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

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

For the fiscal year ended December 31, 1993

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

Commission file number 1-3523

WESTERN RESOURCES, INC.
(Exact name of registrant as specified in its charter)

KANSAS 48-0290150
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

818 KANSAS AVENUE, TOPEKA, KANSAS 66612
(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code 913/575-6300

Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $5.00 par value New York Stock Exchange
(Title of each class) (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, 4 1/2% Series, $100 par value
(Title of Class)

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

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)

State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,871,643,000 of Common Stock and $11,545,000
of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which
there is no readily ascertainable market value) at March 11, 1994.

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

Common Stock, $5.00 par value 61,617,873
(Class) (Outstanding at March 11, 1994)

Documents Incorporated by Reference:
Part Document

III Portions of the Company's Definitive Proxy Statement for
the Annual Meeting of Shareholders to be held May 3, 1994.

WESTERN RESOURCES, INC.
FORM 10-K
December 31, 1993

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 19

Item 3. Legal Proceedings 2

Item 4. Submission of Matters to a Vote of
Security Holders 21

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 21

Item 6. Selected Financial Data 22

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 23

Item 8. Financial Statements and Supplementary Data 32

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 63

PART III
Item 10. Directors and Executive Officers of the
Registrant 63

Item 11. Executive Compensation 63

Item 12. Security Ownership of Certain Beneficial
Owners and Management 63

Item 13. Certain Relationships and Related
Transactions 63

PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 64

Signatures 71

PART I

ITEM 1. BUSINESS

GENERAL

Western Resources, Inc. (formerly The Kansas Power and Light Company, KPL)
is a combination electric and natural gas public utility engaged in the
generation, transmission, distribution and sale of electric energy in Kansas
and the purchase, transmission, distribution, transportation and sale of
natural gas in Kansas, Missouri and Oklahoma. As used herein, the terms
"Company and Western Resources" include its wholly-owned subsidiaries, Astra
Resources, Inc., Kansas Gas and Electric Company (KG&E) since March 31, 1992,
and KPL Funding Corporation (KFC), unless the context otherwise requires.
KG&E 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 at 818 Kansas Avenue, Topeka, Kansas
66612. At December 31, 1993, the Company had 5,192 employees.

On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties". With the sales the Company is no longer operating
as a utility in the State of Missouri.

The portion of the Missouri Properties purchased by Southern Union, were
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The final sale price will be calculated
as of January 31, 1994, within 120 days of closing. Any difference between
the estimated and final sale price will be adjusted through a payment to or
from the Company.

United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri, for $665,000 in cash.

The operating revenues and operating income (unaudited) related to the
Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively, of the Company's
total for 1993, and $299 million and $11 million representing approximately 19
percent and five percent, respectively, of the Company's total for 1992. Net
utility plant (unaudited) for the Missouri Properties, at December 31, 1993,
approximated $296 million and $272 million at December 31, 1992. This
represents approximately seven percent at December 31, 1993, and six percent
at December 31, 1992, of the total Company net utility plant. Separate
audited financial information was not kept by the Company for the Missouri
Properties. This unaudited financial information is based on assumptions and
allocations of expenses of the Company as a whole. For additional information
see Note 13 of the Notes to Consolidated Financial Statements.

On March 31, 1992, the Company through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company for $454 million in cash and 23,479,380
shares of common stock (the Merger). The Company also paid approximately $20
million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas
and Electric Company merged and adopted the name of Kansas Gas and Electric
Company (KG&E).
Additional information relating to the Merger can be found in Management's
Discussion and Analysis of Financial Condition and Results of Operations and
Note 3 of Notes to Consolidated Financial Statements.

The following information includes the operations of KG&E since March 31,
1992.

The percentages of Total Operating Revenues and Operating Income Before
Income Taxes attributable to the Company's electric and natural gas operations
for the past five years were as follows:

Total Operating Income
Operating Revenues Before Income Taxes
Year Electric Natural Gas Electric Natural Gas

1993 58% 42% 85% 15%
1992 57% 43% 89% 11%
1991 41% 59% 84% 16%
1990 40% 60% 85% 15%
1989 40% 60% 81% 19%

The difference between the percentage of electric operating revenues in
relation to the percentage of electric operating income as compared to the
same percentages for gas operations is due to the Company's level of
investment in plant and its fuel costs in each of these segments.

The amount of the Company's plant in service (net of accumulated
depreciation) at December 31, for each of the past five years was as follows:

Year Electric Natural Gas Total
(Thousands of Dollars)

1993 $3,641,154 $759,619 $4,400,773
1992 3,645,364 696,036 4,341,400
1991 1,080,579 628,751 1,709,330
1990 1,092,548 567,435 1,659,983
1989 1,092,534 511,733 1,604,267

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

Electric utilities have been experiencing problems such as controversy
over the safety and use of coal and nuclear power plants, compliance with
changing environmental requirements, long construction periods required to
complete new generating units resulting in high fixed costs for those
facilities, difficulties in obtaining timely and adequate rate relief to
recover these high fixed costs, uncertainties in predicting future load
requirements, competition from independent power producers and cogenerators,
and the effects of changing accounting standards.
The problems which most significantly affect the Company are the use, or
potential use, of cogeneration or self-generation facilities by large
commercial and industrial customers and compliance with environmental
requirements. For additional information see Management's Discussion and
Analysis and Notes 4 and 5 of the Notes to Consolidated Financial Statements
included herein.

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

ELECTRIC OPERATIONS

General. The Company supplies electric energy at retail to approximately
585,000 customers in 462 communities in Kansas. These include Wichita,
Topeka, Lawrence, Manhattan, Salina, and Hutchinson. On September 20 1993,
the Company completed the purchase of the electric distribution system in
DeSoto Kansas. This acquisition added approximately 880 customers to the
Company's system. The Company also supplies electric energy at wholesale to
the electric distribution systems of 67 communities and 5 rural electric
cooperatives. The Company has contracts for the sale, purchase or exchange of
electricity with other utilities. The Company also receives a limited amount
of electricity through parallel generation.

The Company's electric sales for the last five years were as follows
(includes KG&E since March 31, 1992):

1993 1992 1991 1990 1989
(Thousands of MWH)

Residential 4,960 3,842 2,556 2,403 2,248
Commercial 5,100 4,473 3,051 2,952 2,814
Industrial 5,301 4,419 1,947 1,954 1,925
Other 4,628 3,119 1,984* 1,820 2,077
Total 19,989 15,853 9,538* 9,129 9,064

* Includes cumulative effect to January 1, 1991, of change in revenue
recognition. The cumulative effect of this change increased electric
sales by 256,000 MWH.

The Company's electric revenues for the last five years were as follows
(includes KG&E since March 31, 1992):

1993 1992 1991 1990 1989
(Thousands of Dollars)

Residential $ 384,618 $296,917 $160,831 $152,509 $142,308
Commercial 319,686 271,303 149,152 146,001 139,567
Industrial 261,898 211,593 78,138 79,225 78,267
Other 138,335 103,072 83,718 85,972 92,201
Total $1,104,537 $882,885 $471,839 $463,707 $452,343

Capacity. The accredited generating capacity of the Company's system is
presently 5,184 megawatts (MW). The system comprises interests in 22 fossil
fueled steam generating units, one nuclear generating unit (47 percent
interest), seven combustion peaking turbines and one diesel generator located
at eleven generating stations. Two units of the 22 fossil fueled units have
been "mothballed" for future use (see Item 2, Properties).

The Company's 1993 peak system net load occurred on August 16, 1993 and
amounted to 3,821 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 23 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.

In January 1994, the Company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA), whereby, the Company received a prepayment
of approximately $41 million for capacity and transmission charges through the
year 2013.

Future Capacity. The Company does not contemplate any significant
expenditures in connection with construction of any major generating
facilities through the turn of the century (see Management's Discussion and
Analysis, Liquidity and Capital Resources). Although the Company's management
believes, based on current load-growth projections and load management
programs, it will maintain adequate capacity margins through 2000, in view of
the lead time required to construct large operating facilities, the Company
may be required before 2000 to consider whether to reschedule the construction
of Jeffrey Energy Center (JEC) Unit 4 or alternatively either build or acquire
other capacity.

Fuel Mix. The Company's coal-fired units comprise 3,186 MW of the total
5,184 MW of generating capacity and the Company's nuclear unit provides 533 MW
of capacity. Of the remaining 1,465 MW of generating capacity, units that can
burn either natural gas or oil account for 1,373 MW, and the remaining units
which burn only oil or diesel account for 92 MW (see Item 2, Properties).

During 1993, low sulfur coal was used to produce 79 percent of the
Company's electricity. Nuclear produced 17 percent and the remainder was
produced from natural gas, oil, or diesel. Based on the Company's estimate of
the availability of fuel, coal will continue to be used to produce
approximately 78 percent of the Company's electricity and 18 percent from
nuclear.

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

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

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

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

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

Coal. The Company has 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 Cambell
County, Wyoming. The contract expires December 31, 2020. The contract
contains a schedule of minimum annual delivery quantities with deficient mmBTU
provisions applicable to deficiencies in the scheduled delivery. The coal to
be supplied is surface mined and has an average BTU content of approximately
8,300 BTU per pound and an average sulfur content of .43 lbs/mmBTU (see
Environmental Matters). The average delivered cost of coal for JEC was
approximately $1.045 per mmBTU or $17.35 per ton during 1993.

Coal is transported 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. The Company provides 770 aluminum rail cars, under a 20 year lease,
to transport coal to JEC. During 1994, the Company will provide an additional
120 rail cars under a similar lease.

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

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

La Cygne 2 and additional La Cygne 1 Powder River Basin coal was supplied,
through a contract that expired December 31, 1993, by AMAX from its mines in
Gillette, Wyoming. This low sulfur coal had an average BTU content of
approximately 8,500 BTU per pound and a maximum sulfur content of .50
lbs/mmBTU (see Environmental Matters). For 1994, the operator has secured
Powder River Basin coal, similar to the AMAX coal, from two sources; Carter
Mining Company's Caballo Mine, a subsidiary of Exxon Coal USA; and Caballo
Rojo Inc's Caballo Rojo Mine, a subsidiary of Drummond Inc. Transportation is
covered by KCP&L through its Omnibus Rail Transportation Agreement with BN and
Kansas City Southern Railroad through December 31, 1995. An alternative rail
transportation agreement with Western Railroad Property, Inc. (WRPI), a
partnership between UP and Chicago Northwestern (CNW), lasts through December
31, 1995. The WRPI/UP/CNW agreement is a supplemental access contract to
handle tonnages not covered by the Omnibus contract.

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

The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 768 MW (see Item 2. Properties). The
Company contracted with ARCH Mineral Corporation (ARCH Mineral) for low sulfur
coal through December 31, 1993. The coal from ARCH Mineral was surface mined
at its mine in Hanna, Wyoming and had an average BTU content of approximately
10,400 BTU per pound and an average sulfur content of .625 lbs/mmBTU (see
Environmental Matters). During 1993, the average delivered cost of coal for
the Lawrence units was approximately $1.254 per mmBTU or $29.13 per ton and
the average delivered cost of coal for the Tecumseh units was approximately
$1.229 per mmBTU or $26.19 per ton. The Company had a supplemental spot coal
agreement, expiring December 31, 1993, with Cyprus Western Coal Company
(Cyprus) to supply low-sulfur coal from Cyprus's Foidel Creek Mine located in
Routt County, Colorado. The Company entered into a new five year coal supply
agreement, effective January 1, 1994, with Cyprus for coal from the Foidel
Creek mine. This coal will be transported under a new agreement with Southern
Pacific Lines and Atchison and Topeka Santa Fe Railway Company. The coal
supplied from Cyprus has an average BTU content of approximately 11,200 BTU
per pound and an average sulfur content of .38 lbs/mmBTU. The Company
anticipates that the Cyprus agreement will supply the minimum requirements of
the Tecumseh and Lawrence Energy Centers and supplemental coal requirements
will continue to be supplied from favorable coal markets in Wyoming, Utah,
Colorado and/or New Mexico.

Natural Gas. The Company uses natural gas as a primary fuel in its Gordon
Evans, Murray Gill, Abilene, and Hutchinson Energy Centers and in the gas
turbine units at its Tecumseh generating station. Natural gas is also used as
a supplemental fuel in the coal fired units at the Lawrence and Tecumseh
generating stations. Natural gas for Gordon Evans and Murray Gill Energy
Centers is supplied under a firm contract that runs through 1995 by Kansas Gas
Supply (KGS). Short-term economical spot market purchases from the Williams
Natural Gas (WNG) system provide the Company flexible natural gas to meet
operational needs. Natural gas for the Company's Abilene and Hutchinson
stations is supplied from the Company's main system (see Natural Gas
Operations). Natural gas for the units at the Lawrence and Tecumseh stations
is supplied through the WNG system under a short-term spot market agreement.

Oil. The Company uses oil as an alternate fuel when economical or when
interruptions to gas make it necessary. Oil is also used as a supplemental
fuel at each of the coal plants. All oil burned by the Company during the
past several years has been obtained by spot market purchases. At December
31, 1993, the Company had approximately 4 million gallons of No. 2 and 14.7
million gallons of No. 6 oil which is sufficient to meet emergency
requirements and protect against lack of availability of natural gas and/or
the loss of a large generating unit.

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

On March 26, 1992, in connection with the Merger, the Kansas Corporation
Commission (KCC) approved the elimination of the Energy Cost Adjustment Clause
(ECA) for most Kansas retail electric customers of both the Company and KG&E
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. Any increase
or decrease in fuel costs from the projected average will be absorbed by the
Company.

Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.

KPL Plants 1993 1992 1991 1990 1989
Per Million BTU:
Coal $1.13 $1.30 $1.33 $1.33 $1.31
Gas 2.71 2.15 1.72 1.50 2.10
Oil 4.41 4.19 4.25 4.63 3.92

Cents per KWH Generation 1.31 1.49 1.52 1.53 1.51

KG&E Plants 1993 1992 1991 1990 1989
Per Million BTU:
Nuclear $0.35 $0.34 $0.32 $0.34 $0.34
Coal 0.96 1.25 1.32 1.32 1.38
Gas 2.37 1.95 1.74 1.96 1.91
Oil 3.15 4.28 4.13 3.01 3.30

Cents per KWH Generation 0.93 0.98 1.09 1.01 0.96

Environmental Matters. The Company currently holds all Federal and state
environmental approvals required for the operation of all its generating
units. The Company believes it is presently in substantial compliance with
all air quality regulations (including those pertaining to particulate matter,
sulfur dioxide and nitrogen oxides) promulgated by the State of Kansas and the
Environmental Protection Agency (EPA).

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

The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the nitrogen
oxide 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
2.5 pounds of sulfur dioxide per million BTU of heat input at the Company's
Lawrence generating units and 3.0 pounds at all other generating units. The
Company has contracted or intends to contract to purchase low sulfur coal (see
Coal) which will allow compliance with such limits at Lawrence, Tecumseh and
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 nitrogen oxide emissions effective in 1995 and
2000 and a probable reduction in toxic emissions. To meet the monitoring and
reporting requirements under the acid rain program, the Company is installing
continuous monitoring and reporting equipment at a total cost of approximately
$10 million. At December 31, 1993, the Company had completed approximately $4
million of these capital expenditures with the remaining $6 million of capital
expenditures to be completed in 1994 and 1995. The Company does not expect
additional equipment to reduce sulfur emissions to be necessary under Phase
II. The Company currently has no Phase I affected units.

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

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

Additional information with respect to Environmental Matters is discussed
in Note 4 of the Notes to Consolidated Financial Statements included herein.

NATURAL GAS OPERATIONS

General. At December 31, 1993, the Company supplied natural gas at retail
to approximately 1,093,000 customers in 519 communities and at wholesale to
eight communities and two utilities in Kansas, Missouri and Oklahoma. The
natural gas systems of the Company consisted of distribution systems in all
three states purchasing natural gas from interstate pipeline companies and the
main system, an integrated storage, gathering, transmission and distribution
system. The Company also transports gas for its large commercial and
industrial customers purchasing gas on the spot market. The Company earns
approximately the same margin on volume of gas transported as on volumes sold
except where limited discounting occurs in order to retain the customer's
load.

As discussed previously, on January 31, 1994, the Company sold
substantially all of its Missouri natural gas distribution properties and
operations to Southern Union and sold the remaining Missouri properties to
United Cities on February 28, 1994. Additional information with respect to
the impact of the sale of the Missouri Properties is set forth in Notes 2 and
13 of the Notes to Consolidated Financial Statements.

