WESTERN RESOURCES INC /KS, 10-K, 1994-03-22

WESTERN RESOURCES INC /KS
10-K, 1994-03-22
ELECTRIC & OTHER SERVICES COMBINED

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

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

For the fiscal year ended December 31, 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
<PAGE>
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
<PAGE>
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.

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.
<PAGE>
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.
<PAGE>
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

<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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

<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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).
<PAGE>
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.
<PAGE>

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.

<TABLE>
EXECUTIVE OFFICERS OF THE COMPANY
<CAPTION>
Other Offices or Positions
Name Age Present Office Held During Past Five Years
<S> <C> <C> <C>
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)
<PAGE>
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.
</TABLE>
<PAGE>

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)
<PAGE>
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%).

<PAGE>
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.

<PAGE>
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.
<PAGE>

<TABLE>
ITEM 6. SELECTED FINANCIAL DATA

<CAPTION>
Year Ended December 31, 1993 1992(1) 1991 1990 1989
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
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

<PAGE>

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.
</TABLE>
<PAGE>

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.

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.
<PAGE>
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.

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.
<PAGE>
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.
<PAGE>
- ------------------------------------------------------------------------------
| 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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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).
<PAGE>
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.
<PAGE>

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.
<PAGE>

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
<PAGE>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
1993 1992
(Dollars in Thousands)
<S> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands,
except Per Share Amounts)
<S> <C> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)
<S> <C> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES

<CAPTION>
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)
<S> <C> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

<CAPTION>
December 31,
1993 1992
(Dollars in Thousands)
<S> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY

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

<S> <C> <C> <C>
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.
</TABLE>
<PAGE>

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.
<PAGE>

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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>

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.

<PAGE>
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.
<PAGE>
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.
<PAGE>

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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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

<PAGE>
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

<PAGE>

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.
<PAGE>
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
<PAGE>
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.
<PAGE>

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)
<PAGE>

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)

<PAGE>

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.
<PAGE>
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.

<PAGE>
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.
<PAGE>

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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.
<PAGE>
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

<PAGE>

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)
<PAGE>
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)
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1993

<CAPTION>
Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- at End
Classification of Period at Cost ments fication of Period
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
<PAGE>
<TABLE>
WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1992

<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>
<TABLE> WESTERN RESOURCES, INC.

Schedule V - Utility Plant

For the Year Ended December 31, 1991

<CAPTION>
Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- at End
Classification of Period at Cost ments fication of Period
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
<PAGE>
<TABLE>

WESTERN RESOURCES, INC.

Schedule VI - Accumulated Depreciation of Utility Plant

For the Year Ended December 31,

<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>

SIGNATURE

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

WESTERN RESOURCES, INC.

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

<PAGE>
SIGNATURES

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

Signature Title Date

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)

THE KANSAS POWER AND LIGHT COMPANY

Certificate of Designations
for a Series of Preference Stock
designated as "8.50% Preference Stock"

Pursuant to Section 17-6401(g) of the
General Corporation Code of the State of Kansas

The Kansas Power and Light Company, a corporation of
the State of Kansas (hereinafter called the "Corporation"), by
the President and Chief Executive Officer, KPL Division, an
officer, authorized to exercise the duties ordinarily exercised
by a Vice President, and an Assistant Secretary, DOES HEREBY
CERTIFY as follows:

1. That pursuant to Article VI of the Restated
Articles of Incorporation of the Corporation, as amended, the
Corporation is authorized to issue 4,000,000 shares of Preference
Stock, without par value, and the Board of Directors of the
Corporation is expressly authorized to fix, to the extent
permitted by law and said Article VI, the distinctive terms and
characteristics of any and all series of Preference Stock.

2. That the Board of Directors of the Corporation, at
a meeting duly convened and held on May 23, 1991, at which a
quorum was present and acting throughout, duly and unanimously
adopted the following resolutions authorizing the issuance of a
series of the Corporation's Preference Stock, and fixing the
designations, preferences and relative, participating, optional
and other rights and qualifications, limitations and restrictions
thereof other than those which would apply to all series of
Preference Stock of the Corporation (for a statement of which
reference is made to said Article VI) as follows:

WHEREAS, the Board of Directors of The Kansas
Power and Light Company (the "Company"), at a meeting
duly called and held on January 23, 1991, authorized
and empowered the proper officers of the Company to
proceed to prepare for the sale by the Company, of such
number of shares of the Company's authorized and
unissued Preference Stock, without par value (the
"Preference Stock"), in such amounts, up to
$150,000,000 in value and at such time, including but
not limited to a "shelf registration," as they deem
appropriate and in the best interests of the Company;

WHEREAS, pursuant to the authority delegated to
the proper officers of the Company at the January 23
meeting, said officers have made arrangements with
Dillon, Read & Co. Inc., as representative (the
"Representative") of a syndicate of underwriters who
are proposing to purchase 1,000,000 shares of
Preference Stock pursuant to a firm commitment
underwriting agreement substantially in the form
previously distributed to each of the Directors;

WHEREAS, the Company's Restated Articles of
Incorporation, as amended, authorize the issuance in
series of shares of the Preference Stock and fix the
general terms and characteristics of such shares and
authorize the Board of Directors of the Company to fix
the distinctive terms and characteristics of any and
all series of the Preference Stock in a manner not
inconsistent with, and within the prescribed limits of,
the Restated Articles of Incorporation, as amended; and

NOW, THEREFORE, BE IT RESOLVED, that a new series
of the Preference Stock, without par value, of the
Company be, and it hereby is, established;

FURTHER RESOLVED, that the following be, and it
hereby is, a statement of the designation and the
powers, preferences and rights, and the qualifications,
limitations and restrictions, of such series, subject
to the provisions set forth in the Restated Articles of
Incorporation, as amended (the "Articles"):

1. Designation. The Preference Stock created
and authorized hereby shall be designated as the "8.50%
Preference Stock" (the "8.50% Series"). The number of
shares constituting the 8.50% Series shall be 1,000,000
and no more.

2. Dividends. The rate per annum of dividends
on the 8.50% Series shall be $8.50 per share and
dividends thereon shall be cumulative from and
including the date of original issue on all shares
issued before July 1, 1991, which date shall be the
first dividend payment date for said shares, and
payable thereafter on the first day of January, April,
July and October of each year. For any period during
which any share of such series is outstanding less or
more than a full quarterly dividend period, the
dividends payable shall be computed on the basis of
twelve 30-day months and the actual number of days
elapsed in the period for which the dividends are
payable.

3. Optional Redemption. Subject to the
provisions of paragraph 4 hereof, the shares of the
8.50% Series shall be redeemable in whole or in part at
the option of the Company, subject to the terms,
provisions and effect as generally provided for
redemption of shares of the Company's Preference Stock
in the Articles, at a price of $108.50 per share if
such date is prior to July 1, 1992 and at the following
applicable prices per share during the respective
12-month periods beginning on July 1 of the years
indicated:

12-Month Period Redemption 12-Month Period
Redemption
Beginning Price Beginning Price
July 1 Per Share July 1 Per Share

1993 $107.37 1998 $104.53
1994 $106.80 1999 $103.97
1995 $106.23 2000 $103.40
1996 $105.67 2001 $102.83
1997 $105.10

and at $100 per share if redeemed on July 1, 2006 or
thereafter, plus, in each case, an amount equal to the
accrued but unpaid dividends on said shares to the date
of redemption; provided, however, that no shares of the
8.50% Series may be redeemed (otherwise than by sinking
fund redemption provided for in paragraph 4 hereof)
prior to July 1, 1996 if such redemption is for the
purpose of or in anticipation of refunding such shares
through the use, directly or indirectly, of funds
borrowed by the Company, or through the use, directly or
indirectly, of funds derived through the issuance by the
Company of stock ranking prior to or on a parity with
the 8.50% Series as to dividends or assets, if such
borrowed funds have an effective interest cost to the
Company (computed in accordance with generally accepted
financial practice and before deduction of commissions
and expenses) or such stock has an effective dividend
cost to the Company (so computed) of less than 8.50% per
annum.

In the case of an optional redemption of less than
all of the shares of the 8.50% Series at the time
outstanding, the Company shall select by lot the shares
so to be redeemed.

4. Sinking Fund Redemption. Notwithstanding the
provisions of paragraph 3 hereof, the shares of the
8.50% Series shall be subject to redemption as and for a
sinking fund as follows:

On July 1, 1997 and on each July 1, thereafter (each
such date being hereinafter referred to as an "8.50%
Series Sinking Fund Redemption Date") for so long as any
shares of the 8.50% Series shall remain outstanding, the
Company shall redeem, out of funds legally available
therefor and otherwise in the manner hereinafter
provided, 50,000 shares of the 8.50% Series (or the
number of shares then outstanding if less than 50,000)
at the sinking fund redemption price of $100.00 per
share, plus, as to each share so redeemed, an amount
equal to the accrued dividends thereon to the date of
redemption (the obligation of the Company so to redeem
the shares of the 8.50% Series being hereinafter
referred to as the "8.50% Series Sinking Fund
Obligation"). The 8.50% Series Sinking Fund Obligation
shall be cumulative. If on any 8.505 Series Sinking
Fund Redemption Date, the Company shall be prevented
from redeeming the full number of shares required to be
redeemed on the date, the 8.50% Series Sinking Fund
Obligation with respect to the shares not redeemed shall
carry forward and funds legally available for redemption
as aforesaid shall be applied to such 8.50% Series
Sinking Fund Obligation to each succeeding Sinking Fund
Redemption Date on which the Company shall not be
prevented from effecting such redemption until all such
shares have been redeemed. In addition to the 8.50%
Series Sinking Fund Obligation, the Company shall have
the option, which shall be noncumulative, to redeem,
upon authorization of the Board of Directors of the
Company and otherwise in the manner hereinafter
provided, on each 8.50% Series Sinking Fund Redemption
Date, at the sinking fund redemption price of $100.00
per share, plus, as to each share so redeemed, an amount
equal to the accrued dividends thereon to the date of
redemption, up to 50,000 additional shares of the 8.50%
Series. The shares of the 8.50% Series which are to be
the subject of mandatory or optional sinking fund
redemption shall be selected by the Company by lot.

Notice of each sinking fund redemption shall be
given, and deposit of the aggregate sinking fund
redemption price may be made, subject to the terms,
provisions and effect as provided generally for
redemption of shares of the Company's Preference Stock
in the Articles. The Company shall be entitled, at its
election, to credit against its 8.50% Series Sinking
Fund Obligation any shares of the 8.50% Series redeemed
(other than shares of the 8.50% Series redeemed pursuant
to the 8.50% Series Sinking Fund Obligation or
optionally redeemed pursuant to this paragraph 4),
purchased or otherwise acquired and not previously
credited against the 8.50% Series Sinking Fund
Obligation.
<PAGE>
5. Voluntary Liquidation, Dissolution or Winding
Up. In the event of the voluntary liquidation,
dissolution or winding up of the Company, the holders of
the 8.50% Series shall be entitled to receive (on a pro
rata basis with holders of any other series of
Preference Stock, from any assets and funds of the
Company remaining after payment of the debts and other
liabilities of the Company and after payment to the
holders of Preferred Stock of the preferential amount or
amounts to which such holders are entitled thereon) for
each share an amount equal to the then current
redemption price per share provided for under "Optional
Redemption" in paragraph 3 hereof plus, as to each
share, an amount equal to the accrued dividends thereon
to the date of distribution.

6. Involuntary Liquidation, Dissolution or
Winding Up. In the event of the involuntary
liquidation, dissolution or winding up of the Company,
the holders of the 8.50% Series shall be entitled to
receive (on a pro rata basis with holders of any other
series of Preference Stock, from any assets and funds of
the Company remaining after payment of the debts and
other liabilities of the Company and after payment to
the holders of Preferred Stock of the preferential
amount or amounts to which such holders are entitled
thereon) $100 for each share, which amount shall be
deemed to be the involuntary liquidation price per share
for the 8.50% Series, plus, as to each share, an amount
equal to the accrued dividends thereon to the date of
distribution.

7. Conversion Privileges. Shares of the 8.50%
Series shall not be convertible into any class, or
series of any class of, capital stock of the Company.

8. Negative Covenant. The Company hereby
covenants and agrees that, so long as any shares of the
8.50% Series are outstanding, it will not issue any
additional shares of preferred stock or any stock
convertible into such preferred stock.
<PAGE>
IN WITNESS WHEREOF, The Kansas Power and Light Company
has made this Certificate under its seal and the hand of the
President and Chief Executive Officer, KPL Division, an officer
authorized to exercise the duties ordinarily exercised by a Vice
President, and an Assistant Secretary, this 31st day of March,
1991.

THE KANSAS POWER AND LIGHT COMPANY

By /s/ William E. Brown
William E. Brown
President and Chief Executive
Officer, KPL Division

ATTEST:

/s/ Stacy F. Kramer
Stacy F. Kramer
Assistant Secretary

STATE OF KANSAS )
) ss:
COUNTY OF SHAWNEE )

BE IT REMEMBERED, that on this 31st day of March, 1991,
before me, the undersigned, a Notary Public in and for the County
and State aforesaid, personally came William E. Brown, President
and Chief Executive Officer, KPL Division of The Kansas Power and
Light Company, a corporation duly organized, incorporated and
existing under the laws of the State of Kansas, who is personally
known to me to be such officer, and who is personally known to me
to be the same person who executed as such officer the above
instrument in writing, and he duly acknowledge execution of the
same as Vice President of said corporation.

IN WITNESS WHEREOF, I have hereunto subscribed my name
and affixed my official seal the day and year last above written.

Notary Public

My Commission expires:

THE KANSAS POWER AND LIGHT COMPANY

Certificate of Designations
for a Series of Preference Stock
designated as "7.58% Preference Stock"

Pursuant to Section 17-6401(g) of the
General Corporation Code of the State of Kansas

The Kansas Power and Light Company, a corporation of
the State of Kansas (hereinafter called the "Corporation"), by
James S. Haines, Jr., Executive Vice President and Chief
Administrative Officer, authorized to exercise the duties
ordinarily exercised by a Vice President, and an Assistant
Secretary, DOES HEREBY CERTIFY as follows:

2. That the Board of Directors of the Corporation, at
a meeting duly convened and held on February 25, 1992, at which a
quorum was present and acting throughout, duly and unanimously
adopted the following resolutions authorizing the issuance of a
series of the Corporation's Preference Stock, and fixing the
designations, preferences and relative, participating, optional
and other rights and qualifications, limitations and restrictions
thereof other than those which would apply to all series of
Preference Stock of the Corporation (for a statement of which
reference is made to said Article VI) as follows:

WHEREAS, the Board of Directors of The Kansas
Power and Light Company, at a meeting duly called and
held on January 23, 1991, authorized and empowered the
proper officers of the Company to proceed to prepare
for the sale by the Company, of such number of shares
of the Company's authorized and unissued Preference
Stock, without par value (the "Preference Stock"), in
such amounts, up to $150,000,000 in value and at such
time, including but not limited to a "shelf
registration," as they deem appropriate and in the best
interest of the Company;

WHEREAS, on May 17, 1991 the Company filed a
registration statement on Form S-3, File No. 33-40527
(the "Registration Statement") with the Securities and
Exchange Commission ("SEC") to register for the shelf
1,500,000 shares of Preference Stock, which
Registration Statement was declared effective on
May 23, 1991;

WHEREAS, a Prospectus Supplement was filed with
the SEC on May 31, 1991 with respect to the public
offering of 1,000,000 shares of Preference Stock
designated as the "8.50% Preference Stock" (the "8.50%
Series") at $100 per share, the Underwriting Agreement
with respect to the purchase of such shares by the
Underwriters at a discount of $0.875 per share was
signed by the Company and the Underwriters on that date
and the closing for the purchase and sale pursuant
thereto was held on June 10, 1991;

WHEREAS, pursuant to the authority delegated to
the proper officers of the Company at the January 23,
1991 and February 25, 1992 meetings, said officers have
made arrangements with Dillon, Read & Co. Inc., as
representative (the "Representative") of a syndicate of
underwriters who are proposing to purchase the
remaining 500,000 shares of Preference Stock covered by
the Registration Statement pursuant to a firm
commitment underwriting agreement substantially in the
form executed with respect to the 8.50% Series;

NOW, THEREFORE, BE IT RESOLVED, that the Board of
Directors deems it desirable and in the best interests
of the Company to create a new series of Preference
Stock, without par value, consisting of the 500,000
additional shares of Preference Stock covered by the
Registration Statement and that such new series be
publicly offered and sold and issued by the Company;

1. Designation. The Preference Stock created
and authorized hereby shall be designated as the "7.58%
Preference Stock" (the "7.58% Series"). The number of
shares constituting the 7.58% Series shall be 500,000
and no more.

2. Dividends. The rate per annum of dividends
on the 7.58% Series shall be $7.58 per share and
dividends thereon shall be cumulative from and
including the date of original issue on all shares
issued before July 1, 1992, which date shall be the
first dividend payment date for said shares, and
payable thereafter on the first day of January, April,
July and October of each year. For any period during
which any share of such series is outstanding less or
more than a full quarterly dividend period, the
dividends payable shall be computed on the basis of
twelve 30-day months and the actual number of days
elapsed in the period for which the dividends are
payable.

3. Optional Redemption. Subject to the
provisions of paragraph 4 hereof, the shares of the
7.58% Series shall be redeemable in whole or in part at
the option of the Company, subject to the terms,
provisions and effect as generally provided for
redemption of shares of the Company's Preference Stock
in the Articles, at a price of $107.58 per share if
such date is prior to April 1, 1993 and at the
following applicable prices per share during the
respective 12-month periods beginning on April 1 of the
years indicated:

12-Month Period Redemption 12-MonthPeriod
Redemption
Beginning Price Beginning Price
April 1 Per Share April 1 Per Share

1993 $106.82 1998 $103.03
1994 $106.06 1999 $102.27
1995 $105.31 2000 $101.52
1996 $104.55 2001 $100.76
1997 $103.79

and at $100 per share if redeemed on April 1, 2002 or
thereafter, plus, in each case, an amount equal to the
accrued but unpaid dividends on said shares to the date
of redemption; provided, however, that no shares of the
7.58% Series may be redeemed (otherwise than by sinking
fund redemption provided for in paragraph 4 hereof)
prior to April 1, 1997 if such redemption is for the
purpose of or in anticipation of refunding such shares
through the use, directly or indirectly, of funds
borrowed by the Company, or through the use, directly
or indirectly, of funds derived through the issuance by
the Company of stock ranking prior to or on a parity
with the 7.58% Series as to dividends or assets, if
such borrowed funds have an effective interest cost to
the Company (computed in accordance with generally
accepted financial practice and before deduction of
commissions and expenses) or such stock has an
effective dividend cost to the Company (so computed) of
less than 7.58% per annum.

In the case of an optional redemption of less than
all of the shares of the 7.58% Series at the time
outstanding, the Company shall select by lot the shares
so to be redeemed.

4. Sinking Fund Redemption. Notwithstanding the
provisions of paragraph 3 hereof, the shares of the
7.58% Series shall be subject to redemption as and for
a sinking fund as follows:

The Company shall redeem, out of funds legally
available therefor and otherwise in the manner
hereinafter provided, (i) 25,000 shares of the 7.58%
Series (or the number of shares then outstanding if
less than 25,000) on each April 1 of the, years 2002,
2003, 2004, 2005 and 2006, and (ii) 375,000 shares of
the 7.58% Series (or the number of shares then
outstanding if less than 375,000) on April 1, 2007
(each of the dates referred to (i) and (ii) above being
referred to as an "7.58% Series Sinking Fund Redemption
Date"), in each case at the sinking fund redemption
price of $100.00 per share, plus, as to each share so
redeemed, an amount equal to the accrued dividends
thereon to the date of redemption (the obligation of
the Company so to redeem the shares of the 7.58% Series
being hereinafter referred to as the "7.58% Series
Sinking Fund Obligation"). The 7.58% Series Sinking
Fund Obligation shall be cumulative. If on any 7.58%
Series Sinking Fund Redemption Date, the Company shall
be prevented from redeeming the full number of shares
required to be redeemed on that date, the 7.58% Series
Sinking Fund Obligation with respect to the shares not
redeemed shall carry forward and funds legally
available for redemption as aforesaid shall be applied
to such 7.58% Series Sinking Fund Obligation on each
succeeding Sinking Fund Redemption Date on which the
Company shall not be prevented from effecting such
redemption until all such shares shall have been
redeemed. In addition to the 7.58% Series Sinking Fund
Obligation, the Company shall have the option, which
shall be noncumulative, to redeem, upon authorization
of the Board of Directors of the Company and otherwise
in the manner hereinafter provided, on each 7.58%
Series Sinking Fund Redemption Date, at the sinking
fund redemption price of $100.00 per share, plus, as to
each share so redeemed, an amount equal to the accrued
dividends thereon to the date of redemption, up to
25,000 additional shares of the 7.58% Series. The
shares of the 7.58% Series which are to be the subject
of mandatory or optional sinking fund redemption shall
be selected by the Company by lot.

5. Voluntary Liquidation, Dissolution or Winding
Up. In the event of the voluntary liquidation,
dissolution or winding up of the Company, the holders
of the 7.58% Series shall be entitled to receive (on a
pro rata basis with holders of any other series of
Preference Stock, from any assets and funds of the
Company remaining after payment of the debts and other
liabilities of the Company and after payment to the
holders of Preferred Stock of the preferential amount
or amounts to which such holders are entitled thereon)
for each share an amount equal to the then current
redemption price per share provided for under "Optional
Redemption" in paragraph 3 hereof plus, as to each
share, an amount equal to the accrued dividends thereon
to the date of distribution.

6. Involuntary Liquidation, Dissolution or
Winding Up. In the event of the involuntary
liquidation, dissolution or winding up of the Company,
the holders of the 7.58% Series shall be entitled to
receive (on a pro rata basis with holders of any other
series of Preference Stock, from any assets and funds
of the Company remaining after payment of the debts and
other liabilities of the Company and after payment to
the holders of Preferred Stock of the preferential
amount or amounts to which such holders are entitled
thereon) $100 for each share, which amount shall be
deemed to be the involuntary liquidation price per
share for the 7.58% Series, plus, as to each share, an
amount equal to the accrued dividends thereon to the
date of distribution.

7. Conversion Privileges. Shares of the 7.58%
Series shall not be convertible into any class, or
series of any class of, capital stock of the Company.

8. Negative Covenant. The Company hereby
covenants and agrees that, so long as any shares of the
7.58% Series are outstanding, it will not issue any
additional shares of preferred stock or any stock
convertible into such preferred stock.

IN WITNESS WHEREOF, The Kansas Power and Light Company
has made this Certificate under its seal and the hand of James S.
Haines, Jr., Executive Vice President and Chief Administrative
officer, authorized to exercise the duties ordinarily exercised
by a Vice President, and an Assistant Secretary, this 8th day of
April, 1992.

THE KANSAS POWER AND LIGHT COMPANY

By /s/ James S. Haines, Jr.
James S. Haines, Jr.
Executive Vice President and
Chief Administrative Officer

ATTEST:

/s/ Stacy F. Kramer
Stacy F. Kramer
Assistant Secretary

STATE OF KANSAS )
) ss:
COUNTY OF SHAWNEE )

BE IT REMEMBERED that on this 8th day of April, 1992,
before me, the undersigned, a Notary Public in and for the County
and State aforesaid, personally came James S. Haines, Jr.,
Executive Vice President and Chief Administrative Officer, of The
Kansas Power and Light Company, a corporation duly organized,
incorporated and existing under the laws of the State of Kansas,
who is personally known to me to be such officer, and who is
personally known to me to be the same person who executed as such
officer the above instrument in writing, and he duly acknowledge
execution of the same as Executive Vice President of said
corporation.

IN WITNESS WHEREOF, I have hereunto subscribed my name
and affixed my official seal the day and year last above written.

