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, 1993

[ ] 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 18, 1994)

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(2)(c) to Form 10-K
for certain wholly-owned subsidiaries and is therefore filing an abbreviated
form.

KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1993

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 11

Item 3. Legal Proceedings 12

Item 4. Submission of Matters to a Vote of
Security Holders 12

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 12

Item 6. Selected Financial Data 12

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 13

Item 8. Financial Statements and Supplementary Data 19

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 44

PART III
Item 10. Directors and Executive Officers of the
Registrant 45

Item 11. Executive Compensation 46

Item 12. Security Ownership of Certain Beneficial
Owners and Management 46

Item 13. Certain Relationships and Related Transactions 46

PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 47

Signatures 56

PART I

ITEM 1. BUSINESS

ACQUISITION AND MERGER

Additional information relating to the Merger can be found in Management's
Discussion and Analysis of Financial Condition and Results of Operations and
Note 1 of the Notes to Financial Statements.

GENERAL

The Company is an electric public utility engaged in the generation,
transmission, distribution and sale of electric energy in the southeastern
quarter of Kansas including the Wichita metropolitan area. The Company owns
47 percent of Wolf Creek Nuclear Operating Corporation, the operating company
for Wolf Creek Generating Station (Wolf Creek). Corporate headquarters of the
Company is located in Wichita, Kansas. The Company has no gas properties. At
December 31, 1993, the Company had no employees. All employees are provided
by Western Resources.

As a regulated utility, the Company does not have direct competition for
retail electric service in its certified service area. However, there is
competition, based largely on price, from the generation, or potential
generation, of electricity by large commercial and industrial customers, and
independent power producers.

The Company's business is subject to seasonal fluctuations with the peak
period occurring during the summer. Approximately one-third of residential
kilowatthour sales occur in the third quarter. Accordingly, earnings and
revenue information for any quarterly period should not be considered as a
basis for estimating results of operations for a full year.

Electric utilities have been experiencing problems such as controversy
over the safety and use of coal and nuclear power plants, compliance with
changing environmental requirements, long construction periods required to
complete new generating units resulting in high fixed costs for those
facilities, difficulties in obtaining timely and adequate rate relief to
recover these high fixed costs, uncertainties in predicting future load
requirements, competition from independent power producers and cogenerators,
and the effects of changing accounting standards.

The problems which most significantly affect the Company are the use, or
potential use, of cogeneration and self-generation facilities by large
commercial and industrial customers, and compliance with environmental
requirements. For additional information see Management's Discussion and
Analysis and Notes 3 and 4 of the Notes to Financial Statements.

Discussion of other factors affecting the Company are set forth in the
Notes to Financial Statements and Management's Discussion and Analysis
included herein.

ELECTRIC OPERATIONS

General. The Company supplies electric energy at retail to approximately
268,000 customers in 139 communities in Kansas. The Company also supplies
electric energy to 27 communities and 1 rural electric cooperative, and has
contracts for the sale, purchase or exchange of electricity with other
utilities at wholesale.

The Company's electric sales for the last five years were as follows:

1993 1992 1991 1990 1989
(Thousands of MWH)

Residential 2,386 2,102 2,341 2,270 2,105
Commercial 1,991 1,892 1,908 1,838 1,748
Industrial 3,323 3,248 3,194 3,093 2,978
Other 2,049 1,313 1,214 1,736 2,113
Total 9,749 8,555 8,657 8,937 8,944

The Company's electric revenues for the last five years were as follows:

1993 1992 1991 1990 (1) 1989
(Thousands of Dollars)

Residential $219,069 $194,142 $219,907 $214,544 $187,657
Commercial 162,858 154,005 155,847 151,098 135,740
Industrial 179,256 174,226 172,953 168,294 153,360
Other 55,814 31,878 46,261 52,705 56,776
Total $616,997 $554,251 $594,968 $586,641 $533,533

(1) See Note 4 of the Notes to Financial Statements for impact
of rate refund orders.

Capacity. The aggregate net generating capacity of the Company's system
is presently 2,472 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 has been "mothballed" for future use (see
Item 2. Properties).

The Company's 1993 peak system net load occurred on August 16, 1993 and
amounted to 1,811 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 22% above system peak responsibility at the
time of the peak.

The Company and ten companies in Kansas and western Missouri have agreed
to provide capacity (including margin), emergency and economy services for
each other. This arrangement is called the MOKAN Power Pool. The pool
participants also coordinate the planning of electric generating and
transmission facilities.

Future Capacity. The Company does not contemplate any significant
expenditures in connection with construction of any major generating
facilities through the turn of the century (see Management's Discussion and
Analysis, Liquidity and Capital Resources). The Company has capacity
available which may not be fully utilized by growth in customer demand for at
least 5 years. The Company continues to market this capacity and energy to
other utilities.

Fuel Mix. The Company's coal-fired units comprise 1,092 MW of the total
2,472 MW of generating capacity and the Company's nuclear unit provides 533 MW
of capacity. Of the remaining 847 MW of generating capacity, units that can
burn either natural gas or oil account for 844 MW, and the remaining unit
which burns only diesel accounts for 3 MW (see Item 2, Properties).

During 1993, low sulfur coal was used to produce 60% of the Company's
electricity. Nuclear produced 33% and the remainder was produced from natural
gas, oil, or diesel. Based on the Company's estimate of the availability of
fuel, coal will continue to be used to produce approximately 61% of the
Company's electricity and 33% from nuclear.

The Company anticipates the fuel mix to fluctuate with the operation of
the nuclear powered Wolf Creek which operates on an 18-month refueling and
maintenance schedule. The 18-month schedule permits uninterrupted operation
every third calendar year. Beginning March 5, 1993, Wolf Creek was taken off-
line for its sixth refueling and maintenance outage. The refueling outage
took approximately 73 days to complete, during which time electric demand was
met primarily by the Company's coal-fired generating units.

Nuclear. The owners of Wolf Creek have on hand or under contract 73
percent of the uranium required for operation of Wolf Creek through the year
2001. The balance is expected to be obtained through spot market and contract
purchases.

Contractual arrangements are in place for 100 percent of Wolf Creek's
uranium enrichment requirements for 1993-1996, 70 percent for 1997-1998 and
100 percent for 2003-2014. The balance of the 1997-2002 requirements is
expected to be obtained through a combination of spot market and contract
purchases. The decision not to contract for the full enrichment requirements
is one of cost rather than availability of service.

Contractual arrangements are in place for the conversion of uranium to
uranium hexafluoride sufficient to meet Wolf Creek's requirements through 1995
as well as the fabrication of fuel assemblies to meet Wolf Creek's
requirements through 2012. During 1994, the Company plans to begin securing
additional arrangements, for the post 1995 period.

The Nuclear Waste Policy Act of 1982 established schedules, guidelines and
responsibilities for the Department of Energy (DOE) to develop and construct
repositories for the ultimate disposal of spent fuel and high-level waste.
The DOE has not yet constructed a high-level waste disposal site and has
announced that a permanent storage facility may not be in operation prior to
2010 although an interim storage facility may be available earlier. Wolf
Creek contains an on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
2006 while still maintaining full core off-load capability. The Company
believes adequate additional storage space can be obtained, as necessary.

Coal. Western Resources, the operator of Jeffrey Energy Center (JEC) and
KG&E (20% interest in JEC), 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 with
deficient mmBTU provisions applicable to deficiencies in the scheduled
delivery. 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 $1.045 per mmBTU or $17.35 per ton during 1993.

Coal is transported by Western Resources from Wyoming under a long-term
rail transportation contract with Burlington Northern (BN) and Union Pacific
(UP) to JEC through December 31, 2013. Rates are based on net load carrying
capabilities of each rail car. Western Resources provides 770 aluminum rail
cars, under a 20 year lease, to transport coal to JEC. During 1994 Western
Resources will provide an additional 120 rail cars under a similar lease.

The two coal fired units at La Cygne generating station have an aggregate
generating capacity of 677 MW (KG&E's 50 percent share) (see Item 2.
Properties). The operator, Kansas City Power & Light Company (KCP&L),
maintains coal contracts as discussed in the following paragraphs.

During 1993, La Cygne 1 was converted to use low sulfur Powder River Basin
coal which is supplied under the AMAX contract for La Cygne 2, discussed
below. Illinois or 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 blend of 85 percent Powder River Basin coal. During the
third and fourth quarters of 1993, the Company along with the operator secured
supplemental Illinois or Kansas/Missouri coal, for blending purposes, on a
short-term basis through spot market purchase orders.

La Cygne 2 and additional La Cygne 1 Powder River Basin coal was supplied,
through a contract that expired December 31, 1993, by AMAX from its mines in
Gillette, Wyoming. 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). For 1994, the operator has secured
Powder River Basin coal, similar to the AMAX coal, from two sources; Carter
Mining Company's Caballo Mine, a subsidiary of Exxon Coal USA; and Caballo
Rojo Inc's Caballo Rojo Mine, a subsidiary of Drummond Inc. Transportation is
covered by KCP&L through its Omnibus Rail Transportation Agreement with BN and
Kansas City Southern Railroad through December 31, 1995. An alternative rail
transportation agreement with Western Railroad Property, Inc. (WRPI), a
partnership between UP and Chicago Northwestern (CNW), lasts through December
31, 1995. The WRPI/UP/CNW agreement is a supplemental access contract to
handle tonnages not covered by the Omnibus contract.

During 1993, the average delivered cost of all coal procured for La Cygne
1 was approximately $0.81 per mmBTU or $14.24 per ton and the average
delivered cost of Powder River Basin coal for La Cygne 2 was approximately
$0.84 per mmBTU or $14.18 per ton.

Natural Gas. The Company uses natural gas as a primary fuel in its Gordon
Evans and Murray Gill Energy Centers. Natural gas for these generating
stations is supplied under a firm contract that runs through 1995 by Kansas
Gas Supply (KGS). Short-term economical spot market purchases from the
Williams Natural Gas (WNG) system provide the Company flexible natural gas to
meet operational needs.

Oil. The Company uses oil as an alternate fuel when economical or when
interruptions to natural gas make it necessary. Oil is also used as a
supplemental fuel at each of the coal plants. All oil burned by the Company
during the past several years has been obtained by spot market purchases. At
December 31, 1993, the Company had approximately 770 thousand gallons of No. 2
oil and 11.5 million gallons of No. 6 oil which is sufficient to meet
emergency requirements and protect against lack of availability of natural gas
and/or the loss of a large generating unit.

Other Fuel Matters. The Company's contracts to supply fuel for its 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.

On March 26, 1992, in connection with the Merger, the Kansas Corporation
Commission (KCC) approved the elimination of the Energy Cost Adjustment Clause
(ECA) for most Kansas retail customers of the Company effective April 1, 1992.
The provisions for fuel costs included in base rates were established at a
level intended by the KCC to equal the projected average cost of fuel through
August 1995 and to include recovery of costs provided by previously issued
orders relating to coal contract settlements and storm damage recovery. Any
increase or decrease in fuel costs from the projected average will be absorbed
by the Company.

Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
1993 1992 1991 1990 1989
Per Million BTU:
Nuclear $0.35 $0.34 $0.32 $0.34 $0.34
Coal 0.96 1.25 1.32 1.32 1.38
Gas 2.37 1.95 1.74 1.96 1.91
Oil 3.15 4.28 4.13 3.01 3.30

Cents per KWH Generation 0.93 0.98 1.09 1.01 0.96

Environmental Matters. The Company currently holds all Federal and State
environmental approvals required for the operation of all its generating
units. The Company believes it is presently in substantial compliance with
all air quality regulations (including those pertaining to particulate matter,
sulfur dioxide and nitrogen oxides) 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 percent. Federal nitrogen oxides emission standards
applicable to these units prohibit the emission of more than 0.7 pounds of
nitrogen oxides 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 nitrogen
oxides 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.

The Kansas Department of Health and Environment regulations, applicable to
the Company's other generating facilities, prohibit the emission of more than
3.0 pounds of sulfur dioxide per million BTU of heat input at the Company's
generating units. The Company has contracted to purchase low sulfur coal (see
Coal) which will allow compliance with such limits at La Cygne. All
facilities burning coal are equipped with flue gas scrubbers and/or
electrostatic precipitators.