The percentage of total natural gas deliveries, including transportation
and operating revenues for 1993 by state were as follows:

Total Natural Total Natural Gas
Gas Deliveries Operating Revenues

Kansas 54.6% 53.9%
Missouri 43.0% 43.5%
Oklahoma 2.4% 2.6%

The Company's natural gas deliveries for the last five years were as
follows:

1993 1992 1991 1990 1989
(Thousands of MCF)

Residential 110,045 93,779 97,297 95,247 104,057
Commercial 47,536 40,556 47,075 43,973 47,339
Industrial 1,490 2,214 2,655 3,207 5,637
Other 41 94 14,960* 1,361 1,403
Transportation 73,574 68,425 78,055 72,623 58,025
Total 232,686 205,068 240,042* 216,411 216,461

* Includes cumulative effect to January 1, 1991, of change in revenue
recognition. The cumulative effect of this change increased natural
gas sales by 14,838,000 MCF.

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

1993 1992 1991 1990 1989
(Thousands of Dollars)

Residential $529,260 $440,239 $433,871 $439,956 $430,250
Commercial 209,344 169,470 182,486 176,279 172,628
Industrial 7,294 7,804 10,546 12,994 18,021
Other 30,143 27,457 33,434 31,323 30,072
Transportation 28,781 28,393 30,002 25,496 24,309
Total $804,822 $673,363 $690,339 $686,048 $675,280

In compliance with orders of the state commissions applicable to all
natural gas utilities, the Company has established priority categories for
service to its natural gas customers. The highest priority is for residential
and small commercial customers and the lowest for large industrial customers.
Natural gas delivered by the Company from its main system for use as fuel for
electric generation is classified in the lowest priority category.

Interstate Pipeline Supply. During 1993, the Company purchased natural
gas from interstate pipelines, producers, and marketers to distribute at
retail to approximately 966,000 customers located in western Missouri, central
and eastern Kansas and northeastern Oklahoma. The principal market area at
December 31, 1993, was the seven county Kansas City metropolitan area (see
page 3 regarding the sale of the Missouri Properties), which includes Kansas
City and Independence in Missouri and Kansas City and the northeast Johnson
County suburbs in Kansas. Other larger cities which were served in 1993 are
St. Joseph and Joplin, Missouri; Wichita and Topeka, Kansas; and Bartlesville,
Oklahoma.

During 1993, as a result of FERC Order No. 636, significant changes
occurred regarding the acquisition of interstate pipeline supply and
transportation services. The FERC has issued final decisions concerning the
Company's major pipeline suppliers which authorized the implementation of
restructured services before the 1993-94 winter heating season. Appeals have
been filed in several of these cases concerning numerous issues addressed by
the restructuring orders. The Company anticipates that implementation of
restructured pipeline services will not significantly affect its ability to
provide reliable service to its customers. For additional discussion, see
Management's Discussion and Analysis included herein.

In 1993, the Company purchased approximately 56.9 billion cubic feet (BCF)
or 38.7 percent of the interstate pipeline supply compared with 48.1 BCF or
39.4 percent for 1992, from Williams Natural Gas Company (WNG), a
non-affiliated interstate pipeline transmission company. The Company had a
contract with WNG for natural gas purchases which expired on September 30,
1993. The Company's purchase contract has been superseded by transportation
agreements with WNG which have terms varying in length from one to twenty
years. The Company now purchases all the natural gas it delivers to its
customers direct from producers and marketers of natural gas. WNG transported
33.5 BCF under these agreements in 1993.

The Company has gas purchase contracts with Mobil Natural Gas, Inc., OXY
USA, Inc., Williams Gas Marketing, Kansas Pipeline Company, L.P., Mesa, Tri-
Power Fuels, Amoco, Mid-Kansas Partnership, and GPM Gas Corporation expiring
at various times. Some of the Company's gas purchase contracts extend beyond
the year 2000. The Company purchased approximately 77.8 BCF or 52.9 percent
of its natural gas supply from these sources in 1993 and 63.9 BCF or 52.3
percent during 1992. Approximately 94.4 BCF of natural gas is made available
annually under these contracts. The Company has limited rights to substitute
spot gas for this gas under contract.

Other sources of supply for the Company's distribution systems were
Panhandle Eastern Pipeline Company (Panhandle), Northern Natural Gas Company,
Natural Gas Pipeline Company of America, intrastate pipelines, and spot market
suppliers under short term contracts. These sources totalled 5.2 and 2.0 BCF
for 1993 and 1992 representing 3.5 percent and 1.6 percent of the system
requirements, respectively.

During 1993 and 1992, approximately 7.1 BCF and 8.2 BCF, respectively,
were transferred from the Company's main system to serve a portion of Wichita,
Kansas. These system transfers represent 4.9 percent and 6.7 percent,
respectively, of the interstate system supply.

The average wholesale cost per thousand cubic feet (MCF) purchased for the
distribution systems for the past five years was as follows:

Interstate Pipeline Supply
(Average Cost per MCF)

1993 1992 1991 1990 1989

WNG $3.57 $3.64 $3.61 $3.84 $3.23
Other 3.01 2.30 2.36 2.14 2.29
Total Average Cost 3.23 2.88 3.02 3.10 2.91

The increase in the total average cost per MCF in 1993 from 1992 reflects
increased prices in the spot market.

Main System. The Company serves approximately 127,000 customers in
central and north central Kansas with natural gas supplied through the main
system. The principal market areas include Salina, Manhattan, Junction City,
Great Bend, McPherson, Hutchinson and Wichita, Kansas.

Natural gas for the Company's main system is purchased from a combination
of direct wellhead production, from the outlet of natural gas processing
plants, and from interstate pipeline interconnects all within the State of
Kansas. Such purchases are transported entirely through Company owned
transmission lines in Kansas.

During 1993 the Company purchased from Mesa approximately 15.6 BCF of
natural gas (including 2.5 BCF of make-up deliveries) pursuant to a contract
expiring May 31, 1995 (the Hugoton Contract). This compares with 14.3 BCF
(including 2.1 BCF of make-up deliveries) during 1992. These purchases
represent approximately 53.7 percent and 55.2 percent, respectively, of the
Company's main system requirements during such periods.

Pursuant to the Hugoton Contract, the Company expects to purchase
approximately 16.8 BCF of natural gas constituting approximately 56.4 percent
of the Company's main system requirements during 1994. Mesa dedicated its
entire deliverability in the contract area to the Company. However, if the
Company is unable to take 100% of such deliverability, such non-takes by the
Company are released back to Mesa to sell to others. Under the terms of the
Hugoton Contract, the Company is entitled to purchase annually the volume of
natural gas the KCC allows to be produced from the Mesa wells, less gasoline
plant shrinkage and the natural gas used by Mesa in its operations.

Spivey-Grabs field in south-central Kansas supplied approximately 4.8 and
5.4 BCF of natural gas in 1993 and 1992, constituting 16.6 percent and 20.9
percent, respectively, of the main system's requirements during such periods.
Such natural gas is supplied pursuant to contracts with producers in the
Spivey-Grabs field, most of which are for the life of the field, and under
which the Company expects to receive approximately 5.2 BCF of natural gas in
1994.

Other sources of gas for the main system of 4.4 BCF or 15.2 percent of the
system requirements were purchased from or transported through interstate
pipelines during 1993. The remainder of the supply for the main system during
1993 and 1992 of 4.2 and 4.0 BCF representing 14.5 percent and 15.4 percent,
respectively, was purchased directly from producers or gathering systems.

During 1993 and 1992, approximately 7.1 and 8.2 BCF, respectively, of the
total main system supply was transferred to the Company's interstate system
(see Interstate Pipeline Supply).

The main system's average wholesale cost per MCF purchased for the past
five years was as follows:
Natural Gas Supply - Main System
(Average Cost per MCF)

1993 1992 1991 1990 1989

Mesa-Hugoton Contract $1.78(1) $1.47(2) $1.36(3) $1.47(4) $1.35
Other 2.69 2.66 2.68 2.54 2.63
Total Average Cost 2.20 2.00 1.94 1.98 1.84

(1) Includes 2.5 BCF @ $1.31/MCF of make-up deliveries.
(2) Includes 2.1 BCF @ $1.31/MCF of make-up deliveries.
(3) Includes 1.5 BCF @ $1.31/MCF of make-up deliveries.
(4) Includes 1.6 BCF @ $1.12/MCF and 1.8 BCF @ $1.31/MCF of make-up
deliveries.

The Company has determined that it controlled an estimated 448 BCF of
proved natural gas reserves as of December 31, 1993, for the main system. The
Company made this determination based on a study and estimate prepared by K&A
Energy Consultants, Inc., independent petroleum engineers and geologists, of
the natural gas reserves under contract to the Company as of December 31,
1988, and changes in contracted reserves since the date of the study. The
annual amount of natural gas available from these reserves is dependent upon
production allowables granted by the KCC to wells in specific natural gas
fields, and upon the deliverability of the wells under contract.

Production allowables for the Hugoton Field, set by the KCC, determine the
amount of natural gas available to the Company. The production allowables
granted by the KCC are reviewed in March and September of each year.

In the Company's opinion, its contracts and reserves are adequate to meet
the present annual requirements of its main system high priority customers
through 1994. The Company has contracted with various suppliers to assure
adequate supplies will continue beyond 1994.

The load characteristics of the Company's natural gas customers creates
relatively high volume demand on the main system during cold winter days. To
assure peak day service to high priority customers, the Company has developed
the Brehm natural gas storage facility near Pratt, Kansas with working storage
capacity of 1.6 BCF. The Company has an agreement with Williams Natural Gas
Company, expiring March 31, 1998, for an additional 3.3 BCF of storage in the
Alden field in Kansas. Natural gas is transferred to and displaced from Alden
through Williams's pipeline system.

Under the terms of a deferred delivery agreement between the Company and
Enron Gas Marketing (EGM), the Company will receive approximately 1.5 BCF
during the 1993-1994 heating season, which will complete the deferred delivery
agreement.

The Company owns and operates the Brehm field, an underground natural gas
storage facility in Pratt County, Kansas. This facility has a storage
capacity of approximately 1.6 BCF.

The Company has developed additional storage for the main system in the
Yaggy field near Hutchinson, Kansas. This field provides another 2 BCF of
working storage capacity when fully operational, of which approximately 1 BCF
was available for the heating season beginning November 1993.

Environmental Matters. For information with respect to Environmental
Matters see Note 4 of Notes to Consolidated Financial Statements included
herein.

SEGMENT INFORMATION

Financial information with respect to business segments as set forth in
Note 13 of Notes to Consolidated Financial Statements included herein.

FINANCING

The Company's ability to issue additional debt and equity securities is
restricted under limitations imposed by the charter and the Mortgage and Deed
of Trust of Western Resources and KG&E.

Western Resources' mortgage prohibits additional first mortgage bonds from
being issued (except in connection with certain refundings) unless the
Company's net earnings available for interest, depreciation and property
retirement for a period of 12 consecutive months within 15 months preceding
the issuance are not less than the greater of twice the annual interest
charges on, or 10% of the principal amount of, all first mortgage bonds
outstanding after giving effect to the proposed issuance. Based on the
Company's results for the 12 months ended December 31, 1993, approximately
$457 million principal amount of additional first mortgage bonds could be
issued (7.5 percent interest rate assumed).

Additional Western Resources bonds may be issued, subject to the
restrictions in the preceding paragraph, on the basis of property additions
not subject to an unfunded prior lien and on the basis of bonds which have
been retired. As of December 31, 1993, the Company had approximately $148
million of net bondable property additions not subject to an unfunded prior
lien entitling the Company to issue up to $89 million principal amount of
additional bonds. As of December 31, 1993, the Company could also issue up to
$203 million bonds on the basis of retired bonds.

With the sale of the Missouri Properties and the discharge of the Gas
Service mortgage, the Company, as of January 31, 1994, had approximately $387
million of net bondable property additions not subject to an unfunded prior
lien entitling the Company to issue up to $232 million of additional bonds.
In addition, $203 million of retired bonds were repledged to the Trustee for
the release of a portion of the gas properties sold. As of January 31, 1994,
no additional bonds could be issued on the basis of retired bonds.

KG&E's mortgage prohibits additional first mortgage bonds from being
issued (except in connection with certain refundings) unless KG&E'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 KG&E's results for the 12 months ended December 31, 1993,
approximately $1 billion principal amount of additional first mortgage bonds
could be issued (7.5 percent interest rate assumed).

Additional KG&E bonds may be issued, subject to the restrictions in the
preceding paragraph, on the basis of property additions not subject to an
unfunded prior lien and on the basis of bonds which have been retired. As of
December 31, 1993, KG&E had approximately $1.3 billion of net bondable
property additions not subject to an unfunded prior lien entitling KG&E to
issue up to $882 million principal amount of additional bonds. As of December
31, 1993, KG&E could also issue up to $115 million bonds on the basis of
retired bonds.

The most restrictive provision of the Company's charter permits the
issuance of additional shares of preferred stock without certain specified
preferred stockholder approval only if, for a period of 12 consecutive months
within 15 months preceding the issuance, net earnings available for payment of
interest exceed one and one-half times the sum of annual interest requirements
and dividend requirements on preferred stock after giving effect to the
proposed issuance. After giving effect to the annual interest and dividend
requirements on all debt and preferred stock outstanding at December 31, 1993,
such ratio was 1.94 for the 12 months ended December 31, 1993.

REGULATION AND RATES

The Company is subject as an operating electric utility to the
jurisdiction of the KCC and as a natural gas utility to the jurisdiction of
the KCC, the Missouri Public Service Commission (MPSC), and the Corporation
Commission of the State of Oklahoma (OCC), which have 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 subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC), KCC and MPSC with respect to the issuance of
securities. There is no state regulatory body in Oklahoma having jurisdiction
over 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. The Company is not engaged in the interstate transmission or sale of
natural gas which would subject it to the regulatory provisions of the Natural
Gas Act. KG&E is also subject to the jurisdiction of the Nuclear Regulatory
Commission as to nuclear plant operations and safety.

Additional information with respect to Rate Matters and Regulation as set
forth in Note 5 of Notes to Consolidated Financial Statements is included
herein.

EMPLOYEE RELATIONS

As of December 31, 1993, the Company had 5,192 employees. The Company did
not experience any strikes or work stoppages during 1993. The Company's
current contracts with its two electric unions were negotiated in 1993 and
expire June 30, 1995. The two contracts cover approximately 2,000 employees.
The Company has contracts with 5 other unions representing approximately 1,450
employees. These contracts were negotiated in 1992 and will expire June 6,
1996. Following the 1994 sale of the Missouri Properties the Company had
4,164 employees.

EXECUTIVE OFFICERS OF THE COMPANY

Other Offices or Positions
Name Age Present Office Held During Past Five Years

John E. Hayes, Jr. 56 Chairman of the Board, Chairman of the Board (1989)
President, and Chief Triad Capital Partners,
Executive Officer St. Louis, Missouri
(since October 1989) President and Chief Executive
Officer (1986 to 1989), Director
(1984 to 1989), and Chairman of
the Board (1986 to 1989),
Southwestern Bell Telephone
Company, St. Louis, Missouri
Director (1986 to 1989)
Southwestern Bell Corporation,
St. Louis, Missouri

William E. Brown 54 President and Chief President and Chief Operating Officer-
Executive Officer KPL KPL Division (1990)
(since October 1990) Executive Vice President and Chief
Operating Officer (1987 to 1990)
Acting President (1989)

James S. Haines, Jr. 47 Executive Vice President Group Vice President (1985 to 1992)
and Chief Administrative KG&E, Wichita, Kansas
Officer (since March 1992)

Steven L. Kitchen 48 Executive Vice President Senior Vice President, Finance
and Chief Financial and Accounting (1987 to 1990)
Officer (since March 1990)

John K. Rosenberg 48 Executive Vice President Corporate Secretary (1988 to 1992)
(since March 1990) Vice President (1987 to 1990)
and General Counsel
(since May 1987)

Carl M. Koupal, Jr. 40 Vice President, Corporate Vice President, Marketing and Economic
Communications, Marketing, Development (1992)
and Economic Development Director, Economic Development, (1985
(since September 1992) to 1992) Jefferson City, Missouri

Rayford Price 56 Vice President, Corporate President, (1990 to 1993) Rayford
Price
Development (since & Associates P.C., Austin, Texas
September 1993) Partner, (1988 to 1990) Thomas,
Winters
& Newton, Austin, Texas

Kent R. Brown 48 President and Chief Group Vice President (1982 to 1992)
Executive Officer KG&E KG&E, Wichita, Kansas
(since April 1992)

William L. Johnson(1) 51 President and Chief President and Chief Operating Officer-
Executive Officer Gas Gas Service Division (1990)
Service (since Vice President, District Operations
October 1990) (1985 to 1990) Michigan Consolidated
Gas Company, Grand Rapids, Michigan
Jerry D. Courington 48 Controller (since February
1985)

(1) Mr. Johnson left the Company on January 31, 1994.

