<PAGE>

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


                                    FORM 10-K

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


                  For the fiscal year ended December 31, 2000
                                            -----------------


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



                                 Commission file number 1-7324
                                                        ------


                         KANSAS GAS AND ELECTRIC COMPANY
             -----------------------------------------------------
             (Exact name of registrant as specified in its charter)

           KANSAS                                              48-1093840
-------------------------------                           --------------------
(State or other jurisdiction of                             (I.R.S.  Employer
incorporation or organization)                             Identification No.)

     P.O. BOX 208, WICHITA, KANSAS                                   67201
----------------------------------------                           ----------
(Address of Principal Executive Offices)                           (Zip Code)

     Registrant's telephone number, including area code 316/261-6611
                                                        ------------

     Securities registered pursuant to Section 12(b) of the Act: None

     Securities registered pursuant to Section 12(g) of the Act: None

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

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

 Common Stock, No par value                           1,000 Shares
----------------------------                 -------------------------------
   (Title of each class)                     (Outstanding at March 30, 2001)

Indicated by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes  x        No
                                              ----          ----

Registrant meets the conditions of General Instruction I(1)(a) and (b) to Form
10-K for certain wholly-owned subsidiaries and is therefore filing an
abbreviated form.
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                        KANSAS GAS AND ELECTRIC COMPANY
                               TABLE OF CONTENTS

                                                                            Page
                                                                            ----

PART I

  Item 1.  Business                                                            4

  Item 2.  Properties                                                         16

  Item 3.  Legal Proceedings                                                  17

  Item 4.  Submission of Matters to a Vote of
             Security Holders                                                 17

PART II

  Item 5.  Market for Registrant's Common Equity and
             Related Stockholder Matters                                      17

  Item 6.  Selected Financial Data                                            17

  Item 7.  Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations                                                       18

  Item 7A. Quantitative and Qualitative Disclosures
             About Market Risk                                                29

  Item 8.  Financial Statements and
             Supplementary Data                                               30

  Item 9.  Changes in and Disagreements with Accountants on
             Accounting and Financial Disclosure                              50

PART III

  Item 10. Directors and Executive Officers of the
             Registrant                                                       50

  Item 11. Executive Compensation                                             51

  Item 12. Security Ownership of Certain Beneficial
             Owners and Management                                            51

  Item 13. Certain Relationships and Related Transactions                     51

PART IV

  Item 14. Exhibits, Financial Statement Schedules and
             Reports on Form 8-K                                              51

  Signatures                                                                  55

                                       2
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                         KANSAS GAS AND ELECTRIC COMPANY


FORWARD-LOOKING STATEMENTS

     Certain matters discussed here and elsewhere in this Annual Report are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect" or words of similar meaning. Forward-looking statements
describe our future plans, objectives, expectations or goals. Such statements
address future events and conditions concerning capital expenditures, earnings,
litigation, rate and other regulatory matters, possible corporate
restructurings, mergers, acquisitions, dispositions, liquidity and capital
resources, compliance with debt covenants, changes in accounting requirements,
interest and dividends, environmental matters, changing weather, nuclear
operations, and the overall economy of our service area. What happens in each
case could vary materially from what we expect because of such things as
electric utility deregulation, including ongoing municipal, state and federal
activities, such as the Wichita municipalization effort; future economic
conditions; legislative and regulatory developments; our competitive markets;
the proposed separation of Western Resources' electric utility businesses
(including us) from Westar Industries and the consummation of the acquisition of
the electric operations of Western Resources (including us) by Public Service
Company of New Mexico; and other circumstances affecting anticipated operations,
sales and costs. See Risk Factors for additional information on these and other
matters.

                                       3
<PAGE>

                                     PART I

ITEM 1.  BUSINESS
-----------------


GENERAL

     Kansas Gas and Electric Company (KGE), the company, we or us, is a rate-
regulated electric utility and wholly-owned subsidiary of Western Resources,
Inc. (Western Resources). We are engaged principally in the generation,
purchase, transmission, distribution and sale of electricity in southeastern
Kansas, including the Wichita metropolitan area. We own 47% of Wolf Creek
Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek
Generating Station (Wolf Creek). Our corporate headquarters are located in
Wichita, Kansas.

     On November 8, 2000, Western Resources entered into an agreement under
which Public Service Company of New Mexico (PNM) will acquire the electric
utility businesses of Western Resources (including us) in a stock-for-stock
transaction. Under the terms of the agreement, both Western Resources and PNM
will become subsidiaries of a new holding company.

     Western Resources can give no assurance as to whether or when the rights
offering will be consummated or whether or when the consummation of the
acquisition of Western Resources by PNM may occur.

ELECTRIC OPERATIONS

General

     We supply electric energy at retail to approximately 291,000 customers in
Kansas. We also supply electric energy at wholesale to the electric distribution
systems of 28 communities. We have contracts for the sale, purchase or exchange
of electricity with other utilities at wholesale.

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

                                    2000      1999      1998
                                  --------  --------  --------
                                          (In Thousands)
 Residential....................  $246,665  $220,645  $237,571
 Commercial.....................   175,686   169,427   170,473
 Industrial.....................   161,693   163,158   167,331
 Wholesale......................    78,596    63,255    50,634
 System Hedging.................    17,660         -         -
 Other..........................    23,690    21,855    22,370
                                  --------  --------  --------
  Total.........................  $703,990  $638,340  $648,379


                                       4
<PAGE>

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

                                    2000      1999      1998
                                  --------  --------  --------
                                         (Thousands of MWH)
 Residential....................     2,950     2,601     2,784
 Commercial.....................     2,544     2,413     2,383
 Industrial.....................     3,561     3,548     3,569
 Wholesale......................     2,407     1,832     1,541
 Other..........................        45        45        45
                                  --------  --------  --------
  Total.........................    11,507    10,439    10,322

Fossil Fuel Generation

     Capacity: The aggregate net generating capacity of our system is presently
2,615 megawatts (MW). The system comprises interests in twelve fossil-fuel steam
generating units, one nuclear generating unit (47% interest), one diesel
generator and two wind turbines, located at six generating stations.

     Our aggregate 2000 peak system net load occurred on August 24, 2000, and
amounted to 2,107 MW. Our net generating capacity combined with firm purchases
and sales, provided a capacity margin of approximately 14% above system peak
responsibility at the time of the peak. Our all time peak system net load
occurred on August 11, 1999 and amounted to 2,111 MW.

     We are a member of the Southwest Power Pool (SPP). SPP's responsibility is
to maintain system reliability on a regional basis and is working with us and
other members to become an RTO. The region encompasses areas within the eight
states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas,
and Mississippi. We are also a member of the SPP transmission tariff along with
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.

     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 and energy
sales and energy exchanges.

     We have an agreement with Midwest Energy, Inc. to provide it with peaking
capacity of 60 MW through May 2008.

     Future Capacity:  We forecast that we will need additional capacity of
approximately 150 MW by 2005 to serve our customers' expected electricity needs.
We will determine the methods for supplying this estimated additional energy at
a future date.  (See Item 7.  Management's Discussion and Analysis, Liquidity
and Capital Resources).

     Fuel Mix: Coal-fired units comprise 1,126 MW of our total 2,615 MW of
generating capacity and the nuclear unit provides 550 MW of capacity. Of the
remaining 939 MW of generating capacity, units that can burn either natural gas
or oil account for 936 MW, one unit which burns only diesel fuel accounts for 3
MW, and wind turbines account for approximately 1 MW. (See Item 2. Properties).

     During 2000, coal was used to produce 58% of our electricity. Nuclear fuel
produced 31% and the remainder was produced from natural gas, oil, or diesel
fuel. Our fuel mix fluctuates with the operation of the nuclear-powered Wolf
Creek (as discussed below under Nuclear Generation), fuel costs, plant
availability and power available on the wholesale market.

                                       5
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     Coal: The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 445 MW (our 20% share). Western Resources, the operator of
JEC, and 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 (our 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 and 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.

     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 failed 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 and Neosho Energy Centers. Natural gas for these generating stations
is purchased in the short-term spot market which supplies the system with a
flexible natural gas supply necessary to meet operational needs.

                                       6
<PAGE>

     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 agreement that serves Gordon Evans and Murray
Gill extends 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 diesel generator. 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 and Western Resources jointly 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 below 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 $1.03 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).


                                   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

                                       7
<PAGE>

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

                                       8
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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 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 8 of the
Notes to Consolidated Financial Statements.

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. 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.

     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 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 Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation."

                                       9
<PAGE>

     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 in the electric utility
industry and the 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 also subject to the
jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations
and safety.

     On November 27, 2000, we and Western Resources filed applications with the
KCC for a change in retail rates which included a cost allocation study and
separate cost of service studies for KGE and Western Resources' KPL division. We
and Western Resources 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 the 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 Regulation and Rates is discussed in
Notes 1 and 3 of the 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.

                                       10
<PAGE>

     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 8 of the Notes to Consolidated Financial Statements.

SEGMENT INFORMATION

     Financial information with respect to business segments is set forth in
Note 15 of the Notes to Consolidated Financial Statements.