The Clean Air Act Amendments of 1990 (the Act) require a two-phase
reduction in sulfur dioxide and nitrogen oxide emissions effective in 1995 and
2000 and a probable reduction in toxic emissions. To meet the monitoring and
reporting requirements under the acid rain program, the Company is installing
continuous monitoring and reporting equipment at a total cost of approximately
$2.3 million. At December 31, 1993, the Company had completed approximately
$850 thousand of these capital expenditures with the remaining $1.4 million of
capital expenditures to be completed in 1994 and 1995. The Company does not
expect additional equipment to reduce sulfur emissions to be necessary under
Phase II. The Company currently has no Phase I affected units.

The nitrogen oxide and toxic limits, which were not set in the law, will
be specified in future EPA regulations. The EPA has issued, for public
comment, preliminary nitrogen oxide regulations for Phase I group 1 units.
Nitrogen oxide regulations for Phase II units and Phase I group 2 units are
mandated in the Act to be promulgated by January 1, 1997. Although the
Company has no Phase I units, the final nitrogen oxide regulations for Phase 1
group 1 may allow for early compliance for Phase II group 1 units. Until
such time as the Phase I group 1 nitrogen oxide regulations are final, the
Company will be unable to determine its compliance options or related
compliance costs.

All of the Company's generating facilities are in substantial compliance
with the Best Practicable Technology and Best Available Technology
regulations issued by EPA pursuant to the Clean Water Act of 1977. Most EPA
regulations are administered in Kansas by the Kansas Department of Health and
Environment.

Additional information with respect to Environmental Matters is discussed
in Note 3 of the Notes to Financial Statements.

FINANCING

The Company's ability to issue additional debt is restricted under
limitations imposed by the Mortgage and Deed of Trust of the Company.

The Company's mortgage prohibits additional first mortgage bonds from
being issued (except in connection with certain refundings) unless the
Company's net earnings before income taxes and before provision for retirement
and depreciation of property for a period of 12 consecutive months within 15
months preceding the issuance are not less than 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 the Company's results for the 12 months ended December 31, 1993,
approximately $1 billion principal amount of additional first mortgage bonds
could be issued (7.5 percent interest rate assumed).

Additional KG&E 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, 1993, the Company had approximately $1.3 billion of net bondable
property additions not subject to an unfunded prior lien entitling the Company
to issue up to $882 million principal amount of additional bonds. As of
December 31, 1993, the Company could also issue up to $115 million bonds on
the basis of retired bonds.

REGULATION AND RATES

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

Additionally, the Company is 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 4 of the Notes to Financial Statements.

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

Kent R. Brown 48 Chairman of the Board, Group Vice President
(since June 1992) (1982 to 1992)
President and Chief
Executive Officer
(since March 1992)

Richard D. LaGree 63 Vice President, Field Vice President, Electric
Operations (since Distribution
Operations,
April 1992) (1990 to 1992) Western
Resources, Inc.
Vice President, Western
Region Operations
(1985 to 1990) Western
Resources, Inc.

Richard D. Terrill 39 Secretary, Treasurer Secretary and Attorney
and General Counsel (1983 to 1992)
(since April 1992)

The present term of office of each of the executive officers extends to May 3,
1994, or until their respective successors are chosen and appointed by the
Board of Directors. There are no family relationships among any of the
officers, nor any arrangements or understandings between any officer and other
persons pursuant to which he/she was elected as an officer.

ITEM 2. PROPERTIES

The Company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas.

During the five years ended December 31, 1993, the Company's gross
property additions totalled $330,737,000, and retirements were $93,737,000.

ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)

Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 150
2 1967 Gas--Oil 367

Jeffrey Energy Center (20%):
Steam Turbines 1 1978 Coal 140
2 1980 Coal 135
3 1983 Coal 140

La Cygne Station (50%):
Steam Turbines 1 1973 Coal 342
2 1977 Coal 335

Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 69
3 1956 Gas--Oil 107
4 1959 Gas--Oil 105

Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 0 (1)

Wichita Plant:
Diesel Generator 5 1969 Diesel 3

Wolf Creek Generating Station (47%):
Nuclear 1 1985 Uranium 533

Total 2,472

(1) This unit has been "mothballed" for future use.

(2) Based on MOKAN rating.

The Company jointly-owns Jeffrey Energy Center (20%), La Cygne Station
(50%)
and Wolf Creek Generating Station (47%).

ITEM 3. LEGAL PROCEEDINGS

Information on legal proceedings involving the Company is set forth in
Note 10 of Notes to Financial Statements included herein.

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.

PART II

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

On March 31, 1992, Western Resources through its wholly-owned subsidiary
KCA, acquired all of the outstanding common and preferred stock of KG&E. As a
result, the Company's common stock was delisted by the New York Stock Exchange
and the Pacific Stock Exchange.

ITEM 6. SELECTED FINANCIAL DATA

1993 1992 1991 1990(1) 1989
(Dollars in Thousands)

Income Statement Data:

Operating revenues . . . . . . . $ 616,997 $ 554,251 $ 594,968 $ 586,641 $ 533,533
Operating expenses . . . . . . . 469,616 424,089 468,885 447,355 405,938
Operating income . . . . . . . . 147,381 130,162 126,083 139,286 127,595
Net income . . . . . . . . . . . 108,103 77,981 53,602 64,184 47,493

Balance Sheet Data:

Gross electric plant in service. $3,339,832 $3,293,365 $2,468,959 $2,435,090 $2,388,640
Construction work in progress. . 28,436 29,634 13,612 14,760 13,181
Total assets . . . . . . . . . . 3,187,479 3,279,232 2,350,546 2,348,862 2,363,069
Long-term debt . . . . . . . . . 653,543 871,652 850,851 824,424 726,537

Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 3.58 2.35 1.90 2.07 1.71

(1) See Note 4 of the Notes to Financial Statements for impact of rate refund orders.

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

FINANCIAL CONDITION

The results of operations for the year ended December 31, 1993, and the
nine months ended December 31, 1992, included herein, refer to the Company
following the merger with Western Resources, Inc. (formerly The Kansas Power
and Light Company) through its wholly-owned subsidiary, KCA Corporation, on
March 31, 1992 (the Merger) (see Note 1).

Pro forma results of operations for the twelve months ended December 31,
1992 presented herein, give effect to the Merger as if it occurred on January
1, 1992 and were derived by combining the historical information for the three
month period ended March 31, 1992 and the nine month period ended December 31,
1992. The results of operations for the year ended December 31, 1991, refer
to the Company prior to the Merger but are not materially different than if
presented on a pro forma basis. Additional information relating to changes
between years is provided in the Notes to Financial Statements.

General: The Company had net income of $108.1 million for 1993 compared
to pro forma net income of $78 million in 1992. The increase in net income is
a result of the increase in energy sales due to the return of more normal
temperatures compared to unusually mild winter and summer temperatures in
1992, Merger-related cost savings, and reduced interest charges.

Liquidity and Capital Resources: The Company's liquidity is a function of
its ongoing construction program, designed to improve facilities which provide
electric service and meet future customer service requirements.

During 1993, construction expenditures for the Company's electric system
were approximately $61 million and nuclear fuel expenditures were
approximately $6 million. It is projected that adequate capacity margins will
be maintained through the turn of the century. The construction program is
focused on providing service to new customers and improving present electric
facilities.

First mortgage bond maturities and sinking fund requirements through 1998
are $18.6 million. This capital as well as capital required for construction
will be provided from internal and external sources available under then
existing financial conditions. During 1993, the Company issued and retired
long-term debt to take advantage of favorable long-term interest rates and
increased borrowings against the accumulated cash surrender values of the
corporate-owned life insurance policies.

The embedded cost of long-term debt was 7.3% at December 31, 1993, a
decrease from 7.5% at December 31, 1992. The decrease was primarily
accomplished through refinancing of higher cost debt.

On November 22, 1993, the Company redeemed three series of first mortgage
bonds, $25 million principal amount of First Mortgage Bonds, 7 3/8% Series due
2002, $25 million principal of First Mortgage Bonds, 8 3/8% Series due 2006,
and $25 million principal of First Mortgage Bonds, 8 1/2% Series due 2007.

At December 31, 1993, the Company had $150 million of First Mortgage Bonds
available to be issued under a shelf registration filed on August 24, 1993.
On January 20, 1994, the Company issued $100 million of First Mortgage Bonds,
6.20% Series due January 15, 2006 under this shelf registration. The net
proceeds were
used to reduce short-term debt.

On August 12, 1993, the Company issued $65 million of First Mortgage
Bonds, 6 1/2% Series due August 1, 2005. The net proceeds from the new issue,
together with available cash, were used to refund $35 million of First
Mortgage Bonds, 8 1/8% Series due 2001, and $30 million of First Mortgage
Bonds, 8 7/8% Series due 2008.

The Company has a long-term agreement that expires in 1995 which contains
provisions for the sale of accounts receivable and unbilled revenues
(receivables) and phase-in revenues up to a total of $180 million. Amounts
related to receivables are accounted for as sales while those related to
phase-in revenues are accounted for as collateralized borrowings. At December
31, 1993, the Company had receivables amounting to $56.8 million which were
considered sold.

In 1986 the Company purchased corporate-owned life insurance policies
(COLI) on certain of its employees. The annual cash outflow for the premiums
on these policies from 1991 through 1993 was approximately $27 million. On
August 23, 1993, the Company increased its borrowings against the accumulated
cash surrender values of the policies by $164.7 million and received $6.9
million from increased borrowings on Wolf Creek Nuclear Operating Company
(WCNOC) policies. Total 1993 COLI borrowings amounted to $184.6 million. See
Note 2 of the Notes to Financial Statements for additional information on the
accumulated cash surrender value. After 1993, the borrowings are expected to
produce annual cash inflows, net of expenses, through the remaining life of
the policies. Borrowings against the policies will be repaid from death
proceeds.

The Company's short-term financing requirements are satisfied, as needed,
through short-term bank loans and borrowings under other unsecured lines of
credit maintained with banks. At December 31, 1993, short-term borrowings
amounted to $155.8 million (see Note 5).

The KG&E common and preferred stock was redeemed in connection with the
Merger, leaving 1,000 shares of common stock held by Western Resources. The
debt structure of the Company and available sources of funds were not affected
by the Merger.

RESULTS OF OPERATIONS

The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, and
interest charges. Additional information relating to changes between years is
provided in the Notes to Financial Statements.

Revenues: The operating revenues of the Company are based on sales
volumes and rates, authorized by the Kansas Corporation Commission (KCC) and
the FERC, charged for the sale and delivery of electricity. Rates are
designed to recover the cost of service and allow investors a fair rate of
return. Future electric sales will continue to be affected by weather
conditions, competing fuel sources, customer conservation efforts and the
overall economy of the Company's service area.

The KCC order approving the Merger provided a moratorium on increases,
with certain exceptions, in the Company's electric rates until August 1995.
The KCC ordered refunds totalling $32 million to the combined companies'
(Western Resources and the Company) customers to share with customers the
Merger-related cost savings achieved during the moratorium period. The first
refund was made in April 1992 and amounted to approximately $4.9 million for
the Company. A refund of approximately $4.9 million was made in December 1993
and an additional refund of approximately $8.7 million will be made in
September 1994 (see Note 1).

On March 26, 1992, in connection with the Merger, the KCC approved the
elimination of the Energy Cost Adjustment Clause (ECA) for most retail
customers of the Company effective April 1, 1992. The fuel costs are now
included in base rates and were established at a level intended by the KCC to
equal the projected average cost of fuel through August 1995. Any increase or
decrease in fuel costs from the projected average will be absorbed by the
Company.

1993 COMPARED TO 1992: Total operating revenues increased $62.7 million
or 11.3 percent in 1993 compared to 1992 pro forma revenues. The increase is
due to the return of near normal temperatures during 1993 compared to
unusually mild winter and summer temperatures in 1992. All customer classes
experienced increased sales volumes during 1993. The number of cooling degree
days recorded for the city of Wichita were 1,546 for 1993, a 23 percent
increase from 1992. Contributing to the increase in wholesale sales were
sales to neighboring utilities to meet peak demand periods while those
utilities' units were down as a result of the summer flooding.

Partially offsetting these increases in revenues was the amortization of
the Merger-related refund.