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

ITEM 2. PROPERTIES

The Company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas, a natural gas integrated
storage, gathering, transmission and distribution system in Kansas, and a
natural gas distribution system in Kansas, Missouri and Oklahoma (see page 3
with respect to the sale of the Missouri Properties).

During the five years ended December 31, 1993, the Company's gross
property additions totalled $852,650,000 and retirements were $125,287,000.

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

Abilene Energy Center:
Combustion Turbine 1 1973 Gas 67

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

Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18
2 1950 Gas 20
3 1951 Gas 31
4 1965 Gas 196
Combustion Turbines 1 1974 Gas 53
2 1974 Gas 51
3 1974 Gas 55
4 1975 Oil 89

Jeffrey Energy Center (84%):
Steam Turbines 1 1978 Coal 587
2 1980 Coal 566
3 1983 Coal 588

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

Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (1)
3 1954 Coal 56
4 1960 Coal 102
5 1971 Coal 380

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

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

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

Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 83
8 1962 Coal 147
Combustion Turbines 1 1972 Gas 19
2 1972 Gas 19

Wichita Plant:
Diesel Generator 5 1969 Diesel 3

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

Total 5,184

(1) These units have been "mothballed" for future use.

(2) Based on MOKAN rating.

The Company jointly-owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).

NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES

The Company's transmission and storage facility compressor stations, all
located in Kansas, as of December 31, 1993, are as follows:
Mfr Ratings
of MCF/Hr
Capacity at
Driving Type of Mfr hp 14.65 Psia
Location Units Year Installed Fuel Ratings at 60 F

Abilene . . . . . 4 1930 Gas 4,000 5,920
Bison . . . . . . 1 1951 Gas 440 316
Brehm Storage . . 2 1982 Gas 800 486
Calista . . . . . 3 1987 Gas 4,400 7,490
Hope. . . . . . . 1 1970 Electric 600 44
Hutchinson. . . . 2 1989 Gas 1,600 707
Manhattan . . . . 1 1963 Electric 250 313
Marysville. . . . 1 1964 Electric 250 202
McPherson . . . . 1 1972 Electric 3,000 7,040
Minneola. . . . . 5 1952 - 1978 Gas 9,650 14,018
Pratt . . . . . . 3 1963 - 1983 Gas 1,700 3,145
Spivey. . . . . . 4 1957 - 1964 Gas 7,200 1,368
Ulysses . . . . . 12 1949 - 1981 Gas 26,630 15,244
Yaggy Storage . . 3 1993 Electric 7,500 5,000

The Company owns and operates an underground natural gas storage facility,
the Brehm field in Pratt County, Kansas. This facility has a working storage
capacity of approximately 1.6 BCF. The Company withdrew up to 16,930 MCF per
day from this field to meet 1993 winter peaking requirements.

The Company owns and operates an underground natural gas storage field,
the Yaggy field in Reno County, Kansas. This facility has a working storage
capacity of approximately 0.8 BCF to be expanded to 2 BCF. The Company
withdrew up to 6,280 MCF per day from this field to meet 1993 winter peaking
requirements.

The Company has contracted with Williams Natural Gas Company for
additional underground storage in the Alden field in Kansas. The contract,
expiring March 31, 1998, enables the Company to supply customers with up to 75
million cubic feet per day of gas supply during winter peak periods. See Item
I. Business, Gas Operations for proven recoverable gas reserve information.

ITEM 3. LEGAL PROCEEDINGS

Information on legal proceedings involving the Company is set forth in
Note 15 of Notes to Consolidated Financial Statements included herein.

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

No matter was submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.

PART II

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

Stock Trading. Western Resources common stock, which is traded under the
ticker symbol WR, is listed on the New York Stock Exchange. As of March 14,
1994, there 45,317 common shareholders of record. For information regarding
quarterly common stock price ranges for 1993 and 1992, see Note 16 of Notes to
Consolidated Financial Statements included herein.

Dividend Policy. Western Resources common stock is entitled to dividends
when and as declared by the Board of Directors. At December 31, 1993, the
Company's retained earnings were restricted by $857,600 against the payment of
dividends on common stock. However, prior to the payment of common dividends,
dividends must be first paid to the holders of preferred stock and second to
the holders of preference stock based on the fixed dividend rate for each
series.

Dividends have been paid on the Company's common stock throughout the
Company's history. Quarterly dividends on common stock normally are paid on
or about the first of January, April, July, and October to shareholders of
record as of about the third day of the preceding month. Future dividends
depend upon future earnings, the financial condition of the Company and other
factors. For information regarding quarterly dividend declarations for 1993
and 1992, see Note 16 of Notes to Consolidated Financial Statements included
herein.

ITEM 6. SELECTED FINANCIAL DATA

Year Ended December 31, 1993 1992(1) 1991 1990 1989
(Dollars in Thousands)

Income Statement Data:

Operating revenues:
Electric . . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839 $ 463,707 $ 452,343
Natural gas. . . . . . . . . . 804,822 673,363 690,339 686,048 675,280
Total operating revenues . . 1,909,359 1,556,248 1,162,178 1,149,755 1,127,623
Operating expenses . . . . . . . 1,617,296 1,317,079 1,032,557 1,017,765 1,002,087
Allowance for funds used during
construction . . . . . . . . . 2,631 2,002 1,070 1,181 1,503

Income before cumulative effect
of accounting change . . . . . 177,370 127,884 72,285 79,619 72,778
Cumulative effect to January 1,
1991, of change in revenue
recognition. . . . . . . . . . - - 17,360 - -
Net income . . . . . . . . . . . 177,370 127,884 89,645 79,619 72,778
Earnings applicable to common
stock. . . . . . . . . . . . . 163,864 115,133 83,268 77,875 70,921

December 31, 1993 1992(1) 1991 1990 1989
(Dollars in Thousands)
Balance Sheet Data:

Gross plant in service . . . . . $6,222,483 $6,033,023 $2,535,448 $2,421,562 $2,305,279
Construction work in progress. . 80,192 68,041 17,114 20,201 19,571
Total assets . . . . . . . . . . 5,412,048 5,438,906 2,112,513 2,016,029 1,959,044
Long-term debt and preference
stock subject to mandatory
redemption . . . . . . . . . . 1,673,988 2,077,459 690,612 595,524 552,538

Year Ended December 31, 1993 1992(1) 1991 1990 1989

Common Stock Data:

Earnings per share before
cumulative effect of
accounting change. . . . . . . $ 2.76 $ 2.20 $ 1.91 $ 2.25 $ 2.05
Cumulative effect to January 1,
1991, of change in revenue
recognition per share. . . . . - - .50 - -
Earnings per share . . . . . . . $ 2.76 $ 2.20 $ 2.41 $ 2.25 $ 2.05
Dividends per share. . . . . . . $ 1.94 $ 1.90 $ 2.04(2) $ 1.80 $ 1.76
Book value per share . . . . . . $23.08 $21.51 $18.59 $18.25 $17.80
Average shares outstanding(000's) 59,294 52,272 34,566 34,566 34,566
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 2.79 2.27 2.69 2.86 2.96

(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).

(2) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.

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

FINANCIAL CONDITION

General: Earnings were $2.76 per share of common stock based on
59,294,091 average common shares for 1993, an increase from $2.20 in 1992 on
52,271,932 average common shares. The increase resulted from a return to near
normal temperatures compared to unusually mild winter and summer temperatures
in 1992, reduced interest costs, and the full twelve month effect of the
merger with Kansas Gas and Electric Company (KG&E) on March 31, 1992 (the
Merger).

Dividends per common share were $1.94 in 1993, an increase of four cents
from 1992. In January 1994, the Board of Directors declared a quarterly
dividend of 49 1/2 cents per common share, an increase of one cent over the
previous quarter.

The book value per share was $23.08 at December 31, 1993, compared to
$21.51 at December 31, 1992. The increase in book value is primarily the
result of the issuance of additional common stock and an increase in retained
earnings. The 1993 closing stock price of $34 7/8 was 151 percent of book
value. There were 61,617,873 common shares outstanding at December 31, 1993.

On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties." With the sales the Company is no longer operating
as a utility in the State of Missouri.

The portion of the Missouri Properties purchased by Southern Union was
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The final sale price will be calculated
as of January 31, 1994, within 120 days of closing. Any difference between
the estimated and final sale price will be adjusted through a payment to or
from the Company.

United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri, for $665,000 in cash.

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

During 1993, construction expenditures for the Company's electric system
were approximately $138 million and nuclear fuel expenditures were
approximately $6 million. It is projected that adequate capacity margins will
be maintained without the addition of any major generating facilities through
the turn of the century. The construction expenditures for improvements on
the natural gas system, including the Company's service line replacement
program, were approximately $94 million during 1993, of which construction
expenditures for the Missouri Properties were approximately $39 million.

Capital expenditures for 1994 to 1996 are anticipated to be as follows:

Electric Nuclear Fuel Natural Gas
(Dollars in Thousands)

1994 $131,483 $ 20,995 $ 64,608
1995 143,391 21,469 69,482
1996 151,100 9,890 68,747

These expenditures are estimates prepared for planning purposes and are
subject to revisions from time to time (see Note 4).

The Company's net cash flow to capital expenditures was 100 percent for
1993 and during the last five years has averaged 87 percent. The Company
anticipates net cash flow to capital expenditures to be approximately 100
percent in 1994.

The Company's capital needs through 1998 are approximately $33.6 million
for bond maturities and cash sinking fund requirements for bonds and
preference stock. This capital as well as capital required for construction
will be provided from internal and external sources available under then
existing financial conditions.

The Company anticipates using the net proceeds from the sale of the
Missouri Properties to reduce the Company's outstanding debt.

The embedded cost of long-term debt was 7.7% at December 31, 1993, a
decrease from 7.9% at December 31, 1992. The decrease was primarily
accomplished through refinancing of higher cost debt.

The Company's short-term financing requirements are satisfied, as needed,
through the sale of commercial paper, short-term bank loans, and borrowings
under other unsecured lines of credit maintained with banks. At December 31,
1993, short-term borrowings amounted to $441 million, of which $126 million
was commercial paper (see Notes 8 and 9).

On September 20, 1993, KG&E terminated a long-term revolving credit
agreement which provided for borrowings of up to $150 million. The loan
agreement, which was effective through October 1994, was repaid without
penalty.

At December 31, 1993, the Company had $200 million of First Mortgage Bonds
available to be issued under a shelf registration filed August 24, 1993. Also
at December 31, 1993, KG&E had $150 million of First Mortgage Bonds available
to be issued under a shelf registration filed on August 24, 1993. On January
20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due
January 15, 2006, under the KG&E shelf registration. The net proceeds were
used to reduce short-term debt.

On January 31, 1994, the Company redeemed the remaining $2,466,000
principal amount of Gas Service Company 8 1/2% Series First Mortgage Bonds due
1997.

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

The issuance and retirement of long-term debt, borrowings against the cash
surrender value of corporate-owned life insurance policies (COLI), and the
issuance of common stock during 1993 are summarized in the table below.

- ------------------------------------------------------------------------------
| Date Issued Retired |
| (Dollars in Millions) |
|Long-term debt |
|----------------------------------------------------------------------------|
|7 3/8% due 2002 - KG&E | 11/22/93 | | $ 25.0|
|8 3/8% due 2006 - KG&E | | | 25.0|
|8 1/2% due 2007 - KG&E | | | 25.0|
|----------------------------------------------------------------------------|
|9.35% due 1998 | 10/15/93 | | 75.0|
|----------------------------------------------------------------------------|
|6 1/2% due 2005 - KG&E | 08/12/93 | $ 65.0| |
|8 1/8% due 2001 - KG&E | 08/20/93 | | 35.0|
|8 7/8% due 2008 - KG&E | | | 30.0|
|----------------------------------------------------------------------------|
|7.65% due 2023 | 04/27/93 | 100.0| |
|8 3/4% due 2000 | 05/12/93 | | 20.0|
|8 5/8% due 2005 | | | 35.0|
|8 3/4% due 2008 | | | 35.0|
|----------------------------------------------------------------------------|
|6% Pollution Control Revenue Refunding | | | |
| Bonds due 2033 | 02/09/93 | 58.5| |
|9 5/8% Pollution Control Refunding and | | | |
| Improvement Revenue Bonds due 2013 | | | 58.5|
|----------------------------------------------------------------------------|
|Bank term loan | 01/26/93 | | 230.0|
|----------------------------------------------------------------------------|
|Revolving credit agreements (net) | various | | 35.0|
|----------------------------------------------------------------------------|
|Other long-term debt and sinking funds | various | 4.1| |
|----------------------------------------------------------------------------|
|COLI borrowings (net) (1) | various | 183.3| |
|----------------------------------------------------------------------------|
|Common stock | | | |
| 3,425,000 shares (2) | 08/25/93 | 124.2| |
| 147,323 shares (3) | various | 5.3| |
|----------------------------------------------------------------------------|
(1) The COLI borrowings will be repaid upon receipt of proceeds from
death benefits under the contracts. See Note 1 of Notes to
Consolidated Financial Statements for additional information on
the accumulated cash surrender value of COLI policies.
(2) Issued in public offering for net proceeds of $121 million.
(3) Issued under the Dividend Reinvestment and Stock Purchase Plan
(DRIP). The net proceeds from these issues of approximately $5.3
million were added to the general corporate funds of the Company.
Shares issued under the DRIP may either be original issue shares
or shares purchased on the open market.

The Company has a Customer Stock Purchase Plan (CSPP) under which retail
electric and natural gas customers and employees of the Company may purchase
common stock through monthly installments. The initial installment period
runs from September 1993, through June 1994, with monthly installments plus
accumulated interest converted to shares in August 1994. Shares issued under
the CSPP may either be original issue shares or shares purchased on the open
market. Approximately $14.7 million has been pledged for this installment
period.

The capital structure at December 31, 1993, was 45 percent common stock
equity, 6 percent preferred and preference stock, and 49 percent long-term
debt. The capital structure at December 31, 1993, including short-term debt
and current maturities of long-term debt and preference stock, was 40 percent
common stock equity, 5 percent preferred and preference stock, and 55 percent
debt.

RESULTS OF OPERATIONS

The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, interest
charges and preferred and preference dividend requirements. The results of
operations of the Company include the activities of KG&E since the Merger on
March 31, 1992. Additional information relating to changes between years is
provided in the Notes to Consolidated Financial Statements.

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

The Kansas Corporation Commission (KCC) order approving the Merger
provided a moratorium on increases, with certain exceptions, in the Company's
jurisdictional electric and natural gas 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. The first refund of $8.5 million was made in April 1992.
A refund of the same amount was made in December 1993, and an additional
refund of $15 million will be made in September 1994 (see Note 3).

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

Future natural gas revenues will be reduced as a result of the sale of the
Missouri Properties by approximately $350 million annually based on Missouri
revenues recorded in 1993 (see Note 2).

1993 COMPARED TO 1992: Electric revenues increased significantly in 1993
as a result of the Merger. Also contributing to the increase were increased
electric sales for space heating, resulting from colder winter temperatures in
the first quarter of 1993, and increased sales for cooling load, resulting
from warmer temperatures in the second and third quarters of 1993. KG&E
electric revenues of $617 million have been included in the Company's 1993
electric revenues. This compares to KG&E revenues of $424 million, from April
1, 1992, through December 31, 1992, included in the Company's 1992 electric
revenues. Partially offsetting these increases in electric revenues was the
amortization of the Merger-related customer refund.

Electric revenues for 1993 compared to pro forma revenues for 1992, giving
effect to the Merger as if it had occurred at January 1, 1992, would have
increased as a result of the warmer summer and colder winter temperatures in
1993. Retail sales of kilowatt hours on a pro forma comparative basis
increased from approximately 14.6 billion for 1992 to approximately 15.5
billion for 1993, or six percent.

