KANSAS GAS & ELECTRIC CO /KS/ - 10-K Annual Report

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

FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 1998

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

Commission file number 1-7324

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 31, 1999)

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 J(1)(a) and (b) to Form
10-K for certain wholly-owned subsidiaries and is therefore filing an
abbreviated form.
2
KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1998

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 13

Item 3. Legal Proceedings 14

Item 4. Submission of Matters to a Vote of
Security Holders 14

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 15

Item 6. Selected Financial Data 15

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 16

Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 32

Item 8. Financial Statements and Supplementary Data 33

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 54

PART III
Item 10. Directors and Executive Officers of the
Registrant 55

Item 11. Executive Compensation 56

Item 12. Security Ownership of Certain Beneficial
Owners and Management 56

Item 13. Certain Relationships and Related Transactions 56

PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 57

Signatures 60

3
PART I

ITEM 1. BUSINESS

GENERAL

Kansas Gas and Electric Company (the company, KGE) is an electric public
utility engaged in the generation, transmission, distribution and sale of
electric energy in southeastern Kansas including the Wichita metropolitan
area. We are a wholly-owned subsidiary of Western Resources, Inc. (Western
Resources). 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. We have no gas
properties. At December 31, 1998, we had no employees. All employees are
provided by our parent company, Western Resources.

On February 7, 1997, Western Resources signed a merger agreement with
Kansas City Power & Light Company (KCPL) by which KCPL would be merged with
and into Western Resources in exchange for Western Resources common stock. In
December 1997, representatives of Western Resources' financial advisor
indicated that they believed it was unlikely that they would be in a position
to issue a fairness opinion required for the merger on the basis of the
previously announced terms.

On March 18, 1998, Western Resources and KCPL agreed to a restructuring of
their February 7, 1997, merger agreement which will result in the formation of
Westar Energy, a new electric company. Under the terms of the merger
agreement, the electric utility operations of Western Resources will be
transferred to the company, and KCPL and the company will be merged into NKC,
Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar
Energy. In addition, under the terms of the merger agreement, KCPL
shareholders will receive Western Resources common stock which is subject to a
collar mechanism of not less than .449 nor greater than .722, provided the
amount of Western Resources common stock received may not exceed $30.00, and
one share of Westar Energy common stock per KCPL share. The Western Resources
Index Price is the 20 day average of the high and low sale prices for Western
Resources common stock on the NYSE ending ten days prior to closing. If the
Western Resources Index Price is less than or equal to $29.78 on the fifth day
prior to the effective date of the combination, either party may terminate the
agreement. Upon consummation of the combination, Western Resources will own
approximately 80.1% of the outstanding equity of Westar Energy and KCPL
shareholders will own approximately 19.9%. As part of the combination, Westar
Energy will assume all of the electric utility related assets and liabilities
of Western Resources, KCPL, and the company.

Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion
of indebtedness for borrowed money of Western Resources and the company, and
$800 million of debt of KCPL. Long-term debt of Western Resources, excluding
Protection One, Inc. (a subsidiary of Western Resources), and the company was
$2.5 billion at December 31, 1998. Under the terms of the merger agreement,
it is intended that Western Resources will be released from its obligations
with respect to the company's debt to be assumed by Westar Energy. For
additional information concerning the company's long-term debt and obligations
under the La

4
Cygne sale leaseback arrangements which will become obligations of Westar
Energy, see Note 5 and Note 6 of Notes to Financial Statements.

Consummation of the merger is subject to customary conditions. On July
30, 1998, Western Resources' shareholders and the shareholders of KCPL voted
to approve the amended merger agreement at special meetings of shareholders.
Western Resources estimates the transaction to close in 1999, subject to
receipt of all necessary approvals from regulatory and government agencies.

In testimony filed in February 1999, the Kansas Corporation Commission
(KCC) staff recommended the merger be approved but with conditions which
Western Resources believes would make the merger uneconomical. The KCC is
under no obligation to accept the KCC staff recommendation. In addition,
legislation has been proposed in Kansas that could impact the transaction.
Western Resources does not anticipate the proposed legislation to pass in its
current form. Western Resources is not able to predict whether any of these
initiatives will be adopted or their impact on the transaction, which could be
material.

On August 7, 1998, Western Resources and KCPL filed an amended application
with the Federal Energy Regulatory Commission (FERC) to approve the Western
Resources/KCPL merger and the formation of Westar Energy.

Western Resources has received procedural schedule orders in Kansas and
Missouri. These schedules indicate hearing dates beginning May 3, 1999 in
Kansas and July 26, 1999 in Missouri.

KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. KCPL, Western Resources, and the company have joint interests
in certain electric generating assets, including Wolf Creek. For additional
information, see "Financing" below, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations and Note 13 of Notes
to Financial Statements.

The United States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the electricity industry. The Energy Policy Act permitted
the FERC to order electric utilities to allow third parties the use of their
transmission systems to sell electric power to wholesale customers. A
wholesale sale is defined as a utility selling electricity to a "middleman",
usually a city or its utility company, to resell to the ultimate retail
customer. As part of the 1992 acquisition of the company by Western
Resources, we agreed to open access of our transmission system for wholesale
transactions. In 1996, FERC issued order 888 and 889 requiring all
jurisdictional utilities to open their transmission systems to all market
participants on a nondiscriminatory basis and to split their generation market
functions away from their transmission operations. As required by this order
we have completed this split.

For discussion regarding competition in the electric utility industry and
the potential impact on the company, see Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations.
5
Discussion of other factors affecting the company are set forth in the
Notes to Financial Statements and Management's Discussion and Analysis
included herein.

SEGMENT INFORMATION

Financial information with respect to business segments is set forth in
Note 14 of the Notes to Financial Statements included herein.

ELECTRIC OPERATIONS

General

We supply electric energy at retail to approximately 283,000 customers in
147 communities in Kansas. We also supply electric energy to 27 communities
and 1 rural electric cooperative, and have contracts for the sale, purchase or
exchange of electricity with other utilities at wholesale.

Our electric energy deliveries for the last five years were as follows:

1998 1997 1996 1995 1994
(Thousands of MWH)
Residential 2,784 2,490 2,503 2,385 2,384
Commercial 2,383 2,211 2,186 2,095 2,068
Industrial 3,569 3,518 3,501 3,542 3,371
Wholesale and
Interchange 1,541 2,101 2,706 1,292 1,590
Other 45 45 45 45 45
Total 10,322 10,365 10,941 9,359 9,458

Our electric sales for the last five years were as follows:

1998 1997 1996 1995 1994
(Dollars in Thousands)
Residential $237,571 $214,719 $226,456 $221,628 $220,067
Commercial 170,473 162,913 176,963 171,654 167,499
Industrial 167,331 165,614 175,420 182,930 181,119
Wholesale and
Interchange 50,634 53,343 57,242 31,143 38,750
Other 22,370 17,856 18,489 16,813 12,458
Total $648,379 $614,445 $654,570 $624,168 $619,893

Capacity

The aggregate net generating capacity of our system is presently 2,535
megawatts (MW). The system comprises interests in twelve fossil fueled steam
generating units, one nuclear generating unit (47% interest) and one diesel
generator, located at seven generating stations. One of the twelve fossil
fueled units (70 MW capacity) has been "mothballed" for future use (See Item
2. Properties).
6
Our 1998 peak system net load occurred on June 29, 1998 and amounted to
1,972 MW. Our net generating capacity together with power available from firm
interchange and purchase contracts, provided a capacity margin of
approximately 12% above system peak responsibility at the time of the peak.

We are a member of the Southwest Power Pool (SPP). SPP's responsibility
is to maintain system reliability on a regional basis. The region encompasses
areas within the eight states of Kansas, Missouri, Oklahoma, New Mexico,
Texas, 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 economy energy transactions, unit commitment service, firm
capacity and energy sales and energy exchanges.

We have an agreement with Midwest Energy, Inc. (MWE), to provide MWE with
peaking capacity of 61 MW through the year 2008. We also entered into an
agreement with Empire District Electric Company (Empire), to provide Empire
with peaking and base load capacity (20 MW in 1994 increasing to 80 MW in
2000) through the year 2000.

Because the electric utility business is seasonal, the KCC has adopted the
Kansas Cold Weather Rule (CWR). The CWR specifies that business procedures
related to disconnection of service for residential customers have certain
restrictions from November 1 through the following March 31. The CWR is
intended to prevent disconnections due to customers not paying their bills,
leaving the customers facing life threatening risks due to outside
temperatures. Disconnections for customers who do not pay their bills can
occur during this time frame under certain weather conditions. Various pay
agreement rules correspond to the CWR. Due to the CWR, collection efforts for
unpaid bills are much more intense from April 1 to October 31. Sales peaks
correlate directly with the seasonality of the midwestern weather and,
therefore, the workload for customer service is the heaviest from April
through August.

Future Capacity

We are participating with Western Resources in the installation of three
new combustion turbine generators for use as peaking units. The installed
capacity of the three new generators will be 300 MW. The first two units are
scheduled to be placed in operation in 2000 and the third is scheduled to be
placed in operation in 2001. Western Resources estimates that the project
will require $120 million in capital resources through the completion of the
projects in 2001. The extent of our participation in these projects has not
been determined. We are also planning to return our inactive generation plant
in Neosho, Kansas to active service in 1999.
7
For further discussion regarding future capacity and cash requirements,
see Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.

Fuel Mix

Our coal-fired units comprise 1,120 MW of the total 2,535 MW of generating
capacity and our nuclear unit provides 547 MW of capacity. Of the remaining
868 MW of generating capacity, units that can burn either natural gas or oil
account for 865 MW, and the remaining unit which burns only diesel fuel
accounts for 3 MW (See Item 2. Properties).

During 1998, low sulfur coal was used to produce 52% of our electricity.
Nuclear produced 37% and the remainder was produced from natural gas, oil, or
diesel fuel. During 1999, based on our estimate of the availability of fuel,
coal will be used to produce approximately 56% of our electricity and nuclear
will be used to produce 30%.

Our fuel mix fluctuates with the operation of nuclear powered Wolf Creek
as discussed below under Nuclear Generation.

Coal

The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 443 MW (KGE's 20% share) (See Item 2. Properties).
Western Resources, the operator of JEC, and KGE have a long-term coal supply
contract with Amax Coal West, Inc. (AMAX), a subsidiary of Cyprus Amax Coal
Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an
alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder
River Basin in Campbell County, Wyoming. The contract expires December 31,
2020. The contract contains a schedule of minimum annual delivery quantities
based on MMBtu provisions. The coal to be supplied is surface mined and has
an average Btu content of approximately 8,300 Btu per pound and an average
sulfur content of .43 lbs/MMBtu (See Environmental Matters). The average
delivered cost of coal for JEC was approximately $1.13 per MMBtu or $18.96 per
ton during 1998.

Coal is transported by Western Resources from Wyoming under a long-term
rail transportation contract with Burlington Northern Santa Fe and Union
Pacific railroads to JEC through December 31, 2013. Rates are based on net
load carrying capabilities of each rail car. Western Resources provides 868
aluminum rail cars, under a 20 year lease, to transport coal to JEC.

The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 677 MW (KGE's 50% share) (See Item 2. Properties). The operator,
KCPL, maintains coal contracts as discussed in the following paragraphs.

La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under
a variety of spot market transactions, discussed below. High Btu
Kansas/Missouri coal is blended with the Powder River Basin coal and is
secured from time to time under spot market arrangements. La Cygne 1 uses a
blended fuel mix containing approximately 85% Powder River Basin coal.
8
La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied
through several contracts, expiring at various times through 1999. This low
sulfur coal had an average Btu content of approximately 8,500 Btu per pound
and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with Burlington Northern Santa Fe Railroad and Kansas City Southern
Railroad through December 31, 2000.