1992 COMPARED TO 1991: Pro forma operating revenues were $554 million in
1992, a 6.8 percent decrease from 1991. The decrease is a result of unusually
mild temperatures during 1992 compared to 1991. Revenues from residential
customers decreased 11.7 percent compared to 1991 primarily due to reduced air
conditioning load. The Company experienced only 1,258 cooling degree days in
Wichita in 1992, a 38.9 percent decrease from 1991 and a 22.7 percent decrease
from normal weather. Commercial, industrial and wholesale revenues also
reflected small decreases in 1992. Also decreasing revenues was the
amortization of the Merger-related refund discussed previously.

Operating Expenses: 1993 COMPARED TO 1992: Total operating expenses
increased $45.5 million or 10.7 percent in 1993 compared to 1992. Fuel, and
purchased power expenses increased $21.4 million or 22.5 percent primarily due
to increased generation resulting from increased customer demand for
electricity during the summer peak season. Federal and state income taxes
increased $28.6 million primarily as a result of higher net income. General
taxes increased $4.8 million primarily due to an increase in plant, the
property tax assessment ratio, and higher mill levies.

Partially offsetting these increases in total operating expenses was a
decrease in other operations expense of $10.1 million primarily as a result of
merger-related savings for the entire year of 1993 and reduced net lease
expense for La Cygne 2 (see Note 7) compared to pro forma operating expenses
of 1992.

At December 31, 1993, the Company completed the accelerated amortization
of deferred income tax reserves related to the allowance for borrowed funds
used during construction capitalized for Wolf Creek Generating Station. The
amortization of these deferred income tax reserves amounted to approximately
$12 million in 1993. In accordance with the provisions of the Merger order
(see Note 1), the Company is precluded from recovering the $12 million annual
amortization in rates until the next rate filing. Therefore the Company's
earnings will be impacted negatively until these income taxes are recovered in
future rates.

1992 COMPARED TO 1991: Pro forma operating expenses decreased $44.8
million or 9.6 percent in 1992 compared to 1991. Fossil fuel expenses
decreased $23.3 million or 24.1 percent primarily due to decreased generation
resulting from reduced demand for electricity during the summer peak season
and decreased generation by natural gas-fired units with the availability of
Wolf Creek. Merger-related cost savings, an early retirement plan, a
voluntary separation program and unseasonable mild weather allowed other
operating expenses to decrease $19.2 million. Maintenance expenses decreased
$6.2 million primarily due to the scheduled major overhaul at La Cygne 2
during 1991.

Partially offsetting these decreases were higher nuclear fuel expenses of
$4 million as a result of the increased availability of Wolf Creek in 1992
compared to 1991. Property taxes also increased as a result of increased plant
and tax mill levies.

As permitted under the La Cygne 2 generating station lease agreement, in
1992, KG&E 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 the Company's recurring future net lease expense. To
accomplish this transaction, a one-time payment of approximately $27 million
was made which will be amortized over the remaining life of the lease and will
be included in operating expense as part of the future lower lease expense.
On September 29, 1992 the Trustee Lessor refinanced bonds having a coupon rate
of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.

Expenses related to the merger with Western Resources were $1.1 million
for the three months ended March 31, 1992. Other operations expense for 1991,
included $3.8 for expenses related to the Company's response to the
unsolicited tender offer by Kansas City Power & Light Company (KCPL) and the
merger with Western Resources.

Other Income and Deductions: Other income and deductions, net of taxes,
increased slightly in 1993 compared to 1992 due to the increased cash
surrender values of COLI policies and the receipt of death benefit proceeds.
Partially offsetting these increases was higher interest expense on COLI
borrowings.

Pro forma other income and deductions, net of taxes, increased
significantly for 1992 compared to 1991 as a result of increased cash
surrender values of corporate-owned life insurance polices and the recognition
of the recovery of $4.2 million of the previously written-off investment in
Drexel Burnham Lambert Group Inc. (Drexel) commercial paper.

In April 1992, the Company completed the sale of its 80% interest in CIC
Systems, Inc. (CIC). The Company had recorded a $1 million charge in 1991
representing the annual net loss incurred by CIC.

Interest Charges: Interest charges decreased $12.4 million in 1993
compared to 1992 as the Company continued to take advantage of lower interest
rates on variable-rate and fixed-rate debt by retiring and refinancing higher
cost debt. The Company's embedded cost of long-term debt decreased to 7.3% at
December 31, 1993 compared to 7.5% and 7.9% at December 31, 1992 and 1991,
respectively.

Pro forma interest charges decreased $3.3 million in 1992, primarily as a
result of the refinancing of higher cost fixed-rate debt and lower interest
rates on variable-rate debt.

OTHER INFORMATION

Inflation: Under the ratemaking procedures prescribed by the regulatory
commissions to which the Company is subject, only the original cost of plant
is recoverable in revenues as depreciation. Therefore, because of inflation,
present and future depreciation provisions are inadequate for purposes of
maintaining the purchasing power invested by common shareholders and the
related cash flows are inadequate for replacing property. The impact of this
ratemaking process on common shareholders is mitigated to the extent
depreciable property is financed with debt that can be repaid with dollars of
less purchasing power. While the Company has experienced relatively low
inflation in the recent past, the cumulative effect of inflation on operating
costs may require the Company to seek regulatory rate relief to recover these
higher costs.

Environmental: The Company has recognized the importance of environmental
responsibility and has taken a proactive position with respect to the
potential environmental liability associated with former manufactured gas
sites. The Company has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (see Note 3).

The Company currently has no Phase I affected units under the Clean Air
Act of 1990. Until such time that additional regulations become final the
Company will be unable to determine its compliance options or related
compliance costs. (see Note 3).

Energy Policy Act: The 1992 Energy Policy Act (the Act) requires
increased efficiency of energy usage and will potentially change the way
electricity is marketed. The Act also provides for increased competition in
the wholesale electric market by permitting the FERC to order third party
access to utilities' transmission systems and by liberalizing the rules for
ownership of generating facilities. As part of the Merger, the Company agreed
to open access to its transmission system. Another part of the Act requires a
special assessment to be 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.

Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112
(SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on
the Company see Note 8 of the Notes to Financial Statements.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Independent Auditors' Report 20

Financial Statements:

Balance Sheets, December 31, 1993 and 1992 22
Statements of Income for the year ended December 31, 1993 23
(Successor), the nine months ended December 31, 1992
(Successor), the three months ended March 31, 1992
(Predecessor), and the year ended December 31, 1991
(Predecessor)
Statements of Cash Flows for the year ended December 31, 1993 24
(Successor), the period March 31 to December 31, 1992
(Successor), the three months ended March 31, 1992
(Predecessor), and the year ended December 31, 1991
(Predecessor)
Statements of Taxes for the year ended December 31, 1993 25
(Successor), the nine months ended December 31, 1992
(Successor), the three months ended March 31, 1992
(Predecessor), and the year ended December 31, 1991
(Predecessor)
Statements of Capitalization, December 31, 1993 and 1992 26
Statements of Common Stock Equity for the year ended 27
December 31, 1993 (Successor), the nine months ended
December 31, 1992 (Successor), the three months ended
March 31, 1992 (Predecessor), and the year ended
December 31, 1991 (Predecessor)
Notes to Financial Statements 28

Financial Statement Schedules:

V- Utility Plant for the year ended December 31, 1993, 50
(Successor), the nine months ended December 31, 1992
(Successor), the three months ended March 31, 1992
(Predecessor), and the year ended December 31, 1991
(Predecessor)
VI- Accumulated Depreciation of Utility Plant for the year ended 53
December 31, 1993 (Successor), the nine months ended
December 31, 1992 (Successor) the three months ended
March 31, 1992 (Predecessor), and the year ended
December 31, 1991 (Predecessor)

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, VII, VIII, IX, X, XI, XII and XIII.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying balance sheet and statement of capitalization
of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western
Resources, inc.) as of December 31, 1993, and the related statements of
income, cash flows, taxes, and common stock equity for the year then ended.
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 audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance 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 audit provides 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, 1993, and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.

As explained in Note 8 to the financial statements, effective January 1, 1993,
the Company changed its method of accounting for postretirement benefits.

Our audit was made for the purpose of forming an opinion on the 1993 basic
financial statements taken as a whole. The financial statement schedules
listed in the table of contents on page 19 are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules for 1993 have been
subjected to the auditing procedures applied in the audit of the basic
financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in relation to
the basic financial statements taken as a whole.

Kansas City, Missouri, ARTHUR ANDERSEN &
CO.
January 28, 1994

INDEPENDENT AUDITORS' REPORT

Kansas Gas and Electric Company:

We have audited the 1992 and 1991 financial statements of Kansas Gas and
Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) listed
in the accompanying table of contents. Our audits also included the 1992 and
1991 financial statement schedules listed in the accompanying table of
contents. These financial statements and financial statement schedules are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedules based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit 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, such financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 1992 and
the results of its operations and its cash flows for the periods indicated in
conformity with generally accepted accounting principles. Also, in our
opinion, such financial statement schedules, when considered in relation to
the basic financial statements taken as a whole, present fairly in all
material respects the information shown therein.

DELOITTE & TOUCHE

Kansas City, Missouri
January 29, 1993

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

December 31,
1993 1992

ASSETS

UTILITY PLANT:
Electric plant in service (Notes 1, 6, and 12). . . . . . $3,339,832 $3,293,365
Less - Accumulated depreciation . . . . . . . . . . . . . 790,843 724,188
2,548,989 2,569,177
Construction work in progress . . . . . . . . . . . . . . 28,436 29,634
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 29,271 33,312
Net utility plant . . . . . . . . . . . . . . . . . . . 2,606,696 2,632,123

OTHER PROPERTY AND INVESTMENTS:
Decommissioning trust (Note 3). . . . . . . . . . . . . . 13,204 9,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 10,941 13,855
24,145 23,127

CURRENT ASSETS:
Cash and cash equivalents (Note 2). . . . . . . . . . . . 63 892
Accounts receivable and unbilled revenues (net)(Note 6) . 11,112 10,543
Advances to parent company (Note 14). . . . . . . . . . . 192,792 74,289
Fossil fuel, at average cost, . . . . . . . . . . . . . . 7,594 16,101
Materials and supplies, at average cost . . . . . . . . . 29,933 31,453
Prepayments and other current assets. . . . . . . . . . . 14,995 7,820
256,489 141,098

DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 9) . . . . . . . . . . 113,479 138,361
Deferred coal contract settlement costs (Note 4). . . . . 21,247 24,520
Phase-in revenues (Note 4). . . . . . . . . . . . . . . . 78,950 96,495
Other deferred plant costs. . . . . . . . . . . . . . . . 32,008 32,212
Corporate-owned life insurance (net) (Note 2) . . . . . . 45 144,547
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 54,420 46,749
300,149 482,884

TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,187,479 $3,279,232

CAPITALIZATION AND LIABILITIES

CAPITALIZATION (see statement). . . . . . . . . . . . . . . $1,899,221 $2,009,227

CURRENT LIABILITIES:
Short-term debt (Note 5). . . . . . . . . . . . . . . . . 155,800 93,500
Long-term debt due within one year (Note 6) . . . . . . . 238 228
Accounts payable. . . . . . . . . . . . . . . . . . . . . 51,095 60,908
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 12,185 17,684
Accrued interest. . . . . . . . . . . . . . . . . . . . . 7,381 10,935
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 9,427 5,963
236,126 189,218

DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Notes 1 and 9) . . . . . . . . . . 646,159 671,196
Deferred investment tax credits (Note 9). . . . . . . . . 78,048 73,939
Deferred gain from sale-leaseback (Note 7). . . . . . . . 261,981 271,621
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 65,944 64,031
1,052,132 1,080,787
COMMITMENTS AND CONTINGENCIES (Notes 3 and 10)
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,187,479 $3,279,232