EMPLOYEES

     All employees we utilize are provided by Western Resources. Western
Resources' contract with the International Brotherhood of Electrical Workers was
renewed on January 20, 2000, and will be due for renewal July 1, 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,
such as us. Like other businesses, we are susceptible to macroeconomic downturns
in the United States or abroad that may affect the general economic

                                       11
<PAGE>

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 us,
alleging improper affiliate transactions between Western Resources' KPL division
and us. The City of Wichita asked that FERC equalize the generation costs
between us 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.

                                       12
<PAGE>

     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 us 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 our Wichita electric facilities, the City of Wichita would
be required to purchase our 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 our retail electric utility business in Wichita. We 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.

     Our 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, we 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 54% 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. 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. The increased expenses or loss of
revenues associated with this could be material and adverse to our 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 a portion of our
anticipated cost of coal which is indexed to or purchased on the spot market.

                                       13
<PAGE>

     In an effort to mitigate fuel commodity price market risk, we and Western
Resources jointly use hedging agreements 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 agreements we may have. Increases in purchased power and fossil
fuel prices could have a material adverse effect on our results of operation.

                                       14
<PAGE>

EXECUTIVE OFFICERS OF THE COMPANY

<TABLE>
<CAPTION>
                                                    Other Offices or Positions
Name                Age      Present Office         Held During Past Five Years
----                ---      --------------         ---------------------------
<S>                 <C>      <C>                    <C>
Ronald W. Holt      54       Chairman of the Board  Assistant Secretary
                             and President (since   (January 1998 to January
                             January 2000)          2000), Kansas Gas and
                                                    Electric Company. Executive Director, Southern Region (since
                                                    January 2000); Senior Director, Corporate and Community
                                                    Affairs (January 1999 to January 2000); Director, Community
                                                    and Support Services (September 1995 to December 1998),
                                                    Western Resources, Inc.

Richard D. Terrill   46      Secretary, Treasurer   Executive Vice President,
                             and General Counsel    General Counsel and
                                                    Corporate Secretary (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), Western Resources, Inc.
</TABLE>

     Executive officers serve at the pleasure of the board of directors. There
are no family relationships between the officers, nor any arrangements or
understandings between any officer and other persons pursuant to which he was
appointed as an officer.

                                       15
<PAGE>

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

     We own or lease and operate an electric generation, transmission, and
distribution system in Kansas.


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

    Gordon Evans Energy Center:
         Steam Turbines                 1        1961    Gas--Oil     151
                                        2        1967    Gas--Oil     383
         Diesel Generator               1        1969     Diesel        3

    Jeffrey Energy Center (20%) (a):
         Steam Turbines                 1        1978      Coal       149
                                        2        1980      Coal       148
                                        3        1983      Coal       148
         Wind Turbines                  1        1999       -         (c)
                                        2        1999       -         (c)

    La Cygne Station (50%):
         Steam Turbines                 1 (a)    1973      Coal       344
                                        2 (b)    1977      Coal       337

    Murray Gill Energy Center:
         Steam Turbines                 1        1952    Gas--Oil      43
                                        2        1954    Gas--Oil      74
                                        3        1956    Gas--Oil     112
                                        4        1959    Gas--Oil     106

    Neosho Energy Center:
         Steam Turbine                  3        1954    Gas--Oil      67

    Wolf Creek Generating
    Station (47%):
         Nuclear                        1 (a)    1985     Uranium     550
                                                                    -----

         Total                                                      2,615
                                                                    =====

     (a)  We jointly own Jeffrey Energy Center (20%), La Cygne 1 generating unit
          (50%) and Wolf Creek Generating Station (47%). Western Resources
          jointly owns 64% of Jeffrey Energy Center.

     (b)  In 1987, KGE sold and leased back its 50% individual interest in the
          La Cygne 2 generating unit.

     (c)  Our share of each turbine is less than 0.5 MW.

     We own approximately 2,500 miles of transmission lines, approximately 9,300
miles of overhead distribution lines, and approximately 1,700 miles of
underground distribution lines.

FINANCING

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

                                       16
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS
--------------------------

     Information on our legal proceedings is set forth in Notes 3, 8, and 9 of
Notes to Consolidated Financial Statements. See also Item 1. Business,
Environmental Matters, and Regulation and Rates.


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

     Information required by Item 4 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.

                                 PART II


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

     All of our common stock is owned by Western Resources and is not traded on
an established public trading market.


ITEM 6.  SELECTED FINANCIAL DATA
--------------------------------
<TABLE>
<CAPTION>
                                      2000        1999        1998         1997        1996
                                   ----------  ----------  ----------    ---------  ----------
                                                          (In Thousands)
Income Statement Data:
<S>                                <C>         <C>         <C>            <C>        <C>
Sales. . . . . . . . . . . . . .   $  703,990  $  638,340  $  648,379     $614,445   $  654,570
Net income . . . . . . . . . . .       86,708      84,261     103,765       52,128       96,274



Balance Sheet Data:
Total assets . . . . . . . . . .   $2,988,573  $2,989,710  $3,057,971   $3,117,108   $3,318,887
Long-term debt (net) . . . . . .      684,366     684,271     684,167      684,128      684,068

</TABLE>

                                       17
<PAGE>

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," "we," "us," or "our" or similar words are to Kansas
Gas and Electric Company.

     In Management's Discussion and Analysis we explain the general financial
condition, significant annual changes and the operating results for the company.
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, Western Resources entered into an agreement under
which Public Service Company of New Mexico (PNM) will acquire the electric
utility businesses of Western Resources (including us) in a stock-for-stock
transaction. Under the terms of the agreement, both Western Resources and PNM
will become subsidiaries of a new holding company.

     Western Resources can give no assurance as to whether or when the
consummation of the acquisition of Western Resources by PNM may occur.

OPERATING RESULTS

     We supply electric energy at retail to approximately 291,000 customers in
Kansas. We also supply electric energy to at wholesale to the electric
distribution systems of 28 communities. We have contracts for the sale, purchase
or exchange of electricity with other utilities at wholesale.

     In addition, we engage in system hedging transactions which 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

                                       18
<PAGE>

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 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 system hedging transactions

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

                                        2000             1999            1998
                                      --------         --------        --------
                                                     (In Thousands)
 Residential ................         $246,665         $220,645        $237,571
 Commercial .................          175,686          169,427         170,473
 Industrial .................          161,693          163,158         167,331
 Other ......................           23,690           21,855          22,370
 Wholesale ..................           78,596           63,255          50,634
 System Hedging .............           17,660             -               -
                                      --------         --------        --------
  Total .....................         $703,990         $638,340        $648,379
                                      ========         ========        ========

     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
                        ----------  ----------   --------
      Residential.....   2,950,212   2,601,308     13.4 %
      Commercial......   2,544,435   2,413,126      5.4 %
      Industrial......   3,560,916   3,548,216      0.4 %
      Other...........      44,567      44,753     (0.4)%
                        ----------  ----------     -----
        Total Retail..   9,100,130   8,607,403      5.7 %
      Wholesale.......   2,406,950   1,831,943     31.4 %
                        ----------  ----------     -----
        Total.........  11,507,080  10,439,346     10.2 %
                        ==========  ==========     =====


                           1999        1998      % Change
                        ----------  ----------   --------
      Residential.....   2,601,308   2,783,998     (6.6)%
      Commercial......   2,413,126   2,383,197      1.3 %
      Industrial......   3,548,216   3,568,948     (0.6)%
      Other...........      44,753      45,485     (1.6)%
                        ----------  ----------     -----
        Total Retail..   8,607,403   8,781,628     (2.0)%
      Wholesale.......   1,831,943   1,540,546     18.9 %
                        ----------  ----------     -----
        Total.........  10,439,346  10,322,174      1.1 %
                        ==========  ==========     =====

          2OOO compared to 1999: Net income increased $2.4 million and total
gross profit increased $12.6 million, or two percent. These increases are due
primarily to a 13% increase in residential sales volumes and a 31% increase in
wholesale sales volumes. The increase in residential sales is primarily due to
increased demand caused by warm weather. Cooling-degree

                                       19
<PAGE>

days increased by 27%. The increase in wholesale sales volumes was primarily due
to increased wholesale market opportunities. Items included in energy cost of
sales are fuel expense and purchased power expense (electricity we purchase from
others for resale).

     Partially offsetting the higher sales was an increase of $53.0 million in
cost of sales primarily due to increased fuel and purchased power expenses of
approximately $25.5 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: Net income decreased $19.5 million and total gross
profit decreased $9.4 million, or 2%. Total sales decreased $10 million. Our
service territories averaged 27% fewer cooling degree days in 1999, lowering our
retail sales by $12.7 million. The implementation of our electric rate decreases
on June 1, 1999, and June 1, 1998, further decreased our retail sales $10
million. Increased wholesale sales of $12.6 million partially offset the retail
sales decreases. Due to warmer than normal weather throughout the Midwest in
July 1999 and increased availability of our coal-fired generation stations, we
were able to sell more electricity to wholesale customers in 1999.

