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, 1994

[ ] 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 29, 1995)

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

Registrant meets the conditions of General Instruction J(1)(a)(b) to Form 10-K
for certain wholly-owned subsidiaries and is therefore filing an abbreviated
form.
2

KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1994

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 12

Item 3. Legal Proceedings 13

Item 4. Submission of Matters to a Vote of
Security Holders 13

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 13

Item 6. Selected Financial Data 13

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 14

Item 8. Financial Statements and Supplementary Data 20

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 50

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, 1994, the Company had no employees. All employees are provided
by Western Resources.

For discussion regarding competition in the electric utility industry and
the potential impact on the Company, see Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations, Other Information,
Competition included herein.

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.

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 272,000
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.
4

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

1994 1993 1992 1991 1990
(Thousands of MWH)
Residential 2,384 2,386 2,102 2,341 2,270
Commercial 2,068 1,991 1,892 1,908 1,838
Industrial 3,371 3,323 3,248 3,194 3,093
Wholesale and
Interchange 1,590 2,004 1,267 1,168 1,688
Other 45 45 46 46 48
----- ----- ----- ----- -----
Total 9,458 9,749 8,555 8,657 8,937

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

1994 1993 1992 1991 1990
(1)
(Dollars in Thousands)
Residential $220,067 $219,069 $194,142 $219,907 $214,544
Commercial 167,499 162,858 154,005 155,847 151,098
Industrial 181,119 179,256 174,226 172,953 168,294
Wholesale and
Interchange 38,750 45,843 28,086 29,989 36,152
Other 12,445 9,971 3,792 16,272 16,553
-------- -------- -------- -------- --------
Total $619,880 $616,997 $554,251 $594,968 $586,641

(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
2,498 megawatts (MW). The system comprises interests in twelve fossil fueled
steam generating units, one nuclear generating unit (47 percent 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 1994 peak system net load occurred on July 1, 1994 and
amounted to 1,747 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 27 percent 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.

The Company is one of 47 members of the Southwest Power Pool (SPP). SPP's
responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri,
Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi.

In 1994, the Company joined the Western Systems Power Pool (WSPP). Under
this arrangement, over 50 electric utilities and marketers throughout the
western
5

United States have agreed to market energy and to provide transmission
services. WSPP's intent is to increase the efficiency of the interconnected
power systems operations over and above existing operations. Services
available include short-term and long-term economy energy transactions, unit
commitment service, firm capacity and energy sales, energy exchanges, and
transmission service by intermediate systems.

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

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 Item 7. 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 1,101 MW of the total 2,498 MW of
generating capacity and the Company's nuclear unit provides 545 MW of
capacity. Of the remaining 852 MW of generating capacity, units that can burn
either natural gas or oil account for 849 MW, and the remaining unit which
burns only diesel fuel accounts for 3 MW (see Item 2. Properties).

During 1994, low sulfur coal was used to produce 56% of the Company's
electricity. Nuclear produced 34 percent and the remainder was produced from
natural gas, oil, or diesel fuel. During 1995, based on the Company's
estimate of the availability of fuel, coal will to be used to produce
approximately 58 percent of the Company's electricity and nuclear will be used
to produce 36 percent.

The Company's fuel mix fluctuates with the operation of nuclear powered
Wolf Creek which has an 18-month refueling and maintenance schedule. The 18-
month schedule permits uninterrupted operation every third calendar year. In
mid-September 1994, Wolf Creek was taken off-line for its seventh refueling
and maintenance outage. The refueling outage took approximately 47 days to
complete, during which time electric demand was met primarily by the Company's
coal-fired generating units. There is no refueling outage scheduled for 1995.

Nuclear

The owners of Wolf Creek have on hand or under contract 63 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 1995-1997, 90 percent for 1998-1999, 95
percent for
6
2000-2001 and 100 percent for 2005-2014. The balance of the 1998-2004
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 1996
as well as the fabrication of fuel assemblies to meet Wolf Creek's
requirements through 2012.

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.

The Company along with the other co-owners of Wolf Creek are among 14
companies that filed a lawsuit on June 20, 1994, seeking an interpretation of
the DOE's obligation to begin accepting spent nuclear fuel for disposal in
1998. The DOE has filed a motion to have this case dismissed. The issue to
be decided in this case is whether DOE must begin accepting spent fuel in 1998
or at a future date.

Coal

The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 423 MW (KG&E's 20 percent share) (see Item 2.
Properties). Western Resources, the operator of JEC, and KG&E, have a long-
term coal supply contract with Amax Coal West, Inc. (AMAX), a subsidiary of
Cyprus Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle
Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located
in the Powder River Basin in Campbell County, Wyoming. The contract expires
December 31, 2020. The contract contains a schedule of minimum annual
delivery quantities based on MMBtu provisions. The coal to be supplied is
surface mined and has an average Btu content of approximately 8,300 Btu per
pound and an average sulfur content of .43 lbs/MMBtu (see Environmental
Matters). The average delivered cost of coal for JEC was approximately $1.13
per MMBtu or $18.55 per ton during 1994.

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 890 aluminum rail
cars, under a 20 year lease, to transport coal to JEC.

The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 678 MW (KG&E's 50 percent share) (see Item 2. Properties). The
operator, Kansas City Power & Light Company (KCPL), maintains coal contracts
as discussed in the following paragraphs.

7
La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under
a variety of spot market transactions, 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.

La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied
through several contracts expiring at various times through 1998. 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, KCPL secured Powder River Basin 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
KCPL 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. A new five-year coal transportation agreement is being negotiated
to provide transportation beyond 1995.

During 1994, the average delivered cost of all coal procured for La Cygne
1 was approximately $0.78 per MMBtu or $14.11 per ton and the average
delivered cost of Powder River Basin coal for La Cygne 2 was approximately
$0.73 per MMBtu or $12.30 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). After 1995, the Company expects to use the spot market to purchase
most of the natural gas needed to fuel these generating stations. Short-term
economical spot market purchases from the Williams Natural Gas (WNG) system
provide the Company flexible natural gas supply arrangements 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, 1994, the Company had approximately 715 thousand gallons of No. 2
oil and 11 million gallons of No. 6 oil which is believed to be sufficient to
meet emergency requirements and protect against lack of availability of
natural gas and/or the loss of a large generating unit.

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.

8
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 impact the
Company's earnings.

Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
1994 1993 1992 1991 1990
Per Million Btu:
Nuclear $0.36 $0.35 $0.34 $0.32 $0.34
Coal 0.90 0.96 1.25 1.32 1.32
Gas 1.98 2.37 1.95 1.74 1.96
Oil 3.90 3.15 4.28 4.13 3.01

Cents per KWH Generation 0.89 0.93 0.98 1.09 1.01

Environmental Matters

The Company currently holds all Federal and State environmental approvals
required for the operation of 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 oxides
of nitrogen (NOx)) promulgated by the State of Kansas and the Environmental
Protection Agency (EPA).