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

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

Year Ended December 31,
1992
Pro Forma April 1 | January 1
1993 1992 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
|
OPERATING REVENUES (Notes 2 and 4). . . . $ 616,997 $ 554,251 $ 423,538 | $ 130,713 $ 594,968
|
OPERATING EXPENSES: |
Fuel used for generation: |
Fossil fuel . . . . . . . . . . . . . 93,388 73,785 53,701 | 20,084 97,159
Nuclear fuel. . . . . . . . . . . . . 13,275 12,558 10,126 | 2,432 8,593
Power purchased . . . . . . . . . . . . 9,864 8,746 3,207 | 5,539 7,811
Other operations. . . . . . . . . . . . 118,948 129,083 91,436 | 37,647 148,312
Maintenance . . . . . . . . . . . . . . 46,740 46,702 35,956 | 10,746 52,934
Depreciation and amortization . . . . . 75,530 74,696 55,547 | 19,149 75,115
Amortization of phase-in revenues . . . 17,545 17,544 13,158 | 4,386 17,545
Taxes (see statement): |
Federal income. . . . . . . . . . . . 39,553 16,305 17,523 | (1,218) 17,569
State income . . . . . . . . . . . . 9,570 4,264 4,732 | (468) 5,307
General . . . . . . . . . . . . . . . 45,203 40,406 30,155 | 10,251 38,540
Total operating expenses. . . . . . 469,616 424,089 315,541 | 108,548 468,885
|
OPERATING INCOME. . . . . . . . . . . . . 147,381 130,162 107,997 | 22,165 126,083
|
OTHER INCOME AND DEDUCTIONS: |
Investment income . . . . . . . . . . . 629 1,367 953 | 414 3,147
Corporate-owned life insurance (net). . 7,841 10,724 9,308 | 1,416 4,615
Miscellaneous (net) (Note 3). . . . . . 8,642 6,506 8,464 | (1,958) (12,844)
Income taxes (net) (see statement). . . 2,227 191 (1,296) | 1,487 6,921
Total other income and deductions . 19,339 18,788 17,429 | 1,359 1,839
|
INCOME BEFORE INTEREST CHARGES. . . . . . 166,720 148,950 125,426 | 23,524 127,922
|
INTEREST CHARGES: |
Long-term debt. . . . . . . . . . . . . 53,908 57,862 42,889 | 14,973 59,668
Other . . . . . . . . . . . . . . . . . 6,075 15,121 11,777 | 3,344 17,838
Allowance for borrowed funds used during |
construction (credit) . . . . . . . . (1,366) (2,014) (1,181) | (833) (3,186)
Total interest charges. . . . . . . 58,617 70,969 53,485 | 17,484 74,320
|
NET INCOME. . . . . . . . . . . . . . . . 108,103 77,981 71,941 | 6,040 53,602
|
PREFERRED DIVIDENDS . . . . . . . . . . . - - - | 205 821
|
EARNINGS APPLICABLE TO COMMON STOCK . . . $ 108,103 $ 77,981 $ 71,941 | $ 5,835 $ 52,781

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

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

Year Ended December 31,
1992
March 31 | January 1
1993 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net income. . . . . . . . . . . . . . . . . . . . . . $ 108,103 $ 71,941 | $ 6,040 $ 53,602
Depreciation and amortization . . . . . . . . . . . . 75,530 55,547 | 19,149 75,115
Other amortization (including nuclear fuel) . . . . . 11,254 8,929 | 1,352 6,014
Deferred taxes and investment tax credits (net) . . . 22,572 9,326 | (2,851) 3,525
Amortization of phase-in revenues . . . . . . . . . . 17,545 13,158 | 4,386 17,545
Corporate-owned life insurance. . . . . . . . . . . . (21,650) (14,704) | (3,295) (11,986)
Coal contract settlements (Note 4). . . . . . . . . . - - | - (8,500)
Amortization of gain from sale-leaseback. . . . . . . (9,640) (7,231) | (2,409) (9,641)
Changes in working capital items: |
Accounts receivable and unbilled |
revenues (net) (Note 2) . . . . . . . . . . . . . (569) 1,079 | 1,272 346
Fossil fuel . . . . . . . . . . . . . . . . . . . . 8,507 4,425 | (1,858) 3,631
Accounts payable. . . . . . . . . . . . . . . . . . (9,813) (7,216) | (6,100) 15,421
Interest and taxes accrued. . . . . . . . . . . . . (9,053) (14,345) | 10,598 1,296
Other . . . . . . . . . . . . . . . . . . . . . . . (2,191) (8,456) | 1,689 (5,832)
Changes in other assets and liabilities . . . . . . . (16,530) (41,401) | (5,479) 3,947
Net cash flows from operating activities. . . . . . 174,065 71,052 | 22,494 144,483
|
CASH FLOWS USED IN INVESTING ACTIVITIES: |
Additions to utility plant. . . . . . . . . . . . . . 66,886 53,138 | 11,496 74,348
Corporate-owned life insurance policies . . . . . . . 27,268 20,233 | 6,802 27,349
Death proceeds of corporate-owned life insurance. . . (10,160) (6,789) | - -
Purchase of short-term investments . . . . . . . . . - - | - 742
Proceeds from short-term investments. . . . . . . . . - - | - (22,097)
Other investments . . . . . . . . . . . . . . . . . . - - | (552) 1,142
Merger: |
Purchase of KG&E common stock-net of cash received. - 432,043 | - -
Purchase of KG&E preferred stock. . . . . . . . . . - 19,665 | - -
Net cash flows used in investing activities . . . 83,994 518,290 | 17,746 81,484
|
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: |
Short-term debt (net) . . . . . . . . . . . . . . . . 62,300 49,900 | 5,800 7,800
Advances to parent company (net). . . . . . . . . . . (118,503) (74,289) | - -
First mortgage bonds issued . . . . . . . . . . . . . 65,000 135,000 | - 323,406
First mortgage bonds retired. . . . . . . . . . . . . (140,000) (125,000) | - (57,000)
Other long-term debt (net). . . . . . . . . . . . . . 7,043 14,498 | (3,810) (377,031)
Borrowings against life insurance policies (net). . . 183,260 (5,649) | 6,398 3,590
Revolving credit agreement (net). . . . . . . . . . . (150,000) - | - 80,000
Special deposits (net). . . . . . . . . . . . . . . . - - | - 13,263
Other (net) . . . . . . . . . . . . . . . . . . . . . - - | (17) 31
Dividends on preferred and common stock . . . . . . . - - | (13,535) (54,143)
Financing expenses. . . . . . . . . . . . . . . . . . - - | - (8,508)
Issuance of KCA common stock. . . . . . . . . . . . . - 453,670 | - -
Net cash flows from (used in) financing activities (90,900) 448,130 | (5,164) (68,592)
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . (829) 892 | (416) (5,593)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . 892 - | 2,378 7,971
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . $ 63 $ 892 | $ 1,962 $ 2,378
|
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION |
CASH PAID FOR: |
Interest on financing activities (net of amount |
capitalized) . . . . . . . . . . . . . . . . . . $ 77,653 $ 63,451 | $ 11,635 $ 89,901
Income taxes . . . . . . . . . . . . . . . . . . . . 29,354 14,225 | - 11,350

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF TAXES
(Thousands of Dollars)

Year Ended December 31,
1992
April 1 | January 1
1993 to Dec. 31 | to March 31 1991
(Successor) | (Predecessor)
|
FEDERAL INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . $ 19,220 $ 11,356 | $ (322) $ 11,023
Deferred (net). . . . . . . . . . . . . . . . . . . 16,691 8,633 | (1,785) 64
Investment tax credit-Deferral. . . . . . . . . . . 4,900 946 | - 3,622
-Amortization. . . . . . . . . (3,114) (2,400) | (777) (2,913)
Total Federal income taxes . . . . . . . . . . . 37,697 18,535 | (2,884) 11,796
Income taxes applicable to non-operating items. . . . 1,856 (1,012) | 1,666 5,773
Total Federal income taxes charged to operations 39,553 17,523 | (1,218) 17,569
|
STATE INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . 5,104 2,869 | - 1,407
Deferred (net). . . . . . . . . . . . . . . . . . . 4,095 2,147 | (289) 2,752
Total state income taxes . . . . . . . . . . . . 9,199 5,016 | (289) 4,159
Income taxes applicable to non-operating items. . . 371 (284) | (179) 1,148
Total state income taxes charged to operations . 9,570 4,732 | (468) 5,307
|
GENERAL TAXES: |
Property. . . . . . . . . . . . . . . . . . . . . . 38,432 26,380 | 8,622 32,755
Payroll and other taxes . . . . . . . . . . . . . . 6,771 3,775 | 1,629 5,785
Total general taxes charged to operations. . . . 45,203 30,155 | 10,251 38,540
|
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 94,326 $ 52,410 | $ 8,565 $ 61,416

Year Ended December 31,
Pro Forma
1993 1992 1991
(Successor) (Predecessor)
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 30% 21% 23%
Effect of:
Additional depreciation . . . . . . . . . . . . . . (3) (4) (8)
Accelerated amortization of deferred income
tax credits. . . . . . . . . . . . . . . . . . 8 11 15
State income taxes, net of Federal benefit. . . . . (4) (2) (4)
Amortization of investment tax credits. . . . . . . 2 2 4
Corporate-owned life insurance. . . . . . . . . . . 5 6 6
Other items (net) . . . . . . . . . . . . . . . . . (3) - (2)

STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 34% 34%

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

December 31,
1993 1992

COMMON STOCK EQUITY (Note 1):
(see statement)
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 56.1% $1,065,634 53.0%
Retained earnings . . . . . . . . . . . . . . . . . . . . . 180,044 9.5 71,941 3.6
Total common stock equity . . . . . . . . . . . . . . . . 1,245,678 65.6 1,137,575 56.6

LONG-TERM DEBT (Note 6):
First Mortgage Bonds:

Series Due 1993 1992
5-5/8% 1996 $ 16,000 $ 16,000
8-1/8% 2001 - 35,000
7-3/8% 2002 - 25,000
7.6% 2003 135,000 135,000
6-1/2% 2005 65,000 -
8-3/8% 2006 - 25,000
8-1/2% 2007 - 25,000
8-7/8% 2008 - 30,000
216,000 291,000
Pollution Control Bonds:
6.80% 2004 14,500 14,500
5-7/8% 2007 21,940 21,940
6% 2007 10,000 10,000
7.0% 2031 327,500 327,500
373,940 373,940
Total bonds. . . . . . . . . . . . . . . . . . . . . . 589,940 664,940

Other Long-Term Debt:
Pollution control obligations:
5-3/4% series 2003 13,980 14,205
Revolving credit agreement 1993 - 150,000
Other long-term agreement 1995 53,913 46,640
Total other long-term debt . . . . . . . . . . . . . . 67,893 210,845

Unamortized premium and discount (net). . . . . . . . . . . (4,052) (3,905)
Long-term debt due within one year. . . . . . . . . . . . . (238) (228)
Total long-term debt . . . . . . . . . . . . . . . . . 653,543 34.4 871,652 43.4

TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,899,221 100.0% $2,009,227 100.0%

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON STOCK EQUITY
(Thousands of Dollars, Except Shares)
Years Ended December 31,

Other
Common Stock Paid-in Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total

BALANCE DECEMBER 31, 1990. . 40,996,185 $ 636,986 $ 270 $171,139 (9,996,426) (199,255) $ 609,140
(Predecessor)

Net income . . . . . . . . 53,602 53,602
Cash dividends:
Common stock . . . . . . (53,322) (53,322)
Preferred stock. . . . . (821) (821)
Employee stock plans . . . 1,560 17 14 31

BALANCE DECEMBER 31, 1991. . 40,997,745 637,003 284 170,598 (9,996,426) (199,255) 608,630
(Predecessor)

Net income . . . . . . . . 6,040 6,040
Cash dividends:
Common stock . . . . . . (13,330) (13,330)
Preferred stock. . . . . (205) (205)
Employee stock plans . . . (12) (966) (12)
Merger of KG&E with KCA. . (40,997,745) (636,991) (284) (163,103) 9,997,392 199,255 (601,123)

BALANCE MARCH 31, 1992
(Predecessor). . . . . . . -0- -0- -0- -0- -0- -0- -0-

KCA common stock issued. . 1,000 $1,065,634 - - - - $1,065,634
Net income . . . . . . . . $ 71,941 71,941

BALANCE DECEMBER 31, 1992. . 1,000 1,065,634 - 71,941 - - 1,137,575
(Successor)

Net income . . . . . . . . 108,103 108,103

BALANCE DECEMBER 31, 1993. . 1,000 $1,065,634 $ - $ 180,044 - $ - $1,245,678

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

1. ACQUISITION AND MERGER

On March 31, 1992, Western Resources, Inc. (formerly The Kansas Power and
Light Company) (Western Resources) through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company (KG&E) for $454 million in cash and
23,479,380 shares of Western Resources common stock (the Merger). Western
Resources also paid $20 million in costs to complete the Merger. The total
cost of the acquisition to Western Resources was $1.066 billion.
Simultaneously, KCA and KG&E merged and adopted the name of Kansas Gas and
Electric Company. The Merger was accounted for as a purchase. For income tax
purposes the tax basis of the Company's assets was not changed by the Merger.
In the accompanying statements, KG&E prior to the Merger is labeled as the
"Predecessor" and after the Merger as the "Successor". Throughout the notes
to financial statements, the "Company, KG&E" refers to both Predecessor and
Successor.