     Cost of sales decreased approximately $0.7 million primarily due to lower
purchased power expense. We purchased less power to serve our retail customers
because of milder weather which reduced demand.

BUSINESS SEGMENTS

     We have defined two business segments, electric operations and nuclear
generation, based on how management currently evaluates our business. Our
business segments are based on differences in products and services, production
processes and management responsibility.

     We manage our 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 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 two electric utility
business segments.

                                       20
<PAGE>

                                         For the years ended December 31,
                                         --------------------------------
                                           2000        1999        1998
                                         --------    --------    --------
 Electric Operations:                          (Dollars in Thousands)
   External sales.................       $703,990    $638,340    $648,379
   Depreciation and amortization..         64,242      61,531      59,239
   EBIT...........................        194,611     193,980     219,014

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

Electric Operations

     External sales include power produced for sale to wholesale and retail
customers and the amounts associated with the system hedging transactions
discussed above.

     2OOO compared to 1999: External sales increased $65.7 million primarily due
to 13% higher residential sales volumes and 31% higher wholesale sales volumes.
Approximately $17.7 million in system hedging transactions also increased
external sales.

     While sales increased $65.7 million or 10%, EBIT increased only $0.6
million primarily due to higher cost of sales of $53.6 million. Cost of sales
was higher primarily due to increased fuel and purchased power expenses of
approximately $44.3 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 $9.2
million (despite an 11.2% reduction in MMBtu of gas burned). Our average natural
gas price increased 45% during the year compared to 1999. Additionally, coal
costs increased by $8.2 million primarily due to increasing the quantities of
coal burned in our efforts to minimize gas costs and cost of oil increased $3.3
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.

     Operation and maintenance expenses increased $7.0 million primarily due to
our increased sales.

     Other expense increased $3.5 million primarily due to transaction costs
associated with the sale of our accounts receivable in a financing transaction
and because of a gain recorded in 1999 on the disposition of property.

     1999 compared to 1998: External sales decreased $10 million. This decrease
is primarily due to decreased retail sales volumes as a result of milder
temperatures in 1999 and the implementation of our rate decreases. Increased
wholesale sales partially offset these decreases. In 1999 and 1998, the
wholesale power market experienced extreme volatility in prices and supply.

     EBIT decreased $25 million primarily because of lower gross profit,
increased operating expenses and lower other income. Operating expenses were
higher primarily because of higher selling, general and administrative expense
related to increased expenses for salaries and employee benefits. The restarting
of our Neosho generation station, and a boiler outage at our Gordon Evans
generation station also contributed to our increased operating expenses.

     Other income (expense) decreased $11.8 million. No significant corporate-
owned life insurance proceeds were received in 1999. In 1998 we received $13.7
million in proceeds pursuant to our corporate-owned life insurance policies.

                                       21
<PAGE>

Nuclear Generation

     Nuclear generation has only internal sales because it provides all of its
power to its co-owners: Kansas City Power and Light Company, Kansas Electric
Power Cooperative, Inc., and us. We own 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), the operating company for Wolf Creek Generating Station
(Wolf Creek). Internal sales are priced at an internal transfer price that
Nuclear Generation charges to Electric Operations. The amounts above are our 47%
share of Wolf Creek's operating results.

     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.

     2OOO 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 outages.


OTHER

Income Taxes

     2OOO compared to 1999: Total income tax expense included in the Statements
of Income reflects the Federal statutory rate of 35%. The Federal statutory rate
produces effective income tax rates of 28.2% for 2000 and 29.3% for 1999. The
effective income tax rates are lower than the Federal statutory rate due to
differences, such as the amortization of investment tax credits and benefits
from corporate-owned life insurance.

     1999 compared to 1998: Our effective income tax rates are affected by the
receipt of proceeds from our corporate-owned life insurance policies and the
amortization of prior years' investment tax credits. Income taxes decreased $10
million due to lower pre-tax income. Pre-tax income was lower primarily because
of higher operating expenses and the absence of death proceeds received from
corporate-owned life insurance policies.


LIQUIDITY AND CAPITAL RESOURCES

Overview

     Most of our cash requirements consist of capital expenditures and
maintenance costs designed to improve and maintain facilities which provide
electric service and meet future customer service requirements. Our ability to
provide the cash or debt to fund our capital expenditures depends upon many
things, including available resources, our financial condition and current
market conditions.

     Funds are available to us from the sale of securities we register for sale
with the

                                       22
<PAGE>

SEC. As of December 31, 2000, $50 million of KGE first mortgage bonds were
registered.

     Our mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless our 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 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
first mortgage bonds could be issued under the most restrictive tests in the
mortgage.

     Our internally generated cash is generally sufficient to fund operations
and debt service payments. We do not maintain independent short-term credit
facilities and rely on Western Resources for short-term cash needs. If Western
Resources is unable to borrow under its credit facilities, we could have a short
term liquidity issue which could require us to obtain a credit facility for our
short-term cash needs and which could result in higher borrowing costs.

     On June 28, 2000, Western Resources entered into a $600 million, multi-year
term loan that replaced two revolving credit facilities which matured on June
30, 2000. The term loan is secured by first mortgage bonds of the company and
Western Resources and has a final maturity date of March 17, 2003.

     Western Resources also has an arrangement with certain banks to provide a
revolving credit facility on a committed basis totaling $500 million. The
facility is secured by first mortgage bonds of the company and Western Resources
and matures on March 17, 2003.

Sale of Accounts Receivable

          On July 28, 2000, we and Western Resources 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 Western Resources. 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. As of December 31, 2000, net proceeds of
$115 million were received by Western Resources, of which approximately $39.1
million were received by us.

Cash Flows From Operating Activities

     Cash from operating activities decreased 20.8%, or $43.7 million. The
decrease is primarily attributable to changes in working capital requirements at
year end due to higher sales in December 2000 as compared to December 1999.

Cash Flows Used in Financing Activities

     We used $69.9 million less cash for financing activities in 2000 primarily
due to the net proceeds received from the sale of our accounts receivable
discussed above.

                                       23
<PAGE>

     Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and
Moody's Investors Service (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.

     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 the electric utility businesses of
Western Resources, including us, 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.

     The current ratings with these agencies are as follows:


                            Western
                           Resources'       Western       KGE's
                            Mortgage       Resources'    Mortgage
            Rating            Bond         Unsecured       Bond
            Agency           Rating          Debt         Rating
            ------         ----------      ---------      ------
            S&P               BBB-            BB-          BB+
            Fitch             BB+             BB           BB+
            Moody's           Ba1             Ba2          Ba1

Future Cash Requirements

     We believe that internally generated funds and borrowings from Western
Resources will be sufficient to meet our operating and capital expenditure
requirements and debt service payments through the year 2003. Uncertainties
affecting our ability to meet these requirements include the factors affecting
sales described above, the effect of inflation on operating expenses, regulatory
actions, municipalization efforts by the City of Wichita, the pending rate
applications and compliance with future environmental regulations.

     We forecast that we will need additional capacity of approximately 150 MW
by 2005 to serve our customers' expected electricity needs. We will determine
the methods for supplying this additional energy at a future date.

     In 2003, $135 million of our bonds will mature and $65 million of our bonds
will mature in 2005.

     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 and to pay dividends to Western Resources
on our common stock.

     Capital expenditures for 2000 and anticipated capital expenditures for 2001
through 2003 are as follows:

                                       24
<PAGE>

                           Electric    Nuclear
                          Operations  Generation   Total
                          ----------  ----------  --------
                                   (In Thousands)
             2000.......   $56,800     $25,900    $82,700
             2001.......    60,600      16,700     77,300
             2002.......    60,200      19,900     80,100
             2003.......    59,800      29,400     89,200

     These estimates are prepared for planning purposes and will be revised from
time to time. Actual expenditures are likely to differ from our estimates.

Capital Structure

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

                                      2000   1999
                                      ----   ----
              Shareholders' Equity..    62%    62%
              Long-term Debt........    38     38
                                      ----   ----
              Total.................   100%   100%


OTHER INFORMATION

     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 us
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 our
Wichita electric facilities, the City of Wichita would be required to purchase
our 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 our retail
electric utility business in Wichita. We 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.

     Our 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, we will continue to have the right to serve
the customers in Wichita following the expiration of the franchise, assuming the
system is not municipalized. Customer within the Wichita metropolitan area
account for approximately 54% of our total energy sales.

     KCC Rate Proceedings: On November 27, 2000, we and Western Resources filed
applications with the KCC for a change in retail rates which included a cost
allocation study and separate cost of service studies for Western Resources' KPL
division and us. We and Western Resources 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
the KPL division and $58.0 million for us 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

                                       25
<PAGE>

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.

     FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with FERC against us alleging improper affiliate transactions between Western
Resources' KPL division and us. The City of Wichita asked that FERC equalize the
generation costs between us and KPL, 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 caused many states to 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, wholesale electric sales represented
approximately 11% 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 to 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 are approximately 5% 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

                                       26
<PAGE>

Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to
operations. Reasons for discontinuing SFAS 71 accounting treatment include
increasing competition that restricts our ability to charge prices needed to
recover costs already incurred and a significant change by regulators from a
cost-based rate regulation to another form of rate regulation 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 that are currently subject to recovery in future rates of
approximately $225.5 million. Of this amount, $151.8 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 and include
coal contract settlement costs, deferred plant costs and debt issuance 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. We presently own 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 income will be lower than our historical net 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 shutdown 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

                                       27
<PAGE>

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 8 of the Notes to Consolidated Financial
Statements).

Market Risk Disclosure

     Market Price Risk: We are exposed to market risk, including market changes,
changes in commodity prices and interest rates.

     Commodity Price Exposure: We are exposed to commodity price changes and 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 $1.2 million of
operating income. Due to the volatility of the power market, past prices cannot
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 $1.03 per MMBtu. The higher natural gas
prices increased our total cost of gas purchased during 2000 by approximately
$9.2 million although we decreased the quantity burned by 1.6 million MMBtu. If
we were to have a similar increase from 2000 to 2001, we would have an exposure
of approximately $18.5 million of operating income.

     Based on MMBtu's of natural gas and fuel oil burned during 2000, we had
exposure of approximately $5.0 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 cannot 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 the 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.

                                       28
<PAGE>

     In an effort to mitigate fuel commodity price market risk, we and Western
Resources jointly 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 enter into.

     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
customers' 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.

     Interest Rate Exposure: We have approximately $46.4 million of variable
rate debt as of 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 $0.3 million after tax.

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 $21 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.

                                       29
<PAGE>

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

TABLE OF CONTENTS                                                          PAGE

Report of Independent Public Accountants                                     31

Financial Statements:

 Consolidated Balance Sheets, December 31, 2000 and 1999                     32
 Consolidated Statements of Income for the years ended
  December 31, 2000, 1999 and 1998                                           33
 Consolidated Statements of Cash Flows for the years ended
  December 31, 2000, 1999 and 1998                                           34
 Consolidated Statements of Shareholder's Equity for the
  years ended December 31, 2000, 1999 and 1998                               35
 Notes to Consolidated Financial Statements                                  36

SCHEDULES OMITTED

     The following schedules are omitted because of the absence of the
conditions under which they are required or the information is included in the
financial statements and schedules presented:

     I, II, III, IV, and V.

                                       30
<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Board of Directors of
Kansas Gas and Electric Company:

     We have audited the accompanying consolidated balance sheets of Kansas Gas
and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as
of December 31, 2000 and 1999, and the related consolidated statements of
income, cash flows and shareholder's equity for each of the three years in the
period ended December 31, 2000. These financial statements are the
responsibility of the company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audits to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 2000 and 1999, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States.

ARTHUR ANDERSEN LLP

Kansas City, Missouri,
March 9, 2001

                                       31
<PAGE>

                         KANSAS GAS AND ELECTRIC COMPANY
                           CONSOLIDATED BALANCE SHEETS
                             (Dollars in Thousands)

                                                           December 31,
                                                      ----------------------
                                                         2000        1999
                                                      ----------  ----------
ASSETS
------

CURRENT ASSETS:
  Cash and cash equivalents.........................  $    7,101  $       37
  Accounts receivable (net).........................      87,921      67,751
  Receivable from affiliates........................      53,107      37,087
  Inventories and supplies (net)....................      46,388      46,179
  Prepaid expenses and other........................      21,991      19,103
                                                      ----------  ----------
    Total Current Assets............................     216,508     170,157
                                                      ----------  ----------

PROPERTY, PLANT AND EQUIPMENT (NET).................   2,450,061   2,480,696
                                                      ----------  ----------

OTHER ASSETS:
  Regulatory assets.................................     225,479     251,518
  Other.............................................      96,525      87,339
                                                      ----------  ----------
    Total Other Assets..............................     322,004     338,857
                                                      ----------  ----------

TOTAL ASSETS........................................  $2,988,573  $2,989,710
                                                      ==========  ==========


LIABILITIES AND SHAREHOLDER'S EQUITY
------------------------------------

CURRENT LIABILITIES:
  Accounts payable..................................  $   73,562  $   76,995
  Accrued liabilities...............................      28,245      28,052
  Other.............................................      10,396       3,375
                                                      ----------  ----------
    Total Current Liabilities.......................     112,203     108,422
                                                      ----------  ----------

LONG-TERM LIABILITIES:
  Long-term debt (net)..............................     684,366     684,271
  Deferred income taxes and investment tax credits..     736,436     774,961
  Deferred gain from sale-leaseback.................     186,294     198,123
  Other.............................................     160,061     101,428
                                                      ----------  ----------
    Total Long-term Liabilities.....................   1,767,157   1,758,783
                                                      ----------  ----------

COMMITMENTS AND CONTINGENCIES

SHAREHOLDER'S EQUITY:
  Common stock, without par value,
       authorized and issued 1,000 shares...........   1,065,634   1,065,634
  Retained earnings.................................      43,579      56,871
                                                      ----------  ----------
    Total Shareholder's Equity......................   1,109,213   1,122,505
                                                      ----------  ----------

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY..........  $2,988,573  $2,989,710
                                                      ==========  ==========


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

                                       32
<PAGE>

                        KANSAS GAS AND ELECTRIC COMPANY
                       CONSOLIDATED STATEMENTS OF INCOME
                            (Dollars in Thousands)
<TABLE>
<CAPTION>

                                                        Year Ended December 31,
                                                    --------------------------------
                                                      2000        1999        1998
                                                    --------    --------    --------
<S>                                                <C>         <C>         <C>
SALES............................................   $703,990    $638,340    $648,379

COST OF SALES....................................    170,672     117,647     118,322
                                                    --------    --------    --------

GROSS PROFIT.....................................    533,318     520,693     530,057
                                                    --------    --------    --------

OPERATING EXPENSES:
  Operating and maintenance expense..............    189,456     181,784     181,540
  Depreciation and amortization..................    104,294     101,160      98,822
  Selling, general and administrative expense....     62,710      65,900      60,277
                                                    --------    --------    --------
      Total Operating Expenses...................    356,460     348,844     340,639
                                                    --------    --------    --------

INCOME FROM OPERATIONS...........................    176,858     171,849     189,418

OTHER INCOME (EXPENSE)...........................     (6,570)     (3,083)      8,676
                                                    --------    --------    --------

EARNINGS BEFORE INTEREST AND TAXES...............    170,288     168,766     198,094
                                                    --------    --------    --------

INTEREST EXPENSE:
  Interest expense on long-term debt.............     46,241      45,920      45,990
  Interest expense on short-term debt and other..      3,364       3,598       3,368
                                                    --------    --------    --------
      Total Interest Expense.....................     49,605      49,518      49,358
                                                    --------    --------    --------

EARNINGS BEFORE INCOME TAXES.....................    120,683     119,248     148,736

INCOME TAXES.....................................     33,975      34,987      44,971
                                                    --------    --------    --------

NET INCOME.......................................   $ 86,708    $ 84,261    $103,765
                                                    ========    ========    ========

</TABLE>

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

                                       33
<PAGE>

                         KANSAS GAS AND ELECTRIC COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                             (Dollars in Thousands)

<TABLE>
<CAPTION>

                                                              Year Ended December 31,
                                                        ---------------------------------
                                                           2000        1999        1998
                                                        ---------   ---------   ---------
<S>                                                     <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income..........................................  $  86,708   $  84,261   $ 103,765
  Depreciation and amortization.......................    104,294     101,160      98,822
  Amortization of nuclear fuel........................     14,971      15,464      18,694
  Amortization of deferred gain from sale-leaseback...    (11,829)    (11,828)    (11,828)
  Changes in working capital items:
    Accounts receivable (net).........................    (17,453)     (1,238)        141
    Inventories and supplies (net)....................       (209)     (3,059)     (2,102)
    Prepaid expenses and other........................     (2,888)     (4,006)      2,068
    Accounts payable..................................     (3,433)     (1,515)     (3,476)
    Accrued liabilities...............................        193      (6,147)      1,454
    Other.............................................      7,021         596       1,988
  Changes in other assets and liabilities.............    (10,645)     36,703       4,823
                                                        ---------   ---------   ---------
      Net cash flows from operating activities........    166,730     210,391     214,349
                                                        ---------   ---------   ---------

CASH FLOWS USED IN INVESTING ACTIVITIES:
  Additions to property, plant and equipment (net)....    (82,716)    (63,574)    (77,419)
                                                        ---------   ---------   ---------
      Net cash flows (used in) investing activities...    (82,716)    (63,574)    (77,419)
                                                        ---------   ---------   ---------

CASH FLOWS (USED IN) FINANCING ACTIVITIES:
  Short-term debt (net)...............................       -           -        (45,000)
  Net proceeds from accounts receivable sale..........     39,100        -           -
  Advances to parent company (net)....................    (16,020)    (46,801)      8,153
  Retirements of long-term debt.......................        (30)        (20)        (85)
  Dividends to parent company.........................   (100,000)   (100,000)   (100,000)
                                                        ---------   ---------   ---------
     Net cash flows (used in) financing activities....    (76,950)   (146,821)   (136,932)
                                                        ---------   ---------   ---------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..      7,064          (4)         (2)