During 1998, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.74 per MMBtu or $12.77
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.66 per MMBtu or $10.97 per ton.

We have entered into all of our coal contracts during the ordinary course
of business and are not substantially dependent upon these contracts. We
believe there are other suppliers for and plentiful sources of coal available
at reasonable prices to replace, if necessary, fuel to be supplied pursuant to
these contracts. In the event that we were required to replace our coal
agreements, we would not anticipate a substantial disruption of our business.

We have entered into all of our transportation contracts during the
ordinary course of business. At the time of entering into these contracts, we
were not substantially dependent upon these contracts due to the availability
of competitive rail options. Due to recent rail consolidation, there are now
only two rail carriers capable of serving our origin coal mines and our
generating stations. In the event one of these carriers became unable to
provide reliable service, we could experience a short-term disruption of our
business. However, due to the obligation of the remaining carriers to provide
service under the Interstate Commerce Act, we do not anticipate any
substantial long-term disruption of our business.

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 supplied
by readily available gas from the spot market. Short-term economical spot
market purchases will supply the system with the flexible natural gas supply
to meet operational needs. We maintain firm natural gas transportation
capacity through Williams Gas Pipelines Central for the above facilities
through April 1, 2010.

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 JEC and
La Cygne generating stations. All of the oil we have burned during the past
several years has been obtained by spot market purchases. At December 31,
1998, we had approximately one million gallons of No. 2 oil and eighteen
million gallons of No. 6 oil which is believed to be sufficient to meet
emergency requirements and protect against lack of availability of natural gas
and/or the loss of a large generating unit.

9
Other Fuel Matters

Our contracts to supply fuel for our coal and natural gas-fired generating
units, with the exception of JEC, do not provide full fuel requirements at the
various stations. Supplemental fuel is procured on the spot market to provide
operational flexibility and, when the price is favorable, to take advantage of
economic opportunities.

Set forth in the table below is information relating to the weighted
average cost of fuel that we have used.

1998 1997 1996 1995 1994
Per Million Btu:
Nuclear $0.48 $0.51 $0.50 $0.40 $0.36
Coal 0.86 0.89 0.88 0.91 0.90
Gas 2.28 2.56 2.30 1.68 1.98
Oil 4.05 3.32 2.74 4.00 3.90

Cents per KWH Generation $0.94 1.00 0.93 0.82 0.89

Nuclear Generation

The owners of Wolf Creek have on hand or under contract 100% of their
uranium needs for 1999 and 59% of the uranium required to operate Wolf Creek
through September 2003. The balance is expected to be obtained through spot
market and contract purchases. We have active contracts with the following
companies for uranium: Cameco Corporation and Geomex Minerals, Inc.

A contractual arrangement is in place with Cameco Corporation for the
conversion of uranium to uranium hexafluoride sufficient for the operation of
Wolf Creek through the year 2001.

We have active contracts for uranium enrichment with Urenco and USEC.
Contracted arrangements cover 88% of the uranium enrichment required for
operation of Wolf Creek through March 2005. The balance is expected to be
obtained through spot market and term contract purchases.

We have entered into all of our uranium, uranium hexaflouride and uranium
enrichment arrangements during the ordinary course of business and are not
substantially dependent upon these agreements. We believe there are other
supplies available at reasonable prices to replace, if necessary, these
contracts. In the event that we were required to replace these contracts, we
would not anticipate a substantial disruption of our business.

Nuclear fuel is amortized to cost of sales based on the quantity of heat
produced for the generation of electricity. Under the Nuclear Waste Policy
Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the
permanent disposal of spent nuclear fuel. We pay the DOE a quarterly fee of
one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered
and sold for the future disposal of spent nuclear fuel. These disposal costs
are charged to cost of sales and currently recovered through rates.
10
In 1996, a U. S. Court of Appeals issued a decision that the Nuclear Waste
Policy Act unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998. In late 1997, the same court issued another decision
precluding the DOE from concluding that its delay in accepting spent fuel is
"unavoidable" under its contracts with utilities due to lack of a repository
or interim storage authority. By the end of 1997, WCNOC and other utilities
had petitioned the DOE for authority to suspend payments of their quarterly
fees until such time as the DOE begins accepting spent fuel. In January 1998,
the DOE denied the petition of the utilities.

In February 1998, WCNOC and other utilities petitioned the court to: 1)
compel the DOE to submit to the court within 30 days a program, with
appropriate milestones, to dispose of used nuclear fuel beginning immediately,
2) declare that the utilities are relieved of their obligation to pay into the
Nuclear Waste Fund, and are authorized to escrow future fees unless and until
DOE begins disposing of their used fuel, 3) prohibit the federal government
from suspending or terminating it's disposal contracts with the utilities or
from imposing any interest, penalties or other charges as a result of a
utility's suspension of waste fund payments, and 4) preclude the federal
government from using fees paid into the waste fund to compensate the
utilities for damages or additional costs they have incurred as a result of
the agency's breach of its obligation. In May 1998, the court issued an order
disposing of all pending motions and petitions. The court affirmed its
conclusion that the sole remedy for DOE's breach of its statutory obligation
under the NWPA is a contract remedy, and made clear that the court will not
revisit the matter until the utilities have completed their pursuit of that
remedy. WCNOC intends to pursue the appropriate contract remedy against the
DOE.

A permanent disposal site may not be available for the industry until 2010
or later, although an interim facility may be available earlier. Under
current DOE policy, once a permanent site is available, the DOE will accept
spent nuclear fuel on a priority basis; the owners of the oldest spent fuel
will be given the highest priority. As a result, disposal services for Wolf
Creek may not be available prior to 2016. Wolf Creek has on-site temporary
storage for spent nuclear fuel. Under current regulatory guidelines, this
facility can provide storage space until about 2005. Wolf Creek is
implementing a plan to increase its on-site spent fuel storage capacity. That
project, expected to be completed by 2000, should provide storage capacity for
all spent fuel expected to be generated by Wolf Creek through the end of its
licensed life in 2025.

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated
that the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central
Interstate Low-Level Radioactive Waste Compact and selected a site in northern
Nebraska to locate a disposal facility. The present estimate of the cost for
such a facility is about $154 million. WCNOC and the owners of the other five
nuclear units in the compact have provided most of the pre-construction
financing for this project.

There is uncertainty as to whether this project will be completed.
Significant opposition to the project has been raised by Nebraska officials
and residents in the area of the proposed facility, and attempts have been
made

11
through litigation and proposed legislation in Nebraska to slow down or stop
development of the facility.

In December 1998, the Nebraska agencies considering the developer's
license application for the facility issued an order denying the application.
The developer has filed for a "contested case hearing" regarding the license
denial. This is the next step in appealing the agencies decision.

Also in December 1998, WCNOC and other utilities that have provided pre-
construction financing filed suit against the State of Nebraska, the licensing
agencies and others, seeking damages related to the utilities excessive costs
incurred because of the agencies delay in reaching a decision in this matter.

Wolf Creek has an 18-month refueling and maintenance schedule which
permits uninterrupted operation every third calendar year. Wolf Creek is
scheduled to be taken off-line on April 3, 1999 for its tenth refueling and
maintenance outage. During the outage electric demand is expected to be met
primarily by our coal-fired generating units.

Additional information with respect to insurance coverage applicable to
the operations of our nuclear generating facility is set forth in Note 2 of
the Notes to Financial Statements.

Environmental Matters

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

The Federal sulfur dioxide standards applicable to the company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million Btu of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million Btu of heat input and (2) an
opacity greater than 20%. Federal NOx emission standards applicable to these
units prohibit the emission of more than 0.7 pounds of NOx per million Btu of
heat input.

The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the NOx
standards through boiler design and operating procedures. The JEC units are
also equipped with flue gas scrubbers providing additional sulfur dioxide and
particulate matter emission reduction capability when needed to meet permit
limits.

The Kansas Department of Health and Environment (KDHE) regulations,
applicable to our other generating facilities, prohibit the emission of more
than 3.0 pounds of sulfur dioxide per million Btu of heat input at our
generating units. We have sufficient low sulfur coal under contract (See
Coal) to allow compliance with such limits at La Cygne 1 for the life of the
contract. All

12
facilities burning coal are equipped with flue gas scrubbers and/or
electrostatic precipitators.

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

All of our generating facilities are in substantial compliance with the
Best Practicable Technology and Best Available Technology regulations issued
by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are
administered in Kansas by the KDHE.

Additional information with respect to Environmental Matters is discussed
in Note 2 of the Notes to Financial Statements.

REGULATION AND RATES

We are subject as an operating electric utility to the jurisdiction of the
KCC which has general regulatory authority over our rates, extensions and
abandonments of service and facilities, valuation of property, the
classification of accounts and various other matters. We are also subject to
the jurisdiction of the FERC and the KCC with respect to the issuance of our
securities.

Additionally, we are subject to the jurisdiction of the FERC, including
jurisdiction as to rates with respect to sales of electricity for resale, and
the Nuclear Regulatory Commission as to nuclear plant operations and safety.

Additional information with respect to Regulation and Rates is discussed
in Notes 1 and 3 of the Notes to Financial Statements and Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.

EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years

Annette M. Beck 36 Chairman of the Board Vice President, Customer
(since January 1999) Service (since Oct. 1998),
and President (since Director - Customer
October 1998) Service (Aug 1997 to Oct
1998), and prior to that
Director - Strategic
Planning,
Western Resources, Inc.

Richard D. Terrill 44 Secretary, Treasurer
and General Counsel

Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the officers, nor any arrangements or

13
understandings between any officer and other persons pursuant to which she or
he was appointed as an officer.

ITEM 2. PROPERTIES

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

ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)

Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 152
2 1967 Gas--Oil 382

Jeffrey Energy Center (20%) (2):
Steam Turbines 1 1978 Coal 147
2 1980 Coal 148
3 1983 Coal 148

La Cygne Station (50%) (2):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 334

Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 44
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106

Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 0 (3)

Wichita Plant:
Diesel Generator 5 1969 Diesel 3

Wolf Creek
Generating Station (47%)(2):
Nuclear 1 1985 Uranium 547

Total 2,535

(1) Based on MOKAN rating.

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

(3) This unit has been "mothballed" for future use. In 1999 we plan
to return this unit to active service.
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FINANCING

Our ability to issue additional debt is restricted under limitations
imposed by our Mortgage and Deed of Trust.

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 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. Based on our results for the 12
months ended December 31, 1998, approximately $1.1 billion principal amount of
additional first mortgage bonds could be issued (7.0% interest rate assumed).

KGE bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1998, we had approximately $1.4 billion of net bondable property additions not
subject to an unfunded prior lien entitling us to issue up to $1 billion
principal amount of additional bonds. As of December 31, 1998, $17 million in
additional bonds could be issued on the basis of retired bonds.

In connection with the combination of the electric utility operations of
Western Resources, KCPL and the company, Westar Energy will assume $1.9
billion of indebtedness for borrowed money of Western Resources and the
company comprised primarily of the companies' outstanding long-term debt.
Pursuant to the amended and restated agreement and plan of merger, the
company's mortgage, by operation of law, will be assumed by Westar Energy.
See, Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations and Note 13 of Notes to Financial Statements.

ITEM 3. LEGAL PROCEEDINGS

Information on legal proceedings involving the company is set forth in
Notes 2, 3, and 8 of Notes to Financial Statements included herein. 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
J(2)(c) to Form 10-K.