As Western Resources acquired 100% of the common and preferred stock of
KG&E, the Company recorded an acquisition premium of $490 million on the
balance sheet for the difference in purchase price and book value and
increased common stock equity to reflect the new cost basis of Western
Resources' investment in the Company. This acquisition premium and related
income tax requirement of $294 million under Statement of Financial Accounting
Standards No. 109 (SFAS 109) have been classified as plant acquisition
adjustment in electric plant in service on the balance sheets. Under the
provisions of the order of the Kansas Corporation Commission (KCC), the
acquisition premium is recorded as an acquisition adjustment and not allocated
to the other assets and liabilities of the Company.

The pro forma information for the year ended December 31, 1992 in the
accompanying financial statements gives effect to the Merger as if it occurred
on January 1, 1992, and was derived by combining the historical information
for the three month period ended March 31, 1992 and the nine month period
ended December 31, 1992. No purchase accounting adjustments were made for
periods prior to the Merger in determining pro forma amounts, other than the
elimination of preferred dividends, because such adjustments would be
immaterial. This pro forma information is not necessarily indicative of the
results of operations that would have occurred had the Merger been consummated
on January 1, 1992, nor is it necessarily indicative of future operating
results or financial position. The pro forma effects on the Company's net
income for 1991 presented giving effect to the Merger as if it had occurred at
the beginning of the earliest period presented would not be materially
different from that shown in the income statements included herein.

In the November 1991 KCC order approving the Merger, a mechanism was
approved to share equally between the shareholders and ratepayers the cost
savings generated by the Merger in excess of the revenue requirement needed to
allow recovery of the amortization of a portion of the acquisition adjustment,
including income tax, calculated on the basis of a purchase price of KG&E's
common stock at $29.50 per share. The order provides an amortization period

for the acquisition adjustment of 40 years commencing in August 1995, at which
time the full amount of cost savings is expected to have been implemented.
Merger savings will be measured by application of an inflation index to
certain pre-merger operating and maintenance costs at the time of the next
Kansas rate case. While the Company has achieved savings from the Merger,
there is no assurance that the savings achieved will be sufficient to, or the
cost savings sharing mechanism will operate as to fully offset the
amortization of the acquisition adjustment. The order further provides a
moratorium on increases, with certain exceptions, in the Company's Kansas
electric rates until August 1995. The KCC ordered refunds totalling $32
million to the combined companies' (Western Resources and the Company)
customers to share with customers the Merger-related cost savings achieved
during the moratorium period. The first refund was made in April 1992 and
amounted to approximately $4.9 million for the Company. A refund of
approximately $4.9 million was made in December 1993 and an additional refund
of approximately $8.7 million will be made in September 1994.

The KCC order approving the Merger requires the legal reorganization of
the Company so that it is no longer held as a separate subsidiary after
January 1, 1995, unless good cause is shown why such separate existence should
be maintained. The Securities and Exchange Commission order relating to the
Merger granted Western Resources an exemption under the Public Utilities
Holding Company Act until January 1, 1995. In connection with a requested
ruling that a merger of the Company into Western Resources would not adversely
affect the tax structure of the merger, the Company received a response from
the Internal Revenue Service that the IRS would not issue the requested
ruling. In light of the IRS response, the Company withdrew its request for a
ruling. The Company will consider alternative forms of combination or seek
regulatory approvals to waive the requirements for a combination. There is no
certainty as to whether a combination will occur or as to the form or timing
thereof.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: The financial statements of KG&E include, through March 31,
1992, its 80% owned subsidiary, CIC Systems, Inc. (CIC). In April 1992, the
Company disposed of its 80% interest in CIC. KG&E owns 47 percent 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 accounting policies of the Company are in accordance with generally
accepted accounting principles as applied to regulated public utilities. The
accounting and rates of the Company are subject to requirements of the KCC and
the Federal Energy Regulatory Commission (FERC).

Utility Plant: Utility plant (including plant acquisition adjustment) is
stated at cost. For constructed plant, cost includes contracted services,
direct labor and materials, indirect charges for engineering, supervision,
general and administrative costs, and an allowance for funds used during
construction (AFUDC). The AFUDC rate was 4.41% for 1993, 6.51% for the nine
months ended December 31, 1992, 6.70% for the three months ended March 31,
1992, and 7.74% for 1991. The cost of additions to utility plant and
replacement units of property is 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.

Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.9% during 1993, 2.9% during the nine months ended
December 31, 1992, 3.0% during the three months ended March 31, 1992, and 3.0%
during 1991 of the average original cost of depreciable property.

Cash and Cash Equivalents: For purposes of the Statements of Cash Flows,
cash and cash equivalents include cash on hand and highly liquid
collateralized debt instruments purchased with maturities of three months or
less.

Income Taxes: Income tax expense includes provisions for income taxes
currently payable and deferred income taxes calculated in conformance with
income tax laws, regulatory orders and Statement of Financial Accounting
Standards No. 109 (SFAS 109) (see Note 9).

Investment tax credits are deferred as realized and amortized to income
over the life of the property which gave rise to the credits.

Revenues: Operating revenues include amounts actually billed for
services rendered and an accrual of estimated unbilled revenues. Unbilled
revenues represent the estimated amount customers will be billed for service
provided from the time meters were last read to the end of the accounting
period. Unbilled revenues of $22.3 and $16.6 million at December 31, 1993 and
1992, respectively, are recorded as a component of accounts receivable on the
balance sheets. Certain amounts of unbilled revenues have been sold (see Note
6).

The Company had reserves for doubtful accounts receivable of $3.0 and
$2.4 million at December 31, 1993 and 1992, respectively.

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, 1993 and 1992 was $17.4 and $26.0 million,
respectively.

Cash Surrender Value of Life Insurance Contracts: The following amounts
related to corporate-owned life insurance contracts (COLI), primarily with one
highly rated major insurance company, are recorded on the balance sheets
(millions of dollars):

1993 1992
Cash surrender value of contracts. . . $269.1 $230.3
Prepaid COLI . . . . . . . . . . . . . 9.5 4.8
Borrowings against contracts . . . . . (269.0) (85.8)
COLI (net) . . . . . . . . . . . . $ 9.6 $149.3

The decrease in COLI (net) is a result of increased borrowings against
the accumulated cash surrender value of the COLI policies. The COLI
borrowings will be repaid with proceeds from death benefits. Management
expects to realize increases in cash surrender value of contracts resulting
from premiums and investment earnings on a tax free basis upon receipt of net
proceeds from death benefits under the contracts. Interest expense included
in corporate-owned life insurance (net) on the statements of income was $11.9
million for 1993, $5.3 million for the nine months ended December 31, 1992,
$1.9 million for the three months ended March 31, 1992, and $7.3 for 1991.

As approved by the Kansas Corporation Commission (KCC), the Company is
using a portion of the net income stream generated by COLI policies purchased
in 1993 and 1992 (see Note 8) to offset Statement of Financial Accounting
Standards No. 106 (SFAS 106) expenses.

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

3. COMMITMENTS AND CONTINGENCIES

Environmental: The Company and the Kansas Department of Health and
Environment entered into a consent agreement to perform preliminary
assessments of six former manufactured gas sites. The preliminary assessments
of these sites have been completed at minimal cost. Until such time that risk
assessments are completed at these sites, it will be impossible to predict the
cost of remediation. However, the Company is aware of other utilities in
Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have
incurred remediation costs for such sites ranging between $500,000 and $10
million, depending on the site. The Company is also aware that the KCC has
permitted another Kansas utility to recover a portion of the remediation costs
through rates. To the extent that such remediation costs are not recovered
through rates, the costs could be material to the Company's financial position
or results of operations depending on the degree of remediation and number of
years over which the remediation must be completed.

Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982,
the U.S. Department of Energy (DOE) is responsible for the ultimate storage
and disposal of spent nuclear fuel removed from nuclear reactors. Under a
contract with the DOE for disposal of spent nuclear fuel, the Company pays a
quarterly fee to DOE of one mill per kilowatthour of net nuclear generation.
These fees are included as part of nuclear fuel expense and amounted to $3.5
million for 1993, $1.6 million for the nine months ended December 31, 1992,
$.5 million for the three months ended March 31, 1992, and $2.8 million for
1991.

Decommissioning: The Company's share of Wolf Creek decommissioning
costs, currently authorized in rates, was estimated to be approximately $97
million in 1988 dollars. Decommissioning costs are being charged to operating
expenses. Amounts so expensed are deposited in an external trust fund and
will be used solely for the physical decommissioning of the plant. Electric
rates charged to customers provide for recovery of these decommissioning costs
over the estimated life of Wolf Creek. At December 31, 1993 and 1992, $13.2
and $9.3 million respectively, were on deposit in the decommissioning fund.
On September 1, 1993, WCNOC filed an application with the KCC for an order
approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the

Company's share of Wolf Creek decommissioning costs at approximately $174
million in 1993 dollars. If approved by the KCC, management expects
substantially all such cost increases to be recovered through the ratemaking
process.

The Company carries $164 million in premature decommissioning insurance
in the event of a shortfall in the trust fund. The insurance coverage has
several restrictions. One of these is that it can only be used if Wolf Creek
incurs an accident exceeding $500 million in expenses to safely stabilize the
reactor, to decontaminate the reactor and reactor station site in accordance
with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay
for on-site property damages. If the amount designated as decommissioning
insurance is needed to implement the NRC-approved plan for stabilization and
decontamination, it would not be available for decommissioning purposes.

Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.4 billion for a single
nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum
available private insurance of $200 million and the balance is provided by an
assessment plan mandated by the NRC. Under this plan, the Owners are jointly
and severally subject to a retrospective assessment of up to $79.3 million
($37.3 million, Company's share) in the event there is a nuclear incident
involving any of the nation's licensed reactors. This assessment is subject
to an inflation adjustment based on the Consumer Price Index. 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 totalling
approximately $2.8 billion ($1.3 billion, Company's share). This insurance is
provided by a combination of "nuclear insurance pools" ($1.3 billion) and
Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The remaining proceeds from the $2.8 billion insurance
coverage ($1.3 billion, Company's share), if any, can be used for property
damage up to $1.1 billion (Company's share) and premature decommissioning
costs up to $117.5 million (Company's share) in excess of funds previously
collected for decommissioning (as discussed under "Decommissioning"), with the
remaining $47 million (Company's share) available for either property damage
or premature decommissioning costs.

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 of approximately $9 million per year.

There can be no assurance that all potential losses or liabilities will
be insurable or that the amount of insurance will be sufficient to cover them.
Any substantial losses not covered by insurance, to the extent not recoverable
through rates, could have a material adverse effect on the Company's financial
position and results of operations.

Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in sulfur dioxide and nitrogen oxide emissions effective
in 1995 and 2000 and a probable reduction in toxic emissions. To meet the
monitoring and reporting requirements under the acid rain program, the Company
is installing continuous monitoring and reporting equipment at a total cost of
approximately $2.3 million. At December 31, 1993, the Company had completed
approximately $850 thousand of these capital expenditures with the remaining
$1.4 million of capital expenditures to be completed in 1994 and 1995. The
Company does not expect additional equipment to reduce sulfur emissions to be
necessary under Phase II. The Company currently has no Phase I affected
units.

The nitrogen oxide and toxic limits, which were not set in the law, will
be specified in future EPA regulations. The EPA has issued for public comment
preliminary nitrogen oxide regulations for Phase I group 1 units. Nitrogen
oxide regulations for Phase II units and Phase I group 2 units are mandated in
the Act to be promulgated by January 1, 1997. Although the Company has no
Phase I units, the final nitrogen oxide regulations for Phase I group 1 may
allow for early compliance for Phase II group 1 units. Until such time as the
Phase I group 1 nitrogen oxide regulations are final, the Company will be
unable to determine its compliance options or related compliance costs.