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

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

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 sufficient low sulfur coal under contract
(see Coal) to allow compliance with such limits at La Cygne 1. 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 NOx emissions effective in 1995 and 2000 and a
probable
9
reduction in toxic emissions. To meet the monitoring and reporting
requirements under the acid rain program, the Company installed continuous
monitoring and reporting equipment at a total cost of approximately $2.3
million. The Company does not expect additional equipment to reduce sulfur
emissions to be necessary under Phase II. Although the Company currently has
no Phase I affected units, the owners have applied for an early substitution
permit to bring the co-owned La Cygne Generating Station under the Phase I
regulations.
The NOx and toxic limits, which were not set in the law, will be specified
in future EPA regulations. NOx regulations for Phase II units and Phase I
group 2 units are mandated in the Act. The EPA's proposed NOx regulations
were ruled invalid by the U.S. Court of Appeals for the District of Columbia
Circuit in November 1994, and until such time as the EPA resubmits new
proposed regulations, 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, 1994,
approximately $743 million principal amount of additional first mortgage bonds
could be issued (8.75 percent interest rate assumed).

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,
1994, 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 $909 million principal amount of additional 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
10
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.

11
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years

Kent R. Brown 49 Chairman of the Board, Group Vice President
(since June 1992)
President and Chief
Executive Officer
(since March 1992)

Richard D. LaGree 64 Vice President, Field Vice President, Electric
Operations (since Distribution Operations,
April 1992) Western Resources, Inc.

Richard D. Terrill 40 Secretary, Treasurer Secretary and Attorney
and General Counsel
(since April 1992)

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

12
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, 1994, the Company's gross
property additions totalled $358,486,000 and retirements were $130,238,000.

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 143
3 1983 Coal 140

La Cygne Station (50%):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 335

Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 74
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 545
-----
Total 2,498

(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%).

13
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 from the New York Stock
Exchange and the Pacific Stock Exchange.

ITEM 6. SELECTED FINANCIAL DATA

1994 1993 1992 1991 1990(1)
(Dollars in Thousands)

Income Statement Data:

Operating revenues . . . . . . . $ 619,880 $ 616,997 $ 554,251 $ 594,968 $ 586,641
Operating expenses . . . . . . . 470,869 469,616 424,089 468,885 447,355
Operating income . . . . . . . . 149,011 147,381 130,162 126,083 139,286
Net income . . . . . . . . . . . 104,526 108,103 77,981 53,602 64,184

Balance Sheet Data:

Gross electric plant in service. $3,390,406 $3,339,832 $3,293,365 $2,468,959 $2,435,090
Construction work in progress. . 32,874 28,436 29,634 13,612 14,760
Total assets . . . . . . . . . . 3,142,810 3,187,479 3,279,232 2,350,546 2,348,862
Long-term debt . . . . . . . . . 699,992 653,543 871,652 850,851 824,424

Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 4.02 3.58 2.35 1.90 2.07

Ratio of Earnings to Fixed Charges 2.61 2.60 1.89 1.59 1.71

(1) See Note 1 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 years ended December 31, 1994 and 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. Additional information relating to changes between years is provided in
the Notes to Financial Statements.

GENERAL: The Company had net income of $104.5 million for 1994 compared
to net income of $108.1 million in 1993. The decrease in net income is
primarily due to increases in income taxes as a result of the completion of
the accelerated amortization of certain deferred income tax reserves and the
receipt of death benefit proceeds from corporate-owned life insurance policies
in the third quarter of 1993. As of December 31, 1993, the Company had fully
amortized the deferred income tax reserves related to the allowance for funds
used during construction capitalized for Wolf Creek Generating Station (Wolf
Creek). The completion of the amortization of these deferred income tax
reserves increased income tax expense and thereby reduced net income by
approximately $12 million in 1994, and in the future will reduce net income by
this same amount each year.

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 1994, construction expenditures for the Company's electric system
were approximately $69 million and nuclear fuel expenditures were
approximately $21 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.

Capital expenditures for 1995 through 1997 are anticipated to be as
follows:

Electric Nuclear Fuel
(Dollars in Thousands)
1995. . . . . . . . . . $53,961 $ 21,400
1996. . . . . . . . . . 47,388 8,100
1997. . . . . . . . . . 42,453 24,000

These expenditures are estimates prepared for planning purposes and are
subject to revisions from time to time.
15

The Company's net cash flows to capital expenditures exceeded 100 percent
for 1994 and during the last five years has also averaged in excess of 100
percent. The Company anticipates all of its cash requirements for capital
expenditures through 1997 will be provided from net cash flows. The Company
also has $16 million of bonds maturing through 1999 which will be provided
from internal and external sources available under then existing financial
conditions.

During 1994, the Company continued to take advantage of favorable long-
term interest rates by refinancing long-term debt issues. The embedded cost
of long-term debt was 7.3% at December 31, 1994, a decrease from 7.7% at
December 31, 1993.

On January 20, 1994, the Company issued $100 million of First Mortgage
Bonds, 6.20% Series due January 15, 2006. The net proceeds were used to
reduce short-term debt.

On February, 17, 1994, the Company refinanced the City of La Cygne,
Kansas, 5 3/4% Pollution Control Revenue Refunding Bonds Series 1973,
$13,980,000 principal amount, with 5.10% Pollution Control Revenue Refunding
Bonds Series 1994, $13,982,500 principal amount, due 2023.

On April 28, 1994, three series of Market-Adjusted Tax Exempt Securities
totalling $46.4 million were sold on behalf of the Company at a rate of 2.95%
for the initial auction period. The interest rates are being reset
periodically via an auction process. As of December 31, 1994, the rate on
these bonds was 4.10%. The net proceeds from the new issues, together with
available cash, were used to refund three series of Pollution Control Bonds
totalling $46.4 million bearing interest rates between 5 7/8% and 6.8%.

On November 1, 1994, the Company terminated a long-term agreement which
contained provisions for the sale of accounts receivable and unbilled
revenues, and phase-in revenues (see Note 6).

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 1992 through 1994 was approximately $27 million. See
Note 2 of the Notes to Financial Statements for additional information on the
accumulated cash surrender value. 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, 1994, short-term borrowings
amounted to $50 million compared to $155.8 million at December 31, 1993. The
decrease is primarily the result of the issuance of the $100 million of bonds
on January 20, 1994 (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.
16

The Company's capital structure at December 31, 1994, was 64 percent
common stock equity and 36 percent long-term debt. The capital structure at
December 31, 1994, including short-term debt was 62 percent common stock
equity and 38 percent debt. As of December 31, 1994, the Company's bonds were
rated "A3" by Moody's Investors Service, "A-" by Standard & Poor's Ratings
Group, and "A-" by Fitch Investors Service.

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 Federal Energy
Regulatory Commission (FERC). Rates charged for the sale and delivery of
electricity are designed to recover the cost of service and allow investors a
fair rate of return. Future electric sales will continue to be affected by
weather conditions, competition from other generating sources, 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. Refunds of
approximately $4.9 (Company's portion) million were made in April 1992 and
December 1993 and the remaining refund of approximately $8.7 million
(Company's portion) was 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 impact the Company's
earnings.