Notary Public

My Commission expires:

1993
AMENDED AND RESTATED
COAL SUPPLY AGREEMENT

This 1993 Amended and Restated Coal Supply Agreement is made
and entered into this 31st day of March, 1993, by and among Amax
Coal West, Inc., a Delaware corporation ("Seller"), and Western
Resources, Inc., a Kansas corporation (WRI); Kansas Gas and
Electric Company, a Kansas corporation; Missouri Public Service,
a division of UtiliCorp United Inc., a Delaware corporation; and
WestPlains Energy, a division of UtiliCorp United Inc., a
Delaware corporation, (collectively referred to herein as
"Buyers")
WITNESSETH:
WHEREAS, Buyers are public utilities that render electric
utility service to certain areas within the States of Kansas,
Missouri, and Colorado; and

WHEREAS, Seller and WRI (formerly known as The Kansas Power
and Light Company) entered into a Coal Supply Agreement for the
sale and purchase of coal dated July 1, 1973, as such has been
amended from time to time; and

WHEREAS, Buyers desire to secure a supply of coal in the
quantity and of the quality hereinafter specified, suitable for
use in Units 1, 2, and 3, and, upon construction and commencement
of operation, in unit 4 of the Jeffrey Energy Center situated in
Pottawatomie County, Kansas (the "Energy Center") and deliveries
thereof for said Units as hereinafter set forth; and

WHEREAS, Seller has represented to Buyers that it is
experienced in the commercial production of coal and that it now
owns, has leased or controls by location (as such phrase is
commonly used in the coal industry) certain coal reserves that
are assigned to its present surface mining operation located near
Gillette, Wyoming and known as the Eagle Butte Mine (hereinafter
referred to as the "Mine") as shown on Exhibit A attached hereto
and hereby made a part hereof and that said reserves of coal have
the quantity, quality and characteristics hereinafter specified;
and

WHEREAS, Seller desires to mine coal from the Mine and sell
the same to Buyers for utilization in the Energy Center, and
Buyers desire to buy such coal from Seller; and

WHEREAS, the parties hereto desire to set forth their mutual
understandings and covenants with regard to the aforesaid coal
supply arrangements.

NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and undertakings of the parties herein
contained, Seller agrees to sell and deliver to Buyers, and
Buyers agree to buy and accept delivery of coal from Seller
subject to the following terms, conditions and provisions:

Section 1. Definitions.
For purposes of this Agreement:
(a) "Additional Charge" shall apply only to Coal requested
by Buyers pursuant to Section 5(b) hereof and shall be an amount
equal to $0.0150 per MMBtu effective January 1, 1993, as adjusted
pursuant to Section 8(d) hereof.

(b) "Adjustment Quarter" is defined in regard to
adjustments and calculations made hereunder as the Quarter for
which such adjustments or calculations are being made.
(c) "Agent/Operator" is defined as Western Resources,
Inc., a Kansas corporation, formerly known as The Kansas Power
and Light Company, which is the operator of the Energy Center
for Buyers and shall serve as agent for Buyers under this
Agreement.
(d) "Agreement" is defined as this 1993 Amended and
Restated Coal Supply Agreement.
(e) "Alternate Source Coal" shall have the meaning ascribed
to it in Section 5(c) hereof.
(f) "Alternate Source Mine" shall have the meaning ascribed
to it in Section 5(c) hereof.
(g) "Amax Land Royalties" is defined as all Royalties
except those Royalties set out in section l(rr)(i) hereof.
(h) "Annual Base Quantity" is defined as the minimum number
of Btu's to be sold, purchased and delivered under this Agreement
for each Contract Year during the Term pursuant to the provisions
of Section 3(b) hereof.
(i) "as received basis" shall have the meaning ascribed to
it in ASTM Standard D-3180.
(j) "ASTM" means the American Society for Testing and
Materials.
(k) "Basic Source Coal" means coal shipped from the Mine or
Belle Ayr Mine.
(l) "Btu's" are defined as British thermal units.
(m) "Business Day" means any calendar day other than a
Saturday, Sunday or legal holiday recognized and observed by the
Federal Government.
<PAGE>
(n) "Buyers" shall have the meaning ascribed to it in the
preamble hereof.
(o) "Coal" means coal to be delivered by Seller and
purchased by Buyers pursuant hereto.
(p) "Competitive Offer" shall have the meaning ascribed to
it in Section 3(c) hereof.
(q) "Consultant" shall mean an employee or person otherwise
affiliated with one of the entities listed in Exhibit K, attached
hereto and hereby made a part hereof, as the same may be amended
from time to time.

(r) "Contract Year" means a calendar year.

(s) "Current Index" is defined:

(i) for published indices determined on a monthly basis, as
the arithmetic mean of the available monthly index values
for the second and third Quarters preceding an Adjustment
Quarter; provided, if less than three monthly index values
are available for any such two-Quarter period, then the
provisions of Section 8(e) hereof shall apply; and

(ii) for published indices determined on a Quarterly basis,
as the arithmetic mean of the available Quarterly index
values for the second and third Quarters preceding an
Adjustment Quarter; provided, if less than two Quarterly
index values are available for any such two-Quarter period,
then the provisions of Section 8(e) hereof shall apply.

(t) "Deficient Quantity" is defined as the difference, but
not less than zero, obtained by subtracting the total quantity of
Btu's purchased under this Agreement in a Contract Year from the
Annual Base Quantity (less any adjustments allowed pursuant to
the terms of this Agreement) Buyers are required to purchase
during such Contract Year pursuant to Section 3(b) hereof.
(u) "Deficient Quantity Charge" shall be an amount equal to
$0.3163/MMBtu effective for Contract Year 1993, and shall
thereafter be calculated pursuant to Section 4(a) hereof.
(v) "Dispute" shall have the meaning ascribed to it in
Section 16 hereof.
(w) "Energy Center" shall have the meaning ascribed to it
in the preamble hereof.
(x) "Force Majeure" shall have the meaning ascribed to it
in Section 13 hereof.
(y) "IC" (Indexed Component) is defined as that component
of the Price which shall be adjusted pursuant to Section 8(a)(ii)
or Section 8(c) hereof.
(z) "ICIP" (Indexed Component of Incremental Price) is
defined as that component of the Incremental Price which shall be
adjusted pursuant to Section 8(b)(ii) or Section 8(c), or
redetermined pursuant to Section 8(b)(iii) hereof.
(aa) "Incremental Price" (IP) is defined as the dollars per
MMBtu to be paid by Buyers to Seller pursuant to Section 7
hereof, as adjusted pursuant to Section 8(b) or Section 8(c), or
redetermined pursuant to Section 8(b)(iii) hereof, for all
Incremental Quantity Coal, except for Off-Specification Coal
which shall be priced pursuant to Section 6(b) hereof.
(bb) "Incremental Quantity Coal" is defined as all quantity
of Coal delivered hereunder during any Contract Year in excess of
the Annual Base Quantity for that Contract Year.
(cc) "Invoiced Items" shall have the meaning ascribed to it
in Section 12(d) hereof.
(dd) "Market Price" shall mean those determinations made by
Consultants pursuant to Section 8(b)(iii) hereof.
(ee) "Mine" shall have the meaning ascribed to it in the
preamble hereof.
(ff) "MMBtu" is defined as one million Btu's.
(gg) "Monthly Base Quantity" shall have the meaning ascribed
to it in Section 9(b) hereof.
(hh) "New Law" is defined as the enactment, repeal or
amendment of any federal, state or local law, ordinance,
regulation or rule or any judicial, legislative or executive
change in the wording, interpretation or enforcement of any
federal, state or local law, ordinance, regulation or rule or any
mandate, guideline or policy issued pursuant thereto, which
affects Seller's cost of mining, producing, processing, hauling
or loading Coal at the Mine after December 31, 1992.
(ii) "Off-Specification Coal" is defined as Coal delivered
hereunder which (on an "as received basis") on a monthly weighted
average basis, when sampled and analyzed pursuant to Section 11
hereof, has any one of the following specifications:
Coal Characteristics Off-Specifications

Moisture - exceeding 32.1%

Ash - exceeding 7.0 lbs./MMBtu

Volatile Matter - less than 27.8%

Fixed Carbon - less than 26.3%

Sulfur - exceeding 0.55 lbs./MMBtu

Calorific Value - less than 8150 Btu's/lb.

Ash Fusion (Reducing Atmosphere)

Initial Deformation - less than 2020 degrees F
Softening (H=W) less than 2055 degrees F
Softening (H=1/2W) less than 2120 degrees F
Fluid - less than 2130 degrees F

<PAGE>
Grindability (Hardgrove Index)-less than 52 (at 20%
moisture)

(jj) "Other Producer" shall have the meaning ascribed to it
in Section 3(c)(i) hereof.
(kk) "Price" is defined as the dollars per MMBtu to be paid
by Buyers to Seller pursuant to Section 7 hereof, as calculated
pursuant to Section 8(a) and Section 8(c) hereof, for all Annual
Base Quantity Coal delivered and accepted hereunder, except for
Off-Specification Coal which shall be priced pursuant to Section
6(b) hereof.
(ll) "Prior Index" is defined:
(i) for the April 1, 1993, Adjustment Quarter:

(A) for published indices determined on a monthly basis, as
the arithmetic mean of the available monthly index
values for the second and third Quarters of 1992;
provided, if less than three monthly index values are
available for this two-Quarter period, then the
provisions of Section 8(e) hereof shall apply; and

(B) for published indices determined on a Quarterly basis,
as the arithmetic mean of the available Quarterly index
values for the second and third Quarters of 1992;
provided, if less than two Quarterly index values are
available for this two-Quarter period, then the
provisions of Section 8(e) hereof shall apply; and<PAGE>
(ii) after the April 1, 1993, Adjustment Quarter, as the
Current Index from the previous Adjustment Quarter.

(mm) "Quarter" is defined as the three-month period of time
beginning Quarterly.
(nn) "Quarterly" is defined as occurring each January 1,
April 1, July 1 and October 1.
(oo) "Quarterly Adjustment Ratio" is defined as the sum of
the weighted changes of the item indices, described in Columns
(I) and (II) of the PRICE ADJUSTMENT INDEX SOURCES AND WEIGHTS
TABLE below, calculated as follows:

For each item index divide the Current Index by the Prior
Index and multiply the result by the fixed percentage weight
(changed to a decimal) listed under Column (III) of the
PRICE ADJUSTMENT INDEX SOURCES AND WEIGHTS TABLE below. The
result of such multiplication for each item index shall then
be added to obtain the sum of the weighted changes.

The value for each index shall be the value as first
published in the respective publication listed in the PRICE
ADJUSTMENT INDEX SOURCES AND WEIGHTS TABLE below. All
calculations to determine the weighted change for each index
shall be rounded to four decimal places. The Quarterly
Adjustment Ratio shall be calculated to four decimal places. An
example of these calculations is shown on Exhibit D attached
hereto and hereby made a part hereof.
<PAGE>
PRICE ADJUSTMENT INDEX SOURCES AND WEIGHTS TABLE

ITEM SOURCE WEIGHT
(I) (II) (III)

1. Labor
a. Average hourly earnings per worker, not
seasonally adjusted, Private nonfarm
payrolls, Mining (1) 10.0%
b. Average hourly earnings, Wyoming, not
seasonally adjusted (2) 10.0%

2. Materials & Supplies
a. Industrial Commodities (3) 10.0%
b. Intermediate materials, supplies and
components (4) 15.0%
c. Mining machinery parts, excluding
drills Commodity Code 1192-5301 (3) 10.0%

3. Other
a. Gross private domestic investment, Fixed
investments, Nonresidential, Implicit
price deflator (5) 20.0%

b. Gross domestic product, Business, Nonfarm
less housing (6) 5.0%
c. Bituminous coal, Spot sales of prepared
bituminous coal, Steam electric utilities
Commodity Code 0512-0209 (3) 20.0%

4. Total 100%

(1) Listed under the "Hourly and Weekly Earnings" subsection
of "5. Labor Force, Employment and Earnings: of "Current
Business Statistics" section of Survey of Current
Business published monthly by the Bureau of Economic
Analysis of the U. S. Department of Commerce.

(2) Listed under Table C-8 "Average houses and earnings of
production workers on manufacturing payrolls in States and
selected areas," of Employment and Earnings, published
monthly by the Bureau of Labor Statistics, U.S. Department
of Labor.

(3) Listed under Table 6 "Producer price indexes and percent
changes for commodity groupings and individual items, "of
Producer Price Indexes published monthly by the Bureau of
Labor Statistics, U.S. Department of Labor.

(4) Listed under Table 1 "Producer price indexes and percent
changes by state of processing," of Producer Price Indexes,
published monthly by the Bureau of Labor Statistics, U. S.
Department of Labor.

(5) Listed under THE NATIONAL INCOME AND PRODUCT ACCOUNTS,
selected NIPA Tables, Table 7.1 "Fixed-Weighted and
Alternative Quantity and Price Indexes for Gross Domestic
Product" of Survey of Current Business, published monthly by
the Bureau of Economic Analysis of the U. S. Department of
Commerce.

(6) Listed under THE NATIONAL INCOME AND PRODUCT ACCOUNTS,
Selected NIPA Tables, Table 7.14 "Implicit Price Deflators for
Gross Domestic Product by Section," of Survey of Current
Business, published monthly by the Bureau of Economic
Analysis of the U. S. Department of Commerce.

(pp) "Reclamation Fee is defined as costs incurred by Seller
for Abandoned Mine Land Fees as presently set forth in Part 870
of Title 30, Code of Federal Regulations (1992) and such
statutes, rules and regulations as shall be subsequently
applicable.
(qq) "Royalty" or "Royalties" is defined as an amount
payable by Seller to a third party for the right or privilege to
engage in coal mining activities at the Mine.
(rr) "RTRC" (Royalties and Tax Related Component) is defined
as that component of the Price which shall be calculated pursuant
to Section 8(a)(i) hereof and is attributable to:
(i) Royalties payable to the following third parties and
their successors in interest for Coal produced at the
Mine:

(A) the United States Department of the Interior as set
forth in Federal Coal Leases, W-0313773 and
W-78631, and any other coal leases entered into
with the United States Department of the Interior
subsequent to December 31, 1992, with respect to
coal reserves located adjacent to or near the Mine,
coal reserves located adjacent to or near the Mine,

<PAGE>
(B) the State of Wyoming as set forth in Wyoming State
Coal Lease, 0-27078, and any other coal leases
entered into with the State of Wyoming subsequent
to December 31, 1992, with respect to coal reserves
located adjacent to or near the Mine, and

(C) John Organ as set forth in a Letter of Proposed
Settlement dated January 18, 1969 between Ayrshire
Collieries corporation and John E. Organ and Eunice
Organ.

(ii) costs incurred by Seller at the Mine for;

(A) Wyoming severance taxes as presently set forth in
Wyoming Statues Title 39, the Wyoming Constitution
Article XV and Regulations of the Wyoming
Department of Revenue and notices thereunder (1992)
and such constitutions, statutes and regulations as
shall be subsequently applicable; and
(B) Campbell County, Wyoming ad valorem taxes on
production as set forth in Article XV Section 3 of
the Constitution of the State of Wyoming;

(iii) costs incurred by Seller at the Mine for Federal Black
Lung Excise Tax as presently set forth in Section
48.4121-1, Subpart H of Part 48 of Title 26, Code of
Federal Regulations (1992) and such statutes, rules and
regulations as shall be subsequently applicable;

(iv) changes in the Federal Statutory Depletion rate from
the base rate of 10 percent as set forth in Section 613
(b) (4) of Title 26, United States Code (1984); and (v)
costs incurred by Seller for a New Law which are to be
included in the RTRC pursuant to the procedures set
forth in Section 8(c) hereof.

(ss) "RTRCIP" (Royalties and Tax Related Component of
Incremental Price) is defined as the RTRC component of the
Incremental Price which shall be calculated pursuant to Section
8(b)(i) hereof and is attributable to those items set forth in
Section l(rr)(i) through (v) hereof.
(tt) "Seller" shall have the meaning ascribed to it in the
preamble hereof.
(uu) "Seller's Law Costs" is defined as all changes in
Seller's cost of mining, producing, processing, hauling or
delivering Coal at the Mine caused by a New Law.
(vv) "Seller's Scales" means a batch load weighing system
or track scales located at the Mine, Belle Ayr Mine or an
Alternate Source Mine capable of weighing the Coal to be
delivered hereunder.
(ww) "Survey Period" is defined as the four Quarters
subsequent to the date that a New Law first affects Seller's Law
Costs.
(xx) "Term" shall have the meaning ascribed to it in
Section 2 hereof.
(yy) "Termination Charge" shall have the meaning
ascribed to it in Section 15(a) hereof.
(zz) "Utilization Cost" shall mean the net additional cost
per MMBtu reasonably expected to be incurred by Buyers with
respect to the handling and utilization of Alternate Source Coal.
Whenever used in this Agreement, the terms "cost," "costs,"
"paid," "payments," and "expenses" shall include all such items
whether actually paid by Seller or accrued on Seller's books and
records in accordance with generally accepted accounting
principles and procedures.

Section 2. Term of Agreement.
(a) Term. The term of this Agreement shall be for a period
commencing on January 1, 1993, and ending on December 31, 2020
(the "Term").
(b) Extension of Term. If Buyers wish to extend the Term
for an additional period of up to five years for the purposes of
purchasing additional coal hereunder, they shall notify Seller at
least 36 months prior to the expiration of the Term. If, within
30 days after receipt of such notice, Seller determines, in its
sole judgment, that it will have coal available for sale after
the expiration of the Term, it shall notify Buyers of the
quantity of coal which will be available. Buyers and Seller
shall, within 60 days after Buyers' receipt of such notice, meet
in order to arrive at mutually acceptable terms and conditions to
cover the sale of such coal. If no mutually acceptable terms and
conditions are reached, this Agreement shall not be extended
beyond December 31, 2020.

Section 3. Quantities of Coal.
(a) Requirements Contract. This is a requirements contract
pursuant to which Buyers shall purchase exclusively from Seller
under the terms of this Agreement all coal, except as provided in
Sections 6, 13 and 15 hereof, necessary to operate Units 1 - 3 of
the Energy Center through December 31, 2020. If Buyers construct
and commence operations of Unit 4 of the Energy Center and the
Unit utilizes coal then Buyers shall purchase exclusively from
Seller all coal to operate that Unit through December 31, 2013.
At least 30 days prior to the beginning of each Contract Year,
Agent/operator shall provide Seller with a non-binding written
forecast of Buyers' estimated Coal requirements for such Contract
Year.
(b) Annual Base Quantity. Subject to Sections 6, 13, and
15 hereof, the Annual Base Quantity of Coal for each Contract
Year, which Buyers are obligated to purchase, shall be the
minimum number of Btu's respectively set forth opposite such
Contract Year below:
<PAGE>
Contract Year Annual Base Quantity in MMBtu
1993-2013 116,200,000
2014-2020 74,700,000

(c) Right of First Refusal - Unit 4. If Buyers, upon
construction and commencement of operations, plan to utilize coal
to operate Unit 4 between January 1, 2014 and December 31, 2020,
then Buyers shall offer Seller the opportunity to provide such
coal. Seller may, at its option, exercise the right to sell such
quantity of Coal to Buyers on the following terms and conditions:
(i) Buyers shall obtain one or more bona fide written offers
(each a "Competitive Offer") to supply coal to Unit 4
from one or more producers) not affiliated with or
controlled by Buyers (each such producer an "Other
Producer") and shall submit to Seller: (A) the price per
MMBtu F.0.B. Unit 4 from such Competitive Offer(s) ;
and, (B) a summary of the other terms and conditions of
the Competitive offer(s), including, but not limited to,
quality specifications, quantity, term, price adjustment
and payment terms, but without revealing the identity of
the Other Producer(s). Buyers shall at the same time
submit to Seller a verification from the firm of
certified public accountants then acting as
Agent/Operator's auditor of the accuracy of the price
and the summary of the Competitive Offers' terms and
conditions.

(ii) If, within 10 days after receipt of such information
from Buyers, Seller agrees to offer a price for coal to
be delivered F.O.B. Unit 4 equal to or less than the
price from one or more of the other Producer(s) and
agrees to all other reasonable terms and conditions of
the respective Competitive Offer (s) as stated in the
summary, Buyers shall purchase such quantity of coal
during such contract term from Seller at such price and
on such terms and conditions. If Seller advises Buyers
that it does not want to furnish any quantity to
Buyers, then Buyers shall have no further obligation to
Seller with respect to the purchase of coal for use at
Unit 4 during the term of Buyers' contract(s) with the
Other Producer(s); provided, Buyers shall not purchase
all of or any portion of such quantity from any entity
other than the Other Producer(s) which Buyers contracted
with; and provided further, if Buyers wish to purchase
all or any portion of such quantity from an entity other
than the Other Producer(s) which submitted the
Competitive Offer(s), it shall first afford Seller the
opportunity to furnish such quantity by following the
procedures set forth in paragraph (i) above.

(iii) Each time Buyers desire to purchase Coal for use in Unit
4 during the period January 1, 2014 through December 31,
2020, they shall follow the procedure set forth above.

Section 4. Deficient Quantity Charge and Payment.

(a) Deficient Quantity Charge. For Contract Year 1994
and each Contract Year thereafter, the Deficient Quantity Charge
shall be calculated as follows:
A = B ((AR1 + AR2 + AR3 + AR4)/4)

Where:

A=the Deficient Quantity Charge.
B=the previous Contract Year's Deficient Quantity
Charge.

AR1=the Quarterly Adjustment Ratio calculated pursuant to
Section 1(oo) hereof and in effect on January 1 of the
Contract Year during which Buyers incurred the Deficient
Quantity.

AR2=
the Quarterly Adjustment Ratio calculated pursuant to Section
1(oo) hereof and in effect on April 1 of the Contract Year
during which Buyers incurred the Deficient Quantity.

AR3=
the Quarterly Adjustment Ratio calculated pursuant to Section
1(oo) hereof and in effect on July 1 of the Contract Year
during which Buyers incurred the Deficient Quantity.

AR4=
the Quarterly Adjustment Ratio calculated pursuant to Section
1(oo) hereof and in effect on October 1 of the Contract Year
during which Buyers incurred the Deficient Quantity.

(b) Deficient Quantity Payment. If, during any Contract
Year, Buyers incur Deficient Quantity, then they shall pay Seller
an amount determined by multiplying the Deficient Quantity Charge
for such Contract Year by the Deficient Quantity. Such amount
shall be paid by Buyers in six consecutive equal monthly
installments beginning with the first such installment due and
payable on or before April 15 of the Contract Year succeeding the
Contract Year in which the Deficient Quantity is incurred.
Seller, on or before March 1 of such succeeding Contract Year,
shall furnish Buyers with an invoice showing the total and
monthly amounts due for such Deficient Quantity along with any
appropriate documentation supporting the calculation of such
amounts. Exhibit I attached hereto and hereby made a part hereof
is representative of the actual method and procedure which Buyers
and Seller have agreed shall be followed in calculating the
Deficient Quantity payment for any applicable Contract Year.

Section 5. Source and Dedication; Buyers' Request for Belle
Ayr Mine Coal; Alternate Source Coal; Loading; Deliveries; Title
and Risk of Loss.