Federal Income Taxes: During 1991, the Internal Revenue Service (IRS)
completed an examination of the Company's federal income tax returns for the
years 1984 through 1988. In April 1992, the Company received the examination
report and upon review filed a written protest in August 1992. In October
1993, the Company received another examination report for the years 1989 and
1990 covering the same issues identified in the previous examination report.
Upon review of this report, the Company filed a written protest in November
1993. The most significant proposed adjustments reduce the depreciable basis
of certain assets and investment tax credits generated. Management believes
there are significant questions regarding the theory, computations, and
sampling techniques used by the IRS to arrive at its proposed adjustments, and
also believes any additional tax expense incurred or loss of investment tax
credits will not be material to the Company's financial position and results
of operations. Additional income tax payments, if any, are expected to be
offset by investment tax credit carryforwards, alternative minimum tax credit
carryforwards, or deferred tax provisions.

Other Investments: In prior years, the Company routinely purchased
short-term investment grade commercial paper for special deposit interest
accounts associated with tax-exempt pollution control bonds. On February 1,
1990, the Company purchased $6.6 million of Drexel Burnham Lambert Group Inc.
(Drexel) commercial paper. On February 13, 1990, Drexel filed for bankruptcy.
In 1990, additional claims being filed and potential lengthy litigation
indicated full recovery would be unlikely; accordingly, the investment was
written off in 1990. The Company recognized the recovery of approximately
$4.2 million during the nine months ended December 31, 1992, of the
investment, which is included in miscellaneous income.

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, 1993, WCNOC's nuclear fuel commitments (Company's share) were
approximately $18.0 million for uranium concentrates expiring at various times
through 1997, $123.6 million for enrichment expiring at various times through
2014, and $45.5 million for fabrication through 2012. At December 31, 1993,
the Company's coal and natural gas contract commitments in 1993 dollars under
the remaining term of the contracts are $666 million and $20.4 million,
respectively. The largest coal contract was renegotiated in early 1993 and
expires in 2020 with the remaining coal contracts expiring at various times
through 2013. The majority of natural gas contracts expire in 1995 with
automatic one-year extension provisions. In the normal course of business,
additional commitments and spot market purchases will be made to obtain
adequate fuel supplies.

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.

4. RATE MATTERS AND REGULATION

Elimination of the Energy Cost Adjustment Clause (ECA): On March 26,
1992, in connection with the Merger, the KCC approved the elimination of the
ECA for most retail customers effective April 1, 1992. The provisions for
fuel costs included in base rates were established at a level intended by the
KCC to equal the projected average cost of fuel through August 1995, and to
include recovery of costs provided by previously issued orders relating to
coal contract settlements and storm damage recovery discussed below. Any
increase or decrease in fuel costs from the projected average will be absorbed
by the Company.

Rate Stabilization Plan: In 1988, the KCC issued an order requiring that
the accrual of phase-in revenues be discontinued effective December 31, 1988.
Effective January 1, 1989, the Company began amortizing the phase-in revenue
asset on a straight-line basis over 9-1/2 years.

Cost of Service Audit Appeal: In September 1991, the KCC ordered the
Company to refund (which the Company has done) $5.6 million of revenues plus
$0.6 million in interest, for the period July 2, 1990 through January 31,
1991. This order concluded the appeal of the February 1990 KCC order to
reduce rates by $8.7 million. The Company had previously recorded reserves
totalling $10.8 million; however, as the order also made rates permanent, the
excess reserves of $3.3 million were reversed in September 1991.

Coal Contract Settlements: In March 1990, the KCC issued an order
allowing the Company to defer its share of a 1989 coal contract settlement
with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million.
This amount was recorded as a deferred charge on the balance sheets. The
settlement resulted in the termination of a long-term coal contract. In June
1991, the KCC permitted the Company to recover this settlement as follows:
76% of the settlement plus a return over the remaining term of the terminated
contract (through 2002) and 24% to be amortized to expense with a deferred
return equivalent to the carrying cost of the asset.

In February 1991, the Company paid $8.5 million to settle a coal contract
lawsuit with AMAX Coal Company and recorded the payment as a deferred charge
on the Company's balance sheet. In July 1991, the KCC approved the recovery
of the settlement plus a return equivalent to the carrying cost of the asset,
over the remaining term of the terminated contract (through 1996).

Storm Damage Recovery: In October 1990, the Company asked the KCC for
approval of a plan to recover the cost of damage primarily from the March 13
and June 19, 1990 storms. Approximately $15 million of capital expenditures
were incurred. These costs have been included in the Company's electric plant
accounts. In May 1991, the Company amended this request to include the
estimated $5 million of capital expenditures associated with an April 1991
storm. In November 1991 and January 1992, the KCC approved the deferral and
recovery of the capital expenditures of the 1990 and 1991 storms,
respectively, as well as carrying charges thereon.

5. SHORT-TERM BORROWINGS

At December 31, 1993, the Company had bank credit arrangements available
of $35 million. In addition, the Company has uncommitted loan participation
agreements. Maximum short-term borrowings outstanding during 1993 and 1992
were $175.8 million on December 14, 1993 and $128 million on October 6, 1992.
The weighted average interest rates, including fees, were 3.5% for 1993, 6.4%
for the nine months ended December 31, 1992, 7.1% for the three months ended
March 31, 1992, and 7.8% for 1991.

6. LONG-TERM DEBT

The amount of first mortgage bonds authorized by the KG&E 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. During 1993, the Company refinanced $65 million of
first mortgage bonds by issuing $65 million of First Mortgage Bonds, 6 1/2%
Series due 2005. In 1992, the Company refinanced $125 million of first
mortgage bonds by issuing $135 million of First Mortgage Bonds, 7.6% Series
due 2003.

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. The
sinking fund requirements for certain pollution control series bonds can be
met only through the acquisition and retirement of outstanding bonds.

The 6.80% series, due 2004, the 6% and 5 7/8% series due 2007 and the 7%
series due 2031 are pledged as collateral for pollution control revenue bonds
issued by Kansas municipalities.

On September 20, 1993, the Company terminated a long-term revolving
credit agreement which provided for borrowings of up to $150 million. The
loan agreement, which was effective through October 1994, was repaid without
penalty. The weighted average interest rate, including fees, was 3.7% for
1993, 6.8% for the nine months ended December 31, 1992, 7.7% for the three
months ended March 31, 1992, and 8.4% for 1991.

The Company has a long-term agreement, expiring in 1995, which contains
provisions for the sale of accounts receivable and unbilled revenues
(receivables) and phase-in revenues up to a total of $180 million. Amounts
related to receivables are accounted for as sales while those related to
phase-in revenues are accounted for as collateralized borrowings. Additional
receivables are continually sold to replace those collected. At December 31,
1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million,
respectively, were considered sold under the agreement. The credit risk
associated with the sale of customer accounts receivable is considered
minimal. The weighted average interest rate, including fees, on this
agreement was 3.7% for 1993, 6.6% for the nine months ended December 31, 1992,
7.9% for the three months ended March 31, 1992, and 7.8% for 1991. At
December 31, 1993, an additional $16.4 million was available under the
agreement.

Bonds maturing and acquisition and retirement of bonds for sinking fund
requirements for the five years subsequent to December 31, 1993 are as
follows:

Maturing Retiring
Year Bonds Bonds
(Dollars in Thousands)

1994. . . . . . . $ - $ 238
1995. . . . . . . - 253
1996. . . . . . . 16,000 270
1997. . . . . . . - 833
1998. . . . . . . - 1,050

7. SALE-LEASEBACK OF LA CYGNE 2

In 1987, the Company sold and leased back its 50 percent undivided
interest in La Cygne 2 generating unit. The lease has an initial term of 29
years, with various options to renew the lease or repurchase the 50 percent
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 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.

Future minimum annual lease payments required under the lease agreement
are approximately $34.6 million for each year through 1998 and $715 million
over the remainder of the lease.

The gain of approximately $322 million realized at the date of the sale
has been deferred for financial reporting purposes, and is being amortized
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 a one-
time payment, was approximately $22.5 million for 1993, $20.6 million for the
nine months ended December 31, 1992, $7.5 million for the three months ended
March 31, 1992, and $30 million for 1991.

8. EMPLOYEE BENEFIT PLANS

Pension: The Company maintains noncontributory defined benefit pension
plans covering substantially all employees of the Company prior to the Merger.
Pension benefits are based on years of service and the employee's compensation
during the five highest paid consecutive years out of ten before retirement.
The Company's
policy is to fund pension costs accrued, subject to limitations set by the
Employee Retirement Income Security Act of 1974 and the Internal Revenue Code.

The following table provides information on the components of pension
cost for the Company's pension plans (millions of dollars):

The following table sets forth the plans' actuarial present value and
funded status at November 30, 1993 and 1992 (the plan years) and a
reconciliation of such status to the December 31, 1993 and 1992 financial
statements (millions of dollars):

1993 1992
Funded Status:
Actuarial present value of benefit obligations:
Vested. . . . . . . . . . . . . . . . . . . . . $ 95.2 $ 82.9
Non-vested. . . . . . . . . . . . . . . . . . . 6.1 3.6
Total . . . . . . . . . . . . . . . . . . . . $101.3 $ 86.5

Plan assets at November 30 (principally debt
and equity securities) at fair value. . . . . . $119.9 $113.7
Projected benefit obligation at November 30 . . . (125.5) (110.8)
Plan assets in excess of projected benefit
obligation at November 30 . . . . . . . . . . . (5.6) 2.9
Unrecognized transition asset . . . . . . . . . . (1.7) (2.0)
Unrecognized prior service costs. . . . . . . . . 12.4 12.1
Unrecognized net gain . . . . . . . . . . . . . . (20.6) (26.1)
Accrued pension costs at December 31. . . . . . . $(15.5) $(13.1)

Year Ended December 31, 1993 1992

Actuarial Assumptions:
Discount rate . . . . . . . . . . . . . . . . . 7.0-7.75% 8.0-8.5%
Annual salary increase rate . . . . . . . . . . 5.0 % 6.0%
Long-term rate of return. . . . . . . . . . . . 8.0-8.5 % 8.0-8.5%

Early Retirement and Voluntary Separation Plans: In January 1992, the
Board of Directors approved an early retirement plan and a voluntary
separation program. The voluntary early retirement plan was offered to all
vested participants of the Company's defined benefit pension plan who reached
the age of 55 with 10 or more years of service on or before May 1, 1992.
Certain pension plan improvements were made including a waiver of the
actuarial reduction factors for early retirement and a cash incentive payable
as a monthly supplement up to 60 months or a lump sum payment. Of the 111
employees eligible for the early retirement option, 71, representing 6% of the
Company's work force, elected to retire on or before the May 1, 1992,
deadline. Another 29 employees, with 10 or more years of service, elected to
participate in the voluntary separation program. In addition, 61 employees
received Merger-related severance benefits. The actuarial cost, based on plan
provisions for early retirement and voluntary separation programs, and Merger-
related severance benefits, was approximately $3.9 million of which $1.8
million was included in the pension liability at December 31, 1992. The
actuarial cost was considered in purchase accounting for the Merger (See Note
1).
Postretirement: The Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of
1993. This statement requires the accrual of postretirement benefits other
than pensions, primarily medical benefits costs, during the years an employee
provides service.
Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, the annual expense under SFAS 106 was approximately $3.4 million
in 1993 (as compared to approximately $1.8 million on a cash basis) and the
Company's total obligation was approximately $23.9 million at December 31,
1993. To mitigate the impact of SFAS 106 expense, the Company has implemented
programs to reduce health care costs. In addition, the Company has received
an order from the KCC permitting the initial deferral of SFAS 106 expense. To
mitigate the impact SFAS 106 expense will have on rate increases, the Company
will include in the future computation of cost of service the actual SFAS 106
expense and an income stream generated from corporate-owned life insurance
policies (COLI) purchased in 1993 and 1992. To the extent SFAS 106 expense
exceeds income from the COLI program, this excess will be deferred (as allowed
by FASB Emerging Issues Task Force Issue No. 92-12) and offset by income
generated through the deferral period by the COLI program. Should the income
stream generated by the COLI program not be sufficient to offset the deferred
SFAS 106 expense, the KCC order allows recovery of such deficit through the
ratemaking process.

Prior to the adoption of SFAS 106 the Company's policy was to recognize
expenses as claims were paid. The costs of benefits were $0.8 million for the
nine months ended December 31, 1992, $0.2 million for the three months ended
March 31, 1992, and $2.1 million for 1991.