1994 Compared to 1993: Total operating revenues for 1994 of $619.9
million increased less than one percent from revenues of $617.0 million for
1993. The increase can be attributed to higher revenues in all retail
customer classes. While residential sales remained virtually unchanged,
commercial and industrial sales increased over two percent during 1994.
Partially offsetting these increases was a 21 percent decrease in wholesale
and interchange sales as a result of higher than normal sales in 1993 to other
utilities while their generating units were down due to the flooding of 1993.
17

1993 Compared to 1992: Total operating revenues increased $62.7 million
or 11 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.

OPERATING EXPENSES

1994 Compared to 1993: Total operating expenses for 1994 of $470.9
million increased slightly from total operating expenses of $469.6 million for
1993. Federal and state income taxes increased $13.5 million and maintenance
expense increased three percent primarily as a result of the major boiler
overhaul of the Company's coal fired La Cygne 1 generating station.

The increase in income tax expense was due to the completion at December
31, 1993, of the accelerated amortization of deferred income tax reserves
related to the allowance for borrowed funds used during construction
capitalized for Wolf Creek. The completion of the amortization of these
deferred income tax reserves increased income tax expense and thereby reduced
net income by approximately $12 million in 1994, and in the future will reduce
net income by this same amount each year.

Partially offsetting the increases in total operating expenses were lower
fuel costs, due to decreased electric generation during 1994, and lower other
operations expense.

1993 Compared to 1992: Total operating expenses increased $45.5 million
or 11 percent in 1993 compared to 1992. Fuel and purchased power expenses
increased $21.4 million or 23 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 resulting from refinancing of the secured facility
bonds (see Note 7) compared to pro forma operating expenses of 1992.
18

OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes,
decreased significantly in 1994 compared to 1993 primarily as a result of
increased interest expense on higher COLI borrowings. Interest on COLI
borrowings increased $9.1 million in 1994 compared to 1993. Also contributing
to the decrease was the receipt of death benefit proceeds from COLI policies
in the third quarter of 1993.

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.

INTEREST CHARGES: Interest charges decreased 12 percent in 1994 compared
to 1993 primarily as a result of the refinancing of higher cost fixed-rate
debt. Also accounting for the decrease was the impact of increased COLI
borrowings which reduce the need for other long-term debt and thereby reduced
interest expense. COLI interest is reflected in Other Income and Deductions
on the Income Statement. The Company's embedded cost of long-term debt
decreased to 7.3% at December 31, 1994 compared to 7.7% and 7.8% at December
31, 1993 and 1992, respectively.

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.

MERGER IMPLEMENTATION: In accordance with the KCC Merger order,
amortization of the acquisition adjustment will commence August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. Western Resources and the Company (combined companies) can recover
the amortization of the acquisition adjustment through cost savings under a
sharing mechanism approved by the KCC as described in Note 1 of the Notes to
the Financial Statements. While the combined companies have 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.

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 taken a proactive position with respect to
the potential environmental liability associated with former manufactured gas
sites and has an agreement with the Kansas Department of Health and
Environment (KDHE) to systematically evaluate these sites (see Note 3).
19

Although the Company currently has no Phase I affected units under the
Clean Air Act of 1990, the Company has applied for an early substitution
permit to bring the co-owned La Cygne Station under the Phase I guidelines.
The oxides of nitrogen (NOx) and air toxic limits, which were not set in law,
will be specified in future Environmental Protection Agency (EPA) regulations.
The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of
Appeals for the District of Columbia Circuit in November 1994, and until such
time as the EPA resubmits new proposed regulations, the Company will be unable
to determine its compliance options or related compliance costs (see Note 3).

COMPETITION: As a regulated utility, the Company currently has limited
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 1992 Energy Policy Act (Act) requires increased efficiency of energy
usage and has effected 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 of its transmission system for
wholesale transactions. During 1994, wholesale revenues represented less than
seven percent of the Company's total revenues.

Operating in this competitive environment could place pressure on utility
profit margins and credit quality. Wholesale and industrial customers may
threaten to pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to
obtain reduced energy costs. Increasing competition has resulted in credit
rating agencies applying more stringent guidelines when making utility credit
rating determinations.

The Company is providing reduced electric rates for industrial expansion
projects and economic development projects in an effort to maintain and
increase electric load. In 1994, The Boeing Company announced it would
develop its 777 jetliner in Wichita and Cessna Aircraft Company announced it
would build a production plant in Independence, Kansas along with expanding
its Wichita facilities, with an addition of 2,000 jobs.

In order to retain its current electric load, the Company has and will
continue to negotiate with some of its larger industrial customers, who are
able to develop cogeneration facilities, for long term contracts although some
negotiated rates may result in reduced margins for the Company. During 1996,
the Company will lose a major industrial customer to cogeneration resulting in
a reduction to pre-tax earnings of approximately $7 to $8 million. This
customer's decision to develop its own cogeneration project was based
partially on factors other than energy cost.
20

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Report of Independent Public Accountants 21

Financial Statements:

Balance Sheets, December 31, 1994 and 1993 23
Statements of Income for the year ended December 31, 1994 24
and 1993 (Successor), the nine months ended December 31, 1992
(Successor), and the three months ended March 31, 1992
(Predecessor)
Statements of Cash Flows for the years ended December 31, 1994 25
and 1993 (Successor), the period March 31 to December 31, 1992
(Successor), and the three months ended March 31, 1992
(Predecessor)
Statements of Taxes for the years ended December 31, 1994 26
and 1993 (Successor), the nine months ended December 31, 1992
(Successor), and the three months ended March 31, 1992
(Predecessor)
Statements of Capitalization, December 31, 1994 and 1993 27
Statements of Common Stock Equity for the years ended 28
December 31, 1994 and 1993 (Successor), the nine months ended
December 31, 1992 (Successor), and the three months ended
March 31, 1992 (Predecessor)
Notes to Financial Statements 29

SCHEDULES OMITTED

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

I, II, III, IV, and V.
21

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying balance sheets and statements of
capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary
of Western Resources, Inc.) as of December 31, 1994 and 1993, and the related
statements of income, cash flows, taxes, and common stock equity for the years
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 audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 1994 and 1993, and the results of its operations
and its cash flows for the years 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.

ARTHUR ANDERSEN LLP

Kansas City, Missouri,
January 25, 1995
22

INDEPENDENT AUDITORS' REPORT

Kansas Gas and Electric Company:

We have audited the 1992 financial statements of Kansas Gas and Electric
Company (a wholly-owned subsidiary of Western Resources, Inc.) listed in the
accompanying table of contents. 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 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 audit provides a reasonable basis
for our opinion.