(a) Source and Dedication. Basic Source Coal to be
delivered by Seller under this Agreement shall be from the Mine;
provided, Seller shall have the right at any time, and from time
to time, to deliver Coal from Seller's Belle Ayr Mine located
near Gillette, Wyoming and shown on Exhibit A hereto to be used
by itself or blended with Coal at the Mine; and all such Coal
shall be considered to be Basic Source Coal for all purposes
hereunder; provided further, if Seller delivers any Basic Source
Coal from the Belle Ayr Mine or blends Belle Ayr Coal with Coal
at the Mine, it shall notify Agent/Operator in writing prior to
the loading of any such Coal or anytime (i) a change is made to
return Coal sourcing to the Mine or (ii) it discontinues blending
at the Mine. Seller hereby dedicates to Buyers the total
quantities of Coal from the Mine that are required, or may be
required, to be delivered to Buyers in order for Seller to
fulfill the commitments undertaken by it under this Agreement.
(b) Buyers' Request for Belle Ayr Mine Coal. Buyers shall
have the right at any time, and from time to time, to request
that Seller deliver Coal during each Contract Year from the Belle
Ayr Mine. If Seller, in its sole discretion, agrees to deliver
such requested quantity of Coal or portion thereof then the
applicable Additional Charge shall be added to the then
applicable Price or Incremental Price.
(c) Alternate Source Coal. (i) Seller, at all times during
the Term, shall have the right, but not the obligation, to
deliver to Buyers all or part of the Annual Base Quantity from
alternate sources ("Alternate Source Coal") without regard to
whether or not the source mine or mines are owned or controlled
by Seller ("Alternate Source Mines"), so long as such Alternate
Source Coal: (A) is delivered to the Energy Center at a cost per
MMBtu (defined as including cost of Alternate Source Coal,
transportation, loss in transit, any required chemical additive
and rail equipment and/or any other items required to deliver
Coal in a usable form and including the Utilization Cost) not
higher than the cost per MmBtu of Mine Coal delivered to the
Energy Center; (B) is of substantially the same or better quality
and has substantially the same or better characteristics as
required for Basic Source Coal pursuant to Section 6(a) hereof;
(C) enables Buyers, by performance or by compromise agreeable to
Buyers, Seller and Buyers' rail carrier, to comply with Buyers'
obligations under transportation agreements in existence and in
effect at the time of delivery; and (D) has been approved by
Buyers in their reasonable discretion pursuant to the procedures
set forth below.
(ii) In addition, Seller's right to supply Alternate
Source Coal is subject to the following conditions:
(A) At any time, and from time to time, Seller, if it
desires to supply Alternate Source Coal, shall request
Agent/Operator's approval for the delivery of Alternate
Source Coal. At the time of such request Seller shall
provide Agent/Operator with the proximate and ultimate
analyses of such Coal and shall make available
quantities of such Alternate Source Coal as
Agent/operator may reasonably request for purposes of
analyzing and testing, including test burns in the
Energy Center. All such test Coal shall be priced as
though it was Alternate Source Coal purchased hereunder
by Agent/Operator. Agent/Operator shall notify Seller
of its approval or disapproval of such Alternate Source
Coal within 30 days of the later of its receipt of (A)
Seller's request or (B) the last shipment of such
Alternate Source Coal for the test burn. If
Agent/Operator has notified Seller that it has approved
such Alternate Source Coal, it shall also advise Seller
in such notice of the Utilization Cost. Such Utilization
Cost shall be fixed and firm for a period of twelve
months from the date Agent/Operator so notifies Seller.
If Seller desires to deliver such Alternate Source Coal
beyond the twelve month period, it shall notify Buyers
at least 90 days prior to the expiration of such twelve
month period and Buyers, within 60 days of receipt of
such notice, shall advise Seller of the Utilization Cost
to be effective during the ensuing twelve month period.

(B) When securing an Alternate Source Coal for shipment to
Agent/Operator, Seller shall also secure for
Agent/Operator access to and the right to inspect the
mining, weighing, sampling and other applicable
operations of the Alternate Source Mine.

(C) The price payable by Buyers for Alternate Source Coal,
taking into account the Utilization Cost, shall be
calculated pursuant to the procedure set forth in
Exhibit 0 attached hereto and hereby made a part hereof;
provided, if the parties are unable to agree on the
Utilization Cost from such Alternate Source Coal and
Seller desires to deliver Alternate Source Coal as the
result of operational problems, including coal quality,
at the Mine or Belle Ayr Mine, then pending resolution
of such Utilization Cost, Buyers will take the Alternate
Source Coal for such period as long as such Coal meets
the other conditions set forth in this section 5(c);
provided further, the price for Alternate Source Coal
shall not exceed the Price less the Utilization Cost.

(d) Railcar Loading; Rail Tariff. The Coal to be sold
and delivered hereunder shall be loaded F.O.B. railcars at the
Mine, Belle Ayr Mine or Alternate Source Mine with freight
charges paid by Buyers. Coal shall be loaded into railcars
provided by Buyers in accordance with the applicable tariff
and/or contract requirements of Buyers, rail carrier(s) for
transportation by rail to the Energy Center. Seller agrees to
pay all costs, penalties, or increases in freight charges
incurred solely due to Seller's failure to comply with those
applicable tariff and/or contract requirements relative to
loading and weighing time and loaded railcar weight which
requirements (i) are set forth in Exhibit M attached hereto and
hereby made a part hereof or (ii) might be
modified or changed in the future and consented to in writing by
Seller, which consent shall not unreasonably be withheld;
provided, Seller shall not have to incur any increased cost in
order to comply with such new requirements.
(e) Title and Risk of Loss. Delivery and title to the
Coal shall pass to Buyers when a loaded unit train departs the
Mine, Belle Ayr Mine or Alternate Source Mine, if applicable, for
its ultimate destination. Risk of loss shall follow title.
(f) Regular Deliveries. Subject to other provisions of
this Agreement and taking into account the regularly scheduled
holidays and vacation periods of the employees at the Mine,
deliveries of Coal hereunder shall be made in approximately equal
weekly quantities. Such delivery schedules may be adjusted at
any time by mutual agreement between the parties.

<PAGE>
Section 6. Quality of Coal.
(a) Coal Specifications. Except if and to the extent
that Seller and Buyers may from time to time agree in writing,
Coal to be supplied hereunder shall be:
(i) substantially free from impurities such as, but not
limited to, bone, slate, earth, rock, pyrite, wood,
tramp metal and mine debris;

(ii) sized to a top size of two inches (2"); and

(iii) of a typical weighted average quality over any monthly
period substantially equal to the following
specifications, on an "as received basis", as
established by analyses of samples taken and analyzed as
provided in Section 11 hereof, to-wit:

Coal Characteristics Specifications

Moisture 31.1%
Ash 5.85 lbs./MMBtu
Volatile Matter 31.0%
Fixed Carbon 33.0%
Sulfur 0.43 lbs./MMBtu
Calorific Value 8300 Btu's/lb.
Ash Fusion (Reducing Atmosphere)
Initial Deformation 2185 degrees F
Softening (H=W) 2225 degrees F
Softening (H=W/2 W) 2265 degrees F
Fluid 2300 degrees F
Grindability (Hardgrove Index) 58 (at 20% moisture)
Free Swelling Index 0

(b) Off-Specification Coal. Seller shall take all
reasonable necessary precautions in order to avoid delivering
Coal to Buyers that does not meet the above specifications;
however, in the event Off-Specification Coal is delivered, Buyers
shall pay for all such Off-Specification Coal at a price
equivalent to 90 percent of the Price or Incremental Price, as
the case may be. In the event the monthly weighted average
analysis shows that Off-Specification Coal has been delivered,
Buyers have the option to suspend all further shipments until
Buyers are reasonably assured by Seller that Seller will be able
to deliver Coal which will meet the specifications as set out in
Section 6(a) hereof. If Buyers suspend shipments pursuant to
this Section 6(b), then the Annual Base Quantity shall be reduced
by an amount equal to the product obtained by multiplying the
number of days of such suspension by the result obtained by
dividing the Annual Base Quantity by 365.

Section 7. Price and Incremental Price: Certain Taxes:
Economic Controls.
(a) Price and Incremental Price. Buyers shall pay to
Seller the Price for Annual Base Quantity Coal and the
Incremental Price for Incremental Quantity Coal delivered F.O.B.
railcars at the Mine, the Belle Ayr Mine or Alternate source Mine
and accepted under this Agreement. The Price shall consist of
the IC and RTRC and shall be calculated from time to time as
provided for in Section 8(a) hereof. The Incremental Price shall
consist of the ICIP and RTRCIP and shall be calculated or
redetermined from time to time as provided for in Section 8(b)
hereof.
(b) Certain Taxes. If any sales tax, excise tax, use tax
or similar taxes applicable to the sale or use of Coal are levied
at or after the point of delivery, Buyers shall either pay such
taxes directly or reimburse Seller if Seller has paid such taxes.
(c) Economic Controls. In the event the effect of any
adjustment or redetermination of the Price or Incremental Price
provided for herein is hereafter prevented, suspended or limited
by any economic controls required or established by applicable
laws, rules or regulations promulgated by federal, state, county
or local governmental bodies or agencies, then, upon and as of
the effective date of the repeal, modification or lapse thereof,
in whole or in part, the Price or Incremental Price shall be
revised to give effect to all adjustments thereto and
redeterminations thereof required or permitted under this
Agreement but not theretofore made due to such economic controls.
Such revised Price or Incremental Price shall apply (until
further adjusted or redetermined from time to time) to all
subsequent deliveries of Coal made hereunder.
Section 8. Calculation of Price and Incremental Price.
(a) Price Components. Beginning January 1, 1993, the Price
shall consist of two components: RTRC and IC and shall be an
amount equal to the sum of such components. The Price shall be
calculated from time to time to reflect the respective amounts
contained in the RTRC and IC components. Each of these
components shall be calculated pursuant to this Section 8. An
example of the operation of this Section 8 using hypothetical
numbers is set forth in Exhibits B through E and Exhibit G which
are attached hereto and hereby made a part hereof. Exhibits B
through E and Exhibit G are representative of the actual methods
and procedures which Buyers and Seller have agreed shall be
followed, except as otherwise provided for in this Agreement, in
making the calculations.
(i) Calculation of RTRC. The RTRC shall be an amount
equal to the sum of the values of the items of the
RTRC set forth in Sections 8(a)(i)(C),(D),(E),(F), and
(G) hereof and any items added pursuant to Section
8(c)(i) hereof. Such values shall be calculated
Quarterly beginning January 1, 1993, and at any other
time that a change occurs in the respective value of
any such item included in the RTRC. Calculations
shall be made using actual amounts unless such actual
amounts are not available in which case reasonable
estimated amounts shall be used. Documentation to
substantiate the use of such actual or reasonable
estimated amounts shall be provided by Seller to
Buyers at the time Seller notifies Buyers of any
change in the RTRC. If an estimated amount for any
item is used in the calculation of the RTRC, then
such amount shall be reconciled with the final actual
amount of such item as soon as such actual amount
becomes known and, if there is a difference between
the two such amounts, then an appropriate invoice
shall be issued pursuant to Section 9(a) hereof.

The value for each item of the RTRC and the CP shall
be solved to six decimal places. The respective
values of the items of the RTRC shall be added
together and the result thereof shall be rounded to
four decimal places to determine the RTRC. Such
calculations shall be made pursuant to the following
procedures and formulas:

(A) The symbols, descriptions, units of measure and
data sources used to determine values for the items
of the RTRC calculated by equations, set forth in
Section 8(a)(i)(B) hereof, are set forth in the RTRC
EQUATION RELATED SYMBOLS TABLE below:
<PAGE>
RTRC EQUATION RELATED SYMBOLS TABLE

Symbol Description Measure Units of Data Source
BLR Federal Black Lung percent Title 26 United
Excise Tax Rate as of States Codes Section
the date of adjustment 4121 (1992) and Title
26 Code of Federal
Regulations Section
48.4121-1 (1992)

BLT Federal Black Lung
Excise Tax MMBtu Section 8(a)(i)(G)

CDR Current Federal percent Title 26 United
Statutory Depletion States Code sections
rate as of the date of 291(a)(2) and
the adjustment 613(b)(4) (1992)

CP Calculated price MMBtu Section 8(a)(i)(6)
variable hereof

FDR Fixed Federal percent Title 26 United
Statutory Depletion States Code Section
Rate (10%) 613(b)(4) (1984)

FRT All coal produced from Tons Seller's records
Federal leases at the
Mine subject to
royalty assessment
based on percentage of
value during the three
months beginning on
the date of the
calculation

IC Indexed Component $/MMbtu Section 8(a)(ii)
hereof

MDC Total Direct Mining $ Seller's records
Costs at the Mine
related to the
adjustment period as
calculated by Seller
and accepted by the
State of Wyoming

ORG John Organ Royalty $/MMBtu Section 8(a)(i)(F)
hereof

ORR John Organ Royalty percent Letter of Proposed
rate as of the date of Settlement of
the adjustment January 18, 1969,
between John E.
Eunice Organ and
Ayrshire Collieries
Corporation

PRT Wyoming severance $/MMbtu Section 8(a)(i)(C)
taxes and Campbell hereof
County, Wyoming ad
valorem taxes on
production

PRTR Wyoming severance tax percent Wyoming Statutes
rate and the Campbell Section 39-6-302
County, Wyoming ad (1992) and the
valorem tax rate on Campbell County,
production as of the Wyoming ad valorem
date of the adjustment tax rate on
production Article XV
Section 3 of the
Constitution of
Wyoming

R Federal Royalties $/MMBtu Section
8(a)(i)(E) hereof

RR Federal Royalty rate percent Federal Coal
at the Mine as of the Leases,
date of the adjustment W-0313773
calculation

S Statutory Depletion $/MMBtu Section
8(a)(i)(D)
hereof

TDC Total Direct Costs at $ Tax returns
the Mine related to including
the adjustment period all amendments
as calculated by filed by
Seller and accepted by Seller and
the State of Wyoming accepted by the
Wyoming Department
of Revenue

TR Federal corporate percent Title 26 United
income tax rate as of States Code
the date of the Section
adjustment (34% in 11(b)(1)(c)
1992) (1992)

TT Total coal tonnage Tons Seller's records
produced at the Mine
during the three
months beginning on
the date of adjustment

(B) The equations used to determine values for items
of the RTRC calculated by equations are:

(1) BLT = (CP-BLT) (BLR/100)
but not more than the statutory maximum
per ton expressed as $/MMBtu based on
8300 Btu/lb.

(2) R + (CP) (RR) (FRT)/((TT) (100))

(3) PRT = (((CP-R-ORG-BLT-PRT) (MDC/TDC))+

ORG+BLT+PRT) (PRTR)/100

(4) ORG = (CP-BLT-PRT-
R+((.20) (FRT)/(TT)))) (ORR/100

(5) S = (CP-R-ORG) (FDR-CDR) (TR)/10,000

(6) CP = IC+R+ORG+PRT+BLT+S

These equations shall be solved and the equation
determined items of the RTRC calculated
simultaneously by direct substitution iteration
until no change is noted in the sixth decimal place
in each of the variables on both sides of the equal
sign in each equation and the resultant items of
the RTRC shall be rounded to six decimal places.
The non-variable values shall be input to four
decimal places. The above equations exclude the
Reclamation Fee (however, it is agreed that if the
current statutory amount of such Fee is changed by
a New Law, then the difference between the amount
imposed by the New Law and the current amount shall
be included in the RTRC calculations) and Amax Land
Royalties from the appropriate equations in effect
on January 1, 1993, because of their inclusion in
the IC. If, as a result of an action of a third
party, any of the above equations no longer
accurately determines the value of the applicable '
item of the RTRC, then an appropriate change in
such equations) shall be made; provided, if, in
calculating values for items (3), (4) and (5) of
the RTRC enumerated above, a third party, as of
December 31, 1992, deducted amounts for the
Reclamation Fee and/or Amax Land Royalties, then
amounts for the Reclamation Fee and/or Amax Land
Royalties shall never be used in calculating such
values hereunder and the changed equations) shall
replace the appropriate above equations). In such
event Seller shall submit revised equations to
Buyers, along with supporting documentation, for
Buyers' written approval, which shall not
unreasonably be withheld.

(C) The Wyoming severance taxes and Campbell County
(Wyoming) ad valorem taxes on production item of the
RTRC shall be calculated by the equation specified in
Section 8 (a) (i) (B) (3) hereof. An example
calculation is shown on Exhibit C hereto.

(D) The statutory depletion item of the RTRC shall be
calculated by the equation specified in Section
8(a)(i)(B)(5) hereof. An example calculation is shown
on Exhibit C hereto.
(E) The Federal Royalty item of the RTRC shall be
calculated by the equation specified in Section
8(a)(i)(B)(2) hereof. An example calculation is shown
on Exhibit C hereto.

(F) The John Organ Royalty item of the RTRC shall be
calculated by the equation specified in Section
B(a)(i)(B)(4) hereof.

An example calculation is shown on-Exhibit C hereof.

G) The Federal Black Lung Excise Tax item of the RTRC
shall be calculated by the equation specified in Section
8(a) (i) (B) (1) hereof. An example calculation is
shown on Exhibit C hereto.

(ii) Adjustment of IC. As of January 1, 1993, the IC
shall be $0.3455/MMBtu and shall thereafter be adjusted
Quarterly during each Contract Year. The IC for an
Adjustment Quarter shall be determined by multiplying
the amount of the IC for the previous Quarter by the
Quarterly Adjustment Ratio for such Adjustment Quarter.
The product of such calculation shall be rounded to four
decimal places. If any information needed for the
calculation of the Quarterly Adjustment Ratio is not
available until after the beginning of an Adjustment
Quarter, the calculation of the Quarterly Adjustment
Ratio shall be applied retroactively to the beginning of
such Adjustment Quarter. Seller shall use all
reasonable efforts to provide Buyers with documentation
to substantiate the use of all calculations, whether
based upon estimated amounts or actual amounts, together
with supporting calculations and appropriate
documentation, no later than 30 days prior to the
beginning of the Adjustment Quarter. If an estimated
amount for any item is used in the calculation of the
IC, then such amount shall be reconciled with the final
actual amount of such item as soon as such actual amount
becomes known and, if there is a difference between the
two such amounts, then an appropriate invoice shall be
issued pursuant to Section 9 (a) hereof. Example
calculations are shown on Exhibits D, E and G hereto.

(b) Incremental Price Calculation and Redetermination.
Beginning January 1, 1993, the Incremental Price shall consist of
two components: RTRCIP and ICIP and shall be an amount equal to
the sum of such components. The Incremental Price shall be
calculated from time to time to reflect the respective amounts
contained in the RTRCIP and ICIP components. Each of these
components shall be calculated pursuant to this Section 8. An -
example of the operation of this Section 8 using hypothetical
numbers is set forth in Exhibit B and Exhibits D through G
hereto. Exhibit B and Exhibits D through G are representative of
the actual methods and procedures which Buyers and Seller have
agreed shall be followed, except as otherwise provided for in
this Agreement, in making the calculations.
(i) Calculation of RTRCIP. The RTRCIP shall be an
amount equal to the sum of the values of the items of
the RTRCIP set forth in Sections 8(b) (i) (C), (D),
(E),(F) and (G) hereof and any items added pursuant to
Section 8 (c) (i) hereof. Such values shall be
calculated Quarterly beginning January 1, 1993, and at
any other time that a change occurs in the respective
amount of any item included in the RTRCIP. Calculations
shall be made using actual amounts unless such actual
amounts are not available in which case reasonable
estimated amounts shall be used. Documentation to
substantiate the use of such actual or reasonable
estimated amounts shall be provided by Seller to Buyers
at the time Seller notifies Buyers of any change in the
RTRCIP. If an estimated amount for any item is used in
the calculation of the RTRCIP, then such amount shall be
reconciled with the final actual amount of such item as
soon as such actual amount becomes known and, if there
is a difference between the two such amounts, then an
appropriate invoice shall be issued pursuant to Section
9(a)hereof. The value of each item of the RTRCIP and
the CIP shall be solved to six decimal places. The
respective values of the items of the RTRCIP shall be
added together and the result thereof, shall be rounded
to four decimal places to determine the RTRCIP. Such
calculations shall be made pursuant to the following
procedures and formulas:

(A) The symbols, descriptions, units of measure and data
sources used to determine values for the items of the
RTRCIP calculated by equations, set forth in Section
8 (b) (i) (B) hereof, are set forth in the RTRCIP
EQUATION RELATED SYMBOLS TABLE below:

<PAGE>
RTRCIP EQUATION RELATED SYMBOLS TABLE

BLT Federal Black Lung
Excise Tax $/MMBtu Section 8(b)(i)(G)

CDR Current Federal percent Title 26 United
Statutory Depletion States Code sections
rate as of the date of 29(a)(2) and
the adjustment 613(b)(4) (1992)

CIP Calculated incremental $/MMBtu Section 8(b)(i)(B)(6)
price variable hereof

FDR Fixed Federal percent Title 26 United
Statutory Depletion States Code Section
Rate (10%) 613(b)(4) (1984)

FRT All coal produced from Tons Seller's records
Federal leases at the
Mine subject to
royalty assessment
based on percentage of
value during the three
months beginning on
the date of the
calculation

ICIP Indexed Component $/MMbtu Section 8(b)(ii)
hereof

MDC Total Direct Mining $ Seller's records
Costs at the Mine
related to the
adjustment period as
calculated by Seller
and accepted by the
State of Wyoming

ORG John Organ Royalty $/MMBtu Section 8(b)(i)(F)
hereof

ORR John Organ Royalty percent Letter of Proposed
rate as of the date of Settlement of
the adjustment January 18, 1969,
between John E.
Eunice Organ and
Ayrshire Collieries
Corporation

PRT Wyoming severance $/MMbtu Section 8(b)(i)(C)
taxes and Campbell hereof
County, Wyoming ad
valorem taxes on
production

R Federal Royalties $/MMBtu Section
8(b)(i)(E) hereof

RR Federal Royalty rate percent Federal Coal
at the Mine as of the Leases,
date of the adjustment W-0313773
calculation

S Statutory Depletion $/MMBtu Section
8(b)(i)(D)
hereof

TR Federal corporate percent Title 26 United
income tax rate as of States Code
the date of the Section
adjustment (34% in 11(b)(1)(c)
1992) (1992)

TT Total coal tonnage Tons Seller's records
produced at the Mine
during the three
months beginning on
the date of adjustment

(B) The equations used to determine values for items of
the RTRCIP calculated by equations are:

(1) BLT = (CIP-BLT)(BLR/100)
but not more than the statutory maximum per ton
expressed as $/MMBtu based on 8300 Btu/lb.

(2) R = (CIP)(RR)(FRT)/((TT)(100))

(3) PRT = (((CIP-R-ORG-BLT-PRT) (MDC/TDC)) +ORG+ BLT+PRT)
(PRTR) /100

(4) ORG = (CIP-BLT-PRT-R+
((.20) (FRT) / (TT))) (ORR) /100

(5) S = (CIP-R-ORG)(FDR-CDR)(TR)/10,000

(6) CIP = ICIP+R+ORG+PRT+BLT+S

These equations shall be solved and the equation determined items
of the RTRCIP calculated simultaneously by direct substitution
iteration until no change is noted in the sixth decimal place in
each of the variables on both sides of the equal sign in each
equation and the resultant items of the RTRCIP shall be rounded
to six decimal places. The non-variable values shall be input to
four decimal places. The above equations exclude the Reclamation
Fee (however, it is agreed that if the current statutory amount
of such Fee is changed by a New Law, then the difference between
the amount imposed by the New Law and the current amount shall be
included in the RTRCIP calculations) and Amax Land Royalties from
the appropriate equations in effect on January 1, 1993, because
of their inclusion in the ICIP. If, as a result of an action of
a third party, any of the above equations no longer accurately
determines the value of the applicable item of the RTRCIP, then
an appropriate change in such equations) shall be made provided,
if, in calculating values for items (3), (4) and (5) of the
RTRCIP enumerated above, a third party, as of December 31, 1992,
deducted amounts for the Reclamation Fee and/or Amax Land
Royalties, then amounts for the Reclamation Fee and/or Amax Land
Royalties shall never be used in calculating such values
hereunder and the changed equations) shall replace the
appropriate above equations). In such event Seller shall submit
revised equations to Buyers, along with supporting documentation,
for Buyers' written approval, which shall not unreasonably be
withheld.