15
PART II

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

Our common stock is owned by Western Resources and is not traded on an
established public trading market. See Note 13 of Notes to Financial
Statements for information concerning the effect on the ownership of our
common stock caused by the pending transaction with KCPL.

ITEM 6. SELECTED FINANCIAL DATA

1998 1997 1996 1995 1994
(Dollars in Thousands)

Income Statement Data:

Sales. . . . . . . . . . . . . . $ 648,379 $ 614,445 $ 654,570 $ 624,168 $ 619,893
Income from operations . . . . . 189,418 124,008 186,961 209,739 211,248
Net income . . . . . . . . . . . 103,765 52,128 96,274 110,873 104,526

Balance Sheet Data:

Total assets . . . . . . . . . . 3,057,971 3,117,108 3,318,887 3,203,414 3,237,684
Long-term debt . . . . . . . . . 684,167 684,128 684,068 684,082 699,992

Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 4.01 2.38 3.28 4.11 4.02

16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

INTRODUCTION

In Management's Discussion and Analysis we explain the general financial
condition and the operating results for the company. We explain:

- What factors impact our business
- What our earnings and costs were in 1998 and 1997
- Why these earnings and costs differed from year to year
- How our earnings and costs affect our overall financial condition
- What our capital expenditures were for 1998
- What we expect our capital expenditures to be for the years 1999
through 2001
- How we plan to pay for these future capital expenditures
- Any other items that particularly affect our financial condition or
earnings

As you read Management's Discussion and Analysis, please refer to our
Statements of Income on page 35. These statements show our operating results
for 1998, 1997 and 1996. In Management's Discussion and Analysis, we analyze
and explain the significant annual changes of specific line items in the
Statements of Income.

Forward-Looking Statements

Certain matters discussed here and elsewhere in this Annual Report are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect" or words of similar meaning. Forward-looking
statements describe our future plans, objectives, expectations or goals. Such
statements address future events and conditions concerning capital
expenditures, earnings, litigation, rate and other regulatory matters,
possible corporate restructurings, mergers, acquisitions, dispositions,
liquidity and capital resources, interest and dividend rates, Year 2000 Issue,
environmental matters, changing weather, nuclear operations and accounting
matters. What happens in each case could vary materially from what we expect
because of such things as electric utility deregulation, including ongoing
state and federal activities; future economic conditions; legislative
developments; our regulatory and competitive markets; and other circumstances
affecting anticipated operations, sales and costs.

1998 HIGHLIGHTS

We experienced warmer weather during the summer months in 1998 than we did
in 1997 which improved net income by $13.1 million. The effect of our
electric rate decrease lowered 1998 net income $6 million.
17
In January 1997, the Kansas Corporation Commission (KCC) entered an order
reducing our electric rates. Significant terms of the order are as follows:

- We made permanent the May 1996 interim $8.7 million decrease in our
annual rates on February 1, 1997
- We reduced our annual rates by $36 million on February 1, 1997
- We rebated $2.3 million to our customers in January 1998
- We reduced our annual rates by an additional $10 million on
June 1, 1998
- We rebated an additional $2.3 million to our customers in
January 1999
- We will reduce our annual rates by an additional $10 million on
June 1, 1999

These electric rate decreases have negatively impacted our net income.
The total cumulative effect of these rate decreases is approximately $65
million. All rate decreases are cumulative. Rebates are one-time events and
do not influence future rates.

Operating Results

In our "1998 Highlights", we discussed factors that most significantly
changed our operating results for 1998 compared to 1997.

1998 compared to 1997: Net income of $103.8 million increased
significantly from $52.1 million for 1997. The increase in net income is
primarily due to increased electric sales because of warmer weather, lower
operating and maintenance costs, the completion of the amortization of phase-
in revenues in December 1997, and death benefits received from corporate-owned
life insurance policies.

1997 compared to 1996: Net income of $52.1 million for 1997 decreased
substantially from $96.3 million for 1996. The decrease in net income is
primarily attributable to the implementation of a $36 million rate reduction
and an $8.7 million interim rate reduction which became permanent on February
1, 1997.

The following explains significant changes from prior year results in
sales, cost of sales, operating expenses, other income (expense), interest
expense and income taxes.

Sales

Sales are based on energy deliveries and rates authorized by the KCC and
the Federal Energy Regulatory Commission (FERC). Rates charged for the sale
and delivery of electricity are designed to recover the cost of service and
allow investors a fair rate of return. Our sales vary with levels of energy
deliveries. Changing weather affects the amount of energy our customers use.
Very hot summers and very cold winters prompt more demand, especially among
our residential customers. Mild weather reduces demand.
18
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

1998 compared to 1997: Sales increased $33.9 million or six percent due
to increased retail energy deliveries as a result of warmer summer
temperatures. Our annual $10 million electric rate decrease implemented on
June 1, 1998 and decreased wholesale energy deliveries partially offset this
increase.

The following table reflects the change in electric energy deliveries, as
measured by kilowatt hours, for retail customers for 1998 compared to 1997:

Increase
Residential. . . . . . . 11.8%
Commercial . . . . . . . 7.8%
Industrial . . . . . . . 1.5%
Total Retail . . . . . 6.3%

1997 compared to 1996: Sales decreased $40.1 million or six percent
because of lower electric rates which were implemented on February 1, 1997.
Reduced electric rates lowered 1997 sales by an estimated $36.8 million
compared to 1996. Sales volumes to our retail customers remained virtually
unchanged in 1997.

Cost of Sales

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

Electric fuel costs are included in base rates. Therefore, if we wished
to recover an increase in fuel costs, we would have to file a request for
recovery in a rate filing with the KCC which could be denied in whole or in
part. Any increase in fuel costs from the projected average which the company
did not recover through rates would reduce our earnings. The degree of any
such impact would be affected by a variety of factors, however, and thus
cannot be predicted.

1998 compared to 1997: Actual cost of fuel to generate electricity (coal,
nuclear fuel, natural gas or oil) and the amount of power purchased from other
utilities were $19.6 million higher in 1998 than in 1997. With an increase in
customer demand for electricity and the availability of our Wolf Creek nuclear
generating station and La Cygne coal generating station during 1998, we
produced more electricity during 1998 than in 1997. The increase in net
generation caused our fuel costs to increase during 1998.

In 1998, due to warmer than normal weather throughout the Midwest and a
lack of power available for purchase on the wholesale market, the wholesale
power market saw extreme volatility in prices and availability. We believe
future volatility, such as that recently experienced in the market, could
impact our cost of power purchased.
19
1997 compared to 1996: Actual cost of fuel to generate electricity and
the amount of power purchased from other utilities were $6.3 million higher in
1997 than in 1996. Our Wolf Creek nuclear generating station was off-line in
the fourth quarter of 1997 for scheduled maintenance and our La Cygne coal
generating station was off-line during 1997 for an extended maintenance
outage. As a result, we purchased more power from other utilities and burned
more natural gas to generate electricity at our facilities. Natural gas is
more costly to burn than coal and nuclear fuel for generating electricity.

Operating Expenses

Operating and Maintenance Expense

Operating and maintenance expense decreased $29.5 million in 1998 compared
to 1997. The decrease was attributable to a substantial decrease in KGE's
portion of costs shared with Western Resources which are associated with the
dispatching of electric power.

Operating and maintenance expense increased $4 million in 1997 compared to
1996. An extended maintenance outage at our La Cygne generating station
accounted for most of this increase.

We anticipate our operating expenses (including cost of sales) will
increase in 1999 as a result of Wolf Creek being taken out of service for
refueling and maintenance as discussed under Item 1. Business under "Fuel
Mix".

We also expect our operating and maintenance expense to increase when we
bring an inactive generating plant back into active service in 1999. See
LIQUIDITY AND CAPITAL RESOURCES below for further discussion of this project.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $24.6 million in 1998 due
to the complete amortization of a regulatory asset in 1997. During 1997 we
recorded $26.3 million of amortization relating to this regulatory asset.
Depreciation and amortization expense increased $9.6 million in 1997 from 1996
due to the additional amortization of $8.8 million we recorded relating to
phase-in revenues.

Selling, General and Administrative Expense

Selling, general and administrative expense increased $3 million in 1998.
Storm related restoration expenses and increased labor costs contributed to
the increase. In 1997 selling, general and administrative expense increased
$2.9 million from 1996. Most of this increase is attributable to higher
employee benefit costs.

Business Segments

We define and report our business segments based on how management
currently evaluates our business. We are evaluated from a segment perspective
as a part of our parent company, Western Resources. Our company is an
20
integral component of Western Resources and its financial position and
operations are managed as such. Based on the management approach to
determining business segments, our company only has one business segment.
This segment is nuclear generation. Our remaining operations of fossil
generation and energy delivery are fully integrated with those of Western
Resources.

We along with Western Resources manage our business segments' performance
based on our earnings before interest and taxes (EBIT). EBIT does not
represent cash flow from operations as defined by generally accepted
accounting principles, nor should it be construed as an alternative to
operating income. Additionally, it 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.

Allocated sales are external sales collected from customers by our
electric operations segment that are allocated to our nuclear generation
business segment based on demand and energy cost. The following discussion
identifies key factors affecting our business segment.

Nuclear Generation

1998 1997 1996
(Dollars in Thousands)
Allocated sales . . . . . . . . $117,517 $102,330 $100,592
Depreciation and amortization . 39,583 65,902 57,242
EBIT. . . . . . . . . . . . . . (20,920) (60,968) (51,585)

Nuclear fuel generation has no external sales because it provides all of
its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative,
Inc. The amounts above are our 47% share of Wolf Creek's operating results.

Allocated sales and EBIT were higher in 1998 because Wolf Creek operated
the entire year without any outages. In 1997, the Wolf Creek facility was off
line for 58 days for a scheduled maintenance outage.

Depreciation and amortization expense for 1998 compared to 1997 decreased
$26 million because we had fully amortized a regulatory asset during 1997.
This decrease in amortization expense increased EBIT for 1998.

Decommissioning: Decommissioning is a nuclear industry term for the
permanent shut-down of a nuclear power plant when the plant's license expires.
The Nuclear Regulatory Commission (NRC) will terminate a plant's license and
release the property for unrestricted use when a company has reduced the
residual radioactivity of a nuclear plant to a level mandated by the NRC. The
NRC requires companies with nuclear power plants to prepare formal financial
plans. These plans ensure that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
21
The Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:

- Our annual decommissioning expense could be higher than in 1998
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the
Wolf Creek plant

We do not believe that such changes, if required, would adversely affect
our operating results due to our current ability to recover decommissioning
costs through rates (see Note 2).

Stranded Costs

The definition of stranded costs for a utility business is the investment
in and carrying costs on property, plant and equipment and other regulatory
assets which exceed the amount that can be recovered in a competitive market.
We currently apply accounting standards that recognize the economic effects of
rate regulation and record regulatory assets and liabilities related to our
fossil generation, nuclear generation and power delivery operations. If we
determine that we no longer meet the criteria of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to
operations. Reasons for discontinuing SFAS 71 accounting treatment include
increasing competition that restricts our ability to charge prices needed to
recover costs already incurred and a significant change by regulators from a
cost-based rate regulation to another form of rate regulation. We
periodically review SFAS 71 criteria and believe our net regulatory assets,
including those related to generation, are probable of future recovery. If we
discontinue SFAS 71 accounting treatment based upon competitive or other
events, we may significantly impact the value of our net regulatory assets and
our utility plant investments, particularly the Wolf Creek nuclear generation
facility (Wolf Creek). See OTHER INFORMATION for initiatives taken to
restructure the electric industry in Kansas.