In our opinion, such financial statements present fairly, in all material
respects, the results of the Company's operations and its cash flows for the
periods indicated in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Kansas City, Missouri
January 29, 1993
23

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

December 31,
1994 1993

ASSETS

UTILITY PLANT:
Electric plant in service (Notes 2 and 12). . . . . . . . $3,390,406 $3,339,832
Less - Accumulated depreciation . . . . . . . . . . . . . 833,953 790,843
---------- ----------
2,556,453 2,548,989
Construction work in progress . . . . . . . . . . . . . . 32,874 28,436
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 39,890 29,271
---------- ----------
Net utility plant . . . . . . . . . . . . . . . . . . . 2,629,217 2,606,696
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Decommissioning trust (Note 3). . . . . . . . . . . . . . 16,944 13,204
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 11,561 10,941
---------- ----------
28,505 24,145
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents (Note 2). . . . . . . . . . . . 47 63
Accounts receivable and unbilled revenues (net)(Note 6) . 67,833 11,112
Advances to parent company (Note 14). . . . . . . . . . . 64,393 192,792
Fossil fuel, at average cost, . . . . . . . . . . . . . . 13,752 7,594
Materials and supplies, at average cost . . . . . . . . . 30,921 29,933
Prepayments and other current assets. . . . . . . . . . . 16,662 14,995
---------- ----------
193,608 256,489
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 9) . . . . . . . . . . 102,789 102,789
Deferred coal contract settlement costs (Note 4). . . . . 17,944 21,247
Phase-in revenues (Note 4). . . . . . . . . . . . . . . . 61,406 78,950
Other deferred plant costs. . . . . . . . . . . . . . . . 31,784 32,008
Corporate-owned life insurance (net) (Note 2) . . . . . . 9,350 45
Unamortized debt expense. . . . . . . . . . . . . . . . . 27,777 27,365
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 40,430 37,745
---------- ----------
291,480 300,149
---------- ----------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,142,810 $3,187,479
========== ==========

CAPITALIZATION AND LIABILITIES

CAPITALIZATION (see Statements) . . . . . . . . . . . . . . $1,925,196 $1,899,221
---------- ----------
CURRENT LIABILITIES:
Short-term debt (Note 5). . . . . . . . . . . . . . . . . 50,000 155,800
Long-term debt due within one year (Note 6) . . . . . . . - 238
Accounts payable. . . . . . . . . . . . . . . . . . . . . 49,093 51,095
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 15,737 12,185
Accrued interest. . . . . . . . . . . . . . . . . . . . . 8,337 7,381
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 11,160 9,427
---------- ----------
134,327 236,126
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Notes 1 and 9) . . . . . . . . . . 689,169 646,159
Deferred investment tax credits (Note 9). . . . . . . . . 74,841 78,048
Deferred gain from sale-leaseback (Note 7). . . . . . . . 252,341 261,981
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 66,936 65,944
---------- ----------
1,083,287 1,052,132
COMMITMENTS AND CONTINGENCIES (Notes 3 and 10) ---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,142,810 $3,187,479
========== ==========
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

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

Year Ended December 31,
1992
Pro Forma April 1 | January 1
1994 1993 1992 to Dec. 31 | to March 31
(Successor) |(Predecessor)
|
OPERATING REVENUES (Notes 2 and 4). . . . $ 619,880 $ 616,997 $ 554,251 $ 423,538 | $ 130,713
|
OPERATING EXPENSES: |
Fuel used for generation: |
Fossil fuel . . . . . . . . . . . . . 90,383 93,388 73,785 53,701 | 20,084
Nuclear fuel. . . . . . . . . . . . . 13,562 13,275 12,558 10,126 | 2,432
Power purchased . . . . . . . . . . . . 7,144 9,864 8,746 3,207 | 5,539
Other operations. . . . . . . . . . . . 115,060 118,948 129,083 91,436 | 37,647
Maintenance . . . . . . . . . . . . . . 47,988 46,740 46,702 35,956 | 10,746
Depreciation and amortization . . . . . 71,457 75,530 74,696 55,547 | 19,149
Amortization of phase-in revenues . . . 17,544 17,545 17,544 13,158 | 4,386
Taxes (see Statements): |
Federal income. . . . . . . . . . . . 50,212 39,553 16,305 17,523 | (1,218)
State income . . . . . . . . . . . . 12,427 9,570 4,264 4,732 | (468)
General . . . . . . . . . . . . . . . 45,092 45,203 40,406 30,155 | 10,251
--------- --------- --------- --------- | ---------
Total operating expenses. . . . . . 470,869 469,616 424,089 315,541 | 108,548
--------- --------- --------- --------- | ---------
OPERATING INCOME. . . . . . . . . . . . . 149,011 147,381 130,162 107,997 | 22,165
--------- --------- --------- --------- | ---------
OTHER INCOME AND DEDUCTIONS: |
Corporate-owned life insurance (net). . (5,354) 7,841 10,724 9,308 | 1,416
Miscellaneous (net) . . . . . . . . . . 5,079 9,271 7,873 9,417 | (1,544)
Income taxes (net) (see Statements) . . 7,290 2,227 191 (1,296) | 1,487
--------- --------- --------- --------- | ---------
Total other income and deductions . 7,015 19,339 18,788 17,429 | 1,359
--------- --------- --------- --------- | ---------
INCOME BEFORE INTEREST CHARGES. . . . . . 156,026 166,720 148,950 125,426 | 23,524
--------- --------- --------- --------- | ---------
INTEREST CHARGES: |
Long-term debt. . . . . . . . . . . . . 47,827 53,908 57,862 42,889 | 14,973
Other . . . . . . . . . . . . . . . . . 5,183 6,075 15,121 11,777 | 3,344
Allowance for borrowed funds used |
during construction (credit). . . . . (1,510) (1,366) (2,014) (1,181) | (833)
--------- --------- --------- --------- | ---------
Total interest charges. . . . . . . 51,500 58,617 70,969 53,485 | 17,484
--------- --------- --------- --------- | ---------
NET INCOME. . . . . . . . . . . . . . . . 104,526 108,103 77,981 71,941 | 6,040
|
PREFERRED DIVIDENDS . . . . . . . . . . . - - - - | 205
--------- --------- --------- --------- | ---------
EARNINGS APPLICABLE TO COMMON STOCK . . . $ 104,526 $ 108,103 $ 77,981 $ 71,941 | $ 5,835
========= ========= ========= ========= | =========
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.