The following table summarizes the status of the Company's postretirement
plans for financial statement purposes and the related amount included in the
balance sheet:

December 31, 1993
(Dollars in Millions)
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . . $ 12.4
Active employees fully eligible . . . . . . . . 2.5
Active employees not fully eligible . . . . . . 9.0
Unrecognized prior service cost . . . . . . . . (.1)
Unrecognized transition obligation. . . . . . . (20.4)
Unrecognized net loss . . . . . . . . . . . . . (1.7)
Balance sheet liability . . . . . . . . . . . . . . $ 1.7

For measurement purposes, an annual health care cost growth rate of 13%
was assumed for 1994, decreasing to 6% by 2002 and thereafter. The
accumulated post retirement benefit obligation was calculated using a
weighted-average discount rate of 7.75%, a weighted-average compensation
increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%.
The health care cost trend rate has a significant effect on the projected
benefit obligation. Increasing the trend rate by 1% each year would increase
the present value of the accumulated projected benefit obligation by $.6
million and the aggregate of the service and interest cost components by $.1
million.

Postemployment: The FASB has issued Statement of Financial Accounting
Standards No. 112 (SFAS 112), which establishes accounting and reporting
standards for postemployment benefits. The new statement will require the
Company to recognize the liability to provide postemployment benefits when the
liability has been incurred. The Company adopted SFAS 112 effective January
1, 1994. To mitigate the impact adopting SFAS 112 will have on rate
increases, the Company will file an application with the KCC for an order
permitting the initial deferral of SFAS 112 transition costs and expenses and
its inclusion in the future computation of cost of service net of an income
stream generated from COLI. At December 31, 1993, the Company estimates SFAS
112 liability to total approximately $700,000.

Savings Plans: The Company maintains 401(k) savings plans in which
substantially all employees participate. The Company matches employees'
contributions up to a maximum limit of 3 percent of the employees' salary.
Prior to the Merger, the Company's matching contribution was based on the
Company's performance during the prior year and the level of employee
contributions. The funds of the plans are deposited with a trustee and
invested at each employee's option in one or more investment funds, including
a Western Resources common stock fund. The Company's contributions were $1.3
for 1993, $1.7 million for the nine months ended December 31, 1992, $0.2
million for the three months ended March 31, 1992, and $2.0 million for 1991.

9. INCOME TAXES

The Company adopted Statement of Financial Accounting Standards No. 96
(SFAS 96) in 1987. This statement required the Company to establish deferred
tax assets and liabilities, as appropriate, for all temporary differences, and
to adjust deferred tax balances to reflect changes in tax rates expected to be
in effect during the periods the temporary differences reverse. SFAS 96 was
superseded by SFAS 109 issued in February 1992 and the Company adopted the
provisions of that standard prospectively in the first quarter of 1992. The
accounting for SFAS 109 is substantially the same as SFAS 96.

In accordance with various rate orders received from the KCC, the Company
has not yet collected through rates the amounts necessary to pay a significant
portion of the net deferred income tax liabilities. As management believes it
is probable that the net future increases in income taxes payable will be
recovered from customers through future rates, 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. Accordingly, the
adoption of SFAS 109 did not have a material effect on the Company's results
of operations.

At December 31, 1993, the Company had unused investment tax credits of
approximately $7.1 million available for carryforward which, if not utilized,
will expire in the years 2000 through 2002 (see Note 3). In addition, the
Company has alternative minimum tax credits generated prior to April 1, 1992,
which carryforward without expiration, of $53.9 million which may be used to
offset future regular tax to the extent the regular tax exceeds the
alternative minimum tax. These credits have been applied in determining the
Company's net deferred income tax liability and corresponding deferred future
income taxes at December 31, 1993.

Beginning April 1, 1992, the Company is part of the consolidated income
tax return of Western Resources. However, the Company determines its income
tax provisions on a separate company basis.

Deferred income taxes result from temporary differences between the
financial statement and tax basis of the Company's assets and liabilities.
The sources of these differences and their cumulative tax effects are as
follows:

December 31, 1993
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (350,105) $ (350,105)
Energy and purchased gas
adjustment clauses . . . . . . . 3,257 - 3,257
Phase-in revenues. . . . . . . . . - (35,573) (35,573)
Deferred gain on sale-leaseback. . 116,186 - 116,186
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (7,797) (7,797)
Deferred compensation/pension
liability. . . . . . . . . . . . 10,856 - 10,856
Acquisition premium. . . . . . . . - (300,814) (300,814)
Deferred future income taxes . . . - (109,178) (109,178)
Other. . . . . . . . . . . . . . . - (12,873) (12,873)
Total Deferred Income Taxes. . . . . $ 170,181 $ (816,340) $ (646,159)

December 31, 1992
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (324,972) $ (324,972)
Energy and purchased gas
adjustment clauses . . . . . . . 2,691 - 2,691
Phase-in revenues. . . . . . . . . - (37,564) (37,564)
Deferred gain on sale-leaseback. . 104,573 - 104,573
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (9,263) (9,263)
Deferred compensation/pension
liability. . . . . . . . . . . . 11,002 - 11,002
Acquisition premium. . . . . . . . - (313,721) (313,721)
Deferred future income taxes . . . - (146,962) (146,962)
Other. . . . . . . . . . . . . . . 3,138 - 3,138
Total Deferred Income Taxes. . . . . $ 161,286 $ (832,482) $ (671,196)

10. LEGAL PROCEEDINGS

The Company is involved in various other legal and environmental
proceedings. Management believes that adequate provision has been made within
the financial statements for these matters and accordingly believes their
ultimate dispositions will not have a material adverse effect upon the
financial position or results of operations of the Company.

A provision of $12 million was recorded in miscellaneous expenses on the
1991 statement of income with respect to various legal matters.

11. 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:

Cash and Cash Equivalents-
The carrying amount approximates the fair value because of the short-
term maturity of these investments.
Decommissioning Trust-
The fair value of the decommissioning trust is based on quoted market
prices at December 31, 1993 and 1992.
Variable-rate Debt-
The carrying amount approximates the fair value because of the short-
term variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of the
estimated value of each issue taking into consideration the coupon
rate, maturity, and redemption provisions of each issue.

The estimated fair values of the Company's financial instruments are as
follows:

Carrying Value Fair Value
December 31, 1993 1992 1993 1992
(Dollars in Thousands)

Cash and cash
equivalents. . . . . . . $ 63 $ 892 $ 63 $ 892
Decommissioning trust. . . 13,204 9,272 13,929 9,500
Variable-rate debt . . . . 478,743 375,909 478,743 375,909
Fixed-rate debt. . . . . . 603,920 679,145 660,750 705,970

12. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 1993
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)

La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50
Jeffrey 1 (b) Jul 1978 65,803 28,717 140 20
Jeffrey 2 (b) May 1980 64,375 25,552 135 20
Jeffrey 3 (b) May 1983 95,336 31,084 140 20
Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47

(a) Jointly owned with Kansas City Power & Light Company (KCP&L)
(b) Jointly owned with Western Resources, UtiliCorp United Inc., and a third
party
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

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 percent undivided interest in La Cygne 2 (representing 335 MW
capacity) sold and leased back to the Company in 1987, are included in
operating expenses in 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.

13. QUARTERLY FINANCIAL STATISTICS (Unaudited)
(Dollars in Thousands)

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.

1993
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr.
(Successor)

Operating revenues. . . . . $136,097 $191,941 $150,478 $138,481
Operating income. . . . . . 26,188 52,874 35,545 32,774
Net income. . . . . . . . . 13,692 46,406 24,274 23,731
Earnings applicable
to common stock . . . . . 13,692 46,406 24,274 23,731

14. RELATED PARTY TRANSACTIONS

Subsequent to the Merger, the cash management function, including cash
receipts and disbursements, for KG&E has been assumed by Western Resources.
As a result, the proceeds of cash collections, including short-term
borrowings, less disbursements related to KG&E transactions have been recorded
by the Companies through an intercompany account which, at December 31, 1993,
resulted in a net advance by KG&E to Western Resources of $192.8 million.
Certain of the Company's operating expenses have been allocated 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.

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

There were no disagreements with accountants on accounting and financial
disclosure. Information relating to a change in accountants is incorporated
by reference from the Company's Current Report on Form 8-K dated March 8,
1993.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Western Resources, Inc. owns 100 percent of the Company's outstanding
common stock.
A Director
Business Experience Since 1988 and Other Continuously
Name Age Directorships Other Than The Company Since

Kent R. Brown 48 Chairman of the Board, President and 1992
Chief Executive Officer since June
1992, and prior to that President
and Chief Executive Officer since
March 1992, and prior to that Group
Vice President
Directorships
Bank IV Wichita

Robert T. Crain 68 Owner, Crain Realty, Co., Fort Scott, 1992(b)
(a) Kansas
Directorships
Citizens National Bank

Anderson E. 60 President, Jackson Mortuary, Wichita, 1994
Jackson Kansas

Donald A. 60 President, Maupintour, Inc., Lawrence, 1992(b)
Johnston Kansas (Escorted Tours and Travel)
(a) Directorships
Commerce Bank, Lawrence
Maupintour, Inc.

Steven L. 48 Executive Vice President and Chief 1992
Kitchen Financial Officer, Western Resources,
Inc., (since March 1990) and prior to
that Senior Vice President, Finance
and Accounting (October 1987 to
March 1990)

Glenn L. 68 Retired Vice President - Nuclear of the 1992(b)
Koester Company

James J. Noone 73 Attorney and retired Administrative Judge 1992(b)
(a) for the District Court of Sedgwick
County, Kansas

Marilyn B. 44 President, Bank IV Wichita, 1994
Pauly Wichita, Kansas
Directorships
St. Francis Regional Medical Center
Farmers Mutual Alliance Insurance Company

A Director
Business Experience Since 1988 and Other Continuously
Name Age Directorships Other Than The Company Since

Newton C. Smith 72 Physician and Surgeon, Arkansas City, 1992(b)
Kansas

Richard Smith 60 President, Range Oil Company 1993
Directorships
Bank IV Kansas
Wichita HCA Wesley Medical Center

(a) 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.
(b) Mr. Crain, Mr. Johnston, Mr. Koester, Mr. Noone, and Mr. Newton
Smith were directors of the former Kansas Gas & Electric Company
since 1981, 1980, 1986, 1986, and 1985, respectively.

Outside Directors are paid $3,750 per quarter retainer and all Directors
are paid an attendance fee of $600 for Directors' meetings ($300 if attending
by phone) and $500 for committee meetings. An additional committee meeting
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.

The Board of Directors held 5 meetings during the year and the Audit
Committee held 2 meetings. All Directors attended 75% or more of their
applicable meetings.

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.

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, 1993 and 1992
Statements of Income for the year ended December 31, 1993 (Successor),
the nine months ended December 31, 1992 (Successor), the three months
ended March 31, 1992 (Predecessor), and the year ended December
31, 1991 (Predecessor)
Statements of Cash Flows for the year ended December 31, 1993 (Successor),
the period March 31 to December 31, 1992 (Successor), the three months
ended March 31, 1992 (Predecessor), and the year ended December
31, 1991 (Predecessor)
Statements of Taxes for the year ended December 31, 1993 (Successor), the
nine months ended December 31, 1992 (Successor), the three months ended
March 31, 1992 (Predecessor), and the year ended December 31, 1991
(Predecessor)
Statements of Capitalization, December 31, 1993 and 1992
Statements of Common Stock Equity for the year ended December 31, 1993
(Successor), the nine months ended December 31, 1992 (Successor), the
three months ended March 31, 1992 (Predecessor), and the year ended
December 31, 1991 (Predecessor)
Notes to Financial Statements

The following supplemental schedules are included herein.

SCHEDULES

Schedule V - Utility Plant for the year ended December 31, 1993, (Successor),
the nine months ended December 31, 1992 (Successor), the three months ended
March 31, 1992 (Predecessor), and the year ended December 31, 1991
(Predecessor)
Schedule VI - Accumulated Depreciation of Utility Plant for the year ended
December 31, 1993 (Successor), the nine months ended December 31, 1992
(Successor) the three months ended March 31, 1992 (Predecessor), and the
year ended December 31, 1991 (Predecessor)

REPORTS ON FORM 8-K

Form 8-K dated January 31, 1994

EXHIBIT INDEX

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

Description

2(a) Agreement and Plan of Merger (Filed as Exhibit 2 to Form 10-K I
for the year ended December 31, 1990, File No. 1-7324).

2(b) Amendment No. 1 to Agreement and Plan of Merger (Filed as I
Exhibit 2 to Form 10-K for the year ended December 31, 1990,
File No. 1-7324).