Regulatory changes, including competition, could adversely impact our
ability to recover our investment in these assets. As of December 31, 1998,
we have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $261 million. Of this amount, $176 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 that include coal contract settlement costs, deferred plant costs and
debt issuance costs.

In a competitive environment, we may not be able to fully recover our
entire investment in Wolf Creek. We presently own 47% of Wolf Creek. 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.
22
Other Income (Expense)

Other income (expense) includes miscellaneous income and expenses not
directly related to our operations. Other income (expense) increased $12.7
million in 1998 as compared to 1997. The increase is primarily attributable
to benefits received during 1998 pursuant to our corporate-owned life
insurance policies totaling $13.7 million. Other income (expense) for 1997
declined $7.7 million from 1996. The decrease is primarily due to income and
expenses relating to our corporate-owned life insurance policies.

Interest Expense

Interest expense includes the interest we paid on outstanding debt. In
1998 interest expense on short-term debt decreased $1 million. We repaid our
outstanding short-term debt balance during January 1998. After January 1998,
no short-term debt was held. Our average short-term debt balance during 1998
was $0.6 million compared to $22.9 million during 1997. The interest we paid
on long-term debt remained virtually unchanged.

We recognized a $7.4 million decrease in short-term debt interest in 1997
compared to 1996. During 1997 we held a smaller average short-term debt
balance than in 1996.

Income Taxes

Income taxes increased $27.6 million in 1998 as compared to 1997 as a
result of the substantial increase in our 1998 net income.

Income taxes decreased $18.9 million in 1997 as compared to 1996. The
decrease is primarily due to the decrease we recognized in 1997 net income.

LIQUIDITY AND CAPITAL RESOURCES

Overviews

Our cash requirements consist of capital expenditures and maintenance
program costs designed to improve 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.

At December 31, 1998, we had no short-term borrowings compared to $45
million at December 31, 1997.

Other funds are available to us from the sale of securities we register
for sale with the Securities and Exchange Commission (SEC). As of December
31, 1998, $50 million of KGE first mortgage bonds were registered.

The embedded cost of long-term debt was 7.2% and 7.3% at December 31, 1998
and 1997.

23
Capital Structure

Our capital structures at December 31, 1998, and 1997 were as follows:

1998 1997
Common Stock . . . . . . . . 62% 62%
Long-term Debt . . . . . . . 38% 38%
Total. . . . . . . . . . . . 100% 100%

Security Ratings

Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and
Moody's Investors Service (Moody's) are independent credit-rating agencies.
These agencies rate our debt securities. These ratings indicate the agencies'
assessment of our ability to pay interest, dividends and principal on these
securities. These ratings affect how much we will have to pay as interest or
dividends on securities we sell to obtain additional capital. The better the
rating, the less we will have to pay on debt securities we sell.

At December 31, 1998, ratings with these agencies were as follows:

Mortgage
Bond
Rating Agency Rating
S&P BBB+
Fitch A-
Moody's A3

Following the announcement of Western Resources restructed merger
agreement with KCPL, S&P placed its ratings of Western Resources and the
company on CreditWatch with positive implications.

Future Cash Requirements

We believe that internally generated funds and new credit agreements will
be sufficient to meet our operating and capital expenditure requirements and
debt service payments through the year 2001. Uncertainties affecting our
ability to meet these requirements with internally generated funds include the
effect of competition and inflation on operating expenses, sales volume,
regulatory actions, compliance with future environmental regulations, the
availability of generating units and weather. The amount of these
requirements and our ability to fund them will also be significantly impacted
by the pending combination of Western Resources electric utility operations,
KCPL and the company.

We are participating with Western Resources in the installation of three
new combustion turbine generators for use as peaking units. The installed
capacity of the three new generators will be 300 MW. The first two units are
scheduled to be placed in operation in 2000 and the third is scheduled to be
placed in operation in 2001. Western Resources estimates that the project
will require $120 million in capital resources through the completion of the

projects in 2001. The extent of our participation in these projects has not
been determined. We are also planning to return our inactive generation plant
in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7
million.
24
Our business requires a significant capital investment. We currently
expect that through the year 2001, we will need cash mostly for ongoing
utility construction and maintenance programs designed to maintain and improve
facilities providing electric service.

Capital expenditures for 1998 and anticipated capital expenditures for
1999 through 2001 are as follows:

Electric Nuclear
Operations Generation Total
(Dollars in Thousands)
1998. . . . . . . . . . $51,600 $25,800 $77,400
1999. . . . . . . . . . 61,000 19,700 80,700
2000. . . . . . . . . . 61,200 32,200 93,400
2001. . . . . . . . . . 60,600 21,200 81,800

These estimates are prepared for planning purposes and may be revised.
Actual expenditures may differ from our estimates. These expenditures do not
take into account the pending combination of Western Resources electric
utility operations, KCPL and the company.

Acquisition Adjustment Implementation

In accordance with the 1992 KCC merger order relating to the acquisition
of Kansas Gas and Electric Company by Western Resources, amortization of the
acquisition adjustment commenced August 1995. The amortization will amount to
approximately $20 million (pre-tax) per year for 40 years. We and Western
Resources (combined companies) are recovering the amortization of the
acquisition adjustment through cost savings under a sharing mechanism approved
by the KCC.

Based on the order issued by the KCC, with regard to the recovery of the
acquisition premium, the combined companies must achieve a level of savings on
an annual basis (considering sharing provisions) of approximately $27 million
in order to recover the entire acquisition premium.

On January 15, 1997, the KCC fixed the annual merger savings level at $40
million which provides complete recovery of the acquisition premium
amortization expense and a return on the acquisition premium. See Note 3 for
further information relating to rate matters and regulation.

As Western Resources' management presently expects to continue this level
of savings, the amount is expected to be sufficient to allow for the full
recovery of the acquisition premium.

25
OTHER INFORMATION

Competition and Enhanced Business Opportunities

The United States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the electricity industry. The Energy Policy Act permitted
the FERC to order electric utilities to allow third parties the use of their
transmission systems to sell electric power to wholesale customers. A
wholesale sale is defined as a utility selling electricity to a "middleman",
usually a city or its utility company, to resell to the ultimate retail
customer. As part of the 1992 merger, we agreed to open access of our
transmission system for wholesale transactions. FERC also requires us to
provide transmission services to others under terms comparable to those we
provide to ourselves. During 1998, wholesale electric sales represented
approximately 8% of total electric sales.

Various states have taken steps to allow retail customers to purchase
electric power from providers other than their local utility company. The
Kansas Legislature created a Retail Wheeling Task Force (the Task Force) in
1997 to study the effects of a deregulated and competitive market for electric
services. Legislators, regulators, consumer advocates and representatives
from the electric industry made up the Task Force. Several bills were
introduced to the Kansas Legislature in the 1998 legislative session, but none
passed. Hearings on retail wheeling bills are being held in the 1999
legislature. The outcome of retail wheeling legislature in Kansas remains
uncertain.

Increased competition for retail electricity sales may reduce future
electric utility earnings compared to our historical electric utility
earnings. After all ordered electric rate decreases are implemented, our
rates will be at 90% of the national average for retail customers. Because of
these reduced rates, we expect to retain a substantial part of our current
volume of energy deliveries in a competitive environment.

While operating in this competitive environment may place pressure on our
profit margins and credit ratings, we expect it to create opportunities.
Wholesale and industrial customers may pursue cogeneration, self-generation,
retail wheeling, municipalization or relocation to other service territories
in an attempt to cut their energy costs. Credit rating agencies are applying
more stringent guidelines when rating utility companies due to increasing
competition.

We offer competitive electric rates for industrial improvement projects
and economic development projects in an effort to maintain and increase
electric load.

Year 2OOO Issue

We, as part of the Western Resources Year 2000 readiness program, are
currently addressing the effect of the Year 2000 Issue on information systems
and operations. We face the Year 2000 Issue because many computer systems and
applications abbreviate dates by eliminating the first two digits of the year,
assuming that these two digits are always "19". On January 1, 2000, some
computer programs may incorrectly recognize the date as January 1, 1900. Some
computer systems and applications may incorrectly process critical information
26
or may stop processing altogether because of the date abbreviation.
Calculations using dates beyond December 31, 1999 may affect computer
applications before January 1, 2000.

We have recognized the potential adverse effects the Year 2000 Issue could
have on our company. The company shares information and computer systems with
Western Resources. In 1996, we established a formal Year 2000 readiness
program to investigate and correct these problems in the main computer systems
of our company. In 1997, we expanded the program to include all departments
and business units of our company, using a common methodology. The Year 2000
issues concerning the Wolf Creek nuclear operating plant are discussed under
WCNOC below.

The goal of our Year 2000 readiness program is to identify and assess all
critical computer programs, computer hardware and embedded systems potentially
affected by the Year 2000 date change, to repair or replace those systems
found to be incompatible with Year 2000 dates, and to develop predetermined
actions to be used as contingencies in the event any critical business
function fails unexpectedly or is interrupted. The program is directed by a
written policy which provides the guidance and methodology to the departments
and business units to follow. Due to varying degrees of exposure of
departments and business units to the Year 2000 Issue, some departments and
business units are further along in their readiness efforts than others. All
departments have completed the awareness, inventory, and assessment phases,
and have developed their initial contingency plans. Several smaller
departments and business units have completed the assessment, remediation, and
testing phases. The majority of our current efforts are in the remediation
and testing phases. Overall, based on manhours as a measure of work effort,
Western Resources believes it is approximately 74% complete with its readiness
efforts.

The estimated progress of Western Resources departments and business
units, exclusive of WCNOC, at December 31, 1998, based on manhours, is as
follows:

Percentage
Department/Business Unit Completion

Fossil Fuel . . . . . . . . . . . . . . 81%
Power Delivery. . . . . . . . . . . . . 73%
Information Technology. . . . . . . . . 76%
Administrative. . . . . . . . . . . . . 69%

Our Year 2000 readiness program addresses all Information Technology (IT)
and non-IT issues which may be impacted by the Year 2000 Issue. We have
included commercial computer software, including mainframe, client/server, and
desktop software; internally developed computer software, including mainframe,
client/server, and desktop software; computer hardware, including mainframe,
client/server, desktop, network, communications, and peripherals; devices
using embedded computer chips, including plant equipment, controls, sensors,
facilities equipment, heating, ventilating, and air conditioning (HVAC)
equipment; and relationships with third-party vendors, suppliers, and
customers. Our program requires testing as a method for verifying the Year
2000 readiness of an item. For those items which are impossible to test,
27
other methods are being used to identify the readiness status, provided
adequate contingency plans are established to provide a workaround or backup
for the item. Our Year 2000 readiness efforts were substantially completed by
the end of 1998 except for those items scheduled for normal maintenance or
upgrade during 1999.

Western Resources currently estimates that total costs to update all of
its electric utility operating systems for Year 2000 readiness, excluding
costs associated with WCNOC discussed below, to be approximately $7 million,
of which $4.2 million represents IT costs and $2.8 million represents non-IT
costs. As of December 31, 1998 Western Resources has expensed approximately
$4.1 million of these costs, of which $3.2 million represent IT costs and $0.9
million represent non-IT costs. Based on what they know, they expect to incur
the remaining $2.9 million, of which $1 million represents IT costs and $1.9
million represents non-IT costs, by the end of 1999. These costs include
labor costs for both Western Resources' employees and contract personnel used
in our Year 2000 program, and non-labor costs for software tools used in our
remediation and testing efforts, replacement software, replacement hardware,
replacement embedded devices, and miscellaneous costs associated with their
testing and replacement. Western Resources has allocated approximately $1.6
million of the expensed costs to our company and we expect an additional $1.2
million to be allocated for the remaining costs to be incurred.