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

Year Ended December 31,
1992
March 31 | January 1
1994 1993 to Dec. 31 | to March 31
(Successor) | (Predecessor)
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net income. . . . . . . . . . . . . . . . . . . . . . $ 104,526 $ 108,103 $ 71,941 | $ 6,040
Depreciation and amortization . . . . . . . . . . . . 71,457 75,530 55,547 | 19,149
Other amortization (including nuclear fuel) . . . . . 10,905 11,254 8,930 | 1,352
Deferred taxes and investment tax credits (net) . . . 25,349 22,572 9,326 | (2,851)
Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 13,158 | 4,386
Corporate-owned life insurance. . . . . . . . . . . . (17,246) (21,650) (14,704) | (3,295)
Amortization of gain from sale-leaseback. . . . . . . (9,640) (9,640) (7,231) | (2,409)
Changes in working capital items: |
Accounts receivable and unbilled |
revenues (net) (Note 2) . . . . . . . . . . . . . (56,721) (569) 1,079 | 1,272
Fossil fuel . . . . . . . . . . . . . . . . . . . . (6,158) 8,507 4,425 | (1,858)
Accounts payable. . . . . . . . . . . . . . . . . . (2,002) (9,813) (7,216) | (6,100)
Interest and taxes accrued. . . . . . . . . . . . . 4,508 (9,053) (14,345) | 10,598
Other . . . . . . . . . . . . . . . . . . . . . . . (922) (2,191) (8,456) | 1,689
Changes in other assets and liabilities . . . . . . . (11,181) (16,530) (41,402) | (5,479)
--------- --------- --------- | ---------
Net cash flows from operating activities. . . . . 130,419 174,065 71,052 | 22,494
--------- --------- --------- | ---------
CASH FLOWS USED IN INVESTING ACTIVITIES: |
Additions to utility plant. . . . . . . . . . . . . . 89,880 66,886 53,138 | 11,496
Corporate-owned life insurance policies . . . . . . . 26,418 27,268 20,233 | 6,802
Death proceeds of corporate-owned life insurance. . . - (10,160) (6,789) | -
Other investments . . . . . . . . . . . . . . . . . . - - - | (552)
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 . . . 116,298 83,994 518,290 | 17,746
--------- --------- --------- | ---------
CASH FLOWS FROM FINANCING ACTIVITIES: |
Short-term debt (net) . . . . . . . . . . . . . . . . (105,800) 62,300 49,900 | 5,800
Advances to parent company (net). . . . . . . . . . . 128,399 (118,503) (74,289) | -
Bonds issued. . . . . . . . . . . . . . . . . . . . . 160,422 65,000 135,000 | -
Bonds retired . . . . . . . . . . . . . . . . . . . . (46,440) (140,000) (125,000) | -
Other long-term debt (net). . . . . . . . . . . . . . (67,893) 7,043 14,498 | (3,810)
Borrowings against life insurance policies (net). . . 42,175 183,260 (5,649) | 6,398
Revolving credit agreement (net). . . . . . . . . . . - (150,000) - | -
Other (net) . . . . . . . . . . . . . . . . . . . . . - - - | (17)
Dividends to parent company . . . . . . . . . . . . . (125,000) - - | -
Dividends on preferred and common stock . . . . . . . - - - | (13,535)
Issuance of KCA common stock. . . . . . . . . . . . . - - 453,670 | -
--------- --------- --------- | ---------
Net cash flows from (used in) financing activities (14,137) (90,900) 448,130 | (5,164)
--------- --------- --------- | ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . (16) (829) 892 | (416)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . 63 892 - | 2,378
--------- --------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . $ 47 $ 63 $ 892 | $ 1,962
========= ========= ========= | =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION |
CASH PAID FOR: |
Interest on financing activities (net of amount |
capitalized) . . . . . . . . . . . . . . . . . . $ 68,544 $ 77,653 $ 63,451 | $ 11,635
Income taxes . . . . . . . . . . . . . . . . . . . . 28,509 29,354 14,225 | -

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

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

Year Ended December 31,
1992
April 1 | January 1
1994 1993 to Dec. 31 | to March 31
(Successor) | (Predecessor)
|
FEDERAL INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . $ 24,427 $ 19,220 $ 11,356 | $ (322)
Deferred (net). . . . . . . . . . . . . . . . . . . 23,002 16,691 8,633 | (1,785)
Investment tax credit-Deferral. . . . . . . . . . . - 4,900 946 | -
-Amortization. . . . . . . . . (3,208) (3,114) (2,400) | (777)
--------- --------- --------- | ---------
Total Federal income taxes . . . . . . . . . . . 44,221 37,697 18,535 | (2,884)
Less: |
Federal income taxes applicable |
to non-operating items . . . . . . . . . . . . . (5,991) (1,856) 1,012 | (1,666)
--------- --------- --------- | ---------
Total Federal income taxes charged to operations. . 50,212 39,553 17,523 | (1,218)
--------- --------- --------- | ---------
STATE INCOME TAXES: |
Payable currently . . . . . . . . . . . . . . . . . 5,574 5,104 2,869 | -
Deferred (net). . . . . . . . . . . . . . . . . . . 5,554 4,095 2,147 | (289)
--------- --------- --------- | ---------
Total State income taxes . . . . . . . . . . . . 11,128 9,199 5,016 | (289)
Less: |
State income taxes applicable |
to non-operating items . . . . . . . . . . . . . (1,299) (371) 284 | 179
--------- --------- --------- | ---------
Total State income taxes charged to operations. . . 12,427 9,570 4,732 | (468)
--------- --------- --------- | ---------
GENERAL TAXES: |
Property. . . . . . . . . . . . . . . . . . . . . . 40,104 38,432 26,380 | 8,622
Payroll and other taxes . . . . . . . . . . . . . . 4,988 6,771 3,775 | 1,629
--------- --------- --------- | ---------
Total general taxes charged to operations. . . . 45,092 45,203 30,155 | 10,251
--------- --------- --------- | ---------
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 107,731 $ 94,326 $ 52,410 | $ 8,565
========= ========= ========= | =========

Year Ended December 31,
Pro Forma
1994 1993 1992

EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 35% 30% 21%
Effect of:
Additional depreciation . . . . . . . . . . . . . . (1) (3) (4)
Accelerated amortization of deferred income
tax credits. . . . . . . . . . . . . . . . . . - 8 11
State income taxes, net of Federal benefit. . . . . (5) (4) (2)
Amortization of investment tax credits. . . . . . . 2 2 2
Corporate-owned life insurance. . . . . . . . . . . 4 5 6
Other items (net) . . . . . . . . . . . . . . . . . - (3) -
---- ---- ----
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 35% 34%
==== ==== ====

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

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

December 31,
1994 1993

COMMON STOCK EQUITY (Note 1):
(see Statements)
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . . 159,570 180,044
---------- ----------
Total common stock equity . . . . . . . . . . . . . . . . 1,225,204 64% 1,245,678 66%

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

Series Due 1994 1993
5-5/8% 1996 $ 16,000 $ 16,000
7.6% 2003 135,000 135,000
6-1/2% 2005 65,000 65,000
6.20% 2006 100,000 -
316,000 216,000
Pollution Control Bonds:
6.80% 2004 - 14,500
5-7/8% 2007 - 21,940
6% 2007 - 10,000
5.10% 2023 13,982 -
Variable (a) 2027 21,940 -
7.0% 2031 327,500 327,500
Variable (a) 2032 14,500 -
Variable (a) 2032 10,000 -
387,922 373,940
---------- ----------
Total bonds. . . . . . . . . . . . . . . . . . . . . . 703,922 589,940

Other Long-Term Debt:
Pollution control obligations:
5-3/4% series 2003 - 13,980
Other long-term agreement 1995 - 53,913
------- -------
Total other long-term debt . . . . . . . . . . . . . . - 67,893
Less:
Unamortized premium and discount (net). . . . . . . . . . 3,930 4,052
Long-term debt due within one year. . . . . . . . . . . . - 238
---------- ----------
Total long-term debt . . . . . . . . . . . . . . . . . 699,992 36% 653,543 34%
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,925,196 100% $1,899,221 100%
========== ==========

(a) Market-Adjusted Tax Exempt Securities (MATES). The interest rate is reset
periodically via an auction process. As of December 31, 1994, the rate
on these bonds was 4.10%.