(C) The Wyoming severance taxes and Campbell County
(Wyoming) ad valorem taxes on production item of the
RTRCIP shall be calculated by the equation specified in
Section 8(b)(i)(B)(3) hereof. An example calculation is
shown on Exhibit F hereto.

<PAGE>
(D) The statutory depletion item of the RTRCIP shall be
calculated by the equation specified in Section
8(b)(i)(B)(5) hereof. An example calculation is shown
on Exhibit F hereto.

(E) The Federal Royalty item of the RTRCIP shall be
calculated by the equation specified in Section
8(b)(i)(B)(2) hereof. An example calculation is shown
on Exhibit F hereto.

(F) The John Organ Royalty item of the RTRCIP shall be
calculated by the equation specified in Section
8(b)(i)(B)(4) hereof. An example calculation is shown
on Exhibit F hereto.

(G) The Federal Black Lung Excise Tax item of the RTRCIP
shall be calculated by the equation specified in Section
8 (b) (i) (B) (1) hereof. An example calculation is
shown on Exhibit F hereto.

(ii) Adjustment of ICIP. As of January 1, 1993, the ICIP
shall be $0.1540/MMBtu and shall thereafter be adjusted
Quarterly during each Contract Year. The ICIP for an
Adjustment Quarter shall be determined by multiplying
the amount of the ICIP for the previous Quarter by the
Quarterly Adjustment Ratio for such Adjustment Quarter.
The product of such calculation shall be rounded to four
decimal places. If any information needed for the
calculation of the Quarterly Adjustment Ratio is not
available until after the beginning of an Adjustment
Quarter, the calculation of the Quarterly Adjustment
Ratio shall be applied retroactively to the beginning of
such Adjustment Quarter. Seller shall use all
reasonable efforts to provide Buyers with documentation
to substantiate the use of all calculations, whether
based upon estimated amounts or actual amounts, together
with supporting calculations and appropriate
documentation, no later than 30 days prior to the
beginning of the Adjustment Quarter. If an estimated
amount for any item is used in the calculation of the
ICIP, then such amount shall be reconciled with the
final actual amount of such item as soon as such actual
amount becomes known and, if there is a difference
between the two such amounts, then an appropriate
invoice shall be issued pursuant to Section 9 (a)
hereof. Example calculations are shown on Exhibits D, E
and G hereto.

(iii) Market Redetermination. Notwithstanding anything
contained to the contrary in this Agreement, and in
addition to all other rights of the parties contained
herein, it is agreed that a redetermination of the
Incremental Price shall be made hereunder. The purpose
of such redetermination is to change the Incremental
Price so that it is reflective of the then current
market price for similar Powder River Basin coal sold to
utility purchasers buying coal for their own consumption
under five year coal supply agreements commencing at the
time of the redetermination for the purchase of
approximately 1,000,000 tons of coal per year and
containing terms and conditions as set forth in
Exhibit L attached hereto and hereby made a part hereof
(hereinafter such current market price referred to as
the "Market Price").

Redeterminations of the Incremental Price pursuant to
this Section 8(b)(iii) shall be effective on January 1,
1998, January 1, 2003, January 1, 2008, January 1, 2013
and January 1, 2018.

Redetermination shall be initiated by Buyers serving
written notice to Seller of the selection of their
Consultant no later than August 15 prior to the
Contract Year in which such redetermination of the
Incremental Price shall become effective. Upon receipt
of such notice, Seller, within 10 days, shall notify
Buyers of which Consultant it has chosen to determine
the Market Price.

After each party has received its Consultant's
determination of the Market Price, Agent/operator and
Seller shall compare their Consultants' Market Prices,
on or before October 5. If either one of the Market
Prices is within five percent of the simple arithmetic
average of the two Consultant's Market Prices, then the
simple arithmetic average of the two Market Prices
shall be the Incremental Price which will be effective
on such respective January 1. If neither of the
Consultant's Market Price is within five percent of the
simple arithmetic average, as shown on Exhibit J-1
hereto, then a third and fourth Consultant shall be
selected in a random drawing from the list contained on
Exhibit K hereto. The third Consultant selected shall
be contacted within 10 Business Days to ascertain if
such Consultant can determine a Market Price by December
1. If the third Consultant cannot make such a timely
determination, then the fourth Consultant shall be
contacted as soon as possible to see if it can make such
a timely determination. This process shall be repeated,
if necessary, until a Consultant is selected and if the
process is delayed beyond the applicable January 1, the
resulting Incremental Price shall be applied
retroactively to such applicable January 1. Any
communications with the third or fourth or subsequent
Consultant must be made simultaneously by both
Agent/Operator and Seller. When the Consultant has
determined the Market Price, the Incremental Price,
which will become effective on each respective
January 1, shall be the simple arithmetic average of all
three Consultant's Market Prices, as shown on
Exhibit J-2 hereto. The ICIP effective on each
respective January 1 shall be solved by using the
Incremental Price and the formulas and non-variable
inputs used to calculate each respective January 1
RTRCIP.
(c) New Laws. After December 31, 1992, Seller's
Law Costs shall be calculated by Seller and the amount
(whether an increase or decrease) of such change shall be
included in either the RTRC or the IC as an item of cost as
provided for below:
(i) Classification of Seller's Laws Cost.

(A) If an item of cost occasioned by a New Law is a
specific amount per ton or other measure and is
not then an item of the RTRC, then it shall become
an item of and be included in the RTRC on the basis
of the specific amount per ton, converted to the
equivalent dollars per MMBtu based upon 8,300 Btu's
per pound, retroactively to the date the New Law
first affected Seller's Laws Cost.

(B) If an item of cost occasioned by a New Law is
calculated as a percent of Seller's revenue from
the sale of coal from the Mine less applicable
deductions, if any, and is not then an item of the
RTRC, then it shall become an item of and be
included in the RTRC on the basis of an
amount calculated pursuant to the procedures set
forth in Section 8 (a) (i) (B) hereof
retroactively to the date the New Law first
affected Seller's Laws Cost.

(C) If an item of cost occasioned by a New Law causes
Seller's operating costs at the Mine to increase
decrease, then such cost shall become an item of
and be included in the IC on the basis of an amount
calculated pursuant to the procedures set forth in
Section 8 (c) (ii) or (iii) hereof.

(D) Any Seller's Laws Cost which can not be classified
in one of the preceding sections, shall be
classified as either an IC or RTRC cost by mutual
agreement of the parties.

(ii) IC Related Cost Reduction.

(A) If Seller's Laws Cost is classified as an IC cost
and is a reduction for an item of cost, then
Seller and Buyers shall agree on an estimated
amount of the cost reduction and the IC shall be
reduced by such amount retroactively to the date
such New Law first affected Seller's Laws Cost and
this estimated amount shall continue to be used in
calculating the IC until Buyers and Seller agree
to an amount pursuant to Section 8(c)(ii)(B)
hereof.

(B) After the IC has been reduced pursuant to Section
8(c)(ii)(A) hereof for the Survey Period, the
actual amount of reduction for such item of cost
shall be determined. Seller shall calculate and
present to Buyers, Seller's determination of the
actual amount of such cost reduction for each
Quarter of the Survey Period. Buyers or Buyers'
representative shall have the right at Buyers'
expense to review Seller's applicable records to
independently calculate and present to Seller,
Buyers' determination of the actual amount of such
cost reduction for each Quarter of the Survey
Period. Such review shall include an eight Quarter
period commencing four Quarters previous to
the first Quarter of the Survey Period. Buyers'
review shall be completed within 120 days after
Buyers or Buyers' representative has received all
necessary data and information from Seller.
Seller and Buyers shall then review the
available-data and agree on the
actual cost reduction for each Quarter of the
Survey Period.

(C) After Buyers and Seller have reached an agreement
pursuant to Section 8(c)(ii)(B) hereof, the Price
for each Quarter of the Survey Period shall be
recalculated based upon the new values of the IC
(which shall reflect the actual amount of such
cost reduction). The total amount paid by Buyers
for Coal delivered during the Survey Period shall
be compared with the total amount that would have been
paid by Buyers if the recalculated Price had been in
effect and Buyers' account shall either be credited
or debited, as the case may be, for the amount of
any difference between such total amounts.

(D) After Buyers and Seller have reached an agreement
pursuant to Section 8(c)(ii)(B) hereof, the
weighted average actual amount of such cost
reduction for such item of cost shall be calculated
for the Survey Period. For purposes of calculating
the IC pursuant to Section 8(a)(ii) hereof for all
Quarters subsequent to the Survey Period such
weighted average actual amount of such cost
reduction shall replace the estimated amount
previously included in the IC for the fourth
Quarter of the Survey Period.

(iii) IC Related Cost Increase.

(A) If Seller's Laws Cost is classified as an IC
cost and is an increase f or an item of cost, then
Seller and Buyers shall agree on an estimated
amount of the cost increase and include such
amount in the IC retroactively to the date the
New Law first affected Seller's Laws Cost and
this estimated amount shall continue to be used
in calculating the IC until Buyers and Seller
agree to an amount pursuant to Section
8(c)(iii)(B) hereof.

(B) After an item of cost has been included in the IC
pursuant to Section 8(c)(iii)(A) hereof for the
Survey Period, the actual amount of increase for
such item of cost shall be determined. Seller
shall calculate and present to Buyers, Seller's
determination of the actual amount of such cost
increase for each Quarter of the Survey Period.

Buyers or Buyers's representative shall have the
right at Buyers' expense to review Seller's
applicable records to independently
calculate and present to Seller, Buyers'
determination of the actual amount of such cost
increase for each Quarter of the survey Period.

Such review shall include an eight Quarter period
commencing four Quarters previous to the Quarter
during which the IC was first increased and shall
be completed within 120 days after Buyers or
Buyers' representative has received all necessary
data and information from Seller. Seller and
Buyers shall then review the available data and
agree on the actual cost increase for each
Quarter of the Survey Period.

(C) After Buyers and Seller have reached an agreement
pursuant to Section 8(c)(iii)(B) hereof, the
Price for each Quarter of the Survey Period shall
be recalculated based upon the new values of the
IC (which shall reflect the actual amount of such
cost increase). The total amount paid by Buyers
for Coal delivered during the Survey Period shall
be compared with the total amount that would have
been paid by Buyers if the recalculated Price had
been in effect and Buyers, account shall either
be credited or debited, as the case may be, for
the amount of any difference between such total
amounts.

(D) After Buyers and Seller have reached an agreement
pursuant to Section 8 (c) (iii) (B) hereof, the
weighted average actual amount of such cost
increase for such item of cost shall be
calculated for the Survey Period. For purposes
of calculating the IC pursuant to Section
8(A)(ii) hereof for the first Quarter after the
Survey Period, such weighted average actual
amount of such cost increase shall replace the
estimated amount previously included in the IC
for the fourth Quarter of the Survey Period.

(iv) ICIP and RTRCIP Adjustments. If a classification
of Seller's Law Costs pursuant to Section 8(c)(i) hereof
results in an adjustment in the RTRC or IC then a
similar adjustment shall be made to the RTRCIP or ICIP,
as the case may be. If adjustments to the RTRC or IC
made pursuant to Section 8 (c) hereof result in a change
in the Price, then a similar adjustment shall be made to
the Incremental Price based upon the corresponding
changes to the RTRCIP and the ICIP.

(d) Additional Charge Adjustment. As of January 1, 1993,
the Additional Charge shall be $0.0150/MMBtu and shall thereafter
be adjusted Quarterly during each Contract Year. The Additional
Charge for an Adjustment Quarter shall be determined by
multiplying the previous Quarter's Additional Charge by the
Quarterly Adjustment Ratio for such Adjustment Quarter. The
product of such calculation shall be rounded to four decimal
places. If any information needed for the calculation of the
Quarterly Adjustment Ratio is not available until after the
beginning of an Adjustment Quarter, the calculation of the
Quarterly Adjustment Ratio shall be applied retroactively to the
beginning of such Adjustment Quarter. Seller shall use all
reasonable efforts to provide Buyers with documentation to
substantiate the use of all calculations, whether
based upon estimated amounts or actual amounts, together with
supporting calculations and appropriate documentations, no later
than 30 days prior to the beginning of the Adjustment Quarter.
An example calculation is shown on Exhibit H hereto.
(e) Procedure in the Event Indices are Discontinued or
Changed. Buyers and Seller hereby agree that the indices used to
adjust the Price and Incremental Price are not intended to
reflect the changes in Seller's costs of providing Coal hereunder
or the change in the general market price for coal. The sole
purpose in using the various indices is to afford the parties a
method whereby the Price and Incremental Price can be adjusted.
If any index referred to in this Agreement is changed,
discontinued or unavailable for (i) four or more months out of
any two consecutive Quarters, if using monthly indices, or (ii)
two consecutive Quarters, if using Quarterly indices such that
the current index cannot be calculated, then the parties shall
undertake in good faith to agree upon a substitute index. If an
index is only temporarily unavailable then said index shall be
calculated as provided for in Exhibit E attached hereto and
hereby made a part hereof or some other mutually agreed to
method. If the base period of one or more of the indices used in
this Agreement changes, such indices will continue to be used,
but the index values used in the Prior Index calculation will be
changed to the index values for the new base period.
Section 9. Billing and Payment.
(a) Semi-Monthly Invoicing. Each month, Seller shall
render two invoices and Buyers shall make two payments covering
the quantity of Coal delivered during such month. Such quantity
shall
be determined using weights determined pursuant to Section 10
hereof and calorific value determined pursuant to Section 11
hereof. The first invoice shall cover Coal delivered by Seller
during the first 15 days of the month and shall be mailed to
Buyers within five Business Days thereafter. Buyers shall pay
the first invoice within nine Business Days of the date upon
which such first invoice is received. The second invoice shall
cover Coal delivered by Seller from the 16th day to the last day
of the month and shall be mailed to Buyers within five Business
Days after the last day of the month. Buyers shall pay the
second invoice within nine Business Days of the date upon which
such second invoice is received. Invoices or credit memorandums
for retroactive price adjustments and other exceptional
circumstance shall be rendered by Seller as promptly as possible.
Buyers shall make payment on such invoices within nine Business
Days of receipt of an invoice.
(b) Monthly Allocation of Annual Base Quantity and
Incremental Quantity. The Annual Base Quantity shall be
apportioned monthly by dividing the Annual Base Quantity by 365
and multiplying the result by the number of days in each month,
assuming that February always has 28 days in it. The result for
each month shall be called the Monthly Base Quantity. In any
month where the quantity of Coal shipped exceeds the Monthly Base
Quantity, the quantity of Coal which exceeds the Monthly Base
Quantity shall be deemed to be Incremental Quantity Coal.
Such Incremental Quantity Coal shall be invoiced at the
applicable Incremental Price in the second invoice of each month
as provided in Section 9 (a) hereof.
(c) Annual True-up of the Annual Base Quantity. The amount
paid by Buyers for the Annual Base Quantity shall be trued-up at
the end of each Contract Year if: (i) Buyers, during any Contract
Year, fail to take delivery of the Annual Base Quantity (less any
adjustments allowed pursuant to the terms of this Agreement) and
have been invoiced for Incremental Quantity Coal during the
Contract Year, Buyers shall pay to Seller the difference between
the Price and the Incremental Price, as the Price and Incremental
Price existed on December 31 of the Contract Year, multiplied by
the quantity of Incremental Quantity Coal invoiced by Seller
during such Contract Year pursuant to Section 9(b) above; or (ii)
Buyers, during any Contract Year, take delivery of more than the
Annual Base Quantity (less any adjustments allowed pursuant to
the terms of this Agreement) and the quantity of Coal invoiced by
Seller at the applicable Price during such Contract Year is less
than the Annual Base Quantity (less any adjustments allowed
pursuant to the terms of this Agreement), then Buyers shall pay
to Seller the difference between the Price and the Incremental
Price, as those Prices existed on December 31 of such Contract
Year, multiplied by the difference between the Annual Base
Quantity (less any adjustments allowed pursuant to the terms of
this Agreement) and the quantity of Coal invoiced by Seller at
the applicable Price during such Contract Year. Seller shall
invoice Buyers for any amount to be paid under the provisions of
this Section 9(c) within 10 Business Days after the end of the
Contract Year. Buyers shall pay such amount within 15 Business
Days after receipt of such invoice. Example calculations of the
true-up are set forth in Exhibit N hereto.
(d) Method of Payment. All payments required by this
Section 9 shall be made by electronic funds transfer via ACH in
U.S. currency for the invoiced amount to the account of Seller
numbered 72-51807 at Continental Illinois National Bank, ABA
Number 071-000039, Chicago, Illinois 60693 or any other bank and
account specified by Seller.
Section 10. Weights.
(a) Weights. The weights of the Coal delivered hereunder
shall be determined on Seller's Scales at the point of delivery.
The weights thus determined shall be accepted as the weight of
Coal for which invoices are to be rendered and payments made in
accordance with Section 9 hereof. Seller shall furnish the
railroad transporting the Coal with copies of the weights thereby
determined in accordance with the rail tariff or contract in
effect at any given time. Seller's Scales shall be inspected and
certified by the State of Wyoming or an entity mutually agreed
upon by Buyers and Seller at intervals of approximately six
months and Agent/operator shall be furnished with a copy of the
certification. Seller shall use its best efforts to notify
Agent/Operator approximately 15 Business Days prior to any scale
inspection and certification.
(b) Missed Weights. In the event that 50 percent or more
of the individual railcar weights from a unit train are available
from Seller's Scales, the average of the available railcar
weights from that unit train will be used for any unavailable
weights. In the event that less than 50 percent of the
individual railcar weights from a unit train are available from
Seller's Scales, the average railcar weights from the previous 10
unit trains comprised of similar railcars from the same Coal
source shipped to the Energy Center will be used for any
unavailable weights.
(c) Weighing Audits and Adjustments. Buyers shall have the
right to have a representative present at any and all times to
observe weighing of the Coal and inspection and certification of
Seller's Scales. If any party should at any time question the
accuracy of Seller's Scales, such party may request a prompt test
of Seller's Scales at its expense by the State of Wyoming or an
entity mutually agreed upon by Agent/Operator and Seller. If any
such test reveals an error in weight in excess of one and one-
half percent, then the weights of Coal shipped during one-half of
the period since the last preceding test shall be adjusted by the
amount of the error shown, an appropriate debit or credit
memorandum shall be furnished to Buyers by Seller and Seller's
Scales shall be promptly adjusted at Seller's expense.
Section 11. Sampling and Analysis.
(a) Sampling Procedure. Coal to be delivered hereunder
shall be sampled at the Mine, Belle Ayr Mine or Alternate Source
Mine on a continuous basis:
(i) at the batch loading sampling system or
(ii) prior to ultimate loading into railcars.

Such sampling shall be performed in accordance with methods
approved by ASTM, as the same may be supplemented or modified
from time to time, or by such other methods as may mutually be
agreed upon by Seller and Buyers. Gross samples of Coal so taken
shall represent a unit train shipment; be representative of, and
identified as to, each shipment of Coal delivered hereunder to
Buyers; and be taken by equipment and in manners that meet the
requirements of ASTM Standard D2234 (Standard Test Methods for
Collection of a Gross Sample of Coal). Sampling may also be done
by Buyers at destination. Buyers and Seller shall each have the
right to have a representative present in order to observe any
sampling and analysis done by the other and to take check samples
of the Coal. All of Seller's samples shall be divided into three
parts in the manner specified by ASTM Standard D2013 (Standard
Method of Preparing Coal Samples for Analysis) and put into
suitable airtight containers. One part shall be retained and
analyzed by Seller pursuant to applicable ASTM Standards; one
part shall be delivered to Agent/Operator or Buyers' designee by
mutually agreeable means and analyzed by Buyers pursuant to
applicable ASTM Standards; and the third part shall be retained
by Seller in one of the aforesaid containers, properly sealed and
labeled, for not less than 30 days after the last day of the
month in which the sample was taken, to be analyzed if a dispute
arises due to a difference between Buyers' and Seller's analysis.
(b) Analysis Procedures. Seller shall perform a "short
proximate" (for moisture, ash, sulfur and gross calorific value)
analysis and any other analyses mutually agreed upon for each
shipment as soon as practicable upon completion of loading and
shall notify Agent/Operator of the results thereof prior to
receipt of the Coal at the Energy Center. The analysis methods
for moisture, ash, sulfur, gross calorific value and coal size
designation shall be performed in accordance with ASTM Standards
D3302 (Standard Test Method for Total Moisture in Coal), D3174
(Standard Test Method for Ash in the Analysis Sample of Coal and
Coke from Coal), D4239 (Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube
Furnace Combustion Methods), D3286 (Standard Test Method for
Gross Calorific Value of Coal and Coke by the Isoperibol Bomb
Calorimeter) and D4749 (Standard Test Method for Performing the
Sieve Analysis of Coal and Designating Coal Size). The procedure
for determining grindability shall be agreed to in writing by
Buyers and Seller. Each party hereto shall assume the cost of
all sampling and analyses performed by it. The analysis of the
third part of any sample, should its analysis be found necessary,
shall be made by an independent commercial testing laboratory
(pursuant to applicable ASTM Standards), mutually chosen, and the
results of such analysis shall be controlling. The cost of the
analysis made by such commercial laboratory shall be shared
equally by Seller and Buyers.
(c) Analysis Reports. Seller shall mail copies of each
shipment analysis and monthly analyses to Agent/Operator as
completed and, further, shall furnish a monthly report to
Agent/Operator, including a summary of the individual shipment
analyses and weights serving as the basis for invoicing.
Such analyses shall be deemed acceptable and binding unless
protested by Agent/Operator within 30 days after receipt of the
applicable monthly report.
Section 12. Records and Audits.
(a) Recordkeeping. Seller shall keep accurate and
satisfactory records and books of account in compliance with
generally accepted accounting principles showing all weights and
analyses of Coal, costs, payments, invoices, and/or revisions,
adjustments, credits, debits pertaining to Price, Incremental
Price, Deficient Quantity Charge, Additional Charge and annual
true-up of Annual Base Quantity pursuant to Section 9(c) hereof
and
all other information and data required for the purposes of this
Agreement ("Records").
(b) Records' Revisions - Calculations. Each time the
Records are revised in accordance with this Agreement and at any
other time upon 30 days' notice in writing from Buyers, Seller
shall furnish to Buyers a detailed statement showing the
revisions and/or calculations of the Records and the basis
thereof.
(c) Right to Audit. At all reasonable times,
Agent/operator shall have the right to have the applicable
Records audited at Agent/Operator's expense for the purpose of
verifying all Records. Such audit shall be mutually scheduled at
least 30 days prior to the start of the Audit.
(d) Right to Audit Invoiced Items. The Invoiced Items
shall consist of the Price, Incremental Price, Deficient Quantity
Charge, Additional Charge and any annual true-up payment.
The Invoiced Items shall be binding upon Buyers unless the audit
is completed, the written audit report is submitted to Seller,
and Buyers take exception to said Invoiced Items within one year
of the end of the Contract Year in which any change was made to
an Invoiced Item. At Agent/Operator's option any audit shall be
made:
(i) by the nationally recognized firm of certified
public accountants as shall then be
retained by Seller or Buyers or;

(ii) by Buyers' internal audit staffs.