Natural gas revenues increased approximately 20 percent as a result of
increased sales caused by colder winter temperatures, the full impact of
increased retail natural gas rates (see Note 5), and an eleven percent
increase in the unit cost of gas passed on to customers through the purchased
gas adjustment clauses (PGA). The colder winter temperatures are reflected in
a 17 percent increase in natural gas sales to residential customers.

1992 COMPARED TO 1991: Electric revenues increased significantly in 1992
as a result of the Merger. KG&E electric revenues for the nine months ended
December 31, 1992, of $424 million have been included in the Company's
electric revenues. Partially offsetting this increase in revenues were
reduced retail electric sales as a result of the abnormally mild summer
temperatures in 1992 and the amortization of the Merger-related customer
refund.

Electric revenues for 1992 compared to pro forma revenues for 1991, giving
effect to the Merger as if it had occurred at January 1, 1991, also would have
been lower as a result of the mild summer and winter temperatures in 1992.
Retail sales of kilowatthours on a pro forma comparative basis decreased from
approximately 15.1 billion for 1991 to approximately 14.6 billion for 1992, or
four percent.

Natural gas revenues decreased over two percent due to a nine percent
decrease in natural gas deliveries, excluding sales related to the cumulative
effect of the unbilled revenue adjustment in 1991. Also contributing to the
decrease was an approximately four percent decrease in the unit cost of
natural gas which is passed on to customers through the PGA. The decrease in
sales can be attributed to mild winter temperatures in 1992. Partially
offsetting the decreased sales were increased retail rates in Kansas and
Missouri beginning early in 1992.

Operating Expenses: 1993 COMPARED TO 1992: Operating expenses increased
for 1993 primarily as a result of the Merger. KG&E operating expenses of $470
million have been included in the Company's operating expenses for the year
ended December 31, 1993. This compares to KG&E operating expenses of $316
million, from April 1, 1992, through December 31, 1992, included in the
Company's 1992 operating expenses.

Other factors, excluding the Merger, contributing to the increase in
operating expenses were higher fuel and purchased power expenses caused by
increased electric sales to meet cooling load and increased natural gas
purchases caused by a 16 percent increase in natural gas sales and an 11
percent higher unit cost of gas which is passed on to customers through the
PGA.

Also contributing to the increase were higher general taxes due to
increases in plant, the property tax assessment ratio, and higher mill levies.
A constitutional amendment in Kansas changed the assessment on utility
property from 30 to 33 percent. As a result of this change the Company had an
increased property tax expense of approximately $6.1 million in 1993.

Partially offsetting the increases were savings as a result of the Merger
and reduced net lease expense for La Cygne 2 (see Note 10).

At December 31, 1993, KG&E completed the accelerated amortization of
deferred income tax reserves related to the allowance for borrowed funds used
during construction capitalized for Wolf Creek Generating Station. The
amortization of these deferred income tax reserves amounted to approximately
$12 million in 1993. In accordance with the provisions of the Merger order
(see Note 3), the Company is precluded from recovering the $12 million annual
amortization in rates until the next rate filing. Therefore the Company's
earnings will be impacted negatively until these income taxes are recovered in
future rates.

1992 COMPARED TO 1991: Operating expenses increased significantly for
1992 as a result of the Merger. KG&E operating expenses for the nine months
ended December 31, 1992, of $316 million have been included in the Company's
operating expenses.

Other factors, excluding the Merger, contributing to increased operating
expenses were a one-time charge for the Company's portion of the early
retirement plan and voluntary separation program of approximately $11 million;
higher depreciation and amortization expense caused by increased plant
investment and the beginning of the amortization of previously deferred
safety-related expenditures in Kansas; and increased property taxes due to
increases in plant and tax mill levies.

Partially offsetting those increases in operating expenses was the
commencement of savings as a result of the Merger. The Company also changed
the depreciable life of Jeffrey Energy Center, for book purposes, to 40 years,
resulting in a reduction to depreciation expense of approximately $5.4 million
annually. Lower natural gas purchases as a result of the mild temperatures and
a reduced unit cost also partially offset the increase in operating expenses.

As permitted under the La Cygne 2 generating station lease agreement, KG&E
requested the Trustee Lessor to refinance $341,127,000 of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested
to reduce the Company's recurring future net lease expense. To accomplish
this transaction, a one-time payment of approximately $27 million was made
which will be amortized over the remaining life of the lease and will be
included in operating expense as part of the future lower lease expense. On
September 29, 1992, the Trustee Lessor refinanced bonds with a coupon rate of
approximately 11.7% with bonds having a coupon rate of approximately 7.7%.

Other Income and Deductions: Other income and deductions, net of taxes,
increased $1.3 million in 1993 compared to 1992. KG&E other income and
deductions, net of taxes, of $19 million have been included in the Company's
total for 1993 compared to $17 million in 1992 from April 1, through December
31, 1992. Income from KG&E's COLI totalled $8 million in 1993.

Other income and deductions, net of taxes, was significantly higher in
1992 compared to 1991 as a result of the Merger. KG&E contributed, for the
nine months ended December 31, 1992, $17 million to other income and
deductions, net of taxes. Significant items of other income include
approximately $9 million from KG&E's COLI and KG&E's recognition of the
recovery of approximately $4.2 million of a previously written-off investment
in commercial paper.

Interest Charges and Preferred and Preference Dividend Requirements:
Interest charges for 1993 were higher as a result of the Merger. KG&E
interest charges of $59 million for 1993 have been included in the Company's
total interest charges compared to $53 million for the nine months ended
December 31, 1992. The full twelve month effect of interest on debt to
acquire KG&E also contributed to the increase in total interest charges. The
increased interest charges have been partially offset through lower debt
balances and reduced interest charges from refinancing higher cost long-term
debt and lower interest rates on variable-rate debt. The Company's embedded
cost of long-term debt decreased to 7.7% at December 31, 1993, compared to
7.9% and 8.6% at December 31, 1992 and 1991, respectively, primarily as a
result of the refinancing of higher cost debt.

Total interest charges increased significantly for 1992 compared to 1991
as a result of the Merger. Partially offsetting this increase were lower
short-term and long-term interest rates.

Preferred and preference dividend requirements increased six percent in
1993 and significantly in 1992 compared to 1991 as a result of the issuance of
$50 million of 7.58% preference stock in the second quarter of 1992.

Merger Implementation: In accordance with the KCC Merger order,
amortization of the acquisition adjustment will commence August 1995. The
amortization will amount to approximately $19.6 million per year for 40 years.
The Company can recover the amortization of the acquisition adjustment through
cost savings under a sharing mechanism approved by the KCC as described in
Note 3 of the Notes to the Consolidated Financial Statements. While the
Company has achieved savings from the Merger, there is no assurance that the
savings achieved will be sufficient to, or the cost savings sharing mechanism
will operate as to fully offset the amortization of the acquisition
adjustment.

In 1992 the Company completed the consolidation of certain operations of
the Company and KG&E. In conjunction with these efforts the Company incurred
costs of consolidating facilities, transferring certain employees, and other
costs associated with completing the Merger. Certain of these costs related
to KG&E have been considered in purchase accounting for the Merger. Other
costs, including costs of the early retirement incentive programs and other
employee severance compensation programs for former Kansas Power and Light
Company employees were charged to expense in 1992. See Note 6 of Notes to
Consolidated Financial Statements for a discussion regarding the early
retirement and Merger severance plans.

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 requires the Company to seek regulatory rate relief to recover these
higher costs.

FERC Order No. 636: On April 8, 1992, the FERC issued Order No. 636 which
the FERC intended to complete the deregulation of natural gas production and
facilitate competition in the gas transportation industry. Order No. 636 is
expected to affect the Company in several ways. The rules provide greater
protection for pipeline companies by providing for recovery of all fixed costs
through contracts with local distribution companies and other customers
choosing to transport gas on a firm (non-interruptible) basis. The order also
separates the purchase of natural gas from the transportation and storage of
natural gas, shifting additional responsibility to distribution companies for
the provision (through purchase and/or storage) of long-term gas supply and
transportation to distribution points. Under the new rules, distribution
companies elect the amount and type of services taken from pipelines. The
Company may be liable to one or more of its pipeline suppliers for costs
related to the transition from its traditional sales service to the
restructured services required by Order No. 636. The Company believes
substantially all of these costs will be recovered from its customers and any
additional transition costs will be immaterial to the Company's financial
position or results of operations.

The Company was an active participant in pipeline restructuring
negotiations and does not anticipate any material difficulty in obtaining the
pipeline services the Company needs to meet the requirements of its gas
operations.

Environmental: The Company has recognized the importance of environmental
responsibility and has taken a proactive position with respect to the
potential environmental liability associated with former manufactured gas
sites. The Company has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (see Note 4).

The Company currently has no Phase I affected units under the Clean Air
Act of 1990. Until such time that additional regulations become final the
Company will be unable to determine its compliance options or related
compliance costs (see Note 4).

Energy Policy Act: The 1992 Energy Policy Act (Act) requires increased
efficiency of energy usage and will potentially change the way electricity is
marketed. The Act also provides for increased competition in the wholesale
electric market by permitting the FERC to order third party access to
utilities' transmission systems and by liberalizing the rules for ownership of
generating facilities. As part of the Merger, the Company agreed to open
access to its transmission system. Another part of the Act requires a special
assessment to be collected from utilities for a uranium enrichment,
decontamination, and decommissioning fund. KG&E's portion of the assessment
for Wolf Creek is approximately $7 million, payable over 15 years. Management
expects such costs to be recovered through the ratemaking process.

Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112
(SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on
the Company see Note 6 of Notes to the Consolidated Financial Statements.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Independent Auditors' Report 33

Financial Statements:

Consolidated Balance Sheets, December 31, 1993 and 1992 34
Consolidated Statements of Income for the years ended
December 31, 1993, 1992 and 1991 35
Consolidated Statements of Cash Flows for the years ended
1993, 1992 and 1991 36
Consolidated Statements of Taxes for the years ended
December 31, 1993, 1992 and 1991 37
Consolidated Statements of Capitalization, December 31, 1993
and 1992 38
Consolidated Statements of Common Stock Equity for the years
ended December 31, 1993, 1992 and 1991 39
Notes to Consolidated Financial Statements 40

Financial Statement Schedules:

V- Utility Plant for the years ended December 31, 1993, 1992
and 1991 67
VI- Accumulated Depreciation of Utility Plant for the years
ended December 31, 1993, 1992 and 1991 70

SCHEDULES OMITTED

The following schedules are omitted because of the absence of the conditions
under which they are required or the information is included in the
financial statements and schedules presented:
I, II, III, IV, VII, VIII, IX, X, XI, XII and XIII.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of Western Resources, Inc.:

We have audited the accompanying consolidated balance sheets and
statements of capitalization of Western Resources, Inc., and subsidiaries as
of December 31, 1993 and 1992, and the related consolidated statements of
income, cash flows, taxes and common stock equity for each of the three years
in the period ended December 31, 1993. 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 did not
audit the financial statements of Kansas Gas and Electric Company, a wholly-
owned subsidiary of Western Resources, Inc., as of and for the year ended
December 31, 1992, which statements reflect assets and revenues of 61 percent
and 27 percent, respectively, of the consolidated totals for 1992. Those
statements were audited by other auditors whose report has been furnished to
us and our opinion, insofar as it relates to the amounts included for that
entity, is based solely on the report of other auditors.

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

In our opinion, based on our audit and the report of other auditors, the
financial statements referred to above present fairly, in all material
respects, the financial position of Western Resources, Inc., and subsidiaries
as of December 31, 1993 and 1992, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
1993, in conformity with generally accepted accounting principles.

As explained in Note 1 to the consolidated financial statements, effective
January 1, 1991, the Company changed to a preferred method of accounting for
revenue recognition. As explained in Note 12 to the consolidated financial
statements, effective January 1, 1992, the Company changed its method of
accounting for income taxes. As explained in Note 6 to the consolidated
financial statements, effective January 1, 1993, the Company changed its
method of accounting for postretirement benefits.

Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedules
listed in the table of contents on page 32 are the responsibility of the
Company's management and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not a part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion and the opinion of other auditors, fairly state in all material
respects the financial data required to be set forth therein in relation to
the basic financial statements taken as a whole.

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

WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

December 31,
1993 1992
(Dollars in Thousands)

ASSETS
UTILITY PLANT (Notes 1 and 11):
Electric plant in service . . . . . . . . . . . . . . . . $5,110,617 $5,008,654
Natural gas plant in service. . . . . . . . . . . . . . . 1,111,866 1,024,369
6,222,483 6,033,023
Less - Accumulated depreciation . . . . . . . . . . . . . 1,821,710 1,691,623
4,400,773 4,341,400
Construction work in progress . . . . . . . . . . . . . . 80,192 68,041
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 29,271 33,312
Net utility plant. . . . . . . . . . . . . . . . . . . 4,510,236 4,442,753

OTHER PROPERTY AND INVESTMENTS:
Net non-utility investments . . . . . . . . . . . . . . . 61,497 47,680
Decommissioning trust (Note 4). . . . . . . . . . . . . . 13,204 9,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 10,658 13,855
85,359 70,807
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 1,217 875
Accounts receivable and unbilled revenues (net) (Note 1). 238,137 222,601
Fossil fuel, at average cost. . . . . . . . . . . . . . . 30,934 49,007
Gas stored underground, at average cost . . . . . . . . . 51,788 14,644
Materials and supplies, at average cost . . . . . . . . . 55,156 59,357
Prepayments and other current assets. . . . . . . . . . . 34,128 17,574
411,360 364,058
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 12). . . . . . . . . . 135,991 150,636
Deferred coal contract settlement costs (Note 5). . . . . 21,247 24,520
Phase-in revenues (Note 5). . . . . . . . . . . . . . . . 78,950 96,495
Corporate-owned life insurance (net) (Note 1) . . . . . . 4,743 146,713
Other deferred plant costs. . . . . . . . . . . . . . . . 32,008 32,212
Other (Note 5). . . . . . . . . . . . . . . . . . . . . . 132,154 110,712
405,093 561,288

TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $5,412,048 $5,438,906

CAPITALIZATION AND LIABILITIES

CAPITALIZATION (see statement). . . . . . . . . . . . . . . $3,121,021 $3,350,684

CURRENT LIABILITIES:
Short-term debt (Note 9). . . . . . . . . . . . . . . . . 440,895 222,225
Long-term debt due within one year (Note 8) . . . . . . . 3,204 1,961
Preference stock redeemable within one year (Note 14) . . - 1,300
Accounts payable. . . . . . . . . . . . . . . . . . . . . 172,338 215,507
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 46,076 38,591
Accrued interest and dividends. . . . . . . . . . . . . . 65,825 71,877
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 65,492 48,045
793,830 599,506
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 12) . . . . . . . . . . . . . 968,637 990,155
Deferred investment tax credits (Note 12) . . . . . . . . 150,289 149,946
Deferred gain from sale-leaseback (Note 10) . . . . . . . 261,981 271,621
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 116,290 76,994
1,497,197 1,488,716
COMMITMENTS AND CONTINGENCIES (Notes 4 and 15)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $5,412,048 $5,438,906

The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands,
except Per Share Amounts)

OPERATING REVENUES (Notes 1 and 5):
Electric. . . . . . . . . . . . . . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839
Natural gas . . . . . . . . . . . . . . . . . . . . . 804,822 673,363 690,339
Total operating revenues. . . . . . . . . . . . . . 1,909,359 1,556,248 1,162,178

OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 237,053 190,653 146,256
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 13,275 10,126 -
Power purchased . . . . . . . . . . . . . . . . . . . 16,396 14,819 5,335
Natural gas purchases . . . . . . . . . . . . . . . . 500,189 403,326 439,323
Other operations. . . . . . . . . . . . . . . . . . . 349,160 296,642 193,319
Maintenance . . . . . . . . . . . . . . . . . . . . . 117,843 101,611 60,515
Depreciation and amortization . . . . . . . . . . . . 164,364 144,013 85,735
Amortization of phase-in revenues . . . . . . . . . . 17,545 13,158 -
Taxes (see statement):
Federal income. . . . . . . . . . . . . . . . . . . 62,420 34,905 24,516
State income. . . . . . . . . . . . . . . . . . . . 15,558 7,095 6,066
General . . . . . . . . . . . . . . . . . . . . . . 123,493 100,731 71,492
Total operating expenses. . . . . . . . . . . . . 1,617,296 1,317,079 1,032,557

OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 292,063 239,169 129,621

OTHER INCOME AND DEDUCTIONS (net of taxes). . . . . . . 25,482 24,186 3,351

INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 317,545 263,355 132,972

INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 123,551 117,464 51,267
Other . . . . . . . . . . . . . . . . . . . . . . . . 19,255 20,009 10,490
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . . . . . . (2,631) (2,002) (1,070)
Total interest charges. . . . . . . . . . . . . . 140,175 135,471 60,687

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE. . 177,370 127,884 72,285

Cumulative Effect to January 1, 1991, of Change in
Revenue Recognition (net of taxes) (Note 1) . . . . . - - 17,360

NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 177,370 127,884 89,645

PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 13,506 12,751 6,377

EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . $ 163,864 $ 115,133 $ 83,268

AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 59,294,091 52,271,932 34,566,170

EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE . . . . $ 2.76 $ 2.20 $ 1.91

Cumulative Effect to January 1, 1991, of Change in
Revenue Recognition Per Share . . . . . . . . . . . . - - .50

EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING . . . . . $ 2.76 $ 2.20 $ 2.41

DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 1.94 $ 1.90 $ 2.04(2)

(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
(2) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.