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, 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
----------- ---------- ------ --------- ---------- --------- ----------
Net income . . . . . . . . 104,526 104,526
Dividend to parent company (125,000) (125,000)
----------- ---------- ------ --------- ---------- --------- ----------

BALANCE DECEMBER 31, 1994. . 1,000 $1,065,634 $ - $ 159,570 - $ - $1,225,204
=========== ========== ====== ========= ========== ========= ==========

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 $311 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.

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 Western Resources and the Company (combined
companies) have achieved savings from the Merger, there is no assurance that
the savings achieved will be sufficient to, or the cost savings sharing
30

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'
customers to share with customers the Merger-related cost savings achieved
during the moratorium period. Refunds of approximately $4.9 (Company's share)
million for the Company were made in April 1992 and December 1993 and the
remaining refund of approximately $8.7 (Company's share )million was made in
September 1994.

The KCC order approving the Merger required the legal reorganization of
the Company so that it was no longer held as a separate subsidiary after
January 1, 1995, unless good cause was 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 Utility
Holding Company Act (PUHCA) until January 1, 1995. Western Resources has been
granted regulatory approval from the KCC which eliminates the requirement for
a combination. As a result of the sales of Western Resources' Missouri
Properties, Western Resources is now exempt from regulation as a holding
company under Section 3(a)(1) of the PUHCA.

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 4.07% for 1994, 4.41% for 1993,
6.51% for the nine months ended December 31, 1992, and 6.70% for the three
months ended March 31, 1992. 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 2.7% during 1994, 2.9% during 1993, 2.9% during the
nine months ended December 31, 1992, and 3.0% during the three months ended
March 31, 1992 of the average original cost of depreciable property.
31

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 previously deferred are being 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 $21.4 and $22.3 million at December 31, 1994 and
1993, respectively, are recorded as a component of accounts receivable on the
balance sheets. At December 31, 1993, certain amounts of unbilled revenues
were sold (see Note 6).

The Company had reserves for doubtful accounts receivable of $1.9 and
$3.0 million at December 31, 1994 and 1993, 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, 1994 and 1993, was $13.6 and $17.4 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:

1994 1993
(Dollars in Millions)
Cash surrender value of contracts. . . $320.6 $269.0
Borrowings against contracts . . . . . 311.2 (269.0)
------ ------
COLI (net) . . . . . . . . . . . . $ 9.4 $ 0.0
====== ======
The COLI borrowings will be repaid upon receipt of proceeds from death
benefits under contracts. The Company recognizes increases in the cash
surrender value of contracts, resulting from premiums and investment earnings
on a tax free basis, and the tax deductible interest on the COLI borrowings in
Corporate-owned Life Insurance (net) on the Statements of Income. Interest
expense included in corporate-owned life insurance (net) on the statements of
income was $21.0 million for 1994, $11.9 million for 1993, $5.3 million for
the nine months ended December 31, 1992, and $1.9 million for the three months
ended March 31, 1992.
32

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

3. COMMITMENTS AND CONTINGENCIES

Manufactured Gas Sites: The Company was previously associated with six
former manufactured gas sites which contain coal tar and other potentially
harmful materials. The Company and the Kansas Department of Health and
Environment (KDHE) conducted preliminary assessments of these sites at minimal
cost. The results of the preliminary investigations determined the Company
does not have a connection to two of the sites.

The Company and KDHE entered into a consent agreement governing all
future work at the four remaining sites. The terms of the consent agreement
will allow the Company to investigate these sites and set remediation
priorities based upon the results of the investigations and risk analysis.
The prioritized sites will be investigated over a 10 year period. The
agreement will allow the Company to set mutual objectives with the KDHE in
order to expedite effective response activities and to control costs and
environmental impact. 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 and that the KCC has permitted another Kansas utility to
recover its 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 on net nuclear generation.
These fees are included as part of nuclear fuel expense and amounted to $3.8
million for 1994, $3.5 million for 1993, $1.6 million for the nine months
ended December 31, 1992, and $.5 million for the three months ended March 31,
1992.

The Company along with the other co-owners of Wolf Creek are among 14
companies that filed a lawsuit on June 20, 1994, seeking an interpretation of
the DOE's obligation to begin accepting spent nuclear fuel for disposal in
1998. The Federal Nuclear Waste Policy Act requires DOE ultimately to accept
and dispose of nuclear utilities' spent fuel. The DOE has filed a motion to
have this case dismissed. The issue to be decided in this case is whether DOE
must begin accepting spent fuel in 1998 or at a future date. Wolf Creek
contains an on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
the year 2006 while still maintaining full core off-load capability. The
Company believes adequate additional storage space can be obtained as
necessary.
33

Decommissioning: On June 9, 1994, the KCC issued an order approving the
decommissioning costs of the 1993 Wolf Creek Decommissioning Cost Study which
estimates the Company's share of Wolf Creek decommissioning costs, under the
immediate dismantlement method, to be approximately $595 million primarily
during the period from 2025 through 2033, or approximately $174 million in
1993 dollars. These costs were calculated using an assumed inflation rate of
3.45% over the remaining service life, in 1993, of 32 years.

Decommissioning costs are being charged to operating expenses in
accordance with the KCC order. Electric rates charged to customers provide
for recovery of these decommissioning costs over the life of Wolf Creek.
Amounts so expensed ($3.5 million in 1994 increasing annually to $5.5 million
in 2024) and earnings on trust fund assets are deposited in an external trust
fund. The assumed return on trust assets is 5.9%.

The Company's investment in the decommissioning fund, including
reinvested earnings was $16.9 million and $13.2 million at December 31, 1994
and December 31, 1993, respectively. These amounts are reflected in
Decommissioning Trust, and the related liability is included in Deferred
Credits and Other Liabilities, Other, on the Balance Sheets.

The Company carries $118 million in premature decommissioning insurance.
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 $8.9 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 major nuclear
incident involving any of the nation's licensed reactors. This assessment is
subject to an inflation adjustment based on the Consumer Price Index and
applicable premium taxes. There is a limitation of $10 million ($4.7 million,
Company's share) in retrospective assessments per incident per year.

The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totalling
approximately $2.8 billion ($1.3 billion, Company's share). This insurance is
provided by a combination of "nuclear insurance pools" ($500 million) and
Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The Company's share of any remaining proceeds can be
used for property damage up to $1.2 billion (Company's share) and premature
decommissioning costs up to $118 million (Company's share) in excess of funds
previously collected for decommissioning (as discussed under
"Decommissioning").
34

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 $13 million per year.