Such audit report shall set forth, in reasonable detail, all
data necessary to verify any such adjustments of the Invoiced
Items. Any errors made by Seller in making such adjustments as
disclosed by any such audit shall be promptly corrected by making
appropriate retroactive changes, except that claimed errors
resulting from an interpretation of this Agreement by such
auditors
not agreed to by Seller's General Counsel shall be subject to
resolution pursuant to Section 16 hereof.
Section 13. Force Majeure.
(a) Defined. As used herein, the term "Force Majeure shall
mean any and all causes beyond the control and without fault or
negligence of the party affected thereby, including, without
limitation, acts of God, acts or orders of public authorities
(including civil and military authorities and courts of competent
jurisdiction) , acts of the public enemy, embargoes,
insurrections, riots, labor disputes, labor or material
shortages, fires, explosions, floods, river freeze-ups,
breakdowns of or damage to plants, equipment or facilities
(including emergency outages of equipment or facilities to make
repairs to avoid breakdowns thereof or damage thereto) which
wholly or partially prevent or interfere with the mining,
hauling, processing or loading of Coal by Seller or the
receiving, transporting and/or delivering by the carrier thereof,
or the utilizing thereof by Buyers.
(b) Effect Hereunder. If, because of Force Majeure, any
party hereto is unable to carry out any of its obligations under
this Agreement (other than the obligation of a party to pay money
in connection with the performance of this Agreement), and if
such party shall promptly give to the other parties concerned
written notice of such Force Majeure, then the obligation of the
party giving such notice shall be suspended to the extent made
necessary by such Force Majeure and during its continuance;
provided, the party giving such notice shall use its best efforts
to eliminate the cause of such Force Majeure insofar as possible
with a minimum of delay; provided further, any party shall have
the right to
settle or resolve any labor dispute with its employees in its
sole discretion. The parties receiving notice shall, within 30
days, accept or reject the claim of Force Majeure; provided, such
party shall have been afforded reasonable time and access to
appropriate personnel and records to investigate the Force
Majeure.
(c) Deficiencies in Delivery. Any deficiencies in delivery
of Coal hereunder caused by a Force Majeure which are related to
the transportation of Coal from the Mine, Belle Ayr Mine or
Alternate Source Mine to the Energy Center, except where Buyers
have received notice from the rail carrier transporting Coal that
it has incurred a Force Majeure under the rail tariff or
contract, shall be made up as soon as possible unless such Force
Majeure has a duration of 7 or more consecutive days in which
case only that part of the deficiency related to the first 7 days
of such Force Majeure will have to be made up. All other
deficiencies in deliveries of Coal hereunder caused by Force
majeure shall not be made up except by mutual consent. Any
quantity of Coal that would have been shipped during a period of
Force Majeure shall be credited against the Annual Base Quantity
of Coal (by an amount equal to the product obtained by
multiplying the number of days of such suspension by the result
obtained by dividing the Annual Base Quantity by 365). In the
event Force Majeure causes only a partial reduction in the total
quantity of Coal Seller can deliver, Seller shall deliver to
Buyers its pro rata share of the coal produced from the Mine,
Belle Ayr Mine or Alternate Source Mine, if applicable, during
the continuance of such partial reduction.
(d) Rights to Suspend and Purchase and/or Sell to Others.
Either party hereto shall have the right to elect to suspend the
purchase or sale of Coal, as the case may be, for the period of
time during which such Force Majeure may exist, and Buyers, if
they so elect, in the case of an event of Force Majeure (i)
declared by Seller without regard to duration or (ii) caused by
the inability of Buyers' contract rail carrier(s) to transport
Coal from the Mine, Belle Ayr Mine or Alternate Source Mine to
the Energy Center for a period of 14 or more consecutive days,
shall have the right during such period to purchase coal from
other sources and Seller, if it so elects, shall have the right
during such period to sell coal to others. The quantity of coal
so purchased from other sources shall be credited against the
Annual Base Quantity
If Buyers suspend shipments pursuant to this Section 13,
then the Annual Base Quantity shall be reduced by an amount equal
to the product obtained by multiplying the number of days of such
suspension by the result obtained by dividing the Annual Base
Quantity by 365.
(e) Right to Terminate Agreement. Notwithstanding the
foregoing, in the event the party which gave notice of an event
of Force Majeure which has caused such party to be unable to
comply substantially with such party's obligations hereunder has
not substantially eliminated such Force Majeure within 12 months
after so notifying the other party, such other party shall have
the right, at its option, to terminate this Agreement without any
penalty by notifying the party which gave such notice of Force
Majeure of its election to do so. Any such termination shall be
effective 30 days after the giving of such notice.
(f) Exception to Force Majeure. Notwithstanding the
foregoing provisions of this Section 13, it is expressly
understood that any prohibition to take deliveries of, or to
utilize Coal subject hereto, which is imposed upon Buyers by
means of laws, regulations or orders of a court or administrative
body, whether or not such event is beyond the control of Buyers,
shall not for the purposes herein negate the provisions set forth
in Section 15 hereof.
Section 14. Relief From Economic Hardship.
(a) Notice Required. Seller and Buyers acknowledge the
possibility of either party sustaining an economic hardship under
this Agreement because of conditions which were unforeseeable on
January 1, 1993. At any time either party believes it has
sustained an economic hardship under this Agreement and wishes to
invoke the provisions of this Section 14 to obtain relief, if
any, it shall give notice in writing to the other party setting
forth documentary proof of the following:
(i) the existence, nature, cause, extent and impact of
such economic hardship; and

(ii) the facts establishing that the conditions causing
such economic hardship were unforeseeable.

The party sending such notice shall also state the relief
which it considers reasonable and appropriate to eliminate such
economic hardship.
(b) Consideration of Request. Upon receipt of the notice
set forth above, the' party receiving such notice shall consider
the documentary proof submitted and any other relevant matters,
and if (subject to the provisions of section 14(c) hereof), it,
in its judgement, finds that the party sending such notice has
sustained an economic hardship due to the cause stated in such
notice and is entitled to relief hereunder, the party receiving
such notice shall give reasonable and appropriate relief to the
party sustaining the economic hardship. The party receiving such
notice shall not arbitrarily refuse to find that the other party
has sustained an
economic hardship nor arbitrarily deny reasonable and appropriate
relief to eliminate such hardship if found to exist.
<PAGE>
(c) Exceptions. Economic hardship arising from any of the
following types of causes or conditions shall not be grounds for
relief hereunder:
(i) where the cause or condition is provided for in
this Agreement;
(ii) where the cause or condition results from a matter
involving the internal operations of the party
claiming that it has sustained an economic
hardship;

(iii) changes in the market for coal resulting from
competitive factors;
(iv) availability or costs of alternative fuels; or
(v) the prohibition to take deliveries of, or to
utilize the Coal subject hereto, the effect of
which is provided for in Section 15 hereof.

(d) Effect of Refusal. If the party receiving a request
referred to in Section 14(a) hereof, (i) elects to negotiate
regarding the matters set forth in such request but an
appropriate amendment of this Agreement regarding such matters
has not been fully executed within 90 days following the date of
such request, or (ii) refuses to agree to or negotiate regarding
such matters, then the party which made such request may, with
the concurrence of the other party, submit such matters to
arbitration pursuant to Section 16 hereof or, if the other party
does not agree to submit such matters to arbitration hereunder,
exercise any other right or remedies available to it at law or in
equity.
Section 15. Compliance with Anti-Pollution Laws and
Regulations, etc.
(a) Termination Charge. The parties hereto recognize that,
during the Term, legislative, administrative or regulatory bodies
or courts having competent jurisdiction over the subject matter
herein may enact laws, regulations, or issue orders such as, but
not limited to, those relating to air pollution, the effect of
which will make it impossible or impractical for Buyers to
utilize the Coal subject hereto without substantially changing or
altering its utilization, equipment or transportation to the
Energy Center. Any such laws, regulations or orders may pertain
to, but would not necessarily be limited to, sulfur content of
the Coal. If any such laws, regulations or orders are imposed
and, as a result thereof, Buyers, in their sole judgment, decide
that it will be to their best interest not to utilize the Coal
subject hereto, notwithstanding the provisions of this Agreement
to the contrary, Buyers shall have the right to terminate this
Agreement; provided, before Buyers can terminate this Agreement
pursuant to this Section 15, Buyers and Seller shall meet to
attempt to develop a plan that would allow Buyers to continue to
utilize the Coal under this Agreement. Seller shall pay all
costs to develop any plan contemplated by this Section 15,
including, but not limited to, any professional services incurred
by Buyers. The plan design and costing shall be approved by
Buyers in their sole discretion. The plan design, development
and implementation cost shall be paid by Seller, in its sole
discretion. If Seller refuses to pay the total plan design,
development and implementation cost, then Buyers may terminate
this Agreement pursuant to this Section 15; provided, Buyers
agree to pay Seller an annual termination charge
("Termination Charge") for the remaining life of this Agreement.
The Termination Charge shall be equal to $0.0120 per MMBtu
multiplied by the Annual Base Quantity. During any period in
which Buyers are obligated to pay the Termination Charge, Seller
shall use its reasonable efforts to sell the Coal which Buyers
are obligated to purchase hereunder to others.
(b) Termination Charge Reduction. After Seller has shipped
all of the coal contracted from the Mine to others in any
Contract Year, should Seller sell any of the Coal which Buyers
were obligated to purchase hereunder during said Contract Year to
others at a sales price, which is greater than the Price that
would have been in effect for such Contract Year, then, the
Termination Charge shall be reduced by an amount equal to the
product of the difference between such sales price and Price
multiplied by the quantity of such coal sold to others.
(c) Termination Charge - Effect of Other Contracts. In the
event there are other agreements for coal produced at the Mine
that contain a similar termination charge that are also
terminated, the portion of said contracted quantity that is sold
shall be prorated. Said credits are to become effective for all
coal sold over and above the total unaffected portion of the
Mine's contracted annual production. During any period in which
Buyers are obligated to pay the Termination Charge, Seller shall
use its reasonable efforts to sell the entire output of the Mine
to others.
(d) Termination Charge - Seller's Obligation/Buyers'
Recourse. Rejection by Seller of a bona fide offer to purchase
coal at a price at least equal to that which would then be
currently effective under this Agreement shall relieve Buyers of
their obligation to pay the Termination Charge attributable to
said
quantity. Seller shall keep Buyers informed as to offers and
sales of said coal.
Section 16. Arbitration.
(a) Pre-Arbitration Procedure. With respect to any
controversy, claim, counterclaim, dispute, difference or
misunderstanding arising out of or relating to the interpretation
or application of any term or provision of this Agreement
("Dispute") any party may provide written notice to all the other
parties by certified mail, return receipt request ("Notice") of
the existence of a Dispute. The parties shall for a period of 30
calendar days following the date of the Notice that a Dispute
exists engage in good faith discussions and negotiations in an
attempt to resolve such Dispute. If, by the end of such 30 day
period, unless such period is extended by mutual agreement of the
parties, the parties have been unable to resolve such Dispute,
they shall have a period of 15 calendar days to mutually agree to
arbitrate such Dispute pursuant to the procedure set forth below.
If, at the end of such 15 day period the parties have not
mutually agreed to arbitrate such Dispute, then such Dispute may
be resolved in any federal or state court located in the State of
Colorado or the appellate courts thereof.
(b) Arbitration Procedure. Any arbitration hereunder shall
be subject to and conducted pursuant to the procedures set forth
in the Rules for Commercial Arbitration of the American
Arbitration Association and the Federal Arbitration Act;
provided, the parties shall agree prior to arbitration as to
whether or not the arbitration award or decision shall be binding
upon the parties.
Section 17. Notices.
(a) Notices to be in writing; Exceptions; Methods of
Delivery. Any notice, request, consent, demand, report or
statement, which is given to or made upon either party hereto by
the other party hereto under any of the provisions of this
Agreement, shall be in writing unless it is otherwise
specifically provided herein, and shall be treated as duly
delivered when the same is either (i) personally delivered to the
President or a Vice President of Buyers in case of a notice to be
given Buyers, or personally delivered to the President or a Vice
President of Seller in the case of a notice to be given to
Seller, or (ii) deposited in the United States mail, registered
or certified, postage prepaid, and properly addressed as follows;
If the notice is to Buyers:
Western Resources, Inc.
P. 0. Box 889
Topeka, Kansas 66601
Attention: Executive Vice President - Electric
Production

With a copy to:

Western Resources, Inc.
P. 0. Box 889
Topeka, Kansas 66601
Attention: Director, Fuels

or to such other officer or such other address as Buyers shall
have designated by due notice to Seller; and

If the notice is to Seller;

Amax Coal West, Inc.
165 S. Union Boulevard
Suite 1000
P.O. Box 280219
Lakewood, Colorado 80228-0219
Attention: Vice President,
Law and Governmental Affairs

or to such other officer or such other address as Seller shall
have designated by due notice to Buyers.
(b) Notices as to Operating Matters. Any notice, request
or demand pertaining to matters of an operating nature may be
delivered by mail, messenger, telephone, telegraph, facsimile,
electronic communications or orally to such agent of the party
hereto being notified as may be appropriate and, if given by
telephone, telegraph or orally, shall be confirmed in writing as
soon as practicable thereafter, if the party to whom the notice
is given so requests in any particular instance.
Section 18. Efficient and Economical operations.
Seller covenants that all of its activities relating to the
production, sale and delivery of Coal subject hereto and
activities relating to a New Law in Section 8(c) hereof shall, at
all times, be conducted efficiently, economically and in such
manner to be consistent with good and standard operating
practices and procedures.
Section 19. Successors and Assigns.
This Agreement shall inure to the benefit of and be binding
upon the parties hereto and their respective successors and
assigns; provided, this Agreement may not be assigned by either
Seller or Buyers without the written consent of all other
parties, except
(i) an assignment of the Mine and Belle Ayr Mine from Seller
to another wholly-owned subsidiary of Amax Coal
Industries, Inc. or to a wholly-owned subsidiary of Amax
Energy, Inc. shall not be considered an assignment of
this Agreement and

(ii) in the following cases where no such consent will be
required:

(A) pledge, assignment or other security arrangement to
secure indebtedness incurred for the purpose of or
in connection with performance under this Agreement,
specifically including any financing arrangements
deemed advisable by Seller (such as development
carveouts and/or production payments) or any
financing arrangements deemed advisable by Buyers
(such as mortgages and deeds of trust or indentures
supplemental thereto relating to the Energy Center);

(B) assignment to a successor in interest of a part or
all of the assets of any party hereto by way of a
merger, consolidation, sale of substantially all of
the assets, divestiture pursuant to an order or
decree of a court, or similar corporate
reorganization, provided no such
assignment shall be effective unless and until such
assignee shall assume in writing the obligations of
the assignor; or

(C) assignment by any Buyer of its interest, or any part
thereof, in this Agreement pursuant to partnership,
joint ownership, joint venture or other arrangement
with a third party or parties in connection with the
ownership and/or operation of the Energy Center.

Buyers shall not unreasonably withhold their consent to
assignment of this Agreement to another company affiliated with
AMAX Inc., a New York corporation, provided that AMAX Inc. shall
guarantee performance by such affiliate of all obligations under
this Agreement.
Section 20. Several Interests, Agent/Operator and Liability
of Buyers
(a) Energy Center Owners. Buyers' respective interests
in the Energy Center are:
Western Resources, Inc. 64%
Kansas Gas and Electric Company 20%
Missouri Public Service, a division of UtiliCorp
United Inc.
8%
WestPlains Energy, a division of utilicorp United Inc.
8%

(b) Buyers' Obligations - Several. The property and
contractual interests of Buyers in, and their respective rights,
duties, obligations and liabilities under this Agreement shall be
several and not joint and shall be proportional to their
respective interest in the Energy Center. If the respective
interests of Buyers in the Energy Center change during the Term,
then their respective property and contractual interests in, and
their rights, duties, obligations and liabilities under this
Agreement shall be adjusted accordingly upon written notice by
Buyers to Seller.
(c) Agent/Operator. Agent/Operator is hereby authorized to
act on behalf of all Buyers on all matters arising under this
Agreement. In particular, Seller shall accept instructions and
commitments of Agent/Operator and such actions by Agent/Operator
shall bind all Buyers and Seller in the same manner as if the
instructions or commitments were made by each Buyer on its own
behalf. Any dispute any Buyer has with Seller shall be
prosecuted only by Agent/operator.
Section 21. Miscellaneous Provisions.
(a) Nonwaiver. The failure of any party hereto to insist
in any one or more instance upon strict performance of any
provision of this Agreement by any other party hereto, or to take
advantage of any of its rights hereunder, shall not be construed
as a waiver by it of any such provision or the relinquishment by
it of any such rights in respect of any subsequent nonperformance
of such provision, but the same shall continue and remain in full
force and effect.
(b) Remedies. Each remedy specifically provided for under
this Agreement shall be taken and construed as cumulative and in
addition to every other remedy provided for herein, by law or
inequity.
(c) Amendments. Any and all amendments, supplements
and modifications to this Agreement shall be in writing and
signed by the parties hereto.
(d) Indemnity. Each party hereby agrees to defend,
indemnify, save and hold all other parties harmless from and
against all loss, cost and expense arising out of injuries to or
death of any person or persons resulting from willful acts or
negligence of such party, its agents and employees, except that
said agreement of indemnity shall not apply to any injuries to or
the death of such party's own employees acting within the scope
of their employment, even though another party may have been
negligent in connection with the related occurrence.
(e) Headings Not to Affect Construction. The headings to
the respective sections and paragraphs of this Agreement are
inserted for convenience of reference and are neither to be taken
to be any part of the provisions herein nor to control or affect
the meaning, construction or effect of the same.
(f) Written Instrument Contains Entire Agreement.
This written instrument contains the entire agreement
between the parties hereto in respect of the subject matter, and
there are no other understandings or agreements between said
parties, or any of them, in respect thereof.
(g) Controlling Law and Consent to Jurisdiction.
This Agreement shall be governed by and construed according
to the laws of the State of Colorado. Buyers and Seller hereby
irrevocably agree any legal suit, action or proceeding (each an
"Action") arising out of or relating, directly or indirectly, to
this Agreement shall only be brought in the courts of the State
of Colorado or the United States of America for the District of
Colorado and any applicable appellate courts (collectively the
"Courts") and irrevocably consents to service of process outside
the territorial jurisdiction of the Courts. In addition, each
party, in its own behalf, irrevocably waives (i) any objection to
the laying of venue of any Action brought in the Courts, (ii) any
claim that any Action brought in any Court has been brought in an
inconvenient forum, and (iii) any objection, with respect to any
Action brought in any Court, that such Court does not have
jurisdiction over any party.
(h) Rounding of Calculations. Except as otherwise
specified in this Section 21(h) all computations under this
Agreement shall be rounded to four decimal places. All
originally published index numbers shall not be rounded. The
RTRC, IC, RTRCIP and ICIP shall be rounded to the nearest one
ten-thousandth of a dollar. Tons shall be rounded to the
nearest one-hundredth of a ton. All aggregate dollar and
Btu amounts shown on an invoice shall be rounded to the nearest
whole cent or Btu; and the Price, Incremental Price, Additional
Charge and Deficient Quantity Charge shall be rounded to the
nearest ten-thousandth of a dollar. However, if there is no
nearest one-hundredth of a cent, tenth of a cent, cent, Btu, one
ten-thousandth of a dollar or hundredth of a ton, as the case may
be, then the relevant number shall be rounded to the nearest even
fourth decimal place, one-hundredth of a cent, tenth of a cent,
cent, Btu, one ten-thousandth of a dollar or hundredth of a ton.
For example, $0.54825 would be rounded to $0.5482 and $0.54835
would be rounded to $0.5484.
provision in any other jurisdiction.
(i) Severability of Provisions. Any provision of this
Agreement which is prohibited or unenforceable under federal or
Colorado law shall be ineffective to the extent of such
prohibition or enforceability without invalidating the remaining
provisions hereof or affecting the validity or enforceability of
such provision in any other jurisdiction.
(j) Execution of Counterparts. This Agreement may be
simultaneously executed in any number of counterparts, and all
such counterparts shall constitute but one and the same
instrument.
(k) Confidentiality. All of the provisions hereof are
confidential and proprietary in nature and shall not be disclosed
in whole or in part by any party without the prior written
consent of all parties hereto, which consent shall not be
unreasonably withheld; except, (i) pursuant to any existing or
future order of or upon demand of regulatory bodies having
jurisdiction and their staffs, including, but not limited to
disclosure to the Kansas Corporation Commission by Buyer,
WestPlains Energy, under docket no. 106,850-U, dated April 19,
1977; outside accounting firms retained by a party for audit or
tax purposes; outside counsel retained by a party; and any
assignee or successor to the Energy Center ownership interests of
Buyers; any such disclosures shall be upon a restricted,
proprietary and confidential basis; or (ii) as required by law.
IN WITNESS WHEREOF, the parties have executed this Agreement
in their respective corporate names, as of the date first above
written.
Attest: Amax Coal West, Inc.

/s/ George Womack By: /s/
Asst. Secretary President

Attest: Western Resources, Inc.

/s/ Richard D. Terrill By: /s/ William E. Brown

Secretary
President
KPL Division

<PAGE>
Attest: Kansas Gas and Electric Company

/s/ Richard D. Terrill By:/s/ Kent R. Brown
Secretary President
Kansas Gas and Electric
Company

Missouri Public Service, a
division of Utilicorp United,
Inc.

/s/ By:/s/
Assistant Secretary Division President

WestPlains Energy, a
division of
Utilicorp United, Inc.

/s/ By:/s/
Secretary/Assistant Division President

Exhibit 10(b)
Request 0053

TRANSPORTATION-STORAGE SERVICE AGREEMENT
UNDER RATE SCHEDULE TSS

THIS AGREEMENT is made and entered into this 1st day of
October, 1993 by and between WILLIAMS NATURAL GAS COMPANY, a
Delaware corporation, having its principal office in Tulsa,
Oklahoma, hereinafter referred to as "WNG" and WESTERN RESOURCES,
INC., a Kansas corporation, having its principal office in
Topeka, Kansas, hereinafter referred to as "Shipper."

IN CONSIDERATION of the premises and of the mutual covenants
and agreements herein contained, WNG and Shipper agree as
follows:

ARTICLE I
QUANTITY

1.1 Subject to the provisions of this Agreement and of
WNG's Rate Schedule TSS, WNG agrees to receive such quantities of
natural gas as Shipper may cause to be tendered to WNG at the
Primary Receipt Point(s) designated on Exhibit A which are
selected from WNG's Master Receipt Point List, as revised from
time to time, for transportation and storage on a firm basis;
provided, however, that in no event shall WNG be obligated to
receive on any day in excess of the Maximum Daily Quantity (MDQ)
for each Primary Receipt Point or of the Maximum Daily
Transportation Quantity (MDTQ) for all Primary Receipt Points
within any area, all as set forth on Exhibit A.

1.2 WNG agrees to deliver and Shipper agrees to accept (or
cause to be accepted) at the Primary Delivery Point(s) taken from
the Master Delivery Point List and designated on Exhibit B a
quantity of natural gas thermally equivalent to the quantity
received by WNG for transportation and withdrawn from storage as
provided in Article 1.3 hereunder less appropriate reductions for
fuel and loss as provided in WNG's Rate Schedule TSS; provided,
however, that WNG shall not be obligated to deliver on any day
quantities in excess of the MDQ for each Primary Delivery Point
or in excess of the MDTQ within any area for all Primary Delivery
Points, all as set forth on Exhibit B.

1.3 Subject to the provisions of this Agreement and of
WNG's Rate Schedule TSS, WNG agrees to (a) inject and store such
quantities of natural gas up to the Maximum Storage Quantity
(MSQ) and the Maximum Daily Injection Quantity (MDIQ) as Shipper
may cause to be tendered to WNG for injection into storage, less
appropriate reductions for fuel and loss, and (b) withdraw such
quantities of natural gas up to Shipper's gas in storage and the
Maximum Daily Withdrawal Quantity (MDWQ) reflected on Exhibit C,
all on a firm basis.
Request 0053

ARTICLE II
DELIVERY POINT(S) AND DELIVERY PRESSURE

2.1 Natural gas to be delivered hereunder by WNG to or on
behalf of Shipper shall be delivered at the outlet side of the
measuring station(s) at or near the Delivery Point(s) designated
on Exhibit B at WNG's line pressure existing at such Delivery
Point(s).