The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 177,370 $ 127,884 $ 89,645
Depreciation and amortization . . . . . . . . . . . . . . 164,364 144,013 85,735
Other amortization (including nuclear fuel) . . . . . . . 11,254 8,930 -
Deferred taxes and investment tax credits (net) . . . . . 27,686 26,900 9,319
Amortization of phase-in revenues . . . . . . . . . . . . 17,545 13,158 -
Corporate-owned life insurance. . . . . . . . . . . . . . (21,650) (14,704) -
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (7,231) -
Changes in other working capital items:
Accounts receivable and unbilled revenues (net)(Note 1) (15,536) (12,227) (72,879)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . 18,073 14,990 (522)
Gas stored underground. . . . . . . . . . . . . . . . . (37,144) 4,522 (2,340)
Accounts payable. . . . . . . . . . . . . . . . . . . . (43,169) (10,194) (3,125)
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 7,485 (52,185) (14,130)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (3,165) (19,433) 11,661
Changes in other assets and liabilities . . . . . . . . . (18,569) 21,508 31,992
Net cash flows from operating activities. . . . . . . 274,904 245,931 135,356

CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 237,631 202,493 125,675
Merger with KG&E. . . . . . . . . . . . . . . . . . . . . - 473,752 -
Utility investment. . . . . . . . . . . . . . . . . . . . 2,500 - -
Non-utility investments (net) . . . . . . . . . . . . . . 14,271 29,099 18,125
Corporate-owned life insurance policies . . . . . . . . . 27,268 20,233 -
Death proceeds of corporate-owned life insurance
policies. . . . . . . . . . . . . . . . . . . . . . . . (10,160) (6,789) -
Cash flows used in investing activities . . . . . . . . 271,510 718,788 143,800

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 218,670 42,825 20,300
Bank term loan issued for Merger with KG&E. . . . . . . . - 480,000 -
Bank term loan retired. . . . . . . . . . . . . . . . . . (230,000) (250,000) -
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . 223,500 485,000 -
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (366,466) (236,966) (30,233)
Revolving credit agreements (net) . . . . . . . . . . . . (35,000) - -
Other long-term debt (net). . . . . . . . . . . . . . . . 7,043 14,498 -
Common stock issued (net) . . . . . . . . . . . . . . . . 125,991 - -
Preference stock issued (net) . . . . . . . . . . . . . . - 50,000 98,870
Preference stock redeemed . . . . . . . . . . . . . . . . (2,734) (2,600) (1,300)
Bank term loan issuance expenses. . . . . . . . . . . . . - (10,753) -
Borrowings against life insurance policies (net). . . . . 183,260 (5,649) -
Dividends on preferred, preference and common stock . . . (127,316) (99,440) (76,891)
Net cash flows from (used in) financing activities. . . (3,052) 466,915 10,746

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 342 (5,942) 2,302
CASH AND CASH EQUIVALENTS:
BEGINNING OF THE PERIOD . . . . . . . . . . . . . . . . . 875 6,817 4,515
END OF THE PERIOD . . . . . . . . . . . . . . . . . . . . $ 1,217 $ 875 $ 6,817
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized). . . . . . . . . . . . . . . . . . . . . . $ 171,734 $ 128,505 $ 58,462
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 49,108 24,966 40,062
COMPONENTS OF MERGER WITH KG&E:
Assets acquired . . . . . . . . . . . . . . . . . . . . . $3,142,455
Liabilities assumed . . . . . . . . . . . . . . . . . . . (2,076,821)
Common stock issued . . . . . . . . . . . . . . . . . . . (589,920)
Cash paid . . . . . . . . . . . . . . . . . . . . . . . . 475,714
Less cash acquired. . . . . . . . . . . . . . . . . . . . (1,962)
Net cash paid . . . . . . . . . . . . . . . . . . . . . . $ 473,752

(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES

Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)

FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 41,200 $ 16,687 $ 18,479
Deferred taxes arising from:
Depreciation and other property related items . . . . . 25,552 25,163 9,662
Energy and purchased gas adjustment clauses . . . . . . (8,192) (4,180) (15,535)
Unbilled revenues . . . . . . . . . . . . . . . . . . . - 2,458 17,249
Natural gas line survey and replacement program . . . . 355 (1,106) 1,015
Other . . . . . . . . . . . . . . . . . . . . . . . . . 6,166 4,121 (1,109)
Amortization of investment tax credits. . . . . . . . . . (1,982) (4,918) (4,238)
Total Federal income taxes. . . . . . . . . . . . . . 63,099 38,225 25,523
Federal income taxes applicable to non-operating items. . (679) (3,320) (1,007)
Total Federal income taxes charged to operations. . . 62,420 34,905 24,516

STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 9,869 2,522 4,033
Deferred (net). . . . . . . . . . . . . . . . . . . . . . 5,787 5,352 2,276
Total state income taxes. . . . . . . . . . . . . . . 15,656 7,874 6,309
State income taxes applicable to non-operating items. . . (98) (779) (243)
Total state income taxes charged to operations. . . . 15,558 7,095 6,066

GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 84,583 68,643 40,429
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 22,878 19,583 20,576
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 16,032 12,505 10,566
Total general taxes . . . . . . . . . . . . . . . . . 123,493 100,731 71,571
General taxes applicable to non-operating items . . . . . - - (79)
Total general taxes charged to operations . . . . . . 123,493 100,731 71,492

TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $201,471 $142,731 $102,074

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

Year Ended December 31, 1993 1992 1991

EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . 31.0% 27.0% 32.2%

EFFECT OF:
Additional depreciation . . . . . . . . . . . . . . . . . (2.9) (5.1) (2.7)
Accelerated amortization of certain deferred taxes. . . . 6.0 7.6 3.9
State income taxes. . . . . . . . . . . . . . . . . . . . (4.0) (2.6) (4.0)
Amortization of investment tax credits. . . . . . . . . . 2.7 3.4 3.2
Corporate-owned life insurance. . . . . . . . . . . . . . 3.0 2.9 -
Other differences . . . . . . . . . . . . . . . . . . . . (.8) .8 1.4

STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . . . . 35.0% 34.0% 34.0%

(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).

The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31,
1993 1992
(Dollars in Thousands)

COMMON STOCK EQUITY (see statement):
Common stock, par value $5 per share,
authorized 85,000,000 shares, outstanding
61,617,873 and 58,045,550 shares, respectively . . $ 308,089 $ 290,228
Paid-in capital. . . . . . . . . . . . . . . . . . . 667,738 559,636
Retained earnings. . . . . . . . . . . . . . . . . . 446,348 398,503
1,422,175 45% 1,248,367 37%

CUMULATIVE PREFERRED AND PREFERENCE STOCK (Note 14):
Not subject to mandatory redemption,
Par value $100 per share, authorized
600,000 shares, outstanding -
4 1/2% Series, 138,576 shares . . . . . . . . 13,858 13,858
4 1/4% Series, 60,000 shares. . . . . . . . . 6,000 6,000
5% Series, 50,000 shares. . . . . . . . . . . 5,000 5,000
24,858 24,858
Subject to mandatory redemption,
Without par value, $100 stated value,
authorized 4,000,000 shares,
outstanding -
8.70% Series, 0 and 157,000 shares. . . . . . - 15,700
7.58% Series, 500,000 shares. . . . . . . . . 50,000 50,000
8.50% Series, 1,000,000 shares. . . . . . . . 100,000 100,000
Less: Preference stock reacquired,
135,000 shares . . . . . . . . . . . . . . - 12,967
Preference stock redeemable
within one year. . . . . . . . . . . . . . - 1,300
150,000 151,433
174,858 6% 176,291 5%

LONG-TERM DEBT (Note 8)
First mortgage bonds . . . . . . . . . . . . . . . . 842,466 984,932
Pollution control bonds. . . . . . . . . . . . . . . 508,440 508,940
Other pollution control obligations. . . . . . . . . 13,980 14,205
Bank term loan . . . . . . . . . . . . . . . . . . . - 230,000
Revolving credit agreements. . . . . . . . . . . . . 115,000 150,000
Other long-term agreement. . . . . . . . . . . . . . 53,913 46,640
Less:
Unamortized premium and discount (net) . . . . . . 6,607 6,730
Long-term debt due within one year . . . . . . . . 3,204 1,961
1,523,988 49% 1,926,026 58%
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . $3,121,021 100% $3,350,684 100%

The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY

Common Paid-in Retained
Stock Capital Earnings
(Dollars in Thousands)

BALANCE DECEMBER 31, 1990, 34,566,170 shares. . . . . $172,831 $ 88,222 $369,772

Net income. . . . . . . . . . . . . . . . . . . . . . 89,645

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (6,377)
Common stock, $2.04(1) per share. . . . . . . . . . (70,514)

Expenses on preference stock. . . . . . . . . . . . . (1,123) (7)

BALANCE DECEMBER 31, 1991, 34,566,170 shares. . . . . 172,831 87,099 382,519

Net income. . . . . . . . . . . . . . . . . . . . . . 127,884

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (12,751)
Common stock, $1.90 per share . . . . . . . . . . . (99,135)

Expenses on preference stock. . . . . . . . . . . . . 14 (14)

Issuance of 23,479,380 shares of common stock
in the merger with KG&E . . . . . . . . . . . . . . 117,397 472,523

BALANCE DECEMBER 31, 1992, 58,045,550 shares. . . . . 290,228 559,636 398,503

Net income. . . . . . . . . . . . . . . . . . . . . . 177,370

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,506)
Common stock, $1.94 per share . . . . . . . . . . . (116,019)

Expenses on common and preference stock . . . . . . . (3,453)

Issuance of 3,572,323 shares of common stock. . . . . 17,861 111,555

BALANCE DECEMBER 31, 1993, 61,617,873 shares. . . . . $308,089 $667,738 $446,348

(1) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.

The Notes to Consolidated Financial Statements are an integral part of this statement.

WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: The consolidated financial statements of Western Resources, Inc.
(the Company, Western Resources), include the accounts of its wholly-owned
subsidiaries, Astra Resources, Inc., Kansas Gas and Electric Company (KG&E)
since March 31, 1992 (see Note 3), and KPL Funding Corporation (KFC). 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. All significant intercompany transactions have been
eliminated. The operations of Astra Resources, Inc., and KFC are not material
to the Company's results of operations. 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 certain state regulatory commissions
and the Federal Energy Regulatory Commission (FERC). The Company is doing
business as KPL, Gas Service, and, through its wholly-owned subsidiary, KG&E.

Utility Plant: Utility plant 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
4.10% in 1993, 5.99% in 1992, and 6.25% in 1991. The cost of additions to
utility plant and replacement units of property is capitalized. Maintenance
costs and replacement of minor items of property are charged to expense as
incurred. When units of depreciable property are retired, they are removed
from the plant accounts and the original cost plus removal charges less
salvage are charged to accumulated depreciation.

Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 3.02% during 1993, 3.03% during 1992, and 3.34%
during 1991 of the average original cost of depreciable property.

Cash and Cash Equivalents: For purposes of the Consolidated 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 12).

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

Revenues: Effective January 1, 1991, the Company changed its method of
accounting for recognizing electric and natural gas revenues to provide for
the accrual of estimated unbilled revenues. The accounting change provides a
better matching of revenues with costs of services provided to customers and
also serves to conform the Company's accounting treatment of unbilled revenues
with the tax treatment of such 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. Meters are read
and services are billed on a cycle basis and, prior to the accounting change,
revenues were recognized in the accounting period during which services were
billed.

The after-tax effect of the change in accounting method for the year ended
December 31, 1991, was an increase in net income of $15.9 million or $0.46 per
share. This increase was a combination of an increase of $17.3 million or
$0.50 per share, attributable to the cumulative effect of the accounting
change prior to January 1, 1991, and a decrease of $1.4 million or $0.04 per
share in the 1991 income before cumulative effect of a change in accounting
principle. Unbilled revenues of $99 and $86 million are recorded as a
component of accounts receivable on the consolidated balance sheets as of
December 31, 1993 and 1992, respectively. Certain amounts of unbilled
revenues have been sold (see Note 8).

The Company had reserves for doubtful accounts receivable of $4.3 and $3.3
million at December 31, 1993 and 1992, respectively.

Fuel Costs: The cost of nuclear fuel in process of refinement,conversion,
enrichment, and fabrication is recorded as an asset at original cost and is
amortized to expense based upon the quantity of heat produced for the
generation of electricity. The accumulated amortization of nuclear fuel in
the reactor at December 31, 1993 and 1992, was $17.4 million and $26.0
million, respectively.

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

1993 1992
Cash surrender value of contracts. . . $ 326.3 $ 256.3
Prepaid COLI . . . . . . . . . . . . . 11.9 7.0
Borrowings against contracts . . . . . (321.5) (109.6)
COLI (net). . . . . . . . . . $ 16.7 $ 153.7

The decrease in COLI (net) is a result of increased borrowings against the
accumulated cash surrender value of the COLI policies. The COLI borrowings
will be repaid with proceeds from death benefits. Management expects to
realize increases in the cash surrender value of contracts resulting from
premiums and investment earnings on a tax free basis upon receipt of proceeds
from death benefits under the contracts. Interest expense included in other
income and deductions, net of taxes, related to KG&E's COLI for 1993 and the
nine months ended December 31, 1992, was $11.9 and $5.3 million, respectively.

As approved by the Kansas Corporation Commission (KCC) and Missouri Public
Service Commission (MPSC), the Company is using a portion of the net income
stream generated by COLI policies purchased in 1993 and 1992 by the Company
(see Note 6) to offset Statement of Financial Accounting Standards No. 106
(SFAS 106) expenses.

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

2. SALE OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES

On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties." With the sales the Company is no longer operating
as a utility in the State of Missouri.

The portion of the Missouri Properties purchased by Southern Union was
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The final sale price will be calculated
as of January 31, 1994, within 120 days of closing. Any difference between the
estimated and final sale price will be adjusted through a payment to or from
the Company.

United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri, for $665,000 in cash.

The operating revenues and operating income (unaudited) related to the
Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively, of the Company's
total for 1993, and $299 million and$11 million representing approximately 19
percent and five percent, respectively, of the Company's total for 1992. Net
utility plant (unaudited) for the Missouri Properties, at December 31, 1993,
approximated $296 million and $272 million at December 31, 1992. This
represents approximately seven percent at December 31, 1993, and six percent
at December 31, 1992, of the total Company net utility plant. Separate
audited financial information was not kept by the Company for the Missouri
Properties. This unaudited financial information is based on assumptions and
allocations of expenses of the Company as a whole.

3. ACQUISITION AND MERGER

On March 31, 1992, the Company, through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company for $454 million in cash and 23,479,380
shares of common stock (the Merger). The Company also paid $20 million in
costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric
Company merged and adopted the name of Kansas Gas and Electric Company (KG&E).
The Merger was accounted for as a purchase. For income tax purposes the tax
basis of the KG&E assets was not changed by the Merger.