Although the Company maintains various insurance policies to provide
coverage for potential losses or liabilities resulting from an accident or
extended outage, the Company's insurance coverage may not be adequate to cover
the costs that could result from a major accident or extended outage at Wolf
Creek. Any substantial losses not covered by insurance, to the extent not
recoverable through rates, would have a material adverse effect on the
Company's financial 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 oxides of nitrogen (NOx) 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 installed continuous monitoring and reporting equipment at a total
cost of approximately $2.3 million. The Company does not expect additional
equipment to reduce sulfur emissions to be necessary under Phase II. Although
the Company currently has no Phase I affected units, the owners have applied
for an early substitution permit to bring the co-owned La Cygne Station under
the Phase I regulations.

The NOx and air toxic limits, which were not set in the law, will be
specified in future EPA regulations. The EPA's proposed NOx regulations were
ruled invalid by the U.S. Court of Appeals for the District of Columbia
Circuit in November 1994, and until such time as the EPA resubmits new
proposed regulations, 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.

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, 1994, WCNOC's nuclear fuel commitments (Company's share) were
35

approximately $12.6 million for uranium concentrates expiring at various times
through 1997, $122.9 million for enrichment expiring at various times through
2014, and $56.5 million for fabrication through 2012. At December 31, 1994,
the Company's coal and natural gas contract commitments in 1994 dollars under
the remaining term of the contracts are $721 million and $9 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 impact the
Company's earnings.

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. At December 31, 1994
approximately $61 million of deferred phase-in revenues remained on the
Balance Sheet.

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. 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. Approximately $18 million of
this deferral remains on the balance sheet at December 31, 1994.

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).
36

5. SHORT-TERM BORROWINGS

The Company's short-term financing requirements are satisfied through
short-term bank loans and uncommitted loan participation agreements. Maximum
short-term borrowings outstanding during 1994 and 1993 were $172.3 million on
January 4, 1994 and $175.8 million on December 14, 1993. The weighted average
interest rates, including fees, were 4.5% for 1994, 3.5% for 1993, 6.4% for
the nine months ended December 31, 1992, and 7.1% for the three months ended
March 31, 1992.

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.
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.

On November 1, 1994, the Company terminated a long-term agreement which
contained 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 were accounted for as sales while those related to
phase-in revenues were accounted for as collateralized borrowings. At
December 31, 1993, outstanding receivables amounting to $56.8 million, were
considered sold under the agreement. The weighted average interest rate,
including fees, on this agreement was 4.6% for 1994, 3.7% for 1993, 6.6% for
the nine months ended December 31, 1992, and 7.9% for the three months ended
March 31, 1992.

7. SALE-LEASEBACK OF LA CYGNE 2

In 1987, the Company sold and leased back its 50 percent undivided
interest in the 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. At December 31, 1994, approximately $24.8 million of
this deferral remained on the Balance Sheet.
37

Future minimum annual lease payments required under the lease agreement
are approximately $34.6 million for each year through 1999 and $680 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 1994 and 1993, $20.6 million
for the nine months ended December 31, 1992, and $7.5 million for the three
months ended March 31, 1992.

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 (dollars in millions):

1992
April 1 | Jan.1 to
1994 1993 to Dec.31 | March 31
(Successor)|(Predecessor)
Pension Cost: |
Service cost . . . . . . . . . . $ 3.7 $ 3.2 $ 2.5 | $ .8
Interest cost on projected |
benefit obligation . . . . . . 9.7 9.5 6.7 | 2.1
(Gain) loss on plan assets . . . 2.1 (14.1) (5.8) | (9.0)
Net amortization & deferral. . . (11.4) 4.9 (1.0) | 6.7
------ ------ ------ | ------
Net pension cost . . . . . . . $ 4.1 $ 3.5 $ 2.4 | $ .6
====== ====== ====== ======

The following table sets forth the plans' actuarial present value and
funded status at November 30, 1994 and 1993 (the plan years) and a
reconciliation of such status to the December 31, 1994, 1993, and 1992
financial statements (dollars in millions):

1994 1993 1992
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested. . . . . . . . . . . . . . . $ 94.0 $ 95.2 $ 82.9
Non-vested. . . . . . . . . . . . . 6.3 6.1 3.6
------ ------ ------
Total . . . . . . . . . . . . . . $100.3 $101.3 $ 86.5
====== ====== ======
38
Plan assets at November 30 (principally
debt and equity securities)
at fair value . . . . . . . . . . . . . $115.4 $119.9 $113.7
Projected benefit obligation
at November 30 . . . . . . . . . . . . (125.4) (125.5) (110.8)
------ ------ ------
Funded status at November 30. . . . . . . (10.0) (5.6) 2.9
Unrecognized transition asset . . . . . . (1.5) (1.7) (2.0)
Unrecognized prior service costs. . . . . 9.6 12.4 12.1
Unrecognized net gain . . . . . . . . . . (11.1) (20.6) (26.1)
------ ------ -------
Accrued pension costs at December 31. . . $(13.0) $(15.5) $(13.1)
====== ====== =======

Year Ended December 31, 1994 1993 1992

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

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: Western Resources 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 to be allocated to the Company under SFAS 106
was approximately $3.8 million in 1994 and $3.4 million in 1993. The
Company's total obligation to be allocated from Western Resources was
approximately $25.3 million and $23.9 million at December 31, 1994 and 1993,
respectively. To mitigate the impact of SFAS 106 expense, Western Resources
implemented programs to reduce health care costs. In addition, the KCC issued
an order permitting the initial deferral of SFAS 106 expense. To mitigate the
impact SFAS 106 expense will have on rate increases, Western Resources will
include in the future computation of SFAS 106 expense allocated to the Company
for computation of cost of service and
39
expense recognition, 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 by the
Company.

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 and $0.2 million for the three months
ended March 31, 1992.

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, 1994 1993
(Dollars in Millions)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . $ 12.9 $ 12.4
Active employees fully eligible . . . . . . . 3.0 2.5
Active employees not fully eligible . . . . . 9.4 9.0
Unrecognized prior service cost . . . . . . . (3.2) (.1)
Unrecognized transition obligation. . . . . . (19.3) (20.4)
Unrecognized net gain (loss). . . . . . . . . .9 (1.7)
------ ------
Balance sheet liability . . . . . . . . . . . . . $ 3.7 $ 1.7
====== ======

Year Ended December 31, 1994 1993
Assumptions:
Discount rate. . . . . . . . . . . . . . . . . 8.0-8.5 % 7.75%
Annual compensation increase rate. . . . . . . 5.0 % 5.0 %
Expected rate of return. . . . . . . . . . . . 8.5 % 8.5 %

For measurement purposes, an annual health care cost growth rate of 12%
was assumed for 1994, decreasing 1% per year to 5% by 2001 and thereafter.
The health care cost trend rate has a significant effect on the projected
benefit obligation. Increasing the trend rate by 1% each year would increase
the present value of the accumulated projected benefit obligation by $.3
million and the aggregate of the service and interest cost components by
$26,000.