ARTICLE III
RATE, RATE SCHEDULE AND GENERAL TERMS AND CONDITIONS

3.1 Shipper shall pay WNG each month for all service
rendered hereunder the then-effective, applicable rates and
charges under WNG's Rate Schedule TSS, as such rates and charges
and Rate Schedule TSS may hereafter be modified, supplemented,
superseded or replaced generally or as to the service hereunder.
Shipper agrees that WNG shall have the unilateral right from time
to time to file with the appropriate regulatory authority and
make effective changes in (a) the rates and charges applicable to
service hereunder, (b) the rate schedule(s) pursuant to which
service hereunder is rendered, or (c) any provision of the
General Terms and Conditions incorporated by reference in such
rate schedule(s); provided, however, Shipper shall have the right
to protest any such changes.

3.2 This Agreement in all respects is subject to the
provisions of Rate Schedule TSS, or superseding rate schedule(s),
and applicable provisions of the General Terms and Conditions
included by reference in said Rate Schedule TSS, all of which are
by reference made a part hereof.

ARTICLE IV
TERM

4.1 This Agreement shall become effective on the date of
execution and shall continue in full force and effect for an
original term until 7:00 a.m., local time on October 1, 2013;
provided, however, this Agreement shall be considered as renewed
and extended beyond such original term for successive five (5)
year terms thereafter, unless canceled, effective at the end of
the primary term or at the end of any subsequent five (5) year
term, by six (6) months advance written notice by either party.

Request 0053

notice prior to any suspension or termination of service.
Service may continue hereunder if within the thirty-day notice
period satisfactory assurance of payment is made by Shipper in
accord with Article 18 of the General Terms and Conditions.
Suspension or termination of this Agreement shall not excuse
Shipper's obligation to pay all demand and other charges for the
original term of the
Agreement.

ARTICLE V
NOTICES

5.1 Unless otherwise agreed to in writing by the parties,
any notice, request, demand, statement or bill respecting this
Agreement shall be in writing and shall be deemed given when
placed in the regular mail or certified mail, postage prepaid and
addressed to the other party, or sent by overnight delivery
service, or by facsimile, at the following addresses or facsimile
numbers, respectively:

To Shipper:

Billing:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612 Attn: Gas Supply Dept.
Phone: 913/575-6377
Fax: 913/575-6405

Notices:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612 Attn: Gas Supply Dept.
Phone: 913/575-1910
Fax: 913/575-6405

To WNG:

Payments:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Revenue Accounting
<PAGE>
All Notices:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Manager - Transportation Services
Fax: 918/588-3108

Request 0053

ARTICLE VI
MISCELLANEOUS

6.1 The interpretation, performance and enforcement of this
Agreement shall be construed in accordance with the laws of the
State of Oklahoma.

6.2 As of the date of execution of Exhibits A, B, and C
attached to this Agreement, such executed exhibits shall be
incorporated by reference as part of this Agreement. The parties
may amend Exhibits A, B, and C by mutual agreement, which
amendment shall be reflected in a revised Exhibit A, B, and C and
shall be incorporated by reference as part of this Agreement.

6.3 Any Service Agreements under Rate Schedule TSS shall
not cover service under both TSS-P and TSS-M.

6.4 OTHER THAN AS MAY BE SET FORTH HEREIN, WNG MAKES NO
OTHER WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WITHOUT
LIMITATION WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR
MERCHANTABILITY.

6.5 Other Miscellaneous

IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.

ATTEST: WILLIAMS NATURAL GAS COMPANY

By: By: /s/ James O. Henderson

Assistant Secretary Title: Director,
Transportation
Services

ATTEST/WITNESS: WESTERN RESOURCES, INC.

By: /s/ Stacy F.Kramer By: /s/ Richard H. Tangeman
Title Assistant Secretary Title: Assistant Vice President,
Gas Supply, As Shipper

Exhibit 10(c)
Request 0055

TRANSPORTATION-STORAGE SERVICE AGREEMENT
UNDER RATE SCHEDULE TSS

THIS AGREEMENT is made and entered into this 1st day of
October, 1993 by and between WILLIAMS NATURAL GAS COMPANY, a
Delaware corporation, having its principal office in Tulsa,
Oklahoma, hereinafter referred to as "WNG," and WESTERN
RESOURCES, INC., a Kansas corporation, having its principal
office in Topeka, Kansas, hereinafter referred to as "Shipper."

IN CONSIDERATION of the premises and of the mutual covenants
and agreements herein contained, WNG and Shipper agree as
follows:

ARTICLE I
QUANTITY

2.1 Natural gas to be delivered hereunder by WNG to
or on behalf of Shipper shall be delivered at the outlet
side of the measuring station (s) at or near the Delivery Point
(s) designated on Exhibit 3 at WNG's line pressure existing
at such Delivery Point(s).
ARTICLE III
RATE, RATE SCHEDULE AND GENERAL TERMS AND CONDITIONS

4.1 This Agreement shall become effective on the date of
execution and shall continue in full force and effect for an
original term until 7:00 a.m., local time on October 1, 1994.

4.2 This Agreement may be suspended or terminated by WNG in
the event Shipper fails to pay all of the amount of any bill
rendered by WNG hereunder when that amount is due; provided,
however, WNG shall give Shipper and the FERC thirty (30) days
notice prior to any suspension or termination of service.
Service may continue hereunder if within the thirty-day notice
period satisfactory assurance of payment is made by Shipper in
accord with Article 18 of the General Terms and Conditions.
Suspension or termination of this Agreement shall not excuse
Shipper's obligation to pay all demand and other charges for the
original term of the Agreement.
<PAGE>
Request 0055

ARTICLE V
NOTICES

To Shipper:

Billing:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612 Attn: Gas Supply Dept.
Phone: 913/575-6377
Fax: 913/575-6405

Notices:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612 Attn: Gas Supply Dept.
Phone: 913/575-1910
Fax: 913/575-6405

To WNG:

Payments:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Revenue Accounting

All Notices:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Manager - Transportation Services

Fax: 918/588-3108

<PAGE>
Release 0055

ARTICLE VI
MISCELLANEOUS

6.1 The interpretation, performance and enforcement of this
Agreement shall be construed in accordance with the laws of the
State of Oklahoma.

6.3 Any Service Agreements under Rate Schedule TSS shall
not cover service under both TSS-P and TSS-M.

6.4 OTHER THAN AS MAY BE SET FORTH HEREIN, WNG MAKES NO
OTHER WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WITHOUT
LIMITATION WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR
MERCHANTABILITY.

6.5 Other Miscellaneous

IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.

ATTEST: WILLIAMS NATURAL GAS COMPANY

By: By:
Assistant Secretary Title

ATTEST/WITNESS: WESTERN RESOURCES, INC.

By: /s/ Stacy F. Kramer By: /s/ Richard H. Tangeman
Title Assistant Secretary Title: Asst. Vice President,
Gas Supply, As Shipper

Exhibit 10(d)
Request 0195

TRANSPORTATION-STORAGE SERVICE AGREEMENT
UNDER RATE SCHEDULE TSS

THIS AGREEMENT is made and entered into this lst day of
October, 1993 by and between WILLIAMS NATURAL GAS COMPANY, a
Delaware corporation, having its principal office in Tulsa,
Oklahoma, hereinafter referred to as "WNG" and WESTERN RESOURCES,
INC., a Kansas corporation, having its principal office in
Topeka, Kansas, hereinafter referred to as "Shipper."

IN CONSIDERATION of the premises and of the mutual covenants
and agreements herein contained, WNG and Shipper agree as
follows:
ARTICLE I
QUANTITY

Request 0195

ARTICLE II
DELIVERY POINT(S) AND DELIVERY PRESSURE

2.1 Natural gas to be delivered hereunder by WNG to or
on behalf of Shipper shall be delivered at the outlet side of the
measuring station(s) at or near the Delivery Point(s) designated
on Exhibit B at WNG's line pressure existing at such Delivery
Point(s).

ARTICLE III
RATE, RATE SCHEDULE AND GENERAL TERMS AND CONDITIONS

ARTICLE IV
TERM

4.1 This Agreement shall become effective on the date of
execution and shall continue in full force and effect for an
original term until 7:00 a.m., local time on October 1, 1994.

To Shipper:

Billing:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612
Attn: Gas Supply Dept.
Phone: 913/575-6377
Fax: 913/575-6405

Notices:

WESTERN RESOURCES, INC.
818 Kansas Ave.
Topeka, KS 66612
Attn: Gas Supply Dept.
Phone: 913/575-1910
Fax: 913/575-6405

To WNG:

Payments:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Revenue Accounting

All Notices:

Williams Natural Gas Company
P. 0. Box 3288
Tulsa, OK 74101
Attention: Manager - Transportation Services
Fax: 918/588-3108

Request 0195

ARTICLE VI
MISCELLANEOUS

6.1 The interpretation, performance and enforcement of this
Agreement shall be construed in accordance with the laws of the
State of Oklahoma.

6.3 Any Service Agreements under Rate Schedule TSS shall
not cover service under both TSS-P and TSS-M.

6.4 OTHER THAN AS MAY BE SET FORTH HEREIN, WNG MAKES NO
OTHER WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WITHOUT
LIMITATION WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR
MERCHANTABILITY.

6.5 Other Miscellaneous

IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.

ATTEST: WILLIAMS NATURAL GAS COMPANY

By: By:
Assistant Secretary Title

ATTEST/WITNESS: WESTERN RESOURCES, INC.

By: /s/ Stacy F. Kramer By: /s/ Richard H. Tangeman
Title Assistant Secretary Title: Asst. Vice President,
Gas Supply, As Shipper

WESTERN RESOURCES DEFERRED COMPENSATION PLAN

ARTICLE I

Purpose

The purpose of the Western Resources Deferred Compensation
Plan (hereinafter referred to as the "Plan") is to allow deferral
of income for a specified period and to provide funds for
retirement or death for certain executive and management
employees (and their beneficiaries) of Western Resources, Inc.
It is intended that the Plan will aid in retaining and attracting
employees of exceptional ability by providing such employees with
a means to supplement their estate planning and standard of
living at retirement. This Plan is intended to qualify for the
exemptions described in sections 201(2), 301(a)(3), and 401(a)(1)
of the Employee Retirement Income Security Act of 1974, as
amended.

ARTICLE II

Definitions

For the purpose of this Plan, the following words and
phrases shall have the meanings indicated, unless the context
clearly indicates otherwise:

2.1 Beneficiary. "Beneficiary" means the person, persons,
or entity designated by the Participant, or as provided
in Article VIII, to receive any benefits payable under
the Plan. Any Participant Beneficiary designation
shall be made in a written instrument filed with the
Human Resources Committee and shall become effective
only when received in writing by the Committee.

2.2 Board. "Board" means the Board of Directors of Western
Resources, Inc.

2.3 Company. "Company" means Western Resources, Inc.

2.4 Compensation. "Compensation" or "Total Compensation"
means the Base Salary and Incentive Compensation
payable to a Participant during the Plan Year.

(a) Base Salary. "Base Salary" means all regular
remuneration for services, other than such items
as Incentive Compensation, payable by the Company
to a Participant in cash during a Plan Year, but
before reduction for amounts deferred pursuant to
this Plan or any other Plan of the Company. The
Human Resources Committee shall determine whether
a particular item or income constitutes Base
Salary if a question arises.

(b) Incentive Compensation. "Incentive Compensation"
means any cash bonus earned by a Participant in a
Plan Year.

2.5 Declared Rate. "Declared Rate" means the annual
percentage rate (APR) of interest to be credited to the
executive's deferral account. Such rate is to be set
annually by the Human Resources Committee.

2.6 Deferral Benefit. "Deferral Benefit" means the benefit
payable to a Participant or Participant's Beneficiary
on a date specified by the Participant in the
Participation Agreement or on Participant's retirement,
death, disability, or termination of employment as
calculated in Article VII hereof.

2.7 Deferred Benefit Account. "Deferred Benefit Account"
means the accounts maintained on the books of account
of the Company for each Participant pursuant to Article
IV and determined with respect to any Participation
Agreement. Separate Deferred Benefit Accounts shall be
maintained for each Participant. A Participant's
Deferred Benefit Account shall be utilized solely as a
device for the measurement and determination of the
amounts to be paid to the Participant pursuant to the
Plan. A Participant's Deferred Benefit Account shall
not constitute or be treated as a trust fund of any
kind.

2.8 Deferred Compensation Committee . "Deferred
Compensation Committee" means a committee appointed by
the Human Resources Committee to assist in the
Administration of the Plan as provided herein.

2.9 Determination Date. "Determination Date" means the
date on which the amount of a Participant's Deferred
Benefit Account is determined as provided in Article VI
hereof. The last day of each calendar month shall be a
Determination Date.

2.10 Disability. "Disability" or "Disabled Participant"
means a physical or mental condition of a Participant
resulting in a determination of disability for purposes
of receiving benefits under the Company's Long Term
Disability Plan.

2.11 Human Resources Committee. "Human Resources Committee"
means the Human Resources Committee of the Board of
Directors of Western Resources, Inc.

2.12 Participant. "Participant" means any individual who is
deemed eligible by the Human Resources Committee to
participate in this Plan and who elects to participate
by filing a Participation Agreement as provided in
Article IV.

2.13 Participation Agreement. "Participation Agreement"
means the agreement filed by a Participant prior to the
beginning of the first period for which any of the
Participant's Compensation is to be deferred pursuant
to the Plan. A form of such Participation Agreement is
attached hereto.

2.14 Plan Year. "Plan Year" means a twelve month period
commencing January 1 and ending the following December
31. The first Plan Year shall commence on October 15,
1993 and terminate on December 31, 1993.

2.15 Retirement Date. "Retirement Date" means the first day
of the month coincidental with or next following a
Participant's commencement of benefits following actual
retirement under either The Kansas Power and Light
Company or the Retirement Plan for Employees of Kansas
Gas and Electric Company.

2.16 Spouse. "Spouse" means a Participant's wife or husband
who was lawfully married to the Participant at the time
of the Participant's death or a determination of
Participant's incompetency.

ARTICLE III

Administration

3.1 The Committees: Duties. This plan shall be
administered as provided herein by both the Human
Resources Committee of the Board and the Deferred
Compensation Committee. Members of the committees may
be Participants under this Plan. The Human Resources
Committee shall also have the authority to make, amend,
interpret, and enforce all appropriate rules and
regulations for the administration of this Plan and
decide or resolve any and all questions, including
interpretation of this Plan, as may arise in connection
with the Plan.

3.2 Binding Effect of Decision. The decision or action of
the committees with respect to any question arising out
of or in connection with the administration,
interpretation, and application of the Plan and the
rules and regulations promulgated hereunder shall be
final, conclusive, and binding upon all persons having
any interest in the Plan, unless a written appeal is
received by the Human Resources Committee within sixty
days of the disputed action. The appeal will be
reviewed by the Human Resources Committee and the
decision of the committee shall be final, conclusive,
and binding on the Participant and all persons claiming
by, through, or under the Participant.

<PAGE>
ARTICLE IV

Participation

4.1 Participation. Participation in the Plan in any Plan
Year shall be limited to the class of those key
employees selected by the Human Resources Committee who
elect to participate in the Plan by filing a
Participation Agreement with the Committee. A
Participation Agreement must be filed prior to December
15 immediately preceding the Plan Year in which the
Participant's participation under the Agreement will
commence. The election to participate shall be
effective on the first day of the Plan Year following
receipt of a properly completed and executed
Participation Agreement.

With respect to the first Plan Year of the Plan or with
respect to an individual hired or promoted during a
Plan Year who thereby becomes eligible to participate
herein, an initial Participation Agreement may be filed
within thirty days of the notification to Participant
of eligibility to participate. Such election to
participate shall be effective on the first day of the
month following the receipt thereof, except that
elections not received on or before the 15th day of any
calendar month shall be effective no earlier than the
first day of the second month following the month of
receipt.

To participate in any subsequent Plan Year, a
Participant must file a new Participation Agreement.

4.2 Minimum and Maximum Deferral and Length of
Participation. A Participant may elect in a
Participation Agreement to defer a portion of
Participant's Base Salary or Incentive Compensation.
The minimum and maximum amounts that may be deferred
under a Participation Agreement shall be as follows:

Minimum Deferral Maximum
Deferral

With respect to Base 2% of Base Salary 100%
of Base Salary
Salary Deferrals

With respect to 25% of Incentive 100%
of Incentive
Incentive Compensation Compensation
Compensation

<PAGE>
(a) With respect to Base Salary deferrals, the
deferral percentage elected in a Participation
Agreement shall be applied to the Participant's
Base Salary of the Plan Year to which the
Participation Agreement applies. A Participation
Agreement shall apply to the Participant's Base
Salary payable over a deferral period of one Plan
Year.

Deferrals shall commence with the Plan Year
immediately following the Plan Year in which the
respective Participation Agreement is filed;
provided, however, that an initial Participation
Agreement which is effective other than on January
1 of a Plan Year shall apply to the remainder of
the Plan Year.

(b) With respect to Incentive Compensation deferrals,
the deferral percentage selected in a
Participation Agreement shall apply to the
Participant's Incentive Compensation to be earned
in the Plan Year immediately following receipt of
the Participation Agreement.

(c) A Participant's election to defer Compensation
shall be irrevocable upon the filing of the
respective Participation Agreement; provided,
however, that the deferral of Compensation under
any Participation Agreement may be suspended or
amended as provided in paragraphs 7.5 and 9.1.

4.3 Subsequent Participation Agreements. In order to
participate in any subsequent Plan Year, a Participant
must file a new Participation Agreement for that
subsequent Plan Year prior to December 15 of the
previous calendar year, stating the amount that the
Participant elects to have deferred. The new agreement
shall be effective only as to Compensation paid in that
subsequent Plan Year. A new Participation Agreement is
subject to all of the provisions and requirements set
forth in paragraph 4.2.

ARTICLE V

Deferred Compensation

5.1 Elective Deferred Compensation. The amount of
Compensation that a Participant elects to defer in a
Participation Agreement executed by the Participant
with respect to each Plan Year of participation in the
Plan shall be credited by the Company to the
Participant's Deferred Benefit Account throughout each
Plan Year as the Participant is paid the non-deferred
portion of Compensation for such Plan Year. The amount
credited to a Participant's Deferred Benefit Account
shall equal the amount deferred. To the extent that
the Company is required to withhold any taxes or other
amounts from an employee's deferred wages pursuant to
any state, federal, or local law, such amounts shall be
taken out of the Participant's Compensation which is
not deferred under this Plan.

5.2 Effect on Other Plans. To the extent to which
deferrals by a Participant under this Plan cause a
reduction in pension benefits for a Participant under
The Kansas Power and Light Company Retirement Plan or
Retirement Plan for Employees of Kansas Gas and
Electric Company, the Company shall provide
supplementary benefits to the extent of such reduction.
The amount of such reduction shall be determined, as of
the time of the Participant's retirement under said
Retirement Plan, by said Retirement Plan's actuary
based upon the form of pension benefit applicable to
such Participant, which determination shall be binding
and conclusive on such Participant.

To the extent to which deferrals by a Participant under
this Plan cause a reduction in the Company matching
contributions made by the Company on behalf of the
Participant under The Kansas Power and Light Company
Employees' Savings Plan or Kansas Gas and Electric
Company 401(K) Plan, the Company shall credit the
amount of any such reduction to the Participant's
Deferred Benefit Account under the Plan, such amount to
be credited quarterly in the year in which such
reduction of contributions occurs, based on the
Participant's eligible Company match under such savings
plan, not to exceed the maximum contribution by the
Company under such plans.

The Company shall compute life insurance and disability
benefits under any Company plan based on Compensation
without reduction for amounts deferred under this Plan.

5.3 Vesting of Deferred Benefit Account. A Participant
shall be 100% vested in the Participant's Deferred
Benefit Account.

ARTICLE VI

Deferred Benefit Account

6.1 Determination of Account. Each Participant's Deferred
Benefit Account as of each Determination Date shall
consist of the balance of the Participant's Deferred
Benefit Account as of the immediately preceding
Determination Date, plus the Participant's elective
deferred Compensation withheld since the immediately
preceding Determination Date pursuant to paragraph 5.1.
The Deferred Benefit Account of each Participant shall
be reduced by the amount of all distributions, if any,
made from such Deferred Benefit Account since the
preceding Determination Date.

6.2 Crediting of Account. As of each Determination Date,
the Participant's Deferred Benefit Account shall be
increased by the amount of interest earned since the
preceding Determination Date. Interest shall be based
on the Declared Rate as defined in paragraph 2.5 or as
determined under paragraph 7.6(a)(2), as applicable.
Interest shall be credited on the average of the
balances of the Deferred Benefit Account on the
Determination Date and on the last preceding
Determination Date, but after the Deferred Benefit
Account has been adjusted for any contributions or
distributions to be credited or deducted for each such
day. Interest will also accumulate on the unpaid
balance during any payout period in which a participant
is receiving monthly payments.

6.3 Statement of Accounts. The Company shall submit to
each Participant, within 120 days after the close of
each Plan Year, a statement in such form as the Company
deems desirable, setting forth the balance to the
credit of each Participant's Deferred Benefit Account
as of the last day of the preceding Plan Year.

ARTICLE VII

Benefits

7.1 Specified Distribution Date. Unless a Participant
elects to receive benefits under paragraph 7.2 or 7.3
below, on the specified distribution date selected by
the Participant in a Participation Agreement, the
Participant shall be entitled to a Deferral Benefit
equal to the amount of Participant's Deferred Benefit
Account determined under paragraphs 6.1 and 6.2 hereof
as of the Determination Date coincidental with or
immediately following such specified date.

7.2 Retirement or Termination of Employment. Subject to
paragraphs 7.1 and 7.6, upon a Participant's Retirement
Date, or any termination of employment for reasons
other than death or disability, the Participant shall
be entitled to a Deferral Benefit equal to the amount
of Participant's Deferred Benefit Account determined
under paragraphs 6.1 and 6.2 hereof as of the
Determination Date coincidental with or immediately
following such event.

<PAGE>
7.3 Death. Upon the death of a Participant, such
Participant's Beneficiary shall receive a Deferral
Benefit equal to the remaining balance in such
Participant's Deferred Benefit Account.

The Deferral Benefit shall be payable as provided for
in paragraph 7.6.

The Deferral Benefit provided above shall be in lieu of
all other benefits under this Plan.

7.4 Disability. In the event of Disability, as defined in
paragraph 2.10, while employed by the Company, the
disabled Participant shall be allocated the amount in
Participant's Deferred Benefit Account determined under
paragraphs 6.1 and 6.2 as of the Determination Date
next following such Disability.

Payments shall commence upon attainment of the
Participant's Retirement Date in the form specified in
paragraph 7.6(a)(2) over a period from 2 to 360 months.
Before payments commence under the preceding sentence,
a Disabled Participant may elect, subject to Deferred
Compensation Committee approval (Human Resources
Committee approval if the Participant is an officer of
the Company) upon good cause shown: (i) to accelerate
commencement of the payments until the date not earlier
than 60 days after the onset of Disability, and/or (ii)
to change the form of payment to another form permitted
under paragraph 7.6(a).

7.5 Suspension of Participation/Distribution/Failure to
Continue Participation. The Deferred Compensation
Committee (Human Resources Committee if the Participant
is an officer of the Company), in its sole discretion,
may suspend the deferral of a Participant's Base Salary
during a Plan Year, or authorize a distribution from
the Participant's Deferred Benefit Account, upon the
advance written request of a Participant on account of
financial hardship suffered by that Participant. A
Participant must file any request for such suspension
or distribution on or before the 15th day preceding the
regular pay day on which the suspension or distribution
is to take effect. Incentive Compensation deferrals
may not be suspended during the Plan Year.

Financial hardship shall mean an unexpected need for
cash resulting from conditions in the nature of any of
the following:

(a) An accident, illness, or disability suffered by a
Participant or a family member or dependent;

(b) A casualty or the theft loss suffered by a
Participant of a family member or dependent;

(d) A sudden financial reversal or curtailment of
income experienced by a Participant or a family
member or dependent.

The suspension of any deferrals under this paragraph
shall not affect amounts deferred with respect to
periods prior to the effective date of the suspension.