CASH AND CASH EQUIVALENTS:
  Beginning of period.................................         37          41          43
                                                        ---------   ---------   ---------
  End of period.......................................  $   7,101          37   $      41
                                                        =========   =========   =========

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
 Interest on financing activities (net of amount
  capitalized) .......................................  $  85,308   $  77,668   $  75,611

 Income taxes ........................................     22,200        -         37,520

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

</TABLE>

                                       34
<PAGE>

                         KANSAS GAS AND ELECTRIC COMPANY
                 CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
                             (Dollars in Thousands)


                                         Year Ended December 31,
                                  ------------------------------------
                                     2000         1999         1998
                                  ----------   ----------   ----------
Common Stock....................  $1,065,634   $1,065,634   $1,065,634
                                  ----------   ----------   ----------

Retained Earnings:
   Beginning balance............      56,871       72,610       68,845
   Net income...................      86,708       84,261      103,765
   Dividends to parent company..    (100,000)    (100,000)    (100,000)
                                  ----------   ----------   ----------
   Ending balance...............      43,579       56,871       72,610
                                  ----------   ----------   ----------

Total Shareholder's Equity......  $1,109,213   $1,122,505   $1,138,244
                                  ==========   ==========   ==========

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

                                       35
<PAGE>

                         KANSAS GAS AND ELECTRIC COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Description of Business: The company is a rate-regulated electric utility
and wholly owned subsidiary of Western Resources. The company is engaged
principally in the production, purchase, transmission, distribution, and sale of
electricity and serves approximately 291,000 electric customers in southeastern
Kansas. The company has no employees. All employees the company utilizes are
provided by the company's parent, Western Resources, which allocates costs to
the company.

     The company owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC),
the operating company for Wolf Creek Generating Station (Wolf Creek). The
company records its proportionate share of all transactions of WCNOC as it does
other jointly owned facilities.

     The company prepares its financial statements in conformity with accounting
principles generally accepted in the United States. The accounting and rates of
the company are subject to requirements of the Kansas Corporation Commission
(KCC) and the Federal Energy Regulatory Commission (FERC). The financial
statements require management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, to disclose contingent assets and
liabilities at the balance sheet dates, and to report amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

     Regulatory Accounting: The company currently applies accounting standards
for its rate regulated electric business that recognize the economic effects of
rate regulation in accordance with Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS 71)
and, accordingly, has recorded regulatory assets and liabilities when required
by a regulatory order or when it is probable, based on regulatory precedent,
that future rates will allow for recovery of a regulatory asset.

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

     Property, Plant and Equipment: Property, plant and equipment is stated at
cost. For utility plant, cost includes contracted services, direct labor and
materials, indirect charges for engineering, supervision, general and
administrative costs and an allowance for funds used during construction
(AFUDC). AFUDC represents the cost of borrowed funds used to finance
construction projects. The AFUDC rate was 7.45% for 2000, 6.00% for 1999 and
6.00% for 1998. The cost of additions to utility plant and replacement units of
property are capitalized. Interest capitalized into construction in progress was
$1.0 million in 2000, $1.0 million in 1999 and $1.1 million in 1998.

     Maintenance costs and replacement of minor items of property are charged to
expense as incurred. Incremental costs incurred during scheduled Wolf Creek
Generating Station refueling and maintenance outages are deferred and amortized
monthly over the unit's operating cycle, normally about 18 months. When units of
depreciable property are retired, the original cost and removal cost, less
salvage value, are charged to accumulated depreciation.

                                       36
<PAGE>

     In accordance with regulatory decisions made by the KCC, the acquisition
premium of approximately $801 million resulting from Western Resources'
acquisition of KGE in 1992 is being amortized over 40 years. The acquisition
premium is classified as electric plant in service. Accumulated amortization
totaled $108.2 million as of December 31, 2000 and $88.1 million as of December
31, 1999.

     Depreciation: Utility plant is depreciated on the straight-line method at
rates approved by regulatory authorities. Utility plant is depreciated on an
average annual composite basis using group rates that approximated 2.81% during
2000, 2.76% during 1999, and 2.75% during 1998. The company periodically
evaluates its depreciation rates considering the past and expected future
experience in the operation of its facilities.

     Inventories and Supplies:  Inventories and supplies for the company's
utility business are stated at average cost.

     Nuclear Fuel: The cost of nuclear fuel in process of refinement,
conversion, enrichment, and fabrication is recorded as an asset at original cost
and is amortized to cost of sales based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel in
the reactor was $18.6 million at December 31, 2000, and $29.3 million at
December 31, 1999.

     Regulatory Assets and Liabilities: Regulatory assets represent probable
future revenue associated with certain costs that will be recovered from
customers through the ratemaking process. The company has recorded these
regulatory assets in accordance with SFAS 71. If the company were required to
terminate application of SFAS 71 for all of its regulated operations, the
company would have to record the amounts of all regulatory assets and
liabilities in its Statements of Income at that time. The company's earnings
would be reduced by the total amount in the table below, net of applicable
income taxes. Regulatory assets reflected in the financial statements are as
follows:


                                         As of December 31,
                                         ------------------
                                           2000      1999
                                         --------  --------
                                           (In Thousands)
             Recoverable income taxes..  $151,841  $172,335
             Debt issuance costs.......    34,215    37,158
             Deferred plant costs......    29,921    30,306
             Other regulatory assets...     9,502    11,719
                                         --------  --------
              Total regulatory assets..  $225,479  $251,518
                                         ========  ========

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

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

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


                                       37
<PAGE>

     The company expects to recover all of the above regulatory assets in rates
charged to customers. A return is allowed on deferred plant costs and coal
contract settlement costs and approximately $16.2 million of debt issuance
costs.

     Sales Recognition: Sales are recognized as services are rendered and
include estimated amounts for energy delivered but unbilled at the end of each
year. Unbilled sales are recorded as a component of accounts receivable (net)
and amounted to $23.4 million at December 31, 1999. During 2000, the company
sold its accounts receivable, including amounts related to unbilled sales.

     Income Taxes: Deferred tax assets and liabilities are recognized for
temporary differences in amounts recorded for financial reporting purposes and
their respective tax bases. Investment tax credits previously deferred are being
amortized to income over the life of the property which gave rise to the
credits.

     Cash Surrender Value of Life Insurance: The following amounts related to
corporate-owned life insurance policies (COLI) are recorded in other assets on
the Balance Sheets at December 31:

                                                   2000      1999
                                                 -------   -------
                                                   (In Millions)
          Cash surrender value of policies(a)..  $ 595.5   $ 538.3
          Borrowings against policies..........   (584.8)   (527.0)
                                                 -------   -------
          COLI (net)...........................  $  10.7   $  11.3
                                                 =======   =======

     (a)  Cash surrender value of policies as presented represents the value of
          the policies as of the end of the respective policy years and not as
          of December 31, 2000 and 1999.

     Income is recorded for increases in cash surrender value and net death
proceeds. Interest incurred on amounts borrowed is offset against policy income.
Income recognized from death proceeds is highly variable from period to period.
Death benefits recognized as other income approximated $0.2 million in 2000 and
$0.06 million in 1999.

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

     The company adopted SFAS 133 on January 1, 2001. The company has evaluated
its commodity contracts, financial instruments and other contracts and
determined that certain commodity contracts are derivative instruments. Under
current GAAP, these contracts qualify as hedges. However, under SFAS 133, these
contracts will not qualify as hedges. Accordingly, the instruments will be
marked to market through earnings. The company estimates that the effect on its
financial statements of adopting SFAS 133 will be to increase pre-tax earnings
for the first quarter of 2001 by approximately $21 million. Accounting for
derivatives under SFAS 133 may increase volatility in future earnings.

                                       38
<PAGE>

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


2.  PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES

   On November 8, 2000, Western Resources entered into an agreement under which
Public Service Company of New Mexico (PNM) will acquire the electric utility
businesses of Western Resources (including the company) in a stock-for-stock
transaction. Under the terms of the agreement, both Western Resources and PNM
will become subsidiaries of a new holding company.

3.  RATE MATTERS AND REGULATION

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

     FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with FERC against the company alleging improper affiliate transactions between
Western Resources' KPL division and the company. The City of Wichita asked that
FERC equalize the generation costs between the company and KPL, in addition to
other matters. A hearing on the case was held at FERC on October 11 and 12, 2000
and on November 9, 2000, a FERC administrative law judge ruled in favor of the
company that no change in rates was required. On December 13, 2000, the City of
Wichita filed a brief with FERC asking that the Commission overturn the judge's
decision. On January 5, 2001, the company filed a brief opposing the City's
position. The company anticipates a decision by FERC in the second quarter of
2001.