Savings Plans: Effective January 1, 1995, the Company's 401(k) savings
plans were merged with Western Resources savings plans. Prior to the merger
of the savings plans, funds of the plans were 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 $1.8
million for 1994, $2.0 million for 1993, $1.7 million for the nine months
ended December 31, 1992, and $0.2 million for the three months ended March 31,
1992.
40

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, 1994, the Company has alternative minimum tax credits
generated prior to April 1, 1992, which carryforward without expiration, of
$41.2 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, 1994.

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, 1994
Debits Credits Total
(Dollars in Thousands)

Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (381,800) $ (381,800)
Energy and purchased gas
adjustment clauses . . . . . . . 2,245 - 2,245
Phase-in revenues. . . . . . . . . - (27,677) (27,677)
Deferred gain on sale-leaseback. . 110,556 - 110,556
Alternative minimum tax credits. . 41,163 - 41,163
Deferred coal contract
settlements. . . . . . . . . . . - (6,703) (6,703)
Deferred compensation/pension
liability. . . . . . . . . . . . 9,676 - 9,676
Acquisition premium. . . . . . . . - (317,610) (317,610)
Deferred future income taxes . . . - (102,789) (102,789)
Loss on reacquisition of debt. . . - (4,103) (4,103)
Prepaid power sale . . . . . . . . 1,577 1,577
Other. . . . . . . . . . . . . . . - (13,704) (13,704)
----------- ----------- -----------
Total Deferred Income Taxes. . . . . $ 165,217 $ (854,386) $ (689,169)
=========== =========== ===========
41

December 31, 1993
Debits Credits Total
(Dollars in Thousands)

Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (356,494) $ (356,494)
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 . . . - (102,789) (102,789)
Loss on reacquisition of debt. . . - (4,508) (4,508)
Other. . . . . . . . . . . . . . . - (8,365) (8,365)
----------- ----------- -----------
Total Deferred Income Taxes. . . . . $ 170,181 $ (816,340) $ (646,159)
=========== =========== ===========

10. LEGAL PROCEEDINGS

The Company is involved in various 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.

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, 1994 and 1993.
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:
42

Carrying Value Fair Value
December 31, 1994 1993 1994 1993
(Dollars in Thousands)

Cash and cash
equivalents. . . . . . . $ 47 $ 63 $ 47 $ 63
Decommissioning trust. . . 16,944 13,204 16,633 13,929
Variable-rate debt . . . . 407,645 478,743 407,645 478,743
Fixed-rate debt. . . . . . 657,482 603,920 623,331 660,750

12. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 1994
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)

La Cygne 1 (a) Jun 1973 $ 152,816 $ 98,124 343 50
Jeffrey 1 (b) Jul 1978 65,467 30,333 140 20
Jeffrey 2 (b) May 1980 66,475 26,921 143 20
Jeffrey 3 (b) May 1983 95,421 33,491 140 20
Wolf Creek (c) Sep 1985 1,376,335 317,311 545 47

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

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.
43

1994
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.

Operating revenues. . . . . $139,087 $189,202 $154,987 $136,604
Operating income. . . . . . 33,607 56,978 33,548 24,878
Net income. . . . . . . . . 22,212 45,481 23,623 13,210

1993
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.

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

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, 1994,
resulted in a net advance by KG&E to Western Resources of $64.4 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. During 1994, the Company declared a dividend to
Western Resources of $125 million.

44
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.
45

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 49 Chairman of the Board (since June 1992), 1992
President and Chief Executive Officer
(since March 1992), and prior to that
Group Vice President
Directorships
Bank IV Wichita

Robert T. Crain 69 Owner, Crain Realty, Co., Fort Scott, 1992(b)
(a) Kansas
Directorships
Citizens National Bank
Ft. Scott Industries, Inc.

Anderson E. 61 President, Jackson Mortuary, Wichita, 1994
Jackson Kansas

Donald A. 61 President, Maupintour, Inc., Lawrence, 1992(b)
Johnston Kansas (Escorted Tours and Travel)
(a) Directorships
Commerce Bank, Lawrence
Maupintour, Inc.

Steven L. 49 Executive Vice President and Chief 1992
Kitchen Financial Officer, Western Resources,
Inc.

Glenn L. 69 Retired Vice President - Nuclear of the 1992(b)
Koester Company

James J. Noone 74 Attorney and retired Administrative Judge 1992(b)
(a) for the District Court of Sedgwick
County, Kansas

Marilyn B. 45 President (since October 1993) and prior 1994
Pauly to that Executive Vice President,
Bank IV Wichita, Wichita, Kansas
Directorships
Farmers Mutual Alliance Insurance Company
46
A Director
Business Experience Since 1988 and Other Continuously
Name Age Directorships Other Than The Company Since

Newton C. Smith 73 Physician and Surgeon, Arkansas City, 1992(b)
Kansas

Richard D. Smith 61 President, Range Oil Company 1993
Directorships
Bank IV Kansas

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

During 1994, the Board of Directors met seven times and the Audit
Committee met two times. Each director attended at least 75% of the total
number of Board and Committee meetings held while he/she served as a director
or a member of the committee, except Mr. Richard D. Smith who attended 71% of
such 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.
47

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, 1994 and 1993
Statements of Income for the year ended December 31, 1994 and 1993
(Successor), the nine months ended December 31, 1992 (Successor),
and the three months ended March 31, 1992 (Predecessor)
Statements of Cash Flows for the year ended December 31, 1994 and 1993
(Successor), the period March 31 to December 31, 1992 (Successor),
and the three months ended March 31, 1992 (Predecessor)
Statements of Taxes for the year ended December 31, 1994 and 1993
(Successor), the nine months ended December 31, 1992 (Successor),
and the three months ended March 31, 1992 (Predecessor)
Statements of Capitalization, December 31, 1994 and 1993
Statements of Common Stock Equity for the year ended December 31, 1994
and 1993 (Successor), the nine months ended December 31, 1992
(Successor), and the three months ended March 31, 1992 (Predecessor)
Notes to Financial Statements

REPORTS ON FORM 8-K

None
48

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-eight
Supplemental Indentures, dated as of June 1, 1942, March 1, 1948,
December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955,
February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970,
May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975,
December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977,
August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980,
July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981,
May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth
and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991
March 31, 1992, December 17, 1992, August 24, 1993, January 15,
1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to
Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405;
Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626;
Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228;
Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680;
Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File
No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to
Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c),
File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c),
File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3
to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e),
File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit 2(g), File
No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and
2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634;
Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532;
Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31,
1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for
49

Description

December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3,
File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for
December 31, 1993, File No. 1-7324)

4(c)2 Thirty-ninth Supplemental Indenture dated as of April 15, 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 (Filed as Exhibit I
10(c) to the Form 10-K for the year ended December 31, 1993,
File No. 1-7324)

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

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 LLP
(Filed electronically)

23(b) Consent of Independent Public Accountants, Deloitte & Touche LLP
(Filed electronically)
50

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 29, 1995 By KENT R. BROWN
Kent R. Brown, Chairman of the Board,
President and Chief Executive Officer
49