We have identified the following major areas of risk relating to our Year
2000 Issue exposure: 1) vendors and suppliers, 2) internal plant controls and
systems, 3) telecommunications, including phone systems and cellular phones,
4) large customers, and 5) rail transportation. We consider vendors and
suppliers a risk because of the lack of control we have over their operations.
We are in the process of contacting by letter each vendor or supplier critical
to our operations for information pertaining to their Year 2000 readiness. We
consider our plant controls and systems a risk due to the complexity, variety,
and extent of the embedded systems. We consider telecommunications a risk
because it performs a critical function in a large number of our business
processes and plant control functions. We consider large customers a risk
because of the influence their electrical usage patterns have on our
electrical generation and distribution systems. We consider rail
transportation a risk because of our dependence for delivery of coal used at
our coal-fired generating plants.

The most reasonably likely worst case scenario we anticipate is the loss
or partial interruption of local and long-distance telephone service, the
interruption or significant delay to rail service effecting the coal
deliveries to our generating plants, the unscheduled shut-down of the Wolf
Creek nuclear operating plant, the potential loss of load from one or more
large customers, and the loss of minimal generating capacity in the region for
brief periods of time. Approximately 44% of our generating capacity utilizes
coal as fuel and 22% of our generating capacity is attributed to Wolf Creek.

We are addressing these risks in our contingency plans, and have or will
be implementing a number of action plans in advance to mitigate these and
other potential risks. Our contingency plans include pre-established actions
to deal with potential operational impacts. For example, we have installed a
company-wide trunked radio system which can be used in place of the commercial
telecommunications systems, in the event those systems are interrupted. We
plan to place in service, at reduced output, generating units which would
28
normally not be in service to help accommodate load shifts that would be
caused by a large customer suddenly dropping or significantly reducing their
electricity usage, or in the event of unexpected loss of some of our
generation capacity or generation capacity of others in the region. In
addition, we generally maintain more than a 30-day supply of coal at each of
our coal-fired generating plants, reducing the effect of any temporary
interruption of rail transportation and an unscheduled
temporary shut-down of the Wolf Creek nuclear operating plant discussed below.

While all business units and departments have developed contingency plans
to cover essential business functions and anticipated possible Year
2000-related failure or interruption, these plans are continually reviewed and
updated based on information learned as our Year 2000 readiness efforts
proceed.

WOLF CREEK NUCLEAR OPERATING CORPORATION (WCNOC): WCNOC has been
evaluating and adjusting all known date-sensitive systems and equipment for
Year 2000 compliance. WCNOC is developing a plan to effect the readiness of
the plant for the coming of the Year 2000. This plan is designed to closely
parallel the guidance provided by the Nuclear Energy Institute and the Nuclear
Regulatory Commission (NRC). WCNOC is partnering with several industry groups
to share information regarding evaluating items that are Year 2000 sensitive.
As applications and devices are confirmed to be Year 2000 non-compliant,
business decisions are being made to repair or retire the item.

On May 11,1998 the NRC issued Generic Letter 98-01 entitled "Year 2000
Readiness of Computer Systems at Nuclear Power Plants." This letter expressed
the NRC's expectations with regard to Year 2000 readiness. The letter also
requires the licensee to file its Year 2000 plan and status report no later
than July 1, 1999.

WCNOC is developing contingency plans to address risk associated with
Year 2000 Issues. These plans generally follow the guidance contained in
NUCLEAR ENERGY INSTITUTE/NUCLEAR UTILITY SOFTWARE MANAGEMENT GROUP 98-07,
NUCLEAR UTILITY READINESS CONTINGENCY PLANNING. The steps to be taken involve
the determination of which items present a critical risk to the facility,
review of the identified risks, determining mitigation strategies, and
ensuring that each responsible organization develops appropriate contingency
plans.

In order to assess the licensees progress in preparing for Year 2000, the
NRC scheduled audits at various nuclear power plant facilities during 1998 and
early 1999. One of these audits was conducted at WCNOC during the month of
November 1998. The findings of this audit were as follows:

- The NEI/NUSMG 97-07 guidance is being followed. The Wolf Creek licensee
has not identified any systems needed for safe shutdown as having Year
2000 problems.
- Wolf Creek is making use of its existing quality assurance and
modification programs and procedures to achieve Year 2000 readiness.
Furthermore, Wolf Creek is engaged in extensive information sharing
and interfaces with other entities on Year 2000 Issues.
- The need for Year 2000 contingency planning is understood by the Wolf
Creek licensee and in keeping with the NEI/NUSMG 98-07 recommendation,
one individual has been designated as the single point of contact for
contingency planning.
29
- Wolf Creek is at the detailed assessment phase except for the items of
minimal significance designated as Limited Use Databases and
spreadsheets, which come under the category of Limited Use Hardware/
Software. Year 2000 readiness for Wolf Creek is scheduled for
September 15, 1999, and can be achieved based on the effort underway.
- Executive management support was found to be aggressive at Wolf Creek.
Management at Wolf Creek has dedicated the fiscal resources needed
for successful completion of the year 2000 readiness program.

Since Wolf Creek was designed during the 1970s and 1980s, most of the
originally installed electronic plant equipment did not contain
microprocessors. During this time frame, the NRC would not allow components
required for safe shutdown of the plant to contain microprocessors. For these
reasons, there is minimal Year 2000 risk associated with being able to safely
shutdown the plant and maintain it in a safe shutdown condition. During the
years since original construction, microprocessor based electronic components
have been added in non-safe shutdown applications. Some of these (only two
identified thus far and no others are anticipated) could shutdown the plant.
Special attention will be paid to these devices to ensure that there is
minimal Year 2000 risk associated with them.

In the original design and through plant modifications, microprocessor
based components were installed in plant monitoring applications such as the
radiation monitoring equipment and the plant information computer. Similarly,
in the area of non-plant operation computers and applications, WCNOC has
several items which will require remediation. There is a possibility that
these devices could cause a Year 2000 problem. Failure to adequately
remediate any Year 2000 problems could require the plant's operations be
limited or shutdown.

WCNOC estimates that the most reasonably likely worse case scenario would
be a temporary plant shutdown due to external electrical grid disturbances.
While these disturbances may result in a temporary shutdown, the safety of the
plant will not be compromised and the unit should restart shortly after the
grid disturbance has been corrected.

The table below sets forth estimates of the status of the components of
WCNOC's Year 2000 readiness program at December 31, 1998.

Estimated
Completion Percentage
Phase Date Completion

Identification and assessment of plant components Mar 99 89%
Identification and assessment of computers/software (Note 1) Jun 99 64%
Identification and Assessment of Other Areas (Note 2) Jun 99 47%
Identified remediations complete (Note 3) Sep 99 31%
Comprehensive testing guidelines 100%
Comprehensive testing (Note 4) Jun 99 13%
Contingency planning guidelines 100%
Contingency planning individual plans Mar 99 15%

Note 1 - Several computers are on three year lease and will not be obtained until 1999.
Note 2 - Includes items such as measuring/test and telecommunications equipment.
Note 3 - Two major modifications are currently scheduled to be completed after June 1999,
the remaining remediations are presently scheduled for completion prior to July 1999.
Note 4 - Several tests will not be performed until remediations are complete.

30
WCNOC has established a goal of completing all assessments of affected
systems by the end of the second quarter of 1999, with remediations being
completed by the end of the third quarter. Remediations are being planned and
initiated as the detailed assessment phase identifies the need, not at the end
of the assessment period. The areas where the greatest potential for
necessary remediations and/or more complex remediations could result were the
first ones targeted for assessment so remediation planning could be started
earlier. Many remediations will be completed before the end of the assessment
period. In addition, WCNOC is communicating with others with which its
systems interface or on which they rely with respect to those companies' Year
2000 compliance. Letters have been sent to all pertinent vendors to acquire
this information.

WCNOC has estimated the costs to complete the Year 2000 project at $4.6
million ($2.1 million, our share). As of December 31, 1998, $1.4 million
($0.6 million, our share) had been spent on the project. A summary of the
projected costs to complete and actual costs incurred through December 31,
1998 is as follows:

Projected Actual
Costs Costs
(Dollars in Thousands)

Wolf Creek Labor and Expenses. . $ 494 $ 261
Contractor Costs . . . . . . . . 646 493
Remediation Costs. . . . . . . . 3,493 611
Total. . . . . . . . . . . . . $4,633 $1,365

Approximately $3.5 million ($1.6 million, our share) of WCNOC's total Year
2000 cost is associated with remediation. Of these remediation costs, $2.4
million ($1.1 million, our share) are associated with seven major jobs which
are in the initial stages. All of these costs are being expensed as they are
incurred and are being funded on a daily basis along with our normal costs of
operations. In order to minimize the effects of delaying other information
technology projects, WCNOC has and will continue to augment staffing during
the identification and remediation phases of the project. This staffing,
which will include both programmers and technical support personnel, will also
be available during the testing and initial operating phases of the various
systems.

Market Risk Disclosure

Market Price Risk: The company is exposed to market risk, including
changes in commodity prices and interest rates.

Commodity Price Exposure: The company uses derivatives for non-trading
purposes primarily to reduce exposure relative to the volatility of cash
market prices. Given the amount of power purchased for during 1998, the
company would have had exposure of approximately $3 million of operating
income for a 10% increase in price per MW of electricity. Based upon mmbtu's
of natural gas and fuel oil burned during 1998, the company had exposure of
approximately $3 million of operating income for a 10% change in average price
paid per mmbtu. Quantities of natural gas and electricity could vary
dramatically year to year based on weather, unit outages and nuclear
refueling.
31
Interest Rate Exposure: The company has approximately $46 million of
variable rate debt as of December 31, 1998. A 100 basis point change in each
debt series benchmark rate would impact net income on an annual basis by
approximately $0.5 million.

Western Resources Merger Agreement with Kansas City Power & Light Company

On February 7, 1997, Western Resources signed a merger agreement with KCPL
by which KCPL would be merged with and into Western Resources in exchange for
Western Resources common stock. In December 1997, representatives of Western
Resources' financial advisor indicated that they believed it was unlikely that
they would be in a position to issue a fairness opinion required for the
merger on the basis of the previously announced terms.

On March 18, 1998, Western Resources and KCPL agreed to a restructuring of
their February 7, 1997 merger agreement which will result in the formation of
Westar Energy, a new electric company. Under the terms of the merger
agreement, the electric utility operations of Western Resources will be
transferred to the company, and KCPL and the company will be merged into NKC,
Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar
Energy. In addition, under the terms of the merger agreement, KCPL
shareholders will receive Western Resources common stock which is subject to a
collar mechanism of not less than .449 nor greater than .722, provided the
amount of Western Resources common stock received may not exceed $30.00, and
one share of Westar Energy common stock per KCPL share. The Western Resources
Index Price is the 20 day average of the high and low sale prices for Western
Resources common stock on the NYSE ending ten days prior to closing. If the
Western Resources Index Price is less than or equal to $29.78 on the fifth day
prior to the effective date of the combination, either party may terminate the
agreement. Upon consummation of the combination, Western Resources will own
approximately 80.1% of the outstanding equity of Westar Energy and KCPL
shareholders will own approximately 19.9%. As part of the combination, Westar
Energy will assume all of the electric utility related assets and liabilities
of Western Resources, KCPL, and the company.

Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion
of indebtedness for borrowed money of Western Resources and the company, and
$800 million from KCPL. Long-term debt of Western Resources, excluding
Protection One (a subsidiary of Western Resources), and the company was $2.5
billion at December 31, 1998. Under the terms of the merger agreement, it is
intended that Western Resources will be released from its obligations with
respect to the company's debt to be assumed by Westar Energy. For additional
information concerning the company's long-term debt and obligations under the
La Cygne sale leaseback arrangements which will become obligations of Westar
Energy, see Note 5 and Note 6 of Notes to Financial Statements.

Consummation of the merger is subject to customary conditions. On July
30, 1998, the Western Resources' shareholders and the shareholders of KCPL
voted to approve the amended merger agreement at special meetings of
shareholders. Western Resources estimates the transaction to close in 1999,
subject to receipt of all necessary approvals from regulatory and government
agencies.
32
In testimony filed in February 1999, the KCC staff recommended the merger
be approved but with conditions which Western Resources believes would make
the merger uneconomical. The KCC is under no obligation to accept the KCC
staff recommendation. In addition, legislation has been proposed in Kansas
that could impact the transaction. Western Resources does not anticipate the
proposed legislation to pass in its current form. Western Resources is not
able to predict whether any of these initiatives will be adopted or their
impact on the transaction, which could be material.

On August 7, 1998, Western Resources and KCPL filed an amended application
with the FERC to approve the Western Resources/KCPL merger and the formation
of Westar Energy.

Western Resources has received procedural schedule orders in Kansas and
Missouri. These schedules indicate hearing dates beginning May 3, 1999 in
Kansas and July 26, 1999 in Missouri.

In February 1999, KCPL advised Western Resources that its Hawthorne
generating station (479 MW coal facility) suffered material damage to its
boiler which could prevent the unit's operation for an extended period.
Western Resources is not able to ascertain at this time the impact of this
matter on the merger.

KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. We, KCPL and Western Resources have joint interests in
certain electric generating assets, including Wolf Creek. For additional
information see Note 11. Following the closing of the combination, Westar
Energy is expected to have approximately one million electric utility
customers in Kansas and Missouri, approximately $8.2 billion in assets and the
ability to generate more than 8,800 megawatts of electricity.

At December 31, 1998, Western Resources had deferred approximately $14
million related to the KCPL transaction. These costs will be included in the
determination of the total consideration upon consummation of the transaction.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information relating to market risk disclosure is set forth in Other
Information of Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations included herein.
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Report of Independent Public Accountants 34

Financial Statements:

Balance Sheets, December 31, 1998 and 1997 35
Statements of Income for the years ended
December 31, 1998, 1997 and 1996 36
Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 37
Statements of Common Shareholders' Equity for the years ended
December 31, 1998, 1997 and 1996 38
Notes to Financial Statements 39

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.

34
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying balance sheets of Kansas Gas and Electric
Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December
31, 1998 and 1997, and the related statements of income, cash flows and common
shareholders' equity for each of the three years in the period ended December
31, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 27, 1999
35

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

December 31,
1998 1997
ASSETS

CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 41 $ 43
Accounts receivable (net) . . . . . . . . . . . . . . . . 66,513 66,654
Advances to parent company (net). . . . . . . . . . . . . 64,405 72,558
Inventories and supplies (net). . . . . . . . . . . . . . 43,121 41,019
Prepaid expenses and other. . . . . . . . . . . . . . . . 15,097 17,165
Total Current Assets. . . . . . . . . . . . . . . . . . 189,177 197,439

PROPERTY, PLANT AND EQUIPMENT (NET) . . . . . . . . . . . . 2,527,357 2,565,175

OTHER ASSETS:
Regulatory assets . . . . . . . . . . . . . . . . . . . . 260,789 278,568
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 80,648 75,926
Total Other Assets. . . . . . . . . . . . . . . . . . . 341,437 354,494

TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . $3,057,971 $3,117,108

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Short-term debt . . . . . . . . . . . . . . . . . . . . . $ - $ 45,000
Accounts payable. . . . . . . . . . . . . . . . . . . . . 78,510 81,986
Accrued liabilities . . . . . . . . . . . . . . . . . . . 34,199 32,745
Accrued income taxes. . . . . . . . . . . . . . . . . . . 29,599 4,212
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,020 4,032
Total Current Liabilities . . . . . . . . . . . . . . . 148,328 167,975

LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,167 684,128
Deferred income taxes and investment tax credits. . . . . 785,116 820,838
Deferred gain from sale-leaseback . . . . . . . . . . . . 209,951 221,779
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 92,165 87,909
Total Long-term Liabilities . . . . . . . . . . . . . . 1,771,399 1,814,654

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY:
Common stock, without par value,
authorized and issued 1,000 shares . . . . . . . . . 1,065,634 1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . 72,610 68,845
Total Shareholders' Equity . . . . . . . . . . . . . . . 1,138,244 1,134,479

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY . . . . . . . . . $3,057,971 $3,117,108

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

36

KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Dollars in Thousands)

Year Ended December 31,
1998 1997 1996

SALES . . . . . . . . . . . . . . . . . . . . . . . . . $ 648,379 $ 614,445 $ 654,570

COST OF SALES . . . . . . . . . . . . . . . . . . . . . 149,360 129,756 123,269

GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . . 499,019 484,689 531,301

OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . . 150,502 179,991 176,113
Depreciation and amortization . . . . . . . . . . . . 98,822 123,423 113,853
Selling, general and administrative expense . . . . . 60,277 57,267 54,374
Total Operating Expenses. . . . . . . . . . . . . 309,601 360,681 344,340

INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . 189,418 124,008 186,961

OTHER INCOME (EXPENSE). . . . . . . . . . . . . . . . . 8,676 (4,022) 3,633

INCOME BEFORE INTEREST AND TAXES. . . . . . . . . . . . 198,094 119,986 190,594

INTEREST EXPENSE:
Interest expense on long-term debt. . . . . . . . . . 45,990 46,062 46,304
Interest expense on short-term debt and other . . . . 3,368 4,388 11,758
Total Interest Expense. . . . . . . . . . . . . . 49,358 50,450 58,062

INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . 148,736 69,536 132,532

INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . 44,971 17,408 36,258

NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 103,765 $ 52,128 $ 96,274

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

37

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

Year Ended December 31,
1998 1997 1996

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 103,765 $ 52,128 $ 96,274
Depreciation and amortization . . . . . . . . . . . . . . 98,822 123,423 113,853
Amortization of deferred gain from sale-leaseback . . . . (11,828) (11,281) (9,640)
Changes in working capital items:
Accounts receivable (net) . . . . . . . . . . . . . . . 141 9,017 819
Inventories and supplies (net). . . . . . . . . . . . . (2,102) 2,627 5,333
Prepaid expenses and other. . . . . . . . . . . . . . . 2,068 (174) 138
Accounts payable. . . . . . . . . . . . . . . . . . . . (3,476) 33,167 (1,964)
Accrued liabilities . . . . . . . . . . . . . . . . . . 1,454 (3,710) 17,744
Accrued income taxes. . . . . . . . . . . . . . . . . . 25,387 (7,016) 1,555
Other . . . . . . . . . . . . . . . . . . . . . . . . . 1,988 186 (47)
Changes in other assets and liabilities . . . . . . . . . (1,870) (11,013) 3,641
Net cash flows from operating activities. . . . . . . 214,349 187,354 227,706

CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment (net). . . . . (77,419) (88,165) (68,095)
Net cash flows (used in) investing activities . . . . (77,419) (88,165) (68,095)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . (45,000) (177,300) 172,300
Advances to parent company (net). . . . . . . . . . . . . 8,153 178,175 (215,785)
Retirements of long-term debt . . . . . . . . . . . . . . (85) (65) (16,135)
Dividends to parent company . . . . . . . . . . . . . . . (100,000) (100,000) (100,000)
Net cash flows (used in) financing activities. . . . . (136,932) (99,190) (159,620)

NET (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . . (2) (1) (9)

CASH AND CASH EQUIVALENTS:
Beginning of period . . . . . . . . . . . . . . . . . . . 43 44 53
End of period . . . . . . . . . . . . . . . . . . . . . . $ 41 $ 43 $ 44

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized) . . . . . . . . . . . . . . . . . . . . $ 75,611 $ 74,418 $ 78,712
Income taxes . . . . . . . . . . . . . . . . . . . . . . 37,520 52,100 32,100

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

38

KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF SHAREHOLDERS' EQUITY
(Dollars in Thousands)

Year Ended December 31,
1998 1997 1996

Common Stock . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634 $1,065,634

Retained Earnings:
Beginning balance . . . . . . . . . . . . . . . . 68,845 116,717 120,443
Net income. . . . . . . . . . . . . . . . . . . . 103,765 52,128 96,274
Dividends to parent company . . . . . . . . . . . (100,000) (100,000) (100,000)
Ending balance. . . . . . . . . . . . . . . . . . 72,610 68,845 116,717

Total Shareholders' Equity. . . . . . . . . . . . . . $1,138,244 $1,134,479 $1,182,351

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

39

KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business: Kansas Gas and Electric Company (the company,
KGE) is a rate-regulated electric utility and wholly-owned subsidiary of
Western Resources, Inc. (Western Resources). The company is engaged
principally in the production, purchase, transmission, distribution, and sale
of electricity. The company serves approximately 283,000 electric customers
in southeastern Kansas. At December 31, 1998, the company had no employees.
All employees are provided by the company's parent, Western Resources, which
allocates costs related to the employees of 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
generally accepted accounting principles. 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.

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 that includes: contracted services, direct labor and materials, indirect
charges for engineering, supervision, general and administrative costs, and an
allowance for funds used during construction (AFUDC). The AFUDC rate was
6.00% for 1998, 5.86% for 1997, and 5.71% for 1996. The cost of additions and
replacement units of property are capitalized. Maintenance costs and
replacement of minor items of property are charged to expense as incurred.
When units of depreciable property are retired, they are removed from the
plant accounts and the original cost plus removal charges less salvage are
charged to accumulated depreciation. Inventories and supplies are stated at
average cost.
40
In accordance with regulatory decisions made by the KCC, the acquisition
premium of approximately $801 million resulting from the KGE acquisition in
1992 is being amortized over 40 years. The acquisition premium is classified
as property, plant and equipment on the Balance Sheets. Accumulated
amortization as of December 31, 1998 and 1997 totaled $68.0 million and $47.9
million, respectively.

Depreciation: Property, plant and equipment is depreciated on the
straight-line method at rates approved by regulatory authorities. Property,
plant and equipment is depreciated on an average annual composite basis using
group rates that approximated 2.75% during 1998, 2.76% during 1997, and 2.81%
during 1996. The company periodically evaluates its depreciation rates
considering the past and expected future experience in the operation of its
facilities.

Fuel Costs: The cost of nuclear fuel in process of refinement,
conversion, enrichment, and fabrication is recorded as an asset at original
cost and is amortized to expense based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel
in the reactor at December 31, 1998 and 1997, was $39.5 and $20.9 million,
respectively.

Regulatory Assets and Liabilities: Regulatory assets represent probable
future sales 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 was required to
terminate application of that statement for all of its regulated operations,
the company would have to record the amounts of all regulatory assets and
liabilities in its 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 at
December 31, 1998 and 1997 are as follows:

December 31, 1998 1997
(Dollars in Thousands)
Recoverable taxes. . . . . . . . . . . . $175,759 $187,801
Debt issuance costs. . . . . . . . . . . 40,102 43,045
Deferred plant costs . . . . . . . . . . 30,657 30,979
Coal contract settlement costs . . . . . 8,392 10,035
Other regulatory assets. . . . . . . . . 5,879 6,708
Total regulatory assets . . . . . . . $260,789 $278,568

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

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

Deferred plant costs: Disallowances related to the Wolf Creek nuclear
generating facility.
41
Coal contract settlement costs: The company deferred costs associated
with the termination of certain coal purchase contracts. These costs
are being amortized through the year 2002.