4.  SALE OF ACCOUNTS RECEIVABLE

   On July 28, 2000, Western Resources and the company entered into an agreement
to sell, on an ongoing basis, all of their accounts receivable, arising from the
sale of electricity, to WR Receivables Corporation, a special purpose entity
wholly owned by Western Resources. The agreement expires on July 26, 2001, and
is annually renewable upon agreement by both parties. The special purpose entity
has sold and, subject to certain conditions, may from time to time sell, up to
$125 million (and upon request, subject to certain conditions, up to $175
million) of an undivided fractional ownership interest in the pool of
receivables to a third-party, multi-seller receivables funding entity affiliated
with a lender. The company's retained interests in the receivables sold are
recorded at cost which approximates fair value. As of December 31, 2000, net
proceeds of $115 million were received by Western Resources, of which the
company received approximately $39.1 million.

5.  SHORT-TERM BORROWINGS

     The company had no short-term borrowings outstanding at December 31, 2000,
and 1999.

                                       39
<PAGE>

     The company's short-term liquidity needs are met from cash advances by
Western Resources. Western Resources obtains funds from borrowings under its
credit facilities.

     Western Resources has an arrangement with certain banks to provide a
revolving credit facility on a committed basis totaling $500 million. The
facility is secured by first mortgage bonds of the company and Western Resources
and matures on March 17, 2003.

6.  LONG-TERM DEBT

     The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and
Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a
maximum of $2 billion. Amounts of additional bonds which may be issued are
subject to property, earnings, and certain restrictive provisions of the
Mortgage. Electric plant is subject to the lien of the Mortgage except for
transportation equipment.

     Debt discount and expenses are being amortized over the remaining lives of
each issue. With the retirement of certain company pollution control series
bonds, there are no longer any bond sinking fund requirements. During the years
2001 through 2005, $135 million of bonds will mature in 2003 and $65 million of
bonds will mature in 2005.

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


                                                         2000       1999
                                                       --------   --------
                                                          (In Thousands)
    First mortgage bond series:
     7.60% due 2003.................................   $135,000   $135,000
     6.50% due 2005.................................     65,000     65,000
     6.20% due 2006.................................    100,000    100,000
                                                       --------   --------
                                                        300,000    300,000
                                                       --------   --------
    Pollution control bond series:
     5.10% due 2023.................................     13,623     13,653
     Variable due 2027, 4.60% at December 31, 2000..     21,940     21,940
     7.0% due 2031..................................    327,500    327,500
     Variable due 2032, 4.60% at December 31, 2000..     14,500     14,500
     Variable due 2032, 4.60% at December 31, 2000..     10,000     10,000
                                                       --------   --------
                                                        387,563    387,593
                                                       --------   --------
    Less:
     Unamortized discount...........................      3,197      3,322
                                                       --------   --------
    Long-term debt (net)............................   $684,366   $684,271
                                                       ========   ========
7.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in Statement of Financial Accounting Standards No. 107
"Disclosures about Fair Value of Financial Instruments."

     Cash and cash equivalents, short-term borrowings and variable-rate debt are
carried at cost which approximates fair value and are not included in the table
below. The decommissioning trust is recorded at fair value and is based on the
quoted market prices at

                                       40
<PAGE>

December 31, 2000 and 1999. The fair value of fixed- rate debt is estimated
based on quoted market prices for the same or similar issues or on the current
rates offered for instruments of the same remaining maturities and redemption
provisions.

     The recorded amount of accounts receivable and other current financial
instruments approximate fair value.

     The fair value estimates presented herein are based on market information
available at December 31, 2000 and 1999. These fair value estimates have not
been comprehensively revalued for the purpose of these financial statements
since that date and current estimates of fair value may differ significantly
from the amounts presented herein.

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


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

      Decommissioning trust..    $ 64,222  $ 58,286  $ 64,222  $ 58,286
      Fixed-rate debt........     641,123   641,153   635,088   636,599


8.  COMMITMENTS AND CONTINGENCIES

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

     Municipalization Efforts by Wichita 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 the company 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 the company $145 million for its stranded costs
if the City were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize the company's Wichita electric
facilities, the City of Wichita would be required to purchase the company's
facilities or build a separate independent system and arrange for its own power
supply. These costs are in addition to the stranded costs for which the city
would be required to reimburse the company. On February 2, 2001, the City of
Wichita announced its intention to proceed with its attempt to municipalize the
company's retail electric utility business in Wichita. The company will oppose
municipalization efforts by the City of Wichita. Should the city be successful
in its municipalization efforts without providing the company adequate
compensation for its assets and lost revenues, the adverse effect on the
operations and financial condition of

                                       41
<PAGE>

the company could be material.

     The company's franchise with the City of Wichita to provide retail electric
service expires in March 2002. There can be no assurance that this franchise can
be successfully renegotiated with terms similar, or as favorable, as those in
the current franchise. Under Kansas law, the company 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 54% of the company's total
energy sales.

     Purchase Orders and Contracts: The company has commitments under purchase
orders and contracts, other than fuel at WCNOC, which have an unexpended balance
of approximately $2.1 million (company's share) at December 31, 2000.

     Manufactured Gas Sites: The company has been associated with three former
manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials. The company and the Kansas Department of Health
and Environment (KDHE) entered into a consent agreement governing all future
work at these sites. The terms of the consent agreement will allow the company
to investigate these sites and set remediation priorities based on the results
of the investigations and risk analysis. At December 31, 2000, the costs
incurred from preliminary site investigation and risk assessment have been
minimal.

     Clean Air Act: The company must comply with the provisions of The Clean Air
Act Amendments of 1990 that require a two-phase reduction in certain emissions.
The company has installed continuous monitoring and reporting equipment to meet
the acid rain requirements. Material capital expenditures have not been required
to meet Phase II sulfur dioxide and nitrogen oxide requirements.

     Decommissioning: The company accrues decommissioning costs over the
expected life of the Wolf Creek generating facility. The accrual is based on
estimated unrecovered decommissioning costs which consider inflation over the
remaining estimated life of the generating facility and are net of expected
earnings on amounts recovered from customers and deposited in an external trust
fund.

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

     Decommissioning costs are currently being charged to operating expense in
accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of

                                       42
<PAGE>

these decommissioning costs over the life of Wolf Creek. Amounts expensed
approximated $4.0 million in 2000 and will increase annually to $5.5 million in
2024. These amounts are deposited in an external trust fund. The average
after-tax expected return on trust assets is 5.8%.

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

     The 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:

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

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

     Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.5 billion for a single
nuclear incident. If this liability limitation is insufficient, the United
States Congress will consider taking whatever action is necessary to compensate
the public for valid claims. The Wolf Creek owners (Owners) have purchased the
maximum available private insurance of $200 million. The remaining balance is
provided by an assessment plan mandated by the Nuclear Regulatory Commission
(NRC). Under this plan, the Owners are jointly and severally subject to a
retrospective assessment of up to $88.1 million in the event there is a major
nuclear incident involving any of the nation's licensed reactors. This
assessment is subject to an inflation adjustment based on the Consumer Price
Index and applicable premium taxes. There is a limitation of $10 million in
retrospective assessments per incident, per year.

     The Owners carry decontamination liability, premature decommissioning
liability and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion, company's share). This insurance is provided by
Nuclear Electric Insurance Limited (NEIL). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination in accordance with a plan mandated by the NRC. The company's
share of any remaining proceeds can be used to pay for property damage or
decontamination expenses or, if certain requirements are met including
decommissioning the plant, toward a shortfall in the decommissioning trust fund.

     The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other additional expenses incurred during a prolonged
outage resulting from

                                       43
<PAGE>

accidental property damage at Wolf Creek. If losses incurred at any of the
nuclear plants insured under the NEIL policies exceed premiums, reserves and
other NEIL resources, the company may be subject to retrospective assessments
under the current policies of approximately $5.3 million per year.

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

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

     At December 31, 2000, the company's coal and transportation contract
commitments in 2000 dollars under the remaining terms of the contracts were
approximately $523.5 million. The largest contract expires in 2020, with the
remaining contracts expiring at various times through 2013.

     At December 31, 2000, the company's firm natural gas transportation
commitments in 2000 dollars under the remaining terms of the contracts were
approximately $1.5 million. The natural gas transportation contracts provide
firm service to the company's Gordon Evans and Murray Gill Energy Centers
through 2010 and to the Neosho gas burning facility through 2016.

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

9.  LEGAL PROCEEDINGS

     The company is involved in various legal, environmental and regulatory
proceedings. Management believes that adequate provision has been made and
accordingly believes that the ultimate disposition of such matters will not have
a material adverse effect upon the company's overall financial position or
results of operations. See also Notes 3 and 8 for discussion of the City of
Wichita's municipalization efforts and a FERC proceeding including the City of
Wichita.

1O.  LEASES

     At December 31, 2000, the company had leases covering various property and
equipment. The company currently has no capital leases.