In the event the Participant ceases to remain a member
of the class of employees who are eligible to
participate in the Plan, the Participant may elect to
suspend the amount of any remaining deferral commitment
in this same manner as described for other suspensions
in the paragraph, except that committee approval shall
not be required.

7.6 Form of Benefit Payment.

(a) Upon retirement, death, a specified distribution
date, or termination of employment, the Company
shall pay to the Participant or Participant's
Beneficiary the balance in the Participant's
Deferred Benefit Account in one of the following
forms, as elected in the Participation Agreement
filed by the Participant:

(1) A lump sum payment.

(2) A monthly payment of a fixed amount which
shall amortize the Deferred Benefit Account
balance in equal monthly payments of
principal and interest over a period from 2
to 360 months. For purposes of determining
the amount of the monthly payment, the rate
of interest shall be the average of the
Declared Rate for the shorter of (i) the last
five (5) Plan Years preceding the initial
monthly installment payment, or (ii) the
actual number of Plan Years of participation
by the Participant.

(b) In the absence of a Participant's election under
subparagraph 7.6(a), benefits shall be paid in the
form specified in subparagraph 7.6(a)(2) over a
180 month period. In the event of a Disabled
Participant, payment shall be in the form
described in paragraph 7.4.

<PAGE>
7.7 Withholding: Payroll Taxes. To the extent required by
law in effect at the time payments are made, the
Company shall withhold from payments made hereunder any
taxes required to be withheld from any employee's wages
for the federal or any state or local government.

7.8 Commencement of Payments. Commencement of payments
under this Plan shall begin within sixty days following
receipt of notice by the Deferred Compensation
Committee in the event of death, retirement, or
termination of employment which entitles a Participant
(or a Beneficiary) to payments under this Plan. All
payments shall be made as of the first day of the
month.

If a Participant receives benefits hereunder because of
retirement, payments will commence coincident with the
payment of benefits to the Participant under The Kansas
Power and Light Company Retirement Plan or the
Retirement Plan for Employees of Kansas Gas and
Electric Company.

A Participant must elect to receive benefits under each
Participation Agreement upon either i) a specified
distribution date, or ii) retirement or termination of
employment.

Subject to paragraph 7.3 in the event a Participant
elects to receive benefits upon a specified
distribution date, payments will commence upon the
first business day of the year specified.

ARTICLE VIII

Beneficiary Designation

8.1 Beneficiary Designation. Each Participant shall have
the right, at any time, to designate any person or
persons as Beneficiary or Beneficiaries (both principal
as well as contingent) to whom payment under this Plan
shall be made in the event of Participant's death prior
to complete distribution of the benefits due to the
Participant under the Plan.

8.2 Amendments. Any Beneficiary designation may be changed
by a Participant by the written filing of such change
on a form prescribed by the Deferred Compensation
Committee. The filing of a new Beneficiary Designation
form will cancel all Beneficiary designations
previously filed.

<PAGE>
8.3 No Beneficiary Designation. If a Participant fails to
designate a Beneficiary as provided above, or if all
designated Beneficiaries predecease the participant,
then the Participant's designated Beneficiary shall be
deemed to be the person or persons surviving
Participant in the first of the following classes in
which there is a survivor, share and share alike:

(a) The surviving Spouse;

(b) The Participant's children, except that if any of
the children predecease the Participant but leave
issue surviving, then such issue shall take by
right of representation the share their parent
would have taken if living;

8.4 Effect of Payment. The payment to the deemed
Beneficiary shall completely discharge the Company's
obligations under this Plan.

ARTICLE IX

Amendment and Termination of Plan

9.1 Amendment. The Board may at any time amend the Plan in
whole or in part; provided, however, that no amendment
shall be effective to decrease or restrict any Deferred
Benefit Account at the time of such amendment or reduce
any additional benefits provided under paragraph 5.2.
In the event the Plan is amended, a Participation
Agreement shall be subject to the provisions of such
amendment as if set forth in full therein, without
further action or amendment to the Participation
Agreement. The parties shall be bound by, and have the
benefit of, each and every provision of the Plan, as
amended from time to time.

9.2 Company's Right to Terminate. The Board may at any
time terminate the Plan with respect to new elections
to defer if, in its judgment, the continuance of the
Plan, the tax, accounting, or other effects thereof, or
potential payments thereunder would not be in the best
interests of the Company. The Board may also terminate
the Plan in its entirety at any time, and upon any such
termination, all Participants under the Plan shall be
paid the balance in their Deferred Benefit Accounts in
a lump sum, or over such period of time as determined
by the Board.

<PAGE>
9.3 Premature Plan Terminations and Premature
Distributions. The Deferred Compensation Committee
shall have the right (but shall not be obligated) to
require premature Plan termination and premature Plan
distributions to Participants, upon the occurrence of
any of the following conditions or events:

(a) If any rating on any debt securities of the
Company, as rated by Moody's or Standard & Poor's,
is downgraded to a rating lower than that rating
as of the date of this Plan;

(b) If the shareholders of the Company approve the
merger or consolidation of the Company with or
into any other corporation (other than a
corporation wholly-owned by the Company
immediately prior to such event) or the
acquisition of substantially all of the business
or assets of the Company by any other person or
entity (other than a corporation wholly-owned by
the Company immediately prior to such event);

(c) If a change occurs in the Board of Directors of
the Company whereby Directors comprising a
majority of the Board of Directors immediately
prior to such change do not continue to comprise
such a majority immediately after such change,
provided that incremental and/or related changes
(including but not limited to resignations from
the Board of Directors) which occur within a
relatively brief period of time shall be
considered to be but a single change for purposes
of this Subparagraph;

(d) If, as a result of any tender offer or otherwise,
any person or entity or affiliated group becomes
the beneficial or record owner of more than 10% of
the outstanding voting securities of the Company;
or

(e) If, in the Deferred Compensation Committee's sole
judgment and discretion, a change in circumstances
has occurred (including but not limited to a
change in taxation laws or regulations, securities
laws or regulations, accounting requirements or
the events in Subparagraphs (a), (b), (c), and (d)
of this Paragraph 9.3) which causes the Plan to be
undesirable to a significant portion of the
Participants.

<PAGE>
ARTICLE X

Miscellaneous

10.1 Unsecured General Creditor. Participants and their
Beneficiaries shall have no legal or equitable rights,
interest, or claims in any property or assets of the
Company, nor shall they be Beneficiaries of, or have
any rights, claims, or interests in any life insurance
policies, annuity contracts, or the proceeds therefrom
owned or which may be acquired by the Company
("Policies"). Such Policies or other assets of the
Company shall not be held under any trust for the
benefit of Participants or their Beneficiaries or held
in any way as collateral security for the fulfilling of
the obligations of the Company under this Plan. Any
and all of the Company's assets and Policies shall be,
and remain, the general, unpledged, and unrestricted
assets of the Company. The Company's obligation under
the Plan shall be merely that of an unfunded and
unsecured promise of the Company to pay money in the
future.

10.2 Non-assignability. Neither a Participant nor any other
person shall have any right to commute, sell, assign,
transfer, pledge, anticipate, mortgage, or otherwise
encumber, transfer, hypothecate, or convey in advance
of actual receipt the amounts, if any, payable
hereunder, or any part thereof, which are, and all
rights to which are, expressly declared to be
unassignable and non-transferable. No part of the
amounts payable shall, prior to actual payment, be
subject to seizure or sequestration for the payment of
any debts, judgments, alimony, or separate maintenance
owed by a Participant or any other person, nor be
transferable by operation of law in the event of a
Participant's or any other person's bankruptcy or
insolvency.

10.3 Not a Contract of Employment. The terms and conditions
of this Plan shall not be deemed to constitute a
contract of employment between the Company and the
Participant, and the Participant (or Participant's
Beneficiary) shall have no rights against the Company
except as may otherwise be specifically provided
herein. Moreover, nothing in this Plan shall be deemed
to give a Participant the right to be retained in the
service of the Company or to interfere with the right
of the Company to discipline or discharge Participant
at any time.

10.4 Protective Provisions. A Participant ( or
Participant's Beneficiary) will cooperate with the
Company by furnishing any and all information requested
by the Company in order to facilitate the payment of
benefits hereunder, by taking such physical
examinations as the Company may deem necessary, and by
taking such other action as may be requested by the
Company.

10.5 Governing Law. The provisions of this Plan shall be
construed and interpreted according to the laws of the
State of Kansas.

10.6 Successors. The provisions of this Plan shall bind and
inure to the benefit of the Company and its successors
and assigns.

10.7 Effective Date. This Plan shall become effective as of
October 15, 1993.

10.8 Incompetent. In the event that it shall be found upon
evidence satisfactory to the Deferred Compensation
Committee that any Participant or Beneficiary to whom a
benefit is payable under this Plan is unable to care
for such Participant's or such Beneficiary's affairs
because of illness or accident, any payment due (unless
prior claim therefor shall have been made by a duly
authorized guardian or other legal representative) may
be paid, upon appropriate indemnification of the
Company, to the Spouse or other person deemed by the
Committee to have incurred any expense for such
Participant or a Beneficiary. Any such payment shall
be a payment for the account of the Participant or a
Beneficiary and shall be a complete discharge of any
liability of the Company therefor.
<PAGE>
WESTERN RESOURCES DEFERRED COMPENSATION PLAN
PARTICIPATION AGREEMENT

This Agreement is made and entered into as of this _______
day of ______________________________, 19_______, by and between
Western Resources, Inc. (the "Company") and
________________________________________ (a "Participant") and
shall be effective beginning with the _______ day of
______________________________, 19_______ ("Effective Date").

WHEREAS, the Company has adopted the Western Resources
Deferred Compensation Plan (the "Plan"); and,

WHEREAS, the Plan requires that an Agreement be entered into
between the Company and the Participant,

NOW, THEREFORE, the Company and the Participant hereby agree
as follows:

1. Plan. The Plan, a copy of which has been provided to
Participant, is hereby incorporated into and made a
part of this Agreement as though set forth in full
herein. The parties shall be bound by, and have the
benefit of, each and every provision of the Plan. By
executing this Agreement, the Participant acknowledges
receipt of a copy of the Plan and confirms
understanding and acceptance of all of the terms,
provisions, and conditions thereof.

2. Deferral Election.

Base Salary Deferral (for Plan Year 1993)

_____ a) Participant hereby elects to defer an
amount equal to _______% (from 2% to
100%) of Base Salary to be earned by
Participant in the remainder of Plan
Year 1993.

_____ b) Participant is not electing Base Salary
Deferral for the remainder of Plan Year
1993.

Base Salary Deferral (for Plan Year 1994)

_____ a) Participant hereby elects to defer an
amount equal to _______% (from 2% to
100%) of Base Salary to be earned by
Participant in Plan Year 1994.

_____ b) Participant is not electing Base Salary
Deferral for Plan Year 1994.

Incentive Compensation Deferral (for Plan Year 1994)

_____ a) The Participant elects to defer receipt
of _______% (from 25% to 100%) of
Incentive Compensation to be earned by
Participant in Plan Year 1994 and
payable in 1995.

_____ b) Participant is not electing Incentive
Compensation Deferral in this Agreement.

NOTE: All percentages and resulting dollar amounts will be
rounded to the nearest whole percentage or dollar.

3. Payment of Benefits - Death Before Retirement or
Specified Distribution Date

Form of Benefit Payment

_____ a) Not applicable (mark if paragraph 4c or
4g is not selected).

_____ b) A lump sum payment.

_____ c) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

NOTE: Complete either paragraph 4 or both paragraphs 5 and 6. Do
not complete all three paragraphs.

4. Payment of Benefits - Specified Distribution Date;
Death Before Specified Distribution Date

Form of Benefit Payment (Base Salary)

_____ a) A lump sum payment.

_____ b) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

_____ c) I elect to receive benefits upon death
should death occur prior to the
specified distribution date. (complete
paragraph 3)

_____ d) Specified Distribution Date -- (specify
a year when distributions are to
commence on the first business day of
such year).

Form of Benefit Payment (Incentive Compensation)

_____ e) A lump sum payment.

_____ f) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

_____ g) I elect to receive benefits upon death
should death occur prior to the
specified distribution date. (complete
paragraph 3)

_____ h) Specified Distribution Date -- (specify
a year when distributions are to
commence on the first business day of
such year).

5. Payment of Benefits - Termination Other Than Death

Form of Benefit Payment (Base Salary)

_____ a) A lump sum payment.

_____ b) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

Form of Benefit Payment (Incentive Compensation)

_____ c) A lump sum payment.

_____ d) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

6. Payment of Benefits - Retirement Date

Form of Benefit Payment (Base Salary)

_____ a) A lump sum payment.

_____ b) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

<PAGE>
Form of Benefit Payment (Incentive Compensation)

_____ c) A lump sum payment.

_____ d) Level monthly installment payments for
_______ months as provided in paragraph
7.6(a)(2) [specify a period not less
than 2 nor more than 360 months].

7. Amendments. All subsequent amendments to the Plan
shall also be incorporated into and made a part of this
Agreement as though set forth in full herein, without
further action or amendments to this Agreement. The
parties shall be bound by, and have the benefit of,
each and every provision of the Plan, as amended from
time to time.

8. Binding Effect. This Agreement shall inure to the
benefit of, and be binding upon the Company, its
successors and assigns, and the Participant and
Participant's Beneficiaries.

IN WITNESS WHEREOF, the parties hereto have signed and
entered into this Agreement on and as of the date first above
written.

______________________________________________________
Participant's Signature

WESTERN RESOURCES, INC.

By____________________________________________________

Title_________________________________________________

<PAGE>

WESTERN RESOURCES DEFERRED COMPENSATION PLAN
BENEFICIARY DESIGNATION

Name in
full________________________________________________SS#__________
_____

I designate the following as Beneficiary or Beneficiaries to
receive, in accordance with the method indicated, any payments to
which my Beneficiary or Beneficiaries may be entitled under the
Western Resources Deferred Compensation Plan (Paragraph 2.1 and
Article VIII) in the event of my death either prior to or after
my retirement, subject to my right at any time to change such
Beneficiary or Beneficiaries as provided under the Plan.

Beneficiaries Name Relationship Share
of Payment (%)

Primary__________________________________________________________
______________

Primary__________________________________________________________
_______________

Contingent_______________________________________________________
_______________

This beneficiary designation or change supersedes all previous
designations or changes made by me under the Plan.

________________________________________________
__________________________
Participant's Signature Date

________________________________________________
__________________________
Committee Acknowledgement Date
<PAGE>
WESTERN RESOURCES
DEFERRED COMPENSATION PLAN

1. What is the purpose of the Plan?

The purpose of the Plan is to give you the opportunity to
supplement your estate planning and accumulate tax deferred
income by deferring all or a portion of your pre-tax base salary
and/or incentive compensation, which is then credited with
interest on a tax-deferred basis. This will allow you to
supplement your standard of living at retirement.

2. Why is the Deferred Compensation Plan important to me?

It lets you delay the payment of income taxes on all or a
portion of your income, by having Western Resources retain it and
pay it to you at a later date. The amounts which you defer will
earn tax-deferred interest.

3. Who can participate in this Plan?

The Deferred Compensation Plan is available only to Eligible
Key Management Employees, as designated by the Human Resources
Committee of the Board of Western Resources.

You may elect to participate in the Plan in addition to all
other Western Resources benefit plans for which you are currently
eligible.

4. How much can I defer?

Your participation in the Plan is based on deferral of all
or a portion of your base salary and/or incentive cash
compensation for a period of one year. Upon enrolling in the
Plan, you will specify in a Participation Agreement the amount of
your deferral. The minimum annual deferral is 2% of base salary,
and/or 25% of incentive compensation.

5. May I suspend my deferral commitments or receive a
distribution from my Deferred Benefit Account in the event of
financial hardship?

The Deferred Compensation Committee may, in its sole
discretion and upon your written request, suspend the deferral of
your salary that would otherwise occur under a Participation
Agreement and/or authorize a distribution from your Deferred
Benefit Account if you have suffered a financial hardship. The
suspension will take effect only with respect to salary deferrals
which have not already occurred.

<PAGE>
6. What are examples of financial hardship?

Financial hardship means an unexpected need for cash
resulting from an occurrence in the nature of any of the
following:

a) An accident, illness, or disability suffered by you or
a family member or dependent;

b) A casualty or theft loss suffered by you or a family
member or dependent;

c) The rendering of a judgment against you or a family
member or dependent; or

d) A sudden financial reversal or curtailment of income
experienced by you or a family member or dependent.

7. How much interest is credited on the Deferred Benefit
Account?

The interest credited to your Deferred Benefit Account will
be based on Western Resources long term cost of capital, and
established annually by the Human Resources Committee of the
Board. The interest on deferred amounts will change annually.
The rate for the balance of Plan Year 1993 and for Plan Year 1994
will be 10.01% APR.

8. How will benefits be paid?

Generally, benefits may be paid in a lump sum or in equal
monthly installments consisting of principal and interest at the
Plan Credit Rate up to 360 months. You elect the form in which
payments are to be made. If you fail to elect a form of payment,
you will receive your benefit payments in installments over a 180
month period.

9. What happens upon my retirement?

Unless you designate a specific distribution date, upon your
election to retire under either the Retirement Plan for Employees
of Kansas Gas and Electric Company or The Kansas Power and Light
Company Retirement Plan, you will receive benefits commencing
within 60 days after the Committee is notified of your
retirement. Your benefit will be based on your Deferred Benefit
Account balance at that time. In the event the Account balance
is paid out over a number of months, interest will be paid on the
unpaid balance based on the Plan Credit Rate.

<PAGE>
10. What happens to my account in the event of death?

You will designate a beneficiary to receive benefits under
the Plan and will have the right to change the beneficiary
designation from time to time by completing a beneficiary
designation change form.

If your death should occur before retirement, your
beneficiary will be paid your Deferred Benefit Account balance
either as a lump sum or paid monthly (up to 360 months) depending
upon your election.

In the event of your death after deferral benefits have
started, your beneficiary will continue to receive installments
until the balance of your account has been paid. Interest will
continue to accrue on your Deferred Benefit Account at the Plan
Credit Rate during the period of distribution.

11. What if I become disabled?

If disability occurs while employed by Western Resources and
you would qualify for long term disability benefits according to
the terms of the Long Term Disability Plan maintained by Western
Resources, payments from your Deferred Benefit Account will
commence, subject to Committee approval, no earlier than 60 days
after the onset of your disability.

12. What happens if employment is terminated before I am
eligible for Retirement?

Unless you designate a specific distribution date, in the
event of termination of employment for reasons other than death,
retirement, or disability, your Deferred Benefit Account balance
will be payable either as a lump sum or paid monthly (up to 360
months). In the event the Account balance is paid out over a
number of months, interest will be paid on the unpaid balance
based on the Plan Credit Rate.

13. How is the Plan administered?

The Plan is administered by the Human Resources Committee of
the Board and the Deferred Compensation Committee. The
Committees will resolve all questions involving interpretations
of the Plan.

14. Is my Deferred Compensation held in Trust?

No. Benefits payable under the Plan depend upon and will be
paid exclusively from the general assets of Western Resources.
Western Resources' liability, for the payment of benefits under
the Plan, will be unsecured and unfunded, as evidenced by the
terms of the Plan and the current Participation Agreement between
you and the Company.

15. How does participation in the Plan affect my other Western
Resources benefits?

When you participate in the Plan, you are required to defer
current compensation. This may affect your benefits under other
Western Resources plans, which are based upon your compensation.
The following are the main effects of which you should be aware:

a) Life insurance and disability benefits will be based on
your compensation without reduction for any amounts
deferred under this Plan.

b) To the extent to which your deferrals cause a reduction
in pension benefits under either the KP&L or KG&E
retirement plans, Western Resources will provide you
with supplementary benefits to the extent of such
reduction.

These supplemental benefits, like the Deferred
Compensation benefits are unfunded and represent an
unsecured general obligation of the Company.

c) To the extent to which your deferrals cause a reduction
in the Company matching contributions under either the
KP&L or KG&E 401 (K) plans, Western Resources will
credit the amount of any such reduction to your
Deferred Benefit Account on December 31 of the year in
which such reduction of contribution occurs, based on
your eligible Company matching contribution, not to
exceed the maximum company contribution provided in the
401(k) plan.

16. When is the Deferred Compensation Plan effective?

The Plan will become effective October 15, 1993, when the
enrollment process has been completed and the Participation
Agreement has been signed by both you and Western Resources. The
enrollment process includes completion of:

a) Participation Agreement

b) Beneficiary Designation Form

c) Worksheet

WESTERN RESOURCES, INC.
LONG-TERM INCENTIVE PROGRAM

The purpose of the Western Resources, Inc. Long
Term Incentive Program is to provide a select group of
management and executive employees of the Company with
incentives to work for the long-range growth of the
Company and to provide a competitive means by which
management and executive employees with superior capabilities may
be attracted to and retained by the Company.

1. Definitions. As used herein the following words and
phrases shall have the following respective meanings unless the
context clearly indicates otherwise:

(a) Account: The account established by the Company
for the Participant for each Incentive Period. The Account
shall be credited upon an Award to the Participant, and
debited upon distribution or cancellation of an Award.

(b) Award: A grant of Performance Shares made to a
Participant's Account under the terms of the Program.

(c) Beneficiary: The person or persons designated by
a Participant pursuant to Section 9 to receive any
distribution which under the terms and conditions of the
Program may be made on behalf of the Participant after the
Participant's death.

(d) Board of Directors: The Board of Directors of the
Company.

(e) Committee: The committee which may be established
by the Board of Directors pursuant to section 2 to
administer the Program.

(f) Common Stock: The Company's common stock, par
value $5.00 per share.

(g) Company: Western Resources, Inc. a Kansas
corporation, and its successors and assigns.

(h) Incentive Period: A three year period at the
beginning of which an Award is made to Participants'
Accounts and at the end of which a determination is made
whether or not the Performance Standard has been obtained.
Each January 1 a new Incentive Period shall commence. The
first Incentive Period shall be January 1, 1991 through
December 31, 1993.

(i) Market Value: The average of the high and low
prices for the Common Stock reported by the New York Stock
Exchange (NYSE) on the date or dates specified in the
Program (or, if such date shall not be a NYSE business day,
the next succeeding day which shall be a business day).

(j) Participant: An employee to whom an Award has
been made which has not been paid, canceled, or otherwise
terminated or satisfied under the terms of the Program.

(k) Performance Share: The unit of measurement for
Awards under the Program which, at any given time, shall be
equal in value to the current Market Value of one share of
Common Stock.

(l) Performance Standards: The standards described in
Section 5 relating to each Incentive Period, the
satisfaction of which shall determine the Participant's
entitlement to a Stock Distribution.

(m) Program: The program herein set forth, as from
time to time amended.

(n) Stock Distribution: The common stock to which a
Participant is entitled to receive at the end of any
Incentive Period, as determined in accordance with Sections
5 and 6.

2. Administration. The entire Board of Directors, or if
one shall be appointed by the Board of Directors, a committee of
at least three directors, all of whom are not eligible to be
Participants (the "Committee"), shall be responsible for
administering, construing and interpreting the Program. The
interpretation and construction by the Board of Directors, or the
Committee if one shall be appointed, of any provision of the
Program shall be final and conclusive.

The day-to-day administration of the Program shall be
carried out by such employees of the Company as shall be
designated from time to time by the Board of Directors, or the
Committee if one shall be appointed.

The members of the Board of Directors, the members of the
Committee, and all agents, officers, fiduciaries and employees of
the Company shall not be liable for any act, omission,
interpretation, construction or determination made in good faith
in connection with their responsibilities with respect to the
Program; and the Company hereby agrees to indemnify the members
of the Board of Directors, the members of the Committee, and all
agents, officers, fiduciaries, and employees of the Company in
respect of any claim, loss, damage or expense (including counsel
fees) arising from any such act, omission, interpretation,
construction or determination to the full extent permitted by
law.
3. Eligibility to Participate. Only those employees who
are members of the President's Council shall automatically be
eligible to participate in the Program. Such participation shall
commence with the first Incentive Period. The Board of
Directors, or the Committee if one shall be appointed, shall
determine, from time to time, whether members of the Senior
Management Council and employees in Pay Grades 30 and above shall
be eligible to participate with respect to any subsequent
Incentive Period.