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) to Form 10-K I
for the year ended December 31, 1992, File No. 1-7324)

4(c)1 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-six
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, and August 24, 1993, (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

Description

December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3,
File No. 33-50075)

4(c)2 Thirty-seventh Supplemental Indenture dated as of January 15, 1994,
to the Company's Mortgage and Deed of Trust (Filed electronically)

4(c)3 Thirty-eighth Supplemental Indenture dated as of March 1, 1994,
to the Company's Mortgage and Deed of Trust (Filed electronically)

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)1 Severance Agreement (Filed as Exhibit 10(a)1 to Form 10-K for the I
year ended December 31, 1990, File No. 1-7324).

10(a)2 Severance Agreement (Filed as Exhibit 10(a)2 to Form 10-K for the I
year ended December 31, 1990, File No. 1-7324).

10(a)3 Severance Agreement (Filed as Exhibit 10(a)3 to Form 10-K for the I
year ended December 31, 1990, File No. 1-7324).

10(b) 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(b)1 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(c) Outside Directors' Deferred Compensation Plan

12 Computation of Ratio of Consolidated Earnings to Fixed Charges.
(Filed electronically)

16 Letter re Change in Certifying Accountant. (Filed as Exhibit 16 to I
the Current Report on Form 8-K dated March 8, 1993.

23(a) Consent of Independent Public Accountants, Arthur Andersen & Co.
(Filed electronically)

23(b) Consent of Independent Public Accountants, Deloitte & Touche
(Filed electronically)

KANSAS GAS AND ELECTRIC COMPANY

Schedule V - Utility Plant

(Successor)

Balance at Transfers, Balance at
Beginning Additions Retire- Reclassi- End
Classification of Period at Cost ments fications of Period
(Thousands of Dollars)

For the Year Ended December 31, 1993

Electric Plant:
Steam Production. . . . . . . . . $ 469,258 $ 26,648 $ 2,710 $ - $ 493,196
Nuclear Production. . . . . . . . 1,355,678 11,324 614 - 1,366,388
Transmission. . . . . . . . . . . 215,898 1,422 141 - 217,179
Distribution. . . . . . . . . . . 371,714 19,630 1,872 - 389,472
General . . . . . . . . . . . . . 62,110 6,839 1,846 - 67,103
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 29,634 (1,198) - - 28,436
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,458 5 129 - 15,334
Nuclear Fuel. . . . . . . . . . . 59,305 6,764 19,381 - 46,688
Plant Acquisition Adjustment. . . 796,265 - - (12,089) 784,176
$3,382,304 $ 71,434 $ 26,693 $ (12,089) $3,414,956

KANSAS GAS AND ELECTRIC COMPANY

Schedule V - Utility Plant

Balance at Transfers, Balance at
Beginning Additions Retire- Reclassi- End
Classification of Period at Cost ments fications of Period
(Thousands of Dollars)
(Pro Forma) (2)
For the Year Ended December 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $ 463,198 $ 8,420 $ 2,354 $ (6) $ 469,258
Nuclear Production. . . . . . . . 1,358,428 4,283 7,033 - 1,355,678
Transmission. . . . . . . . . . . 213,928 2,328 358 - 215,898
Distribution. . . . . . . . . . . 357,486 15,764 1,536 - 371,714
General . . . . . . . . . . . . . 62,295 1,933 762 (1,356) 62,110
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 13,612 16,024 - (2) 29,634
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,433 - - 25 15,458
Nuclear Fuel. . . . . . . . . . . 42,731 16,661 - (87) 59,305
Plant Acquisition Adjustment. . . - 796,265(1) - - 796,265
$2,534,095 $861,678 $12,043 $ (1,426) $3,382,304

(Successor)
For the Nine Months Ended December 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $ 468,032 $ 3,034 $ 1,808 $ - $ 469,258
Nuclear Production. . . . . . . . 1,358,833 3,505 6,660 - 1,355,678
Transmission. . . . . . . . . . . 213,898 2,220 220 - 215,898
Distribution. . . . . . . . . . . 359,223 13,531 1,040 - 371,714
General . . . . . . . . . . . . . 61,007 1,799 696 - 62,110
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 15,744 13,892 - (2) 29,634
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,458 - - - 15,458
Nuclear Fuel. . . . . . . . . . . 43,456 15,936 - (87) 59,305
Plant Acquisition Adjustment. . . - 796,265(1) - - 796,265
$2,542,635 $850,182 $10,424 $ (89) $3,382,304

(Predecessor)
For the Three Months Ended March 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $ 463,198 $ 5,386 $ 546 $ (6) $ 468,032
Nuclear Production. . . . . . . . 1,358,428 778 373 - 1,358,833
Transmission. . . . . . . . . . . 213,928 108 138 - 213,898
Distribution. . . . . . . . . . . 357,486 2,233 496 - 359,223
General . . . . . . . . . . . . . 62,295 134 66 (1,356) 61,007
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 13,612 2,132 - - 15,744
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,433 - - 25 15,458
Nuclear Fuel. . . . . . . . . . . 42,731 725 - - 43,456
$2,534,095 $11,496 $ 1,619 $ (1,337) $2,542,635

(1) See Note 1 of Notes to the Financial Statements for explanation of plant acquisition adjustment.
(2) The pro forma information for the year ended December 31, 1992 was derived by combining the
historical information of the three month period ended March 31, 1992 (Predecessor) and the
nine month period ended December 31, 1992 (Successor). No purchase accounting adjustments
were made for periods prior to the Merger in determining pro forma amounts because such
adjustments would be immaterial.

KANSAS GAS AND ELECTRIC COMPANY

Schedule V - Utility Plant

(Predecessor)

Balance at Transfers, Balance at
Beginning Additions Retire- Reclassi- End
Classification of Period at Cost ments fications of Period
(Thousands of Dollars)

For the Year Ended December 31, 1991

Electric Plant:
Steam Production. . . . . . . . . $ 450,753 $13,746 $ 1,300 $ (1) $ 463,198
Nuclear Production. . . . . . . . 1,363,312 11,032 15,916 - 1,358,428
Transmission. . . . . . . . . . . 208,705 6,356 1,129 (4) 213,928
Distribution. . . . . . . . . . . 340,458 19,206 2,178 - 357,486
General . . . . . . . . . . . . . 58,353 5,286 1,342 (2) 62,295
Electric Plant Leased to Others . 6,980 - - 4 6,984
Construction Work in Progress . . 14,760 (1,148) - - 13,612
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,370 88 28 3 15,433
Nuclear Fuel. . . . . . . . . . . 28,152 19,782 5,203 - 42,731
$2,486,843 $74,348 $27,096 $ - $2,534,095

KANSAS GAS AND ELECTRIC COMPANY

Schedule VI - Accumulated Depreciation of Utility Plant

(Successor)

Additions
Balance at Charged to Balance at
Beginning Costs and Retire- Other End
Description of Period Expenses ments Charges of Period
(Thousands of Dollars)

For the Year Ended December 31, 1993

Electric Plant:
Steam Production. . . . . . . . . $242,596 $16,486 $ 3,159 $ - $255,923
Nuclear Production. . . . . . . . 247,370 35,465 832 31 282,034
Transmission. . . . . . . . . . . 74,167 5,244 20 - 79,391
Distribution. . . . . . . . . . . 120,897 11,324 2,449 - 129,772
General . . . . . . . . . . . . . 29,100 4,576 1,359 1,260 33,577
Electric Plant Leased to Others . 1,239 174 - 1,413
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,819 - 86 - 8,733
Nuclear Fuel. . . . . . . . . . . 25,993 10,805 19,381 - 17,417
$750,181 $84,074 $27,286 $1,291 $808,260

KANSAS GAS AND ELECTRIC COMPANY

Schedule VI - Accumulated Depreciation of Utility Plant

Additions
Balance at Charged to Balance at
Beginning Costs and Retire- Other End
Description of Period Expenses ments Charges of Period
(Thousands of Dollars)

(Pro Forma) (1)
For the Year Ended December 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $228,538 $16,433 $ 2,374 $ (1) $242,596
Nuclear Production. . . . . . . . 219,311 35,361 7,302 - 247,370
Transmission. . . . . . . . . . . 69,355 5,199 387 - 74,167
Distribution. . . . . . . . . . . 111,961 10,835 1,899 - 120,897
General . . . . . . . . . . . . . 25,003 4,369 745 473 29,100
Electric Plant Leased to Others . 1,065 174 - - 1,239
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,793 - - 26 8,819
Nuclear Fuel. . . . . . . . . . . 16,132 9,850 - 11 25,993
$680,158 $82,221 $12,707 $ 509 $750,181

(Successor)
For the Nine Months Ended December 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $232,589 $11,942 $ 1,935 $ - $242,596
Nuclear Production. . . . . . . . 227,819 26,438 6,887 - 247,370
Transmission. . . . . . . . . . . 70,547 3,960 340 - 74,167
Distribution. . . . . . . . . . . 114,153 8,113 1,369 - 120,897
General . . . . . . . . . . . . . 26,211 3,147 695 437 29,100
Electric Plant Leased to Others . 1,109 130 - - 1,239
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,819 - - - 8,819
Nuclear Fuel. . . . . . . . . . . 17,377 8,605 - 11 25,993
$698,624 $62,335 $11,226 $ 448 $750,181

(Predecessor)
For the Three Months Ended March 31, 1992

Electric Plant:
Steam Production. . . . . . . . . $228,538 $ 4,491 $ 439 $ (1) $232,589
Nuclear Production. . . . . . . . 219,311 8,923 415 - 227,819
Transmission. . . . . . . . . . . 69,355 1,239 47 - 70,547
Distribution. . . . . . . . . . . 111,961 2,722 530 - 114,153
General . . . . . . . . . . . . . 25,003 1,222 50 36 26,211
Electric Plant Leased to Others . 1,065 44 - - 1,109
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,793 - - 26 8,819
Nuclear Fuel. . . . . . . . . . . 16,132 1,245 - - 17,377
$680,158 $19,886 $ 1,481 $ 61 $698,624

(1) The pro forma information for the year ended December 31, 1992 was derived by combining the
historical information of the three month period ended March 31, 1992 (Predecessor) and the
nine month period ended December 31, 1992 (Successor). No purchase accounting adjustments
were made for periods prior to the Merger in determining pro forma amounts because such
adjustments would be immaterial.

KANSAS GAS AND ELECTRIC COMPANY

Schedule VI - Accumulated Depreciation of Utility Plant

(Predecessor)

Additions
Balance at Charged to Balance at
Beginning Costs and Retire- Other End
Description of Period Expenses ments Charges of Period
(Thousands of Dollars)

For the Year Ended December 31, 1991

Electric Plant:
Steam Production. . . . . . . . . $212,421 $17,305 $ 1,207 $ 19 $228,538
Nuclear Production. . . . . . . . 199,938 35,460 16,087 - 219,311
Transmission. . . . . . . . . . . 65,463 5,107 1,215 - 69,355
Distribution. . . . . . . . . . . 104,043 10,396 2,478 - 111,961
General . . . . . . . . . . . . . 21,582 4,127 1,278 572 25,003
Electric Plant Leased to Others . 891 174 - - 1,065
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,841 - 29 (19) 8,793
Nuclear Fuel. . . . . . . . . . . 15,607 5,728 5,203 - 16,132
$628,786 $78,297 $27,497 $ 572 $680,158

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 18, 1994 By KENT R. BROWN
(Kent R. Brown, Chairman of the Board,
President and Chief Executive Officer)

SIGNATURES

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

Signature Title Date

Chairman of the Board, President
KENT R. BROWN and Chief Executive Officer March 18,
1994
(Kent R. Brown) (Principal Executive Officer)

Secretary, Treasurer and General
RICHARD D. TERRILL Counsel (Principal Financial March 18,
1994
(Richard D. Terrill) and Accounting Officer)

ROBERT T. CRAIN
(Robert T. Crain)

(Anderson E. Jackson)

DONALD A. JOHNSTON
(Donald A. Johnston)

S. L. KITCHEN Directors March 18,
1994
(S. L. Kitchen)

GLENN L. KOESTER
(Glenn L. Koester)

JAMES J. NOONE
(James J. Noone)

(Marilyn B. Pauly)

NEWTON C. SMITH, M.D.
(Newton C. Smith, M. D.)

RICHARD SMITH
(Richard Smith)