                                       44
<PAGE>

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

                                                    Operating
                Year Ended December 31,              Leases
                ------------------------------------------------
                                                  (In Thousands)
                Rental payments:
                 1998 .........................     $ 44,075
                 1999 .........................       43,827
                 2000 .........................       42,559

                Future Commitments:
                 2001 .........................       42,841
                 2002 .........................       41,730
                 2003 .........................       45,304
                 2004 .........................       40,157
                 2005 .........................       43,505
                 Thereafter ...................      496,878
                                                    --------
                  Total future commitments ....     $710,415
                                                    ========

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

     As permitted under the La Cygne 2 lease agreement, the company in 1992
requested the Trustee Lessor to refinance $341.1 million of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested to
reduce recurring future net lease expense. In connection with the refinancing on
September 29, 1992, a one-time payment of approximately $27 million was made by
the company which has been deferred and is being amortized over the remaining
life of the lease and included in operating expense as part of the future lease
expense. As of December 31, 2000, the deferral cost was $18.0 million.

     Future minimum annual lease payments, included in the table above, required
under the La Cygne 2 lease agreement are approximately $34.6 million for each
year through 2002, $39.4 million in 2003, $34.6 million in 2004, $38.0 million
in 2005 and $464.6 million over the remainder of the lease.

     The gain realized at the date of the sale of La Cygne 2 has been deferred
for financial reporting purposes, and is being amortized ($11.8 million per
year) over the initial lease term in proportion to the related lease expense.
The company's lease expense, net of amortization of the deferred gain and
refinancing costs, was approximately $28.9 million annually for 2000, 1999 and
1998.

                                       45
<PAGE>

11.  INCOME TAXES

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

                                        2000       1999       1998
                                       -------    -------   --------
                                               (In Thousands)
        Currently payable:
         Federal....................   $38,754    $38,710   $ 53,297
         State......................     9,683      9,453     12,080
        Deferred:
         Federal....................    (9,837)    (8,531)   (14,299)
         State......................    (1,388)    (1,407)    (2,866)
        Amortization of investment
         tax credits................    (3,237)    (3,238)    (3,241)
                                       -------    -------   --------
        Total income tax expense ...   $33,975    $34,987   $ 44,971
                                       =======    =======   ========

     Under SFAS No. 109, "Accounting for Income Taxes," temporary differences
gave rise to deferred tax assets and deferred tax liabilities as follows at
December 31:
                                                     2000       1999
                                                   --------   --------
                                                      (In Thousands)
        Deferred tax assets:
         Deferred gain on sale-leaseback........   $ 82,013   $ 87,220
         Other..................................     43,778     40,969
                                                   --------   --------
          Total deferred tax assets.............    125,791    128,189
                                                   --------   --------
        Deferred tax liabilities:
         Accelerated depreciation and other.....    369,765    375,917
         Acquisition premium....................    274,579    282,578
         Deferred future income taxes...........    151,842    172,336
         Other..................................      9,282     12,322
                                                   --------   --------
          Total deferred tax liabilities........    805,468    843,153
                                                   --------   --------
        Investment tax credits..................     56,759     59,997
                                                   --------   --------
        Accumulated deferred income taxes, net..   $736,436   $774,961
                                                   ========   ========

     In accordance with various rate orders, the company has not yet collected
through rates certain accelerated tax deductions which have been passed on to
customers. As management believes it is probable that the net future increases
in income taxes payable will be recovered from customers, it has recorded a
deferred asset for these amounts. These assets are also a temporary difference
for which deferred income tax liabilities have been provided.

     The effective income tax rates set forth below are computed by dividing
total federal and state income taxes by the sum of such taxes and net income.
The difference between the effective tax rates and the federal statutory income
tax rates are as follows:

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

      Effective Income Tax Rate.................    28%    29%    30%
      Effect of:
       State income taxes.......................    (4)    (4)    (4)
       Amortization of investment tax credits...     3      3      2
       Corporate-owned life insurance policies..     9      7      9
       Accelerated depreciation flow through
         and amortization, net..................    (4)    (2)    (2)
       Other....................................     3      2      -
                                                  ----   ----   ----
      Statutory Federal Income Tax Rate.........    35%    35%    35%
                                                  ====   ====   ====


                                       46
<PAGE>

12.  RELATED PARTY TRANSACTIONS

     The cash management function, including cash receipts and disbursements,
for the company is performed by Western Resources. An intercompany account is
used to record net receipts and disbursements between KGE and Western Resources
and KGE and WR Receivables Corporation. The net amount receivable from
affiliates approximated $53.1 million at December 31, 2000 and $37.1 million at
December 31, 1999 as reflected in the Consolidated Balance Sheets.

     Certain operating expenses have been allocated to the company from Western
Resources. These expenses are allocated, depending on the nature of the expense,
based on allocation studies, net investment, number of customers, and/or other
appropriate factors. Management believes such allocation procedures are
reasonable. During 2000, the company declared dividends to Western Resources of
$100 million.

13.  PROPERTY, PLANT AND EQUIPMENT

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

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

        Electric plant in service............  $3,674,643  $3,623,852
        Less - Accumulated depreciation......   1,288,676   1,206,607
                                               ----------  ----------
                                                2,385,967   2,417,245
        Construction work in progress........      33,233      35,219
        Nuclear fuel (net)...................      30,791      28,013
                                               ----------  ----------
         Net utility plant...................   2,449,991   2,480,477
        Non-utility plant in service.........          70         219
                                               ----------  ----------
         Net property, plant and equipment.    $2,450,061  $2,480,696
                                               ==========  ==========

          The company's depreciation expense on property, plant and equipment
was $84.2 million in 2000, $81.1 million in 1999 and $78.7 million in 1998.


                                       47
<PAGE>

14.  JOINT OWNERSHIP OF UTILITY PLANTS
<TABLE>
<CAPTION>
                                   Company's Ownership at December 31, 2000
                                   ----------------------------------------
                         In-Service         Invest-       Accumulated       Net      Per-
                            Dates            ment        Depreciation      (MW)      cent
                            -----            ----        ------------      ----      ----
                                              (Dollars in Thousands)
<S>           <C>        <C>        <C>               <C>              <C>       <C>
La Cygne 1      (a)       Jun 1973       $  182,794        $ 115,903        344       50
Jeffrey  1      (b)       Jul 1978           72,810           33,299        149       20
Jeffrey  2      (b)       May 1980           69,780           33,083        148       20
Jeffrey  3      (b)       May 1983          101,478           45,016        148       20
Jeffrey wind 1  (b)       May 1999              193               12        (d)       20
Jeffrey wind 2  (b)       May 1999              192               11        (d)       20
Wolf Creek      (c)       Sep 1985        1,381,656          491,978        550       47
</TABLE>

(a)  Jointly owned with Kansas City Power & Light Company (KCPL)
(b)  Jointly owned with Western Resources and UtiliCorp United Inc.
(c)  Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
(d)  The company's share is less than 0.5 MW

     Amounts and capacity presented above represent the company's share. The
company's share of operating expenses of the plants in service above, as well as
such expenses for a 50% undivided interest in La Cygne 2 (representing 337 MW
capacity) sold and leased back to the company in 1987, are included in operating
expenses on the Statements of Income. The company's share of other transactions
associated with the plants is included in the appropriate classification in the
company's financial statements.

15.  SEGMENTS OF BUSINESS

     In 1998, the company adopted SFAS 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement requires the company to
define and report the company's business segments based on how management
currently evaluates its business. Based on management's approach to determining
business segments, the company has two business segments, electric operations
and nuclear generation.

     Electric operations involve the production, transmission and distribution
of electric power for sale to approximately 291,000 retail and wholesale
customers in Kansas. Nuclear generation represents the company's 47% ownership
in the Wolf Creek nuclear generating facility. This segment has only internal
sales because it provides all of its power to its co-owners.

     The accounting policies of the segments are substantially the same as those
described in the summary of significant accounting policies. The company
evaluates segment performance based on earnings before interest and taxes. The
company has no single external customer from which it receives ten percent or
more of its revenues.

                                       48
<PAGE>

<TABLE>
<CAPTION>

Year Ended December 31, 2000:
-----------------------------

                                       Electric     Nuclear     Eliminating
                                      Operations   Generation      Items       Total
                                      ----------   ----------   -----------    -----
                                                        (In Thousands)
     <S>                              <C>         <C>           <C>         <C>
     External sales.................  $  703,990    $    -      $    -      $  703,990
     Internal sales.................        -         107,770    (107,770)        -
     Depreciation and
      amortization..................      64,242       40,052        -         104,294
     Earnings before
      interest and taxes                 194,611      (24,323)       -         170,288
     Interest expense...............                                            49,605
     Earnings before
      income taxes..................                                           120,683
     Identifiable assets               1,920,345    1,068,228        -       2,988,573
</TABLE>


<TABLE>
<CAPTION>
Year Ended December 31, 1999:
-------------------------------
                                       Electric     Nuclear     Eliminating
                                      Operations   Generation      Items       Total
                                      ----------   ----------   -----------    -----
                                                        (In Thousands)
     <S>                              <C>         <C>           <C>         <C>
     External sales.................  $  638,340    $    -       $   -    $  638,340
     Internal sales.................        -         108,445    (108,445)      -
     Depreciation and
      amortization..................      61,531       39,629        -       101,160
     Earnings before
      interest and taxes                 193,980      (25,214)       -       168,766
     Interest expense...............                                          49,518
     Earnings before
      income taxes..................                                         119,248
     Identifiable assets               1,906,366    1,083,344        -     2,989,710

<CAPTION>
Year Ended December 31, 1998:
-------------------------------
                                       Electric     Nuclear     Eliminating
                                      Operations   Generation      Items       Total
                                      ----------   ----------   ----------     -----
                                                        (In Thousands)
     External sales.................  $  648,379    $     -     $     -     $  648,379
     Internal sales.................        -          117,517    (117,517)       -
     Depreciation and
      amortization..................      59,239       39,583         -         98,822
     Earnings before
      interest and taxes                 219,014      (20,920)        -        198,094
     Interest expense...............                                            49,358
     Earnings before
      income taxes..................                                           148,736
     Identifiable assets               1,936,462    1,121,509         -      3,057,971
</TABLE>

16.  QUARTERLY FINANCIAL STATISTICS (Unaudited)

     The amounts in the table are unaudited but, in the opinion of management,
contain all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the results of such periods. The business
of the company is seasonal in nature and, in the opinion of management,
comparisons between the quarters of a year do not give a true indication of
overall trends and changes in operations.