The company expects to recover all of the above regulatory assets in
rates. A return is allowed on debt issuance costs, other than the refinancing
of the La Cygne 2 lease, deferred plant costs and coal contract settlement
costs.

Sales: Sales are recognized as services are rendered and include
estimated amounts for energy delivered but unbilled at the end of each year.
Unbilled sales of $22.0 million and $21.5 million are recorded as a component
of accounts receivable (net) on the Balance Sheets as of December 31, 1998 and
1997, respectively.

The company's allowance for doubtful accounts receivable totaled $1.9
million and $1.7 million at December 31, 1998 and 1997, respectively.

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

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:

1998 1997
(Dollars in Millions)
Cash surrender value of policies. . . . $486.3 $453.8
Borrowings against policies . . . . . . 476.9 442.2
COLI (net). . . . . . . . . . . . . . . $ 9.4 $ 11.6

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 $13.7
million in 1998, $0.6 in 1997 and $5.5 in 1996.

New Pronouncements: In June 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133). This statement
establishes accounting and reporting standards requiring that every derivative
instrument, including certain derivative instruments embedded in other
contracts, be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting and is effective for fiscal years beginning after June 15,
42
1999. SFAS 133 cannot be applied retroactively. SFAS 133 must be applied to
(a) derivative instruments and (b) certain derivative instruments embedded in
hybrid contracts that were issued, acquired, or substantively modified after
December 31, 1997 and, at the company's election, before January 1, 1998. The
company will adopt SFAS 133 no later than January 1, 2000. Management is
presently evaluating the impact that adoption of SFAS 133 will have on the
company's financial position and results of operations. Adoption of SFAS 133,
however, could increase volatility in earnings.

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

2. COMMITMENTS AND CONTINGENCIES

Manufactured Gas Sites: The company has been associated with three
former manufactured gas sites 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 upon the results
of the investigations and risk analyses. At December 31, 1998, 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. The company does not expect
material capital expenditures to be required to meet Phase II sulfur dioxide
and nitrogen oxide requirements.

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

In February 1997, the KCC approved the 1996 Decommissioning Cost Study.
Based on the study, the company's share of WCNOC's decommissioning costs,
under the immediate dismantlement method, is estimated to be approximately
$624 million during the period 2025 through 2033, or approximately $192
million in 1996 dollars. These costs were calculated using an assumed
inflation rate of 3.6% over the remaining service life from 1996 of 29 years.

Decommissioning costs are currently being charged to operating expense in
accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf
Creek. Amounts expensed approximated $3.8 million in 1998 and will increase
annually to $5.6 million in 2024. These amounts are deposited in an external
trust fund. The average after-tax expected return on trust assets is 5.7%.

The company's investment in the decommissioning fund, including
reinvested earnings approximated $52.1 million and $43.5 million at December
31, 1998 and 1997, respectively. Trust fund earnings accumulate in the fund
balance and increase the recorded decommissioning liability.
43
The Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:

- The company's annual decommissioning expense could be higher than in
1998
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the
Wolf Creek plant

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

Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.7 billion for a single
nuclear incident. If this liability limitation is insufficient, the U.S.
Congress will consider taking whatever action is necessary to compensate the
public for valid claims. The Wolf Creek owners (Owners) have purchased the
maximum available private insurance of $200 million. The remaining balance is
provided by an assessment plan mandated by the Nuclear Regulatory Commission
(NRC). Under this plan, the Owners are jointly and severally subject to a
retrospective assessment of up to $88.1 million ($41.4 million, company's
share) in the event there is a major nuclear incident involving any of the
nation's licensed reactors. This assessment is subject to an inflation
adjustment based on the Consumer Price Index and applicable premium taxes.
There is a limitation of $10 million ($4.7 million, company's share) in
retrospective assessments per incident, per year.

The Owners carry decontamination liability, premature decommissioning
liability and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion, company's share). This insurance is provided by
Nuclear Electric Insurance Limited (NEIL). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination in accordance with a plan approved by the NRC. The company's
share of any remaining proceeds can be used for property damages. If an
accident at Wolf Creek exceeds $500 million in property damage and
decontamination expenses and the decision is made to decommission the plant,
the company's share of any remaining proceeds can be used to make up a
shortfall in the decommissioning trust fund.

The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves and other NEIL resources, the company may be subject to retrospective
assessments under the current policies of approximately $7 million per year.

Although the company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or an
extended outage, the company's insurance coverage may not be adequate to cover
the costs that could result from a catastrophic accident or extended outage at
Wolf Creek. Any substantial losses not covered by insurance, to the extent
not recoverable through rates, would have a material adverse effect on the
company's financial condition and results of operations.
44
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, coal and natural gas. Some of these contracts contain
provisions for price escalation and minimum purchase commitments. At December
31, 1998, WCNOC's nuclear fuel commitments (company's share) were
approximately $6.1 million for uranium concentrates expiring at various times
through 2001, $24.9 million for enrichment expiring at various times through
2003 and $60.1 million for fabrication through 2025.

At December 31, 1998, the company's coal contract commitments in 1998
dollars under the remaining terms of the contracts were approximately $598.3
million. The largest coal contract expires in 2020, with the remaining coal
contracts expiring at various times through 2013.

At December 31, 1998, the company's natural gas transportation commitment
in 1998 dollars under the remaining terms of the contract were approximately
$0.5 million. The natural gas transportation contract provides firm service
to the company's Neosho gas burning facility through 2003.

Energy Act: As part of the 1992 Energy Policy Act, a special assessment
is being collected from utilities for a uranium enrichment decontamination and
decommissioning fund. The company's portion of the assessment for Wolf Creek
is approximately $7 million, payable over 15 years. Management expects such
costs to be recovered through the ratemaking process.

3. RATE MATTERS AND REGULATION

KCC Rate Proceedings: In January 1997, the KCC approved an agreement
that reduced electric rates for the company. Significant terms of the
agreement are as follows:

- The company made permanent an interim $8.7 million rate reduction
implemented in May 1996. This reduction was effective February
1, 1997.
- The company reduced annual rates by $36 million effective February
1, 1997.
- The company rebated $2.3 million to its customers in January 1998.
- The company reduced annual rates by an additional $10 million
on June 1, 1998.
- The company rebated an additional $2.3 million to its
customers in January 1999.
- The company will reduce annual rates by an additional $10 million
on June 1, 1999.

All rate decreases are cumulative. Rebates are one-time events and do
not influence future rates.
45

4. SHORT-TERM BORROWINGS

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

Year ended December 31, 1998 1997
(Dollars in Thousands)
Borrowings outstanding at year end:
Bank loans $ - $ 45,000

Weighted average interest rate on
debt outstanding at year end
(including fees) - % 6.44%

Weighted average short-term debt
outstanding during the year $ 616 $ 22,945

Weighted daily average interest
rates during the year
(including fees) 6.44% 6.46%

5. 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. The improvement and maintenance fund requirements for certain
first mortgage bond series can be met by bonding additional property. With the
retirement of certain company pollution control series bonds, there are no
longer any bond sinking fund requirements. During the years 1999 through
2003, $135 million of bonds will mature in 2003. No other bonds will mature
during this time period.

46
Long-term debt outstanding is as follows at December 31:

1998 1997
(Dollars in Thousands)
First mortgage bond series:
7.6% due 2003. . . . . . . . . . $ 135,000 $ 135,000
6-1/2% due 2005. . . . . . . . . 65,000 65,000
6.20% due 2006 . . . . . . . . . 100,000 100,000
300,000 300,000
Pollution control bond series:
5.10% due 2023 . . . . . . . . . 13,673 13,757
Variable due 2027 (1). . . . . . 21,940 21,940
7.0% due 2031. . . . . . . . . . 327,500 327,500
Variable due 2032 (2). . . . . . 14,500 14,500
Variable due 2032 (3). . . . . . 10,000 10,000
387,613 387,697
Less:
Unamortized discount . . . . . . 3,446 3,569
Long-term debt (net) . . . . . . . . $ 684,167 $ 684,128

Rates at December 31, 1998: (1) 3.50%, (2) 3.75%, (3) 3.75%

6. SALE-LEASEBACK OF LA CYGNE 2

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. At December 31, 1998, approximately $20.3
million of this deferral remained in regulatory assets on the Balance Sheet.

Future minimum annual lease payments required under the La Cygne 2 lease
agreement are approximately $34.6 million for each year through 2002, $39.4
million in 2003, and $537.2 million over the remainder of the lease.

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 for 1998, $27.3 million for
1997, and $22.5 million for 1996.
47
In addition the company has future minimum annual lease payments of
approximately $965,000 for each year through 2003 and $2.9 million over the
remainder of the lease.

7. INCOME TAXES

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

1998 1997 1996
(Dollars in Thousands)
Currently payable:
Federal. . . . . . . . . $ 53,297 $ 34,641 $ 31,135
State. . . . . . . . . . 12,080 7,982 11,948
Deferred:
Federal. . . . . . . . . (14,299) (18,503) (218)
State. . . . . . . . . . (2,866) (3,467) (3,358)
Amortization of investment
tax credits . . . . . . (3,241) (3,245) (3,249)
Total income tax expense . $ 44,971 $ 17,408 $ 36,258

Under SFAS 109, temporary differences gave rise to deferred tax assets
and deferred tax liabilities as follows at December 31:

1998 1997
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . $ 92,427 $ 97,634
Other. . . . . . . . . . . . . . . . . . 42,806 43,330
Total deferred tax assets. . . . . . . 135,233 140,964
Deferred tax liabilities:
Accelerated depreciation and other . . . 376,113 386,382
Acquisition premium. . . . . . . . . . . 290,576 298,582
Deferred future income taxes . . . . . . 175,759 187,801
Other. . . . . . . . . . . . . . . . . . 14,667 22,561
Total deferred tax liabilities . . . . 857,115 895,326

Investment tax credits . . . . . . . . . . 63,234 66,476

Accumulated deferred income taxes, net . . $ 785,116 $ 820,838

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.
48

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:

Year Ended December 31, 1998 1997 1996
(Dollars in Thousands)
Effective Income Tax Rate 30% 25% 27%
Effect of:
State income taxes (4) (4) (4)
Amortization of investment tax credits 2 5 2
Corporate-owned life insurance policies 9 12 7
Accelerated depreciation flow through
and amortization, net (2) (4) 2
Other - 1 1

Statutory Federal Income Tax Rate 35% 35% 35%

8. 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 dispositions of these matters will not
have a material adverse effect upon the company's overall financial position
or results of operations.