As the Company acquired 100 percent of the common and preferred stock of
KG&E, the Company recorded an acquisition premium of $490 million on the
consolidated balance sheet for the difference in purchase price and book
value. This acquisition premium and related income tax requirement of $294
million under SFAS 109 have been classified as plant acquisition adjustment in
electric plant in service on the consolidated balance sheets. The total cost
of the acquisition was $1.066 billion. Under the provisions of orders of the
KCC and the MPSC the acquisition premium is recorded as an acquisition
adjustment and not allocated to the other assets and liabilities of KG&E.

In the November 1991 KCC order approving the Merger, a mechanism was
approved to share equally between the shareholders and ratepayers the cost
savings generated by the Merger in excess of the revenue requirement needed to
allow recovery of the amortization of a portion of the acquisition adjustment,
including income tax, calculated on the basis of a purchase price of KG&E's
common stock at $29.50 per share. The order provides an amortization period
for the acquisition adjustment of 40 years commencing in August 1995, at which
time the full amount of cost savings is expected to have been implemented.
Merger savings will be measured by application of an inflation index to
certain pre-merger operating and maintenance costs at the time of the next
Kansas rate case. While the Company has achieved savings from the Merger,
there is no assurance that the savings achieved will be sufficient to, or the
cost savings sharing mechanism will operate as to fully offset the
amortization of the acquisition adjustment. The order further provides a
moratorium on increases, with certain exceptions, in the Company's Kansas
electric and natural gas 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. The first refund was made in April 1992 and amounted to $8.5 million.
A refund of the same amount was made in December 1993 and an additional refund
of $15 million will be made in September 1994.

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

As the Merger did not occur until March 31, 1992, the twelve months ended
December 31, 1992, results of operations for the Company reported in its
statements of income, cash flows, and common stock equity reflect KG&E's
results of operations for only the nine months ended December 31, 1992. The
pro forma combined revenues, operating income, net income, and earnings per
common share of the Company presented below give effect to the Merger as if it
had occurred at January 1, 1991. This pro forma information is not
necessarily indicative of the results of operations that would have occurred
had the Merger been consummated for the period for which it is being given
effect nor is it necessarily indicative of future operating results.

Year Ended December 31, 1992 1991
(Dollars in Thousands, except per share amounts)

Revenues. . . . . . . . . . . . $1,684,885 $1,748,844
Operating Income. . . . . . . . 268,772 279,458
Net Income. . . . . . . . . . . 131,524 110,290(1)
Earnings Per Common . . . . . . $ 2.03 $ 1.72(1)

(1) Reflects information before the cumulative effect of the January 1,
1991 change in accounting method of recognizing revenues.

4. COMMITMENTS AND CONTINGENCIES

As part of its ongoing operations and construction program, the Company
has commitments under purchase orders and contracts which have an unexpended
balance of approximately $86 million at December 31, 1993. Approximately $36
million is attributable to modifications to upgrade the turbines at Jeffrey
Energy Center to be completed by December 31, 1998. Plans for future
construction of utility plant are discussed in the "Management's Discussion
and Analysis" section.

Environmental: The Company has been associated with 28 (20 in Kansas and
8 in Missouri) former manufactured gas sites which may contain coal tar and
other potentially harmful materials. These sites were operated decades ago by
other companies, and were acquired by the Company after they had ceased
operation. The Environmental Protection Agency (EPA) has performed
preliminary assessments of eleven of these sites (EPA sites), six of which are
under site investigation. The Company has not received any indication from
the EPA that further action will be taken at the EPA sites, nor does the
Company have reason to believe there will be any fines or penalties assessed
related to these sites. The Company and the Kansas Department of Health and
Environment (KDHE) entered into a consent agreement to conduct separate
preliminary assessments of the 20 former manufactured gas sites located in
Kansas. The preliminary assessments of these 20 sites have been completed at
a total cost of approximately $500,000. The Company plans to initiate site
investigation and risk assessments at the two highest priority sites in 1994
at a total cost of approximately $500,000. Until such time that risk
assessments are completed at these or the remaining sites, it will be
impossible to predict the cost of remediation. However, the Company is aware
of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and
Iowa) which have incurred remediation costs for such sites ranging between
$500,000 and $10 million, depending on the site. The Company is also aware
that the KCC has permitted another Kansas utility to recover a portion of the
remediation costs through rates. To the extent that such remediation costs
are not recovered through rates, the costs could be material to the Company's
financial position or results of operations depending on the degree of
remediation and number of years over which the remediation must be completed.

The Company has been identified as one of numerous potentially responsible
parties in four hazardous waste sites listed by the EPA as Superfund sites.
One site is a groundwater contamination site in Wichita, Kansas, and one is an
oil soil contamination site in Springfield, Missouri. The other two sites are
solid waste land fills located in Edwardsville and Hutchinson, Kansas. The
Company's obligation at these sites appears to be limited, and it is the
opinion of the Company's management that the resolution of these matters will
not have a material impact on the Company's financial position or results of
operations.

As part of the sale of the Company's Missouri Properties to Southern
Union, Southern Union assumed responsibility under an agreement for any
environmental matters now pending or that may arise after closing. For any
environmental matters now pending or discovered within two years of the date
of the agreement, and after pursuing several other potential recovery options,
the Company may be liable for up to a maximum of $7.5 million under a sharing
arrangement with Southern Union provided for in the agreement.

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 $3.5
million for 1993 and $1.6 million for 1992.

Decommissioning: The Company's share of Wolf Creek decommissioning costs,
currently authorized in rates, was estimated to be approximately $97 million
in 1988 dollars. Decommissioning costs are being charged to operating
expenses. Amounts so expensed are deposited in an external trust fund and will
be used solely for the physical decommissioning of the plant. Electric rates
charged to customers provide for recovery of these decommissioning costs over
the estimated life of Wolf Creek. At December 31, 1993, and December 31,
1992, $13.2 and $9.3 million, respectively, were on deposit in the
decommissioning fund. On September 1, 1993, WCNOC filed an application with
the KCC for an order approving a 1993 Wolf Creek Decommissioning Cost Study
which estimates the Company's share of Wolf Creek decommissioning costs at
approximately $174 million in 1993 dollars. If approved by the KCC,
management expects substantially all such cost increases to be recovered
through the ratemaking process.

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

Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.4 billion for a single
nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum
available private insurance of $200 million and the balance is provided by an
assessment plan mandated by the NRC. Under this plan, the Owners are jointly
and severally subject to a retrospective assessment of up to $79.3 million
($37.3 million, Company's share) in the event there is a nuclear incident
involving any of the nation's licensed reactors. This assessment is subject
to an inflation adjustment based on the Consumer Price Index. There is a
limitation of $10 million ($4.7 million, Company's share) in retrospective
assessments per incident per year.

The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totalling
approximately $2.8 billion ($1.3 billion, Company's share). This insurance is
provided by a combination of "nuclear insurance pools" ($1.3 billion) and
Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The remaining proceeds from the $2.8 billion insurance
coverage ($1.3 billion, Company's share), if any, can be used for property
damage up to $1.1 billion (Company's share) and premature decommissioning
costs up to $117.5 million (Company's share) in excess of funds previously
collected for decommissioning (as discussed under "Decommissioning"), with the
remaining $47 million (Company's share) available for either property damage
or premature decommissioning costs.

The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves, and other NEIL resources, the Company may be subject to
retrospective assessments of approximately $9 million per year.

There can be no assurance that all potential losses or liabilities will be
insurable or that the amount of insurance will be sufficient to cover them.
Any substantial losses not covered by insurance, to the extent not recoverable
through rates, could have a material adverse effect on the Company's financial
condition 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 nitrous oxide emissions effective in
1995 and 2000 and a probable reduction in toxic emissions. To meet the
monitoring and reporting requirements under the acid rain program, the Company
is installing continuous monitoring and reporting equipment at a total cost of
approximately $10 million. At December 31, 1993, the Company had completed
approximately $4 million of these capital expenditures with the remaining
$6 million of capital expenditures to be completed in 1994 and 1995. The
Company does not expect additional equipment to reduce sulfur emissions to be
necessary under Phase II. The Company currently has no Phase I affected
units.

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

Federal Income Taxes: During 1991, the Internal Revenue Service (IRS)
completed an examination of KG&E's federal income tax returns for the years
1984 through 1988. In April 1992, KG&E received the examination report and
upon review filed a written protest in August 1992. In October 1993, KG&E
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, KG&E 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, 1993, WCNOC's nuclear fuel commitments (Company's share) were
approximately $18.0 million for uranium concentrates expiring at various times
through 1997, $123.6 million for enrichment expiring at various times through
2014, and $45.5 million for fabrication through 2012. At December 31, 1993,
the Company's coal and natural gas contract commitments in 1993 dollars under
the remaining term of the contracts were $2.8 billion and $20.4 million,
respectively. The largest coal contract was renegotiated early in 1993 and
expires in 2020, with the remaining coal contracts expiring at various times
through 2013. The majority of natural gas contracts continue through 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.

5. RATE MATTERS AND REGULATION

The Company, under rate orders from certain state regulatory commissions
and the FERC, recovers increases in fuel and natural gas costs through fuel
adjustment clauses for wholesale and certain retail electric customers and
various purchased gas adjustment clauses (PGA) for natural gas customers.
Certain state regulatory commissions require the annual difference between
actual gas cost incurred and cost recovered through the application of the PGA
be deferred and amortized through rates in subsequent periods.

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 Kansas retail electric customers of both the Company and KG&E
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. Any increase
or decrease in fuel costs from the projected average will be absorbed by the
Company.

MPSC Rate Proceedings: On October 5, 1993, the MPSC approved an agreement
among the Company, the MPSC staff, and intervenors to increase natural gas
rates $9.75 million annually, effective October 15, 1993. Also on October 15,
1993, the Company discontinued the deferral of service line replacement
program costs deferred since July 1, 1991, and began amortizing the balance to
expense over twenty years. At December 31, 1993, approximately $8.3 million
of these deferrals have been included in other deferred charges on the
consolidated balance sheet.

On January 22, 1992, the MPSC issued an order authorizing the Company to
increase natural gas rates $7.3 million annually.

KCC Rate Proceedings: On January 24, 1992, the KCC issued an order
allowing the Company to continue the deferral of service line replacement
program costs incurred since January 1, 1992, including depreciation, property
taxes, and carrying costs for recovery in the next general rate case. At
December 31, 1993, approximately $2.9 million of these deferrals have been
included in other deferred charges on the consolidated balance sheet.

On December 30, 1991, the KCC approved a permanent natural gas rate
increase of $39 million annually and the Company discontinued the deferral of
accelerated line survey costs on January 1, 1992. Approximately $8.3 million
of deferred costs remain in other deferred charges on the consolidated balance
sheet at December 31, 1993, with the balance being included in rates and
amortized to expense during a 43-month period, commencing January 1, 1992.

Gas Transportation Charges: On September 12, 1991, the KCC authorized the
Company to begin recovering, through the PGA, deferred supplier gas
transportation costs of $9.9 million incurred through December 31, 1990, based
on a three-year amortization schedule. On December 30, 1991, the KCC
authorized the Company to recover deferred transportation costs of
approximately $2.8 million incurred subsequent to December 31, 1990, through
the PGA over a 32-month period. At December 31, 1993, approximately $4.8
million of these deferrals remain in other deferred charges on the
consolidated balance sheet.

Tight Sands: In December 1991, the KCC, MPSC, and Oklahoma Corporation
Commission (OCC) approved agreements authorizing the Company to refund to
customers approximately $40 million of the proceeds of the Tight Sands
antitrust litigation settlement to be collected on behalf of Western
Resources' natural gas customers. To secure the refund of settlement
proceeds, the Commissions authorized the establishment of an independently
administered trust to collect and maintain cash receipts received under Tight
Sands settlement agreements and provide for the refunds made. The trust has a
term of ten years.

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

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

In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit
with AMAX Coal Company and recorded the payment as a deferred charge on the
consolidated balance sheet. 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).

FERC Order No. 528: In 1990, the FERC issued Order No. 528 which
authorized new methods for the allocation and recovery of take-or-pay
settlement costs by natural gas pipelines from their customers. Settlements
have been reached between the Company's two largest gas pipelines and their
customers in FERC proceedings related to take-or-pay issues. The settlements
address the allocation of take-or-pay settlement costs between the pipelines
and their customers. However, the amount which one of the pipelines will be
allowed to recover is yet to be determined. Litigation continues between the
Company and a former upstream pipeline supplier to one of the Company's
pipeline suppliers concerning the amount of such costs which may ultimately be
allocated to the Company's pipeline supplier. A portion of any costs
allocated to the Company's pipeline supplier will be charged to the Company.
Due to the uncertainty concerning the amount to be recovered by the Company's
current suppliers and of the outcome of the litigation between the Company and
its current pipeline's upstream supplier, the Company is unable to estimate
its future liability for take-or-pay settlement costs. However, the KCC and
MPSC have approved mechanisms which are expected to allow the Company to
recover these take-or-pay costs from its customers.

6. EMPLOYEE BENEFIT PLANS

Pension: The Company maintains noncontributory defined benefit pension
plans covering substantially all employees. 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 tables provide information on the components of pension
cost, funded status, and actuarial assumptions for the Company's pension
plans:

Year Ended December 31, 1993 1992 1991
(Dollars in Thousands)
Pension Cost:
Service cost................... $ 9,778 $ 9,847 $ 6,589
Interest cost on projected
benefit obligation........... 35,688 29,457 20,985
Return on plan assets.......... (64,113) (38,967) (59,161)
Deferred gain on plan assets... 29,190 7,705 38,015
Net amortization............... (669) (948) (131)
Net pension cost........... $ 9,874 $ 7,094 $ 6,297

December 31, 1993 1992 1991
(Dollars in Thousands)
Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $353,023 $316,100 $200,435
Non-vested . . . . . . . . . 26,983 19,331 13,935
Total. . . . . . . . . . . $380,006 $335,431 $214,370
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $490,339 $452,372 $324,780
Projected benefit obligation . . . 468,996 424,232 282,062
Plan assets in excess of
projected benefit obligation . . 21,343 28,140 42,718
Unrecognized transition asset. . . (2,756) (3,092) (1,253)
Unrecognized prior service costs . 64,217 55,886 27,216
Unrecognized net gain. . . . . . . (108,783) (106,486) (69,494)
Accrued pension costs. . . . . . . $(25,979) $(25,552) $ (813)

Year Ended December 31, 1993 1992 1991
Actuarial Assumptions:
Discount rate. . . . . . . . . . 7.0-7.75% 8.0-8.5% 8.0%
Annual salary increase rate. . . 5.0 % 6.0% 6.0%
Long-term rate of return . . . . 8.0-8.5 % 8.0-8.5% 8.0%

Retirement and Voluntary Separation Plans: In January 1992, the Board of
Directors approved early retirement plans and voluntary separation programs.
The voluntary early retirement plans were offered to all vested participants
in the Company's defined 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 as a lump sum payment. Of the 738 employees eligible for the
early retirement option, 531, representing ten percent of the combined
Company's work force, elected to retire on or before the May 1, 1992,
deadline. Seventy-one of those electing to retire were employees of KG&E
acquired March 31, 1992 (see Note 3). Another 67 employees, with 10 or more
years of service, elected to participate in the voluntary separation program.
Of those, 29 were employees of KG&E. In addition, 68 employees received
Merger-related severance benefits, including 61 employees of KG&E. The
actuarial cost, based on plan provisions for early retirement and voluntary
separation programs, and Merger-related severance benefits for the KG&E
employees, were considered in purchase accounting for the Merger. The
actuarial cost of the former Kansas Power and Light Company employees, of
approximately $11 million, was expensed in 1992.

Postretirement: The Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of
1993. This statement requires the accrual of postretirement benefits other
than pensions, primarily medical benefit costs, during the years an employee
provides service.

Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, the annual expense under SFAS 106 was approximately $26.5 million
in 1993 (as compared to approximately $9.6 million on a cash basis) and the
Company's total obligation was approximately $166.5 million at December 31,
1993. To mitigate the impact of SFAS 106 expense, the Company has implemented
programs to reduce health care costs. In addition, the Company has received
orders from the KCC and MPSC permitting the initial deferral of SFAS 106
expense. To mitigate the impact SFAS 106 expense will have on rate increases,
the Company will include in the future computation of cost of service the
actual SFAS 106 expense and an income stream generated from corporate-owned
life insurance (COLI). To the extent SFAS 106 expense exceeds income from the
COLI program, this excess will be deferred (as allowed by the FASB Emerging
Issues Task Force Issue No. 92-12) and offset by income generated through the
deferral period by the COLI program. The OCC is reviewing the Company's
application for similar treatment in Oklahoma. Should the OCC require
recognition of postretirement benefit costs for regulatory purposes under a
different method than that proposed
under the Company's application, the impact on earnings would not be material.
Should the income stream generated by the COLI program not be sufficient to
offset the deferred SFAS 106 expense, the KCC and MPSC orders allow recovery
of such deficit through the ratemaking process.