                                               2000
                              --------------------------------------
                                First    Second    Third     Fourth
                              --------  --------  --------  --------
                                          (In Thousands)
    Sales...................  $149,913  $164,967  $229,456  $159,654
    Income from Operations..    22,067    45,706    84,668    24,417
    Net income..............     5,968    23,007    49,395     8,338

                                               1999
                              --------------------------------------
                                First    Second    Third     Fourth
                              --------  --------  --------  --------
                                          (In Thousands)
    Sales...................  $133,910  $147,170  $217,986  $139,274
    Income from Operations..    30,172    31,735    86,982    22,960
    Net income..............    12,905    14,070    49,512     7,774

                                       49
<PAGE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
------------------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------

     None.


                                 PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
------------------------------------------------------------

     Western Resources, Inc. owns 100% of the Company's outstanding common
stock.

                                                                 A Director
                    Business Experience Since 1996 and Other    Continuously
 Name        Age    Directorships Other Than The Company            Since
 ----        ---    ----------------------------------------    ------------

Ronald W.    54     Chairman of the Board and President             2000
Holt                (since January 2000), Assistant
                    Secretary (January 1998 to January
                    2000), Kansas Gas and Electric Company.
                    Executive Director, Southern Region
                    (since January 2000); Senior Director,
                    Corporate and Community Affairs (January
                    1999 to January 2000); Director, Community
                    and Support Services (September 1995 to
                    December 1998), Western Resources, Inc.
                    Directorships
                    Commerce Bank, N.A., Wichita, Kansas
                    Via Christi Medical Center, Wichita,
                    Kansas

James A.     43     Senior Vice President and Treasurer             1997
Martin               (since August 2000), Vice President,
                     (July 1995 to August 2000),
                     Western Resources, Inc.

Marilyn B.   51     Vice Chairman - Wichita Market Area,            1994
Pauly                Commerce Bank N.A., Wichita, Kansas
(1)                  (since February 2001)
                     Executive Vice President, Bank of
                       America, N.A., Wichita, Kansas
                       (1997 to 2000)
                    Directorships
                    Farmers Mutual Alliance Insurance Company

Richard D.   68     President, Range Oil Company                    1993
Smith                Directorships
(1)                  HCA Wesley Medical Center, Wichita, Kansas

(1)  Member of the Audit Committee of which Marilyn B. Pauly is Chairperson. The
     Audit Committee has responsibility for the investigation and review of the
     financial affairs of the company and its relations with independent
     accountants.


                                       50
<PAGE>


     Outside directors are paid a $3,750 per quarter retainer and are paid an
attendance fee of $600 for board meetings ($300 if attending by phone). A
committee attendance fee of $800 is paid to the outside director Audit Committee
Chairperson, and $500 to other outside Committee members. All outside directors
are reimbursed expenses while attending board and Committee Meetings.

     During 2000, the Board of Directors met three times and the Audit Committee
met once. Each director attended at least 75% of the total number of Board and
Committee meetings held while he/she served as a director or a member of the
committee.

     Other information required by Item 10 is omitted pursuant to General
Instruction I(2)(c) to Form 10-K.


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

     Information required by Item 11 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.


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

     Information required by Item 12 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.


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

     Information required by Item 13 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.

                                 PART IV

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

     The following financial statements are included herein under Item 8.

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

Consolidated Balance Sheets, December 31, 2000 and 1999
Consolidated Statements of Income for the years ended December 31, 2000, 1999
 and 1998
Consolidated Statements of Cash Flows for the years ended December 31, 2000,
 1999 and 1998
Consolidated Statements of Shareholder's Equity for the years ended December
 31, 2000, 1999 and 1998
Notes to Consolidated Financial Statements

                                       51
<PAGE>

REPORTS ON FORM 8-K
-------------------

 Form 8-K filed November 28, 2000 - Press release announcing that Western
   Resources and KGE filed separate requests with the KCC seeking recovery of
   investments in new power plants and higher operating and maintenance costs.

                                       52
<PAGE>

                                  EXHIBIT INDEX

  All exhibits marked "I" are incorporated herein by reference.

<TABLE>
<CAPTION>
                                   Description
                                   -----------
<S>      <C>
 3(a)    Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K for the          I
         year ended December 31, 1992, File No. 1-7324)

 3(b)    Certificate of Merger of Kansas Gas and Electric Company into KCA              I
         Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended
         December 31, 1992, File No. 1-7324)

 3(c)    By-laws as amended (Filed as Exhibit 3(c) Form 10-K for the year               I
         ended December 31, 1992, File No. 1-7324)

 4(c)    Mortgage and Deed of Trust, dated as of April 1, 1940 to                       I
          Guaranty Trust Company of New York (now Morgan Guaranty Trust Company
          of New York) and Henry A. Theis (to whom W. A. Spooner is successor),
          Trustees, as supplemented by forty Supplemental Indentures, dated as
          of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952,
          October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961, May
          1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31, 1973, July
          1, 1975, December 1, 1975, September 1, 1976, March 1, 1977, May 1,
          1977, August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980,
          July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981, May 1,
          1982, March 15, 1984, September 1, 1984 (Twenty-ninth and Thirtieth),
          February 1, 1985, April 15, 1986, June 1, 1991, March 31, 1992,
          December 17, 1992, August 24, 1993, January 15, 1994, March 1, 1994,
          April 15, 1994 and June 28, 2000, (Filed, respectively, as Exhibit A-1
          to Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405;
          Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626; Exhibit
          4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228; Exhibit 4(c),
          File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File
          No. 2-36170; Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d),
          File No. 2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989,
          File No. 1-7324; Exhibit 2(c), File No. 2- 53765; Exhibit 2(e), File
          No. 2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No.
          2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No.
          1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No.
          2-60777; Exhibit2(g), File No. 2-64521; Exhibit 2(h), File No.
          2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and
          4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit 4(d),
          File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for
          December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form
          10-K for December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3,
          File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December
          31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K for December 31,
          1994, File No. 1-7324)

          Instruments defining the rights of holders of other long-term debt not
          required to be filed as exhibits will be furnished to the Commission
          upon request.
</TABLE>

                                       53
<PAGE>

10(a)    La Cygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the     I
         year ended December 31, 1988, File No. 1-7324)

10(a)    Amendment No. 3 to La Cygne 2 Lease Agreement dated as of         I
         September 29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K
         for the year ended December 31, 1992, File No. 1-7324)

10(b)    Outside Directors' Deferred Compensation Plan (Filed as           I
         Exhibit 10(c) to the Form 10-K for the year ended
         December 31, 1993, File No. 1-7324)

12       Computation of Ratio of Consolidated Earnings to
         Fixed Charges

23       Consent of Independent Public Accountants, Arthur Andersen LLP


                                       54
<PAGE>

                                    SIGNATURE
                                    ---------

     Pursuant to the requirements of Sections 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                             KANSAS GAS AND ELECTRIC COMPANY


          April 2, 2001                  By      /s/ Ronald W. Holt
   ------------------------------        ---------------------------------------
                                                  Ronald W. Holt
                                                  Chairman of the Board
                                                  and President

                                       55
<PAGE>

                                   SIGNATURES
                                   ----------

     Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:

       Signature                         Title                     Date
       ---------                         -----                     ----

/s/ RONALD W. HOLT            Chairman of the Board and
---------------------------   President (Principal Executive
 (Ronald W. Holt)                        Officer)              April 2, 2001


/s/ RICHARD D. TERRILL       Secretary, Treasurer and General
---------------------------  Counsel (Principal Financial
 (Richard D. Terrill)             and Accounting Officer)      April 2, 2001


/s/ JAMES A. MARTIN           Director                         April 2, 2001
---------------------------
 (James A. Martin)

/s/ MARILYN B. PAULY          Director                         April 2, 2001
---------------------------
 (Marilyn B. Pauly)

/s/ RICHARD D. SMITH          Director                         April 2, 2001
---------------------------
 (Richard D. Smith)

                                       56