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Cash and cash equivalents, short-term borrowings and variable-rate debt
are carried at cost which approximates fair value. The decommissioning trust
is recorded at fair value and is based on the quoted market prices at December
31, 1998 and 1997. 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 information
available at December 31, 1998 and 1997. These fair value estimates have not
been comprehensively revalued for the purpose of these financial statements
since that date and current estimates of fair value may differ significantly
from the amounts presented herein. Because the company's operations are
regulated, the company believes that any gains or losses related to the
retirement of debt would not have a material effect on the company's financial
position or results of operations.
49
The carrying values and estimated fair values of the company's financial
instruments are as follows:

Carrying Value Fair Value
December 31, 1998 1997 1998 1997
(Dollars in Thousands)

Decommissioning trust. . . $ 52,093 $ 43,514 $ 52,093 $ 43,514
Fixed-rate debt. . . . . . 641,172 641,257 684,125 660,266

10. PROPERTY, PLANT AND EQUIPMENT

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

1998 1997
(Dollars in Thousands)

Electric plant in service. . . . . . $3,580,433 $3,545,942
Less - Accumulated depreciation. . . 1,125,735 1,051,107
2,454,698 2,494,835
Construction work in progress. . . . 32,943 29,432
Nuclear fuel (net) . . . . . . . . . 39,497 40,696
Net Utility Plant. . . . . . . . . 2,527,138 2,564,963
Non-utility plant in service . . . . 219 212
Net Property, Plant and Equipment. $2,527,357 $2,565,175

The carrying value of long-lived assets, including intangibles are
reviewed for impairment whenever events or changes in circumstances indicate
they may not be recoverable.

11. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 1998

In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 162,756 $ 109,336 343 50
Jeffrey 1 (b) Jul 1978 71,831 31,883 147 20
Jeffrey 2 (b) May 1980 68,477 31,734 147 20
Jeffrey 3 (b) May 1983 99,964 41,061 144 20
Wolf Creek (c) Sep 1985 1,377,348 429,934 547 47

(a) Jointly owned with Kansas City Power & Light Company (KCPL) (which owns
50%)
(b) Jointly owned with Western Resources (which owns 64%) and UtiliCorp
United Inc. (which owns 16%)
(c) Jointly owned with KCPL (which owns 47%) and Kansas Electric Power
Cooperative, Inc. (which owns 6%)
50
Amounts and capacity represent the company's share. The company's share
of operating expenses of the plants in service above, as well as such expenses
for a 50% undivided interest in La Cygne 2 (representing 334 MW capacity) sold
and leased back to the company in 1987, are included in operating expenses on
the 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.

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 handled by Western Resources.
The net amount advanced by the company to Western Resources approximated $64
million and $73 million at December 31, 1998 and 1997, respectively. These
amounts are recorded as advances to parent company in current assets on the
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 allocators. Management believes such allocation
procedures are reasonable. During 1998, the company declared dividends to
Western Resources of $100 million.

13. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT

On February 7, 1997, Kansas City Power & Light Company (KCPL) and Western
Resources entered into an agreement whereby KCPL would be combined with
Western Resources. In December 1997, representatives of Western Resources'
financial advisor indicated that they believed it was unlikely that they would
be in a position to issue a fairness opinion required for the merger on the
basis of the previously announced terms.

On March 18, 1998, Western Resources and KCPL agreed to a restructuring
of their February 7, 1997 merger agreement which will result in the formation
of Westar Energy, a new electric company. Under the terms of the merger
agreement, the electric utility operations of Western Resources will be
transferred to the company, and KCPL and the company will be merged into NKC,
Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar
Energy. In addition, under the terms of the merger agreement, KCPL
shareholders will receive Western Resources common stock which is subject to a
collar mechanism of not less than .449 nor greater than .722, provided the
amount of Western Resources common stock received may not exceed $30.00, and
one share of Westar Energy common stock per KCPL share. The Western Resources
Index Price is the 20 day average of the high and low sale prices for Western
Resources common stock on the NYSE ending ten days prior to closing. If the
Western Resources Index Price is less than or equal to $29.78 on the fifth day
prior to the effective date of the combination, either party may terminate the
agreement. Upon consummation of the combination, Western Resources will own
51
approximately 80.1% of the outstanding equity of Westar Energy and KCPL
shareholders will own approximately 19.9%. As part of the combination, Westar
Energy will assume all of the electric utility related assets and liabilities
of Western Resources, KCPL, and the company.

Westar Energy will assume $2.7 billion in debt, consisting of $1.9
billion of indebtedness for borrowed money of Western Resources and the
company, and $800 million from KCPL. Long-term debt of Western Resources,
excluding Protection One (a subsidiary of Western Resources), and the company
was $2.5 billion at December 31, 1998, and $2.1 billion at December 31, 1997.
Under the terms of the merger agreement, it is intended that Western Resources
will be released from its obligations with respect to the company's debt to be
assumed by Westar Energy.

Consummation of the merger is subject to customary conditions. On July
30, 1998, the Western Resources' shareholders and the shareholders of KCPL
voted to approve the amended merger agreement at special meetings of
shareholders. Western Resources estimates the transaction to close in 1999,
subject to receipt of all necessary approvals from regulatory and government
agencies.

In testimony filed in February 1999, the KCC staff recommended the merger
be approved but with conditions which Western Resources believes would make
the merger uneconomical. The KCC is under no obligation to accept the KCC
staff recommendation. In addition, legislation has been proposed in Kansas
that could impact the transaction. Western Resources does not anticipate the
proposed legislation to pass in its current form. Western Resources is not
able to predict whether any of these initiatives will be adopted or their
impact on the transaction, which could be material.

On August 7, 1998, Western Resources and KCPL filed an amended
application with the FERC to approve the Western Resources/KCPL merger and the
formation of Westar Energy.

Western Resources has received procedural schedule orders in Kansas and
Missouri. These schedules indicate hearing dates beginning May 3, 1999 in
Kansas and July 26, 1999 in Missouri.

In February 1999, KCPL advised Western Resources that its Hawthorne
generating station (479 MW coal facility) suffered material damage to its
boiler which could prevent the unit's operation for an extended period.
Western Resources is not able to ascertain at this time the impact of this
matter on the merger.

KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. The company, KCPL and Western Resources have joint interests
in certain electric generating assets, including Wolf Creek.

At December 31, 1998, Western Resources had deferred approximately $14
million related to the KCPL transaction. These costs will be included in the
determination of total consideration upon consummation of the transaction.

For additional information on the Merger Agreement with KCPL, see Western
Resources' Registration Statement on Form S-4 filed on June 9, 1998.
52

14. 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. The company is evaluated from a segment
perspective as a part of its parent company, Western Resources. The company
is an integral component of Western Resources and its financial position and
operations are managed as such. Based on the management approach to
determining business segments, the company only has one business segment.
This segment is nuclear generation. The company's remaining operations of
fossil generation and energy delivery are fully integrated with those of
Western Resources.

Electric operations and nuclear generation comprise the company's
regulated electric utility business in Kansas. Electric operations involve
the production, transmission and distribution of electric power for sale to
approximately 283,000 retail and wholesale customers in Kansas. Nuclear
generation represents the company's 47% ownership in the Wolf Creek nuclear
generating facility. This segment does not have any external sales.

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 revenues.

Year Ended December 31, 1998:

Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)

External sales. . . $ 648,379 $ - $ - $ 648,379
Allocated sales . . 117,517 117,517 (235,034) -
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

53
Year Ended December 31, 1997:

Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)

External sales. . . $ 614,445 $ - $ - $ 614,445
Allocated sales . . 102,330 102,330 (204,660) -
Depreciation and
amortization . . . 57,521 65,902 - 123,423
Earnings before
interest and taxes 180,954 (60,968) - 119,986
Interest expense. . 50,450
Earnings before
income taxes . . . 69,536
Identifiable assets 1,962,856 1,154,522 3,117,108

Year Ended December 31, 1996:

Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)

External sales. . . $ 654,570 $ - $ - $ 654,570
Allocated sales . . 100,592 100,592 (201,184) -
Depreciation and
amortization . . . 56,611 57,242 - 113,853
Earnings before
interest and taxes 242,179 (51,585) 190,594
Interest expense. . 58,062 58,062
Earnings before
income taxes . . . 132,532
Identifiable assets 2,128,552 1,190,335 3,318,887

54
15. 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.

1998
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $134,566 $162,816 $216,034 $134,963
Income from Operations. . . 36,033 44,112 81,063 28,210
Net income. . . . . . . . . 22,415 28,507 43,329 9,514

1997
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $143,791 $148,826 $191,066 $130,762
Income from Operations. . . 30,364 32,421 66,724 (5,501)
Net income. . . . . . . . . 11,172 15,492 31,775 (6,311)

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

There were no disagreements with accountants on accounting and financial
disclosure.

55
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 1994 and Other Continuously
Name Age Directorships Other Than The Company Since

Annette M. 36 Chairman of the Board (since Jan. 1999) 1999
Beck and President (since Oct. 1998), Kansas
Gas and Electric Company; Vice President,
Customer Service (since Oct. 1998);
Director Customer Operations (Aug. 1997
to Oct. 1998); and prior to that Director
Strategic Planning, Western Resources, Inc.

Anderson E. 65 President, Jackson Mortuary, 1994
Jackson Wichita, Kansas
Directorships
The National Business League

Donald A. 65 Consultant, Investment Management Group, 1992
Johnston Commerce Bank, Lawrence, Kansas,
(1)(2) (since July 1996); Retired President and
Chairman (Emeritus), Maupintour, Inc,
Lawrence, Kansas
Directorships
Commerce Bank, Lawrence, Kansas

James A. 41 Vice President, Investor Relations and 1997
Martin Strategic Planning (since Oct. 1998);
Vice President, Finance (July 1995 to
Oct. 1998); and prior to that Executive
Director Regulatory and Rates
Western Resources, Inc.

Marilyn B. 49 President Kansas, NationsBank N.A. 1994
Pauly Wichita, Kansas
(1) Directorships
Farmers Mutual Alliance Insurance Company

Richard D. 66 President, Range Oil Company 1993
Smith Directorships
NationsBank N.A.
HCA Wesley Medical Center,
Wichita, Kansas

(1) Member of the Audit Committee of which Mr. Johnston is Chairman.
The Audit Committee has responsibility for the investigation and
review of the financial affairs of the Company and its relations
with independent accountants.
56
(2) Mr. Johnston was a director of the former Kansas Gas and Electric
Company since 1980.

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

During 1998, the Board of Directors met five 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 J(2)(c) to Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

57
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

Balance Sheets, December 31, 1998 and 1997
Statements of Income for the years ended December 31, 1998, 1997 and 1996
Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996
Statements of Common Shareholders' Equity for the years ended December 31,
1998, 1997 and 1996
Notes to Financial Statements

REPORTS ON FORM 8-K

None

58
EXHIBIT INDEX

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

Description

2(a) Amended and Restated Agreement and Plan of Merger
dated March 18, 1998 (Filed electronically)

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

3(b) Certificate of Merger of Kansas Gas and Electric Company into I
KCA 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 I
for the year 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 thirty-eight
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 and March 1, 1994, (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; Exhibit 2(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
59
Description

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.

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

10(a) Amendment No. 3 to La Cygne 2 Lease Agreement dated as of September I
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 Exhibit I
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
(Filed electronically)

23 Consent of Independent Public Accountants, Arthur Andersen LLP
(Filed electronically)

27 Financial Data Schedule (Filed electronically)

60
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

March 31, 1999 By /s/ Annette M. Beck
Annette M. Beck,
Chairman of the Board
and President
61
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/ ANNETTE M. BECK Chairman of the Board and
(Annette M. Beck) President (Principal Executive March 31, 1999
Officer)

/s/ RICHARD D. TERRILL Secretary, Treasurer and General
(Richard D. Terrill) Counsel (Principal Financial March 31, 1999
and Accounting Officer)

/s/ ANDERSON E. JACKSON
(Anderson E. Jackson)

/s/ DONALD A. JOHNSTON
(Donald A. Johnston)

/s/ JAMES A. MARTIN Directors March 31, 1999
(James A. Martin)

/s/ MARILYN B. PAULY
(Marilyn B. Pauly)

/s/ RICHARD D. SMITH
(Richard D. Smith)