Prior to the adoption of SFAS 106 the Company's policy was to recognize
the cost of retiree health care and life insurance benefits as expense when
claims and premiums for life insurance policies were paid. The cost of
providing health care and life insurance benefits to 2,928 retirees was $8.1
million in 1992.

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

December 31, 1993
(Dollars in Thousands)
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . . $ 111,499
Active employees fully eligible . . . . . . . . 11,848
Active employees not fully eligible . . . . . . 43,109
Unrecognized prior service cost . . . . . . . . 18,195
Unrecognized transition obligation. . . . . . . (160,731)
Unrecognized net loss . . . . . . . . . . . . . (7,100)
Balance sheet liability . . . . . . . . . . . . . . $ 16,820

For measurement purposes, an annual health care cost growth rate of 13%
was assumed for 1994, decreasing to 6% by 2002 and thereafter. The
accumulated post retirement benefit obligation was calculated using a
weighted-average discount rate of 7.75%, a weighted-average compensation
increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%.
The health care cost trend rate has a significant effect on the projected
benefit obligation. Increasing the trend rate by 1% each year would increase
the present value of the accumulated projected benefit obligation by $11.1
million and the aggregate of the service and interest cost components by $1.5
million.

Postemployment: The FASB has issued Statement of Financial Accounting
Standards No. 112 (SFAS 112), which establishes accounting and reporting
standards for postemployment benefits. The new statement will require the
Company to recognize the liability to provide postemployment benefits when the
liability has been incurred. The Company adopted SFAS 112 effective January
1, 1994. To mitigate the impact adopting SFAS 112 will have on rate
increases, the Company will file applications with the KCC and OCC for orders
permitting the initial deferral of SFAS 112 transition costs and expenses and
its inclusion in the future computation of cost of service net of an income
stream generated from COLI. However, if the state regulatory commissions were
to recognize postemployment benefit costs under a different method, 1994
earnings could be impacted negatively. At December 31, 1993, the Company
estimates SFAS 112 liability to total approximately $11 million.

Savings: The Company maintains savings plans in which substantially all
employees participate. The Company matches employees' contributions up to
specified maximum limits. The funds of the plans are deposited with a trustee
and invested at each employee's option in one or more investment funds,
including a Company stock fund. The Company's contributions were $5.4, $5.4,
and $3.3 million for 1993, 1992, and 1991, respectively.

Missouri Property Sale: Effective January 31, 1994, the Company
transferred a portion of the assets and liabilities of the Company's pension
plan to a pension plan established by Southern Union. The amount of assets
transferred equal the projected benefit obligation for employees and retirees
associated with Southern Union's portion of the Missouri Properties plus an
additional $9 million.

7. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

Carrying Value Fair Value
December 31, 1993 1992 1993 1992
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . . $ 1,217 $ 875 $ 1,217 $ 875
Decommissioning trust. . . 13,204 9,272 13,929 9,500
Variable-rate debt . . . . 931,352 758,449 931,352 758,449
Fixed-rate debt. . . . . . 1,364,886 1,508,077 1,473,569 1,563,375
Redeemable preference
stock. . . . . . . . . . 150,000 152,733 160,780 161,733

8. LONG-TERM DEBT

The amount of first mortgage bonds authorized by the Western Resources
Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited.
The amount of first mortgage bonds authorized by the KG&E Mortgage and Deed of
Trust, 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 each Mortgage.

On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds,
6.20% Series due January 15, 2006.

On January 31, 1994, the Company redeemed the remaining $2,466,000
principal amount of Gas Service Company (GSC) 8 1/2% Series First Mortgage
Bonds due 1997. In addition, the Company took measures to have the GSC
Mortgage and Deed of Trust discharged.

Debt discount and expenses are being amortized over the remaining lives of
each issue. The Western Resources and KG&E improvement and maintenance fund
requirements for certain first mortgage bond series can be met by bonding
additional property. The sinking fund requirements for certain Western
Resources and KG&E pollution control series bonds can be met only through the
acquisition and retirement of outstanding bonds. Bonds maturing and
acquisition and retirement of bonds for sinking fund requirements for the five
years subsequent to December 31, 1993, are as follows:

Maturing Retiring
Year Bonds Bonds
(Dollars in Thousands)

1994. . . . . $ 2,466 $ 738
1995. . . . . - 753
1996. . . . . 16,000 770
1997. . . . . - 1,333
1998. . . . . - 1,550

Long-term debt outstanding at December 31, 1993 and 1992, was as follows:

1993 1992
(Dollars in Thousands)
Western Resources
First mortgage bond series:
9.35 % due 1998. . . . . . . . . . . . . $ - $ 75,000
7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000
7 5/8% due 1999. . . . . . . . . . . . . 19,000 19,000
8 3/4% due 2000. . . . . . . . . . . . . - 20,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000
8 5/8% due 2005. . . . . . . . . . . . . - 35,000
8 1/8% due 2007. . . . . . . . . . . . . 30,000 30,000
8 3/4% due 2008. . . . . . . . . . . . . - 35,000
8 5/8% due 2017. . . . . . . . . . . . . 50,000 50,000
8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000
7.65% due 2023. . . . . . . . . . . . . 100,000 -
624,000 689,000
Pollution control bond series:
5.90 % due 2007. . . . . . . . . . . . . 31,000 31,500
6 3/4% due 2009. . . . . . . . . . . . . 45,000 45,000
9 5/8% due 2013. . . . . . . . . . . . . - 58,500
6% due 2033. . . . . . . . . . . . . 58,500 -
134,500 135,000
KG&E
First mortgage bond series:
5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000
8 1/8% due 2001. . . . . . . . . . . . . - 35,000
7 3/8% due 2002. . . . . . . . . . . . . - 25,000
7.60% due 2003. . . . . . . . . . . . . 135,000 135,000
6 1/2% due 2005. . . . . . . . . . . . . 65,000 -
8 3/8% due 2006. . . . . . . . . . . . . - 25,000
8 1/2% due 2007. . . . . . . . . . . . . - 25,000
8 7/8% due 2008. . . . . . . . . . . . . - 30,000
216,000 291,000
Pollution control bond series:
6.80% due 2004. . . . . . . . . . . . . 14,500 14,500
5 7/8% due 2007. . . . . . . . . . . . . 21,940 21,940
6% due 2007. . . . . . . . . . . . . 10,000 10,000
7.0% due 2031. . . . . . . . . . . . . 327,500 327,500
373,940 373,940
GSC
First mortgage bond series:
8 1/2% due 1997. . . . . . . . . . . . . 2,466 4,932
2,466 4,932

Bank term loan . . . . . . . . . . . . . . - 230,000
Other pollution control obligations. . . . 13,980 14,205
Revolving credit agreement . . . . . . . . 115,000 150,000
Other long term agreement. . . . . . . . . 53,913 46,640
Less:
Unamortized debt discount. . . . . . . . 6,607 6,730
Long-term debt due within one year . . . 3,204 1,961
$1,523,988 $1,926,026

In January 1993, the Company renegotiated its $600 million bank term loan
and revolving credit facility used to finance the Merger into a $350 million
revolving credit facility, secured by KG&E common stock. The revolver has an
initial term of three years with options to renew for an additional two years
with the consent of the banks. The unused portion of the revolving credit
facility may be used to provide support for outstanding short-term debt. At
December 31, 1993, $115 million was outstanding under the facility.

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

9. SHORT-TERM DEBT

The Company's short-term financing requirements are satisfied, as needed,
through the sale of commercial paper, short-term bank loans and borrowings
under other unsecured lines of credit maintained with banks. Information
concerning these arrangements for the years ended December 31, 1993, 1992, and
1991, is set forth below:

Year Ended December 31, 1993 1992 1991
(Dollars in Thousands)
Lines of credit at year end. . . . $145,000 $250,000(1) $185,000(2)
Short-term debt out-
standing at year end . . . . . . 440,895 222,225 135,800
Weighted average interest rate
on debt outstanding at year
end (including fees) . . . . . . 3.67% 4.70% 5.07%
Maximum amount of short-
term debt outstanding during
the period. . . .. . . . . . . . $443,895 $263,900 $175,000
Monthly average short-term debt. . 347,278 179,577 125,968
Weighted daily average interest
rates during the year
(including fees) . . . . . . . . 3.44% 4.90% 6.69%

(1) Decreased to $155 million in January 1993.
(2) Increased to $200 million in January 1992.

In connection with the commitments, the Company has agreed to pay certain
fees to the banks. Available lines of credit and the unused portion of the
revolving credit facility are utilized to support the Company's outstanding
short-term debt.

10. LEASES

At December 31, 1993, the Company had leases covering various property and
equipment. Certain lease agreements meet the criteria, as set forth in
Statement of Financial Accounting Standards No. 13, for classification as
capital leases.

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

Capital Operating
Year Ending December 31, Leases Leases
(Dollars in Thousands)
1991 $ 1,217 $21,501
1992 2,426 52,701
1993 3,272 55,011
Future Commitments:
1994 $ 4,002 $47,729
1995 3,752 45,825
1996 3,627 44,176
1997 1,209 41,644
1998 - 41,019
Thereafter - 771,157
Total $12,590 $ 991,550
Less Interest 1,466
Net obligation $11,124

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

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

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

The gain of approximately $322 million realized at the date of the sale
has been deferred for financial reporting purposes, and is being amortized
over the initial lease term in proportion to the related lease expense.
KG&E's lease expense, net of amortization of the deferred gain and a one-time
payment, was approximately $22.5 million for the year ended December 31, 1993,
and $20.6 million for the nine months ended December 31, 1992.

11. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 1993
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50
Jeffrey 1 (b) Jul 1978 277,087 116,526 587 84
Jeffrey 2 (b) May 1980 274,018 106,301 566 84
Jeffrey 3 (b) May 1983 386,925 124,158 588 84
Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47

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

Amounts and capacity represent the Company's share. The Company's share
of operating expenses of the plants in service above, as well as such expenses
for a 50 percent undivided interest in La Cygne 2 (representing 335 MW
capacity) sold and leased back to the Company in 1987, are included in
operating expenses in the statements of income. The Company's share of other
transactions associated with the plants is included in the appropriate
classification in the Company's consolidated financial statements.

12. INCOME TAXES

The Company adopted the provisions of SFAS 109 in the first quarter of
1992. KG&E adopted the provisions of SFAS 96 in 1987 and SFAS 109 in 1992.
These statements require 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.

In accordance with various rate orders received from the KCC, the MPSC,
and the OCC, 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 impact on the Company's results of operations.

At December 31, 1993, KG&E has unused investment tax credits of
approximately $7.1 million available for carryforward which, if not utilized,
will expire in the years 2000 through 2002. In addition, the Company has
alternative minimum tax credits generated prior to April 1, 1992, which
carryforward without expiration, of $57.2 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, 1993.

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

December 31, 1993
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (647,202) $ (647,202)
Energy and purchased gas
adjustment clauses . . . . . . . 2,452 - 2,452
Phase-in revenues. . . . . . . . . - (35,573) (35,573)
Natural gas line survey and
replacement program. . . . . . . - (7,721) (7,721)
Deferred gain on sale-leaseback. . 116,186 - 116,186
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (14,980) (14,980)
Deferred compensation/pension
liability. . . . . . . . . . . . 11,301 - 11,301
Acquisition premium. . . . . . . . - (301,394) (301,394)
Deferred future income taxes . . . - (117,549) (117,549)
Other. . . . . . . . . . . . . . . - (14,039) (14,039)
Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $ (968,637)

December 31, 1992
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (607,303) $ (607,303)
Energy and purchased gas
adjustment clauses . . . . . . . - (7,717) (7,717)
Phase-in revenues. . . . . . . . . - (37,564) (37,564)
Natural gas line survey and
replacement program. . . . . . . - (7,473) (7,473)
Deferred gain on sale-leaseback. . 104,573 - 104,573
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (9,318) (9,318)
Deferred compensation/pension
liability. . . . . . . . . . . . 8,488 - 8,488
Acquisition premium. . . . . . . . - (314,241) (314,241)
Deferred future income taxes . . . - (158,102) (158,102)
Other. . . . . . . . . . . . . . . - (1,380) (1,380)
Total Deferred Income Taxes. . . . . $ 152,943 $(1,143,098) $ (990,155)

13. SEGMENTS OF BUSINESS

The Company is a public utility engaged in the generation, transmission,
distribution, and sale of electricity in Kansas and the transportation,
distribution, and sale of natural gas in Kansas, Missouri, and Oklahoma.

Year Ended December 31, 1993 1992(1) 1991
(Dollars in Thousands)
Operating revenues:
Electric. . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839
Natural gas . . . . . . . . . 804,822 673,363 690,339
1,909,359 1,556,248 1,162,178

Operating expenses excluding
income taxes:
Electric. . . . . . . . . . . 791,563 632,169 337,150
Natural gas . . . . . . . . . 747,755 642,910 664,825
1,539,318 1,275,079 1,001,975

Income taxes:
Electric. . . . . . . . . . . 73,425 41,184 32,239
Natural gas . . . . . . . . . 4,553 816 (1,657)
77,978 42,000 30,582

Operating income:
Electric. . . . . . . . . . . 239,549 209,532 102,450
Natural gas . . . . . . . . . 52,514 29,637 27,171
$ 292,063 $ 239,169 $ 129,621

Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,231,277 $4,390,117 $1,196,023
Natural gas . . . . . . . . . 1,040,513 918,729 840,692
Other corporate assets(2) . . 140,258 130,060 75,798
$5,412,048 $5,438,906 $2,112,513

Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 126,034 $ 105,842 $ 53,632
Natural gas . . . . . . . . . 38,330 38,171 32,103
$ 164,364 $ 144,013 $ 85,735

Maintenance:
Electric. . . . . . . . . . . $ 87,696 $ 73,104 $ 34,240
Natural gas . . . . . . . . . 30,147 28,507 26,275
$ 117,843 $ 101,611 $ 60,515

Capital expenditures:
Electric. . . . . . . . . . . $ 137,874 $ 95,465 $ 43,714
Nuclear fuel. . . . . . . . . 5,702 15,839 -
Natural gas . . . . . . . . . 94,055 91,189 81,961
$ 237,631 $ 202,493 $ 125,675

(1)Information reflects the merger with KG&E on March 31, 1992.
(2)Principally cash, temporary cash investments, non-utility assets, and
deferred charges.

The portion of the table above related to the Missouri Properties is as
follows (unaudited):

1993
(Dollars in Thousands)
Natural gas revenues. . . . . . . . . . $ 349,749
Operating expenses excluding
income taxes. . . . . . . . . 326,329
Income taxes. . . . . . . . . . . . . . 2,672
Operating income. . . . . . . . . . . . 20,748
Identifiable assets . . . . . . . . . . 398,464
Depreciation and amortization . . . . . 12,668
Maintenance . . . . . . . . . . . . . . 10,504
Capital expenditures. . . . . . . . . . 38,821

14. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK

The Company's Restated Articles of Incorporation, as amended, provides for
85,000,000 authorized shares of common stock. During 1993, the Company issued
3,572,323 shares of common stock and at December 31, 1993, 61,617,873 shares
were outstanding.

Not subject to mandatory redemption: The cumulative preferred stock is
redeemable in whole or in part on 30 to 60 days notice at the option of the
Company.

Subject to mandatory redemption: On October 1, 1993, the Company redeemed
the remaining 22,000 shares of the 8.70% Series preference stock.

The mandatory sinking fund provisions of the 8.50% Series preference stock
require the Company to redeem 50,000 shares annually beginning on July 1,
1997, at $100 per share. The Company may, at its option, redeem up to an
additional 50,000 shares on each July 1, at $100 per share. The 8.50% Series
also is redeemable in whole or in part, at the option of the Company, subject
to certain restrictions on refunding, at a redemption price of $107.37,
$106.80, and $106.23 per share beginning July 1, 1993, 1994, and 1995,
respectively.

