC.

(Exact name of registrant as specified in its charter)

KANSAS

48-0290150

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

818 KANSAS AVENUE, TOPEKA, KANSAS

66612

(Address of Principal Executive Offices)

(Zip Code)

Registrant's telephone number, including area code 785/575-6300

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $5.00 par value

New York Stock Exchange

(Title of each class)

(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:

Preferred Stock, 4 1/2% Series, $100 par value

(Title of Class)

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 No

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

State the aggregate market value of the voting stock held by nonaffiliates of the registrant. Approximately $1,682,196,624 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

(Class)
(Outstanding at March 19, 2001)

Documents Incorporated by Reference:

Part

Document

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

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

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

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

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

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 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. 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.

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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

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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 herein. See also Item 1. Business, Environmental Matters and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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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.

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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

For the Year Ended December 31,

2000 1999(a) 1998(b) 1997(c) 1996

(In Thousands)

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.

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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.

Strategic Transactions 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. 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 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:

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

(In Thousands)

Fossil Generation:

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:

Rating Agency

Western
Resources'
Mortgage
Bond
Rating

Western
Resources
Unsecured
Debt

KGE's
Mortgage
Bond
Rating

Protection
One's
Senior
Unsecured
Debt

Protection
One's
Senior
Subordinated
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.

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