The mandatory sinking fund provisions of the 7.58% Series preference stock
require the Company to redeem 25,000 shares annually beginning on April 1,
2002, and each April 1 through 2006 and the remaining shares on April 1, 2007,
all at $100 per share. The Company may, at its option, redeem up to an
additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series
also is redeemable in whole or in part, at the option of the Company, subject
to certain restrictions on refunding, at a redemption price of $106.82,
$106.06, and $105.31 per share beginning April 1, 1993, 1994, and 1995,
respectively.

15. LEGAL PROCEEDINGS

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

16. QUARTERLY RESULTS (UNAUDITED)

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

First Second Third Fourth
(Dollars in Thousands, except Per Share Amounts)
1993
Operating revenues. . . . . . . $579,581 $400,411 $419,018 $510,349
Operating income. . . . . . . . 85,950 60,282 81,225 64,606
Net income. . . . . . . . . . . 54,814 30,723 56,807 35,026
Earnings applicable to
common stock. . . . . . . . . 51,468 27,320 53,405 31,671
Earnings per share. . . . . . . $ 0.89 $ 0.47 $ 0.90 $ 0.51
Dividends per share . . . . . . $ 0.485 $ 0.485 $ 0.485 $ 0.485
Average common shares
outstanding . . . . . . . . . 58,046 58,046 59,441 61,603
Common stock price:
High. . . . . . . . . . . . . $ 35 3/4 $ 36 1/8 $ 37 1/4 $ 37
Low . . . . . . . . . . . . . $ 30 3/8 $ 32 3/4 $ 35 $ 32 3/4

1992(1)
Operating revenues. . . . . . . $373,620 $341,715 $380,745 $460,168
Operating income. . . . . . . . 42,684 45,830 77,010 73,645
Net income. . . . . . . . . . . 27,984 18,434 42,185 39,281
Earnings applicable to
common stock. . . . . . . . . 25,472 15,113 38,726 35,822
Earnings per share. . . . . . . $ 0.74 $ 0.26 $ 0.67 $ 0.62
Dividends per share . . . . . . $ 0.475 $ 0.475 $ 0.475 $ 0.475
Average common shares
outstanding . . . . . . . . . 34,566 58,046 58,046 58,046
Common stock price:
High. . . . . . . . . . . . . $ 29 1/2 $ 26 7/8 $ 30 1/2 $ 32 5/8
Low . . . . . . . . . . . . . $ 25 3/8 $ 25 1/4 $ 26 3/4 $ 28 1/2

(1) Information reflects the merger with KG&E on March 31, 1992.

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information relating to the Company's Directors required by Item 10 is
set forth in the Company's definitive proxy statement for its 1994 Annual
Meeting of Shareholders to be filed with the Commission. Such information is
incorporated herein by reference to the material appearing under the caption
Election of Directors in the proxy statement to be filed by the Company with
the Commission. See EXECUTIVE OFFICERS OF THE COMPANY on page 18 for the
information relating to the Company's Executive Officers as required by Item
10.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is set forth in the Company's
definitive proxy statement for its 1994 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the captions Information Concerning
the Board of Directors, Executive Compensation, Compensation Plans, and Human
Resources Committee Report in the proxy statement to be filed by the Company
with the Commission.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 12 is set forth in the Company's
definitive proxy statement for its 1994 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the caption Beneficial Ownership of
Voting Securities in the proxy statement to be filed by the Company with the
Commission.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 13 is set forth in the Company's
definitive proxy statement for its 1994 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the caption Transactions with
Management in the proxy statement to be filed by the Company with the
Commission.

PART IV

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

The following financial statements are included herein.

FINANCIAL STATEMENTS

Report of Independent Public Accountants
Consolidated Balance Sheets - December 31, 1993 and 1992
Consolidated Statements of Income - years ended December 31, 1993,
1992 and 1991
Consolidated Statements of Cash Flows - years ended December 31,
1993, 1992 and 1991
Consolidated Statements of Taxes - years ended December 31, 1993,
1992 and 1991
Consolidated Statements of Capitalization - December 31, 1993 and
1992
Consolidated Statements of Common Stock Equity - years ended
December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements

The following supplemental schedules are included herein.

SCHEDULES

Schedule V - Utility Plant - years ended December 31, 1993, 1992 and 1991
Schedule VI - Accumulated Depreciation of Utility Plant - years ended
December 31, 1993, 1992 and 1991

Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, II, III, IV, VII, VIII, IX, X, XI, XII, and XIII

REPORTS ON FORM 8-K

Form 8-K dated February 2, 1994

EXHIBIT INDEX

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

Description

3(a) -Restated Articles of Incorporation of the Company, as amended I
May 25, 1988. (filed as Exhibit 4 to Registration Statement
No. 33-23022)
3(b) -Certificate of Correction to Restated Articles of Incorporation. I
(filed as Exhibit 3(b) to the December 1991 Form 10-K)
3(c) -By-laws of the Company, as amended July 15, 1987. (filed as I
Exhibit 3(d) to the December 1987 Form 10-K)
3(d) -Certificate of Designation of Preference Stock, 8.50% Series,
without par value. (filed electronically)
3(e) -Certificate of Designation of Preference Stock, 7.58% Series,
without par value. (filed electronically)
4(a) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I
and Harris Trust and Savings Bank, Trustee. (filed as Exhibit
4(a) to Registration Statement No. 33-21739)
4(b) -First through Fifteenth Supplemental Indentures dated July 1, I
1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1,
1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1,
1954, September 1, 1961, April 1, 1969, September 1, 1970,
February 1, 1975, May 1, 1976 and April 1, 1977, respectively.
(filed as Exhibit 4(b) to Registration Statement No. 33-21739)
4(c) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
4(d) -Seventeenth Supplemental Indenture dated February 1, 1978. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(e) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(f) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(g) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(h) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(i) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)
4(j) -Twenty-Third Supplemental Indenture dated July 2, 1986. (filed I
as Exhibit 4(j) to Registration Statement No. 33-12054)
4(k) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. (filed I
as Exhibit 4(k) to Registration Statement No. 33-21739)
4(l) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(m) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
4(n) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(o) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(p) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)

Description

4(q) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(r) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Form S-3, Registration Statement
No. 33-50069)

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) -Agreement between the Company and AMAX Coal West Inc.
effective March 31, 1993. (filed electronically)
10(b) -Agreement between the Company and Williams Natural Gas Company
dated October 1, 1993. (filed electronically)
10(c) -Agreement between the Company and Williams Natural Gas Company
dated October 1, 1993. (filed electronically)
10(d) -Agreement between the Company and Williams Natural Gas Company
dated October 1, 1993. (filed electronically)
10(e) -Executive Salary Continuation Plan of The Kansas Power and Light I
Company, as revised, effective May 3, 1988. (filed as Exhibit
10(b) to the September 1988 Form 10-Q)
10(f) -Letter of Agreement between The Kansas Power and Light Company and I
John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit
10(w) to the December 1989 Form 10-K)
10(g) -Amended Agreement and Plan of Merger by and among The Kansas I
Power and Light Company, KCA Corporation, and Kansas Gas and
Electric Company, dated as of October 28, 1990, as amended by
Amendment No. 1 thereto, dated as of January 18, 1991. (filed
as Annex A to Registration Statement No. 33-38967)
10(h) -Deferred Compensation Plan
10(i) -Long-term Incentive Plan
10(j) -Short-term Incentive Plan
10(k) -Outside Directors' Deferred Compensation Plan
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I
to the Current Report on Form 8-K dated March 8, 1993)
21 -Subsidiaries of the Registrant. (filed as Exhibit 22 to the I
December 1992 Form 10-K)
23(a) -Consent of Independent Public Accountants, Arthur Andersen
& Co. (filed electronically)
23(b) -Consent of Independent Public Accountants, Deloitte & Touche
(filed electronically))
23(c) -Consent of K&A Energy Consultants, Inc. (filed as Exhibit 24(b) I
to the December 1988 Form 10-K)
99(a) -Kansas Gas and Electric Company's Annual Report on Form 10-K
for the year ended December 31, 1993 (filed electronically)
99(b) -Report of K&A Energy Consultants, Inc. (filed as Exhibit 28 to I
the December 1988 Form 10-K)

WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1993

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

Electric Plant:
Steam Production. . . . . . . . $1,367,730 $ 52,064 $ 7,406 $ (7,154) $1,405,234
Nuclear Production. . . . . . . 1,355,678 11,324 614 - 1,366,388
Internal Combustion
Production. . . . . . . . . . 34,273 1,374 445 - 35,202
Transmission. . . . . . . . . . 499,775 7,082 1,296 27 505,588
Distribution. . . . . . . . . . 809,617 43,216 4,859 (138) 847,836
General . . . . . . . . . . . . 111,666 15,211 2,658 13 124,232
Electric Plant Leased
to Others . . . . . . . . . . 6,984 - - - 6,984
Construction Work in Progress . 49,068 10,230 - - 59,298
Electric Plant Held for Future
Use . . . . . . . . . . . . . 25,290 5 129 7,109 32,275
Nuclear Fuel. . . . . . . . . . 59,305 6,764 19,381 - 46,688
Plant Acquisition Adjustment. . 796,265 1,347 21 (12,089) 785,502
5,115,651 148,617 36,809 (12,232) 5,215,227

Natural Gas Plant:
Production and Gathering. . . . 9,704 24 23 5 9,710
Underground Storage . . . . . . 5,951 9,135 - - 15,086
Transmission. . . . . . . . . . 97,480 6,258 967 (26) 102,745
Distribution. . . . . . . . . . 845,332 70,694 4,712 29 911,343
General . . . . . . . . . . . . 62,933 12,292 5,228 16 70,013
Gas Stored Underground. . . . . 2,969 - - - 2,969
Construction Work in Progress . 18,973 1,921 - - 20,894
1,043,342 100,324 10,930 24 1,132,760

Steam Heat Plant. . . . . . . . . 1,376 - - - 1,376
$6,160,369 $ 248,941 $ 47,739 $ (12,208) $6,349,363

WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1992

Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- Acquisition at End
Classification of Period at Cost ments fication of KG&E of Period
(Thousands of Dollars)

Electric Plant:
Steam Production. . . . . . . .$ 892,082 $ 10,603 $ 2,987 $ - $ 468,032 $1,367,730
Nuclear Production. . . . . . . - 3,505 6,660 - 1,358,833 1,355,678
Internal Combustion
Production. . . . . . . . . . 34,168 106 1 - - 34,273
Transmission. . . . . . . . . . 276,889 9,997 935 (74) 213,898 499,775
Distribution. . . . . . . . . . 416,027 38,636 4,343 74 359,223 809,617
General . . . . . . . . . . . . 46,075 5,578 976 (18) 61,007 111,666
Electric Plant Leased
to Others . . . . . . . . . . - - - - 6,984 6,984
Construction Work in Progress . 7,697 25,630 - (3) 15,744 49,068
Electric Plant Held for Future
Use . . . . . . . . . . . . . 9,832 - - - 15,458 25,290
Nuclear Fuel. . . . . . . . . . - 15,936 - (87) 43,456 59,305
Plant Acquisition Adjustment. . - - - 796,265 796,265
1,682,770 109,991 15,902 (108) 3,338,900 5,115,651

Natural Gas Plant:
Production and Gathering. . . . 9,711 18 12 (13) - 9,704
Underground Storage . . . . . . 5,632 319 - - - 5,951
Transmission. . . . . . . . . . 94,388 3,542 464 14 - 97,480
Distribution. . . . . . . . . . 687,148 70,913 5,120 92,391 (1) - 845,332
General . . . . . . . . . . . . 59,151 5,172 1,407 17 - 62,933
Gas Stored Underground. . . . . 2,969 - - - - 2,969
Construction Work in Progress . 9,417 9,556 - - - 18,973
868,416 89,520 7,003 92,409 - 1,043,342

Steam Heat Plant. . . . . . . . . 1,376 - - - - 1,376
$2,552,562 $199,511 $22,905 $92,301 $3,338,900 $6,160,369

(1) Includes $92,389,000 resulting from the adoption of Statement of Financial Accounting Standards
No. 109 relating to the GSC acquisition adjustment.

WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1991

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

Electric Plant:
Steam Production. . . . . . . . $ 886,296 $ 9,135 $ 3,348 $ (1) $ 892,082
Internal Combustion
Production. . . . . . . . . . 33,595 588 15 - 34,168
Transmission. . . . . . . . . . 272,772 5,185 656 (412) 276,889
Distribution. . . . . . . . . . 397,082 21,895 3,362 412 416,027
General . . . . . . . . . . . . 43,693 2,705 327 4 46,075
Construction Work in Progress . 4,721 2,976 - - 7,697
Electric Plant Held for Future
Use . . . . . . . . . . . . . 9,832 - - - 9,832
1,647,991 42,484 7,708 3 1,682,770

Natural Gas Plant:
Production and Gathering. . . . 9,847 80 216 - 9,711
Underground Storage . . . . . . 5,566 5 (61) - 5,632
Transmission. . . . . . . . . . 93,222 1,643 350 (127) 94,388
Distribution. . . . . . . . . . 618,856 69,725 8,862 7,429 687,148
General . . . . . . . . . . . . 46,455 15,223 2,792 265 59,151
Gas Stored Underground. . . . . 2,969 - - - 2,969
Construction Work in Progress . 15,481 (6,064) - - 9,417
792,396 80,612 12,159 7,567 868,416

Steam Heat Plant. . . . . . . . . 1,376 - - - 1,376
$2,441,763 $123,096 $19,867 $7,570 $2,552,562

WESTERN RESOURCES, INC.

Schedule VI - Accumulated Depreciation of Utility Plant

For the Year Ended December 31,

Additions
Balance at Charged to Acquisition Balance
Beginning Costs and Retire- Other of at End
Description of Period Expenses ments Charges(1) KG&E of Period
(Thousands of Dollars)

1993
Electric. . . . . . . . . $1,387,907 $134,658 $39,012 $ 1,951 $ - $1,485,504

Natural Gas . . . . . . . 328,333 35,702 11,788 - - 352,247

Steam Heat. . . . . . . . 1,376 - - - - 1,376

$1,717,616 $170,360 $50,800 $ 1,951 $ - $1,839,127

1992
Electric. . . . . . . . . $ 593,311 $112,631 $16,497 $ (162) $698,624 $1,387,907

Natural Gas . . . . . . . 231,431 32,918 6,315 70,299 (2) - 328,333

Steam Heat. . . . . . . . 1,376 - - - - 1,376

$ 826,118 $145,549 $22,812 $70,137 $698,624 $1,717,616

1991
Electric. . . . . . . . . $ 550,722 $ 53,384 $ 7,508 $(3,287) $ - $ 593,311

Natural Gas . . . . . . . 209,481 35,912 11,477 (2,485) - 231,431

Steam Heat. . . . . . . . 1,376 - - - - 1,376

$ 761,579 $ 89,296 $18,985 $(5,772) $ - $ 826,118

(1) Removal costs of assets retired less salvage value.

(2) Includes $71,488,000 resulting from the adoption of Statement of Financial Accounting Standards
No. 109 relating to the GSC acquisition adjustment.

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.

WESTERN RESOURCES, INC.

March 18, 1994 By JOHN E. HAYES, JR.
(John E. Hayes, Jr., Chairman of the Board,
President, and Chief Executive Officer)

SIGNATURES

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

Signature Title Date

Chairman of the Board, President,
JOHN E. HAYES, JR. and Chief Executive Officer March 18, 1994
(John E. Hayes, Jr.) (Principal Executive Officer)

Executive Vice President and
S. L. KITCHEN Chief Financial Officer March 18, 1994
(S. L. Kitchen) (Principal Financial and
Accounting Officer)

FRANK J. BECKER
(Frank J. Becker)

GENE A. BUDIG
(Gene A. Budig)

C. Q. CHANDLER
(C. Q. Chandler)

THOMAS R. CLEVENGER
(Thomas R. Clevenger)

JOHN C. DICUS Directors March 18, 1994
(John C. Dicus)

DAVID H. HUGHES
(David H. Hughes)

RUSSELL W. MEYER, JR.
(Russell W. Meyer, Jr.)

JOHN H. ROBINSON
(John H. Robinson)

MARJORIE I. SETTER
(Marjorie I. Setter)

LOUIS W. SMITH
(Louis W. Smith)

KENNETH J. WAGNON
(Kenneth J. Wagnon)