4. General Terms and Conditions of Awards.

(a) Performance Share Grants. At the beginning of the
first year of each Incentive Period, an Award of Performance
Shares shall be made to each Participant's Account. The
number of Performance Shares to be awarded to each
Participant's Account shall equal the number of shares of
Common Stock having a Market Value on January 2 of such year
equal to 10 percent of the Participant's base annual
compensation determined as of January 1 of the first year of
the Incentive Period. Except with respect to the dividend
equivalent distributions to be made pursuant to Section
4(b), Participants shall not receive any payment with
respect to the Performance Shares until the accomplishment
of the Performance Standard in accordance with Section 5.

(b) Distributions. In the event the Company pays any
dividends or makes any other distributions with respect to
its Common Stock in cash or in property, including
securities (other than a dividend or distribution of shares
of Common Stock), each Participant shall be entitled to
receive in cash at the same time as such dividend is paid or
other distribution is made to the stockholders, an amount
equal to the value of such dividend or other distribution
determined as if the Participant were the holder of the
number of shares of Common Stock equal to the number of
Performance Shares in his or her account. The value of such
distribution, if other than cash, shall be determined by the
Board of Directors, or the Committee if one shall be
appointed, and such determination shall be conclusive.

(c) Changes in Capitalization. In the event of a
stock dividend, stock split, recapitalization,
reorganization, merger, consolidation, split-up, or any
similar change affecting the Common Stock while any
Performance Shares are outstanding, the Board of Directors,
or the Committee if one shall be appointed, shall make such
adjustments in the number of Performance Shares in each
Participant's Account as shall, in the sole judgment of the
Board of Directors or the Committee, as appropriate, be
equitable and appropriate in order to make such Account, as
nearly as practicable, equivalent to the value of the
Performance Shares in the Account immediately prior to such
change.

5. Performance Standards. The Performance Standards
establish certain corporate goals to be attained during each
Incentive Period in order for a Participant to receive a Stock
Distribution. A Participant's right to a Stock Distribution, and
the amount thereof, shall be determined by the Distribution
Percentage.

(a) Distribution Percentage. The Distribution
Percentage shall consist of two weighted elements, the
Financial Criteria Percentage and the Performance Criteria
percentage. The sum of the weighted Financial Criteria
Percentage and the weighted Performance Criteria percentage
shall equal the Distribution Percentage. The following
formula shall be used: (Financial Criteria Percentage X
70%) + (Performance Criteria Percentage X 30%) =
Distribution Percentage.

(1) Financial Criteria Percentage. By May 31,
1991 for the first Incentive Period, and as early as
practical each succeeding Incentive Period, the Board
of Directors, or the Committee if one shall be
appointed, shall establish for the Incentive Period
certain annual financial goals. Promptly following the
end of each Incentive Period, the Board of Directors,
or the Committee if one shall be appointed, shall
determine the Financial Criteria Percentage over the
Incentive Period.

(2) Performance Criteria Percentage. The
Performance Criteria Percentage is derived by
evaluating the performance of the Company and the
Participants. The Performance Criteria for each
Incentive Period, which shall consist of the long-range
strategic goals, objectives, and planned targets for
the Company and the Participants, shall be established
at the beginning of the respective Incentive Period.
The Board of Directors, of the Committee if one shall
be appointed, without the participation of the Chief
Executive Officer of the Company (the "CEO"), shall
determine and set forth in writing the Performance
Criteria for the CEO. The CEO shall set forth in
writing the Performance Criteria for the members of the
President's Council other than the CEO. The
President's Council shall set forth in writing the
Performance Criteria for all other Participants. At
the end of each Incentive Period, the Board of
Directors, without the participation of the CEO, shall
determine the percentage of Performance Criteria
achieved by the CEO. The percentage of Performance
Criteria achieved by the members of the President's
Council other than the CEO shall be determined by the
CEO. The percentage of Performance Criteria achieved
by the remaining Participants shall be determined by
the President's Council. The percentage of Performance
Criteria achieved shall be called the "Performance
Criteria Percentage."

(b) Earned Performance Shares. The actual number of
Performance Shares earned by the Participant shall be
determined by reference to the Actual Distribution
Percentage determined by the Board of Directors. Such
percentage shall not exceed 110%.

The Actual Distribution Percentage shall be multiplied by
the number of Performance Shares in the Participant's Account for
the Incentive Period, and the product shall be the number of
Earned Performance Shares upon which the Participant's Stock
Distribution shall be based. If the Actual Distribution
Percentage is greater than 100%, the Participant shall have more
Earned Performance Shares than are credited to his or her
Account.

6. Distribution of Awards.

(a) Generally. The Participant shall be entitled to
receive one share of Common Stock for each Earned
Performance Share determined in accordance with Section 5(b)
(the "Stock Distribution"). All Stock Distributions shall
be made within 60 days of the last day of the appropriate
Incentive Period. Partial Earned Performance Shares shall
be distributed in cash and shall equal the Market Value of
one share of Common Stock as of the last day of the
Incentive Period multiplied by the fraction of the Earned
Performance Share.

(b) Termination of Employment. A Participant who
ceases to be continually employed by the Company throughout
the Incentive Period (other than as a result of a Company-
approved leave of absence or the Participant's death,
disability, or retirement under the Company pension plan's
early or normal retirement provisions), shall forfeit all
rights to any allocated Performance Shares and any Stock
Distribution for such Incentive Period.

(c) Payment in the Event of Death, Disability or
Retirement. If a Participant dies, becomes disabled or
retires under the Company pension plan's early or normal
retirement provisions during any Incentive Period, the
Participant (or the appointed Beneficiaries in the case of
death) shall receive any payment to which the Participant
would otherwise have been entitled had he or she been
employed on the last day of the Incentive Period, including
the distributions provided for in Section 4(b). All
payments, including the Stock Distribution, shall be made to
the Participant (or the Participant's Beneficiary) at the
time and in the manner that such payment and stock
distribution would have been made to the Participant had he
or she remained employed.

7. Change in Control. Notwithstanding any contrary
provisions of this Program or any instruments evidencing Awards
granted hereunder, in the case of a Change in Control of the
Company, each Participant shall immediately become fully vested
in and be entitled to receive, a Stock Distribution in an amount
equal to the number of the Performance Shares allocated to his or
her Account. Such Stock Distribution shall be made to
Participants as soon as practicable. A Change in Control shall
occur if:

(a) any "person" or group of persons" (as such terms
are used in sections 13(d) and 14(d) of the Securities
Exchange Act of 1934) other than pursuant to a transaction
or agreement previously approved by the Board of Directors,
directly or indirectly purchases or otherwise becomes the
"beneficial owner" (as defined in Rule 13d-3 under the
Securities Exchange Act of 1934) or has the right to acquire
such beneficial ownership (whether or not such right is
exercisable immediately, with the passage of time, or
subject to any condition), of voting securities representing
20% or more of the combined voting power of all outstanding
voting securities of the Company;

(b) during any period of 24 consecutive calendar
months, the individuals who at the beginning of such period
constitute the Company's Board of Directors, and any new
directors whose election by such Board of nomination for
election by stockholders was approved by a vote of at least
two-thirds of the members of such Board who were either
directors on such Board at the beginning of the period or
whose election or nomination for election as directors was
previously so approved, for any reason cease to constitute
at least a majority of the members thereof;

(d) all or substantially all of the business of the
Company is disposed of pursuant to a merger, consolidation
or other transaction in which the Company is not the
surviving Company or is substantially or completely
liquidated (unless the shareholders of the Company
immediately prior to such merger, consolidation or other
transaction beneficially own, directly or indirectly, in
substantially the same proportion as they owned the voting
stock of the Company, all of the voting stock or other
ownership interests of the entity or entities, if any, that
succeed to the business of the Company);

(e) the Company enters into a contract to sell 50
percent or more of its assets or earning power; or

(f) the Company combines with another company and is
the surviving corporation but, immediately after the
combination, the shareholders of the Company immediately
prior to the combination (other than shareholders who,
immediately prior to the combination, were "affiliates" of
such other company, as such term is defined in the rules of
the Securities and Exchange Commission) do not beneficially
own, directly or indirectly, more than 50% of the voting
stock of the combined corporation.

If a Change in Control shall occur by reason of any of the
events described in (c) through (f) above, the Awards which shall
become vested and non-forfeitable shall be distributed to
Participants immediately prior to such Change in Control.

8. Withholding for Taxes. The Company will provide for the
withholding of any taxes required by any governmental authority
with respect to any payment that is to be made under the Program.
The amount withheld shall be paid over by the Company to such
governmental authority for the account of the Participant
entitled to the payment.

9. Designation of Beneficiary. A Participant shall
designate a Beneficiary or Beneficiaries on the Beneficiary
Designation form in the appendix (which may be designated
contingently and which may be an entity other than a natural
person) to receive any amounts which under the terms of the
Program may become payable on or after the Participant's death.
Any such designation may, unless the Participant has waived such
right, from time to time and at any time, be changed or cancelled
by the Participant without the consent of a Beneficiary. Any
such designation must be in writing and filed with the Board of
Directors, or the Committee if one shall be appointed. If a
Participant designated more than one Beneficiary, any payments
under the Plan to such Beneficiaries shall be made in equal
shares unless the Participant has designated otherwise, in which
case the payments shall be made in the shares designated by the
Participant. If a Participant does not designate a Beneficiary
or there is no proper designation of a Beneficiary or no person
designated as a Beneficiary shall survive the Participant, the
Participant's Beneficiary shall be his or her estate.

10. No Rights to Corporate Assets. Nothing contained herein
shall be construed as giving a Participant, his or her
Beneficiary or any other person any equity or other interest of
any kind in any assets of the Company or creating a trust of any
kind or a fiduciary relationship of any kind between the Company
and any such person. As to any claim for any unpaid amounts
under the Plan, a Participant, his or her Beneficiary and any
other person having a claim for payments shall be unsecured
creditors.

11. Non-Assignability. Except as provided in Section 9,
neither a Participant nor a Participant's Beneficiary shall have
the power or right to transfer, assign, anticipate, mortgage or
otherwise encumber his or her interest in the Program; nor shall
such interest be subject to seizure for the payment of a
Participant's or Beneficiary's debts, judgments, alimony, or
separate maintenance or be transferable by operation of law in
the event of a Participant's or Beneficiary's bankruptcy or
insolvency.

The Company's obligations under the Program are not
assignable or transferable except to a Company which acquires all
or substantially all of the assets of the Company or to any
corporation into which the Corporation may be merged or
consolidated.

12. Amendment and Termination. The Board of Directors may
from time to time and at any time alter, amend, suspend,
discontinue or terminate the Program. Nothing contained in the
Program shall be construed to prevent the Company from taking any
corporate action which is deemed by the Company to be appropriate
or in its best interest, whether or not such action would have an
adverse effect on the Program or any Participant's interest in
the Program. Neither any Participant nor any other person shall
have any claim against the Company as a result of any such
action. Notwithstanding the foregoing, the Company may not
modify (or terminate) the Program to the extent doing so would
adversely affect the rights of Participants to Performance Shares
in their Accounts at the time of the modification.

13. No Right of Employment. Nothing contained in the
Program shall be construed as conferring upon a Participant the
right to continue in the employ of the Company.

14. Governing Law. All rights and obligations under the
Program shall be governed by, and the Program shall be construed
in accordance with the laws of the State of Kansas.

15. Titles and Headings. Titles and headings to sections
herein are for purposes of reference only, and shall in no way
limit, define or otherwise affect the meaning or interpretation
of any provisions of the Program.

16. Effective Date. The Program shall become effective
January 1, 1991.

<PAGE>
BENEFICIARY DESIGNATION

Pursuant to Section 9 of the Western Resources' Long-Term
Incentive Plan, the Participant hereby designates as Primary
Beneficiary under this Plan:
_________________________________________________________________
_____________
_________________________________________________________________
_____________
and, Participant hereby designates as Secondary Beneficiary under
this Plan:
_________________________________________________________________
_____________
_________________________________________________________________
_____________
The term "Beneficiary" as used herein shall mean the Primary
Beneficiary if such Primary Beneficiary shall survive Participant
by at least 30 days, and shall mean the Secondary Beneficiary if
Primary Beneficiary does not survive Participant by at least 30
days, and shall mean the Estate of the Participant, if neither
Primary nor Secondary Beneficiary survives the Participant by at
least 30 days. Participant shall have the right to change
Participant's designation of Primary and/or Secondary Beneficiary
from time to time in such manner as shall be required by the
Board of Directors or the Committee, it being agreed that no
change in beneficiary shall be effective until acknowledged in
writing by the Company.

IN WITNESS WHEREOF, Participant has executed this
designation this __________ day of _______________________,
19____.

PARTICIPANT:

_________________________________
(signature)

_________________________________
(type or print name)

WESTERN RESOURCES, INC.
SHORT-TERM INCENTIVE PLAN

The purpose of the Western Resources, Inc. Short-Term
Incentive Plan (Plan) is to motivate key executives, directors,
managers, and select exempt employees to achieve the highest
level of performance to further the achievement of Western
Resources' (WR's) goals, objectives, and strategies. This Plan
is designed to reward exceptional performance using financial
incentives to supplement base compensation. Also, the Plan will
enhance the ability of WR to attract new executive talent when
needed. Finally, the Plan is intended to benefit WR in the
pursuit of its goals and objectives by stimulating and motivating
the President's Council (PC), the Senior Management Council (SMC)
and select exempt employees, which will in turn enhance
productivity and promote the retention of experienced and
qualified executive talent in a cost effective and efficient
manner.

1. Definitions. As used herein the following words and
phrases shall have the following respective meanings unless the
context clearly indicates otherwise:

(a) Award: A grant of a percentage of the total
incentive award made to a Participant under the terms of the
Plan.

(b) Award Criteria: The criteria described in Section
4, consisting of financial, individual, and discretionary
criteria, the satisfaction of which shall determine the
Participant's percentage entitlement to an Incentive Award.

(c) Beneficiary: The person or persons designated by
a Participant pursuant to Section 7 to receive any payment
which under the terms and conditions of the Plan may be made
on behalf of the Participant on or after the Participant's
death.

(d) Board of Directors: The Board of Directors of the
Company.

(e) Company: Western Resources, Inc. a Kansas
corporation, and its successors and assigns.

(f) Discretionary Criteria: Criteria based solely on
the Participant's Supervisor's discretion.

(g) Financial Criteria: Criteria which is based on
the overall company profitability as compared to budget.

(h) Incentive Award: That percentage of a
Participant's base compensation which the Board of Directors
shall, from time to time, determine to be available to a
Participant under the Plan. As an example, a PC member may
be entitled to earn up to 20% of their base compensation as
an Award. The Incentive Award may apply to a class of
employees or to individual employees, at the discretion of
the Board of Directors or the Committee.

(i) Individual Criteria: Criteria which is based on
financial or nonfinancial criteria or both, as determined by
the Participant and the Participant's Supervisor.

(j) Individual Agreement: An agreement developed
during the strategic and financial planning process at the
beginning of each WR fiscal year, which outlines a
Participant's participation in the Plan. Goals and
objectives critical to the successful implementation of the
WR Strategic Plan are the basis for developing the detail
components of each Agreement.

(k) Participant: An employee with whom an Individual
Agreement has been made, but which has not been paid,
canceled, or otherwise terminated or satisfied under the
terms of the Plan.

(l) Plan: The Plan herein set forth, and as from time
to time amended.

(m) Select Exempt Employees: WR executive employees
in pay grades 30 and above.

(n) Participant's Supervisor: The officer, director
or manager to whom the Participant directly reports. The
CEO's Supervisor shall mean the Board of Directors. A PC
member's supervisor is the CEO . A SMC member's supervisor
is the member of the PC to whom that member directly
reports. A Select Exempt Employee's Supervisor shall be the
member of the PC or the SMC to whom that Exempt Employee
reports.

(o) Committee: The committee which may be established
by the Board of Directors pursuant to Section 2 to
administer the Plan.

2. Administration. The Board of Directors, or if one
shall be appointed by the Board of Directors, a committee of at
least three directors, a majority of whom are not eligible to be
Participants (the "Committee"), shall be responsible for
establishing the overall Plan, administering the Plan,
determining whether actual individual compensation awards will be
paid, and approving the amount of the actual individual
compensation awards.

The individual PC members, SMC members, or named exempt
employees are responsible for the preparation of all forms and
reports for reporting regarding their respective Plan
accomplishments.

The members of the Board of Directors and all agents,
officers, fiduciaries, and employees of the Company shall not be
liable for any act, omission, interpretation, construction, or
determination made in good faith in connection with their
responsibilities with respect to the Plan; and the Company hereby
agrees to indemnify the members of the Board of Directors and all
agents, officers, fiduciaries, and employees of the Company in
respect to any claim, loss, damage, or expense (including counsel
fees) arising from any such act, omission, interpretation,
construction, or determination to the full extent permitted by
law.

The day-to-day administration of the Plan with regard to
specific classes of employees shall be carried out as follows:

(a) CEO: The Board, or the Committee if one is
appointed, is responsible for the day-to-day supervision of
the Plan, including designation of the CEO's personal goals,
determination of the achievement of such goals,
determination of the award size relating to the CEO's goals,
and the determination of the amount of the discretionary
award.

(b) PC Members and Presidents: The CEO is responsible
for the day-to-day supervision of the Plan, as it relates to
a PC member and the two Presidents of WR's subsidiary and/or
divisions, Kansas Gas and Electric Company and Gas Service
Company ("Presidents"), including the designation of the PC
member's and Presidents' personal goals, determination of
the achievement of such goals, determination of the award
size relating to the PC member's and Presidents' goals, and
the determination of the amount of the discretionary award.

(c) SMC Members/Executive Vice Presidents: The
Participant's Supervisor is responsible for the day-to-day
supervision of the Plan, as it relates to a SMC member and
WR Executive Vice President (EVP), including designation of
the SMC member's and EVP's personal goals, determination of
the achievement of such goals, determination of the award
size relating to the SMC member's and EVP's goals, and the
determination of the amount of the discretionary award.

(d) Select Exempt Employees: The Participant's
Supervisor is responsible for the day-to-day supervision of
the Plan, as it relates to a select exempt employee,
including designation of the exempt employee's personal
goals, determination of the achievement of such goals,
determination of the award size relating to the exempt
employee's goals, and the determination of the amount of the
discretionary award.

3. Eligibility to Participate. Only employees who are
members of WR's President's Council, members of WR's Senior
Management Council, and WR exempt employees in pay grades 30 and
above shall automatically be eligible to participate in the Plan.
The Board of Directors, or the Committee if one shall be
appointed, shall determine, from time to time, whether the
benefits of the Plan should be extended to other groups of
employees of the Company.

4. Award Criteria. This Plan incorporates three types of
criteria: financial, individual, and discretionary. The
detailed measurement methods for PC members and Presidents, SMC
members/EVP, and select exempt employees are as follows:

(a) PC Members and Presidents.

(1) Financial Criteria (50%). The individual PC
member and Presidents are eligible to receive up to 50%
of the total incentive award based on the overall
company profitability as compared to budget. In other
words, the individual may receive up to an additional
15% of base compensation if certain company standards
are met when actual profitability is compared to
budgeted profitability. However, an additional award
may be available if certain financial criteria is met.

% of Actual Profitability Financial
Criteria
to Budgeted Profitability Award

110% or more of Budget 70%
105% to 109% of Budget 60%
100% to 104% of Budget 50%
95% to 99% of Budget 40%
90% to 94% of Budget 30%
Less than 90% of Budget 0%

The percentage of actual to budgeted profitability is
rounded to the nearest whole percent.

(2) Individual Criteria (30%). The individual PC
member and Presidents and the CEO design the specifics
of this criteria, except for the CEO's individual
criteria, which is designed by the CEO and the Board.
The individual and the CEO may settle on financial
criteria or nonfinancial criteria or both. They must
annually agree on the specific criteria. They may also
determine how to use the criteria and measure the PC
member and President's performance. Under this
criteria, the individual is eligible to receive up to
30% of the total incentive award or an additional 9% of
base compensation. The CEO is eligible to receive up
to 30% of the total incentive award or an additional 9%
of base compensation.

(3) Discretionary Criteria (20%). The individual
PC member and Presidents are eligible to receive up to
20% of the total incentive award or an additional 6% of
base compensation. This criteria is solely at the
CEO's discretion, except for the CEO's award, which is
at the Board's discretion.
<PAGE>
(b) SMC Members/EVP.

(1) Financial Criteria (40%/50%). The individual
SMC member is eligible to receive up to 40% of the
total incentive award based on the overall Company
profitability as compared to budget. In other words,
the SMC member may receive up to an additional 4% of
base compensation if certain Company standards are met
when actual profitability is compared to budgeted
profitability. However, an additional award may be
available if certain financial criteria is met.

% of Actual Profitability Financial
Criteria
to Budgeted Profitability Award

110% or more of Budget 60%
105% to 109% of Budget 50%
100% to 104% of Budget 40%
95% to 99% of Budget 30%
90% to 94% of Budget 20%
Less than 90% of Budget 0%

The individual EVP is eligible to receive up to 50% of
the total incentive award based on the overall Company
profitability as compared to budget. In other words,
the EVP may receive up to an additional 10% of base
compensation if certain Company standards are met when
actual profitability is compared to budgeted
profitability. However, an additional award may be
available if certain financial criteria is met.

% of Actual Profitability Financial
Criteria
to Budgeted Profitability Award

110% or more of Budget 70%

105% to 109% of Budget 60%
100% to 104% of Budget 50%
95% to 99% of Budget 40%
90% to 94% of Budget 30%
Less than 90% of Budget 0%

The percentage of actual to budgeted profitability is
rounded to the nearest whole percent.

(2) Individual Criteria (40%/30%). The
individual SMC member and EVP and the PC contact design
the specifics of this criteria. The individual and the
PC contact may settle on financial criteria or
nonfinancial criteria or both. They must annually
agree on the specific criteria. They must also
determine how to use the criteria and measure the SMC
member's and EVP's performance. Under this criteria,
the individual SMC member is eligible to receive up to
40% of the total incentive award or an additional 4% of
base compensation. The individual EVP is eligible to
receive up to 30% of the total incentive award or an
additional 6% of base compensation.

(3) Discretionary Criteria (20%). The individual
SMC member is eligible to receive up to 20% of the
total incentive award or an additional 2% of the base
compensation. The EVP is eligible to receive up to 20%
of the total incentive award or an additional 4% of
base compensation. This criteria is solely at the PC
contact's discretion.

(1) Financial Criteria (30%). The select exempt
employee is eligible to receive up to 30% of the total
incentive award based on the overall Company
profitability as compared to budget. In other words,
the exempt employee may receive up to an additional
1.5% of base compensation if certain Company standards
are met when actual profitability is compared to
budgeted profitability. However, an additional award
may be available if certain financial criteria is met.

% of Actual Profitability Financial
Criteria
to Budgeted Profitability Award

110% or more of Budget 50%
105% to 109% of Budget 40%
100% to 104% of Budget 30%
95% to 99% of Budget 20%
90% to 94% of Budget 10%
Less than 90% of Budget 0%

The percentage of actual to budgeted profitability is
rounded to the nearest whole percent.

(2) Individual Criteria (50%). The select exempt
employee and the PC or SMC contact design the specifics
of this criteria. The individual and PC or SMC contact
may settle on financial criteria or nonfinancial
criteria or both. They must annually agree on the
specific criteria. They must also determine how to use
the criteria and measure the exempt employee's
performance. Under this criteria, the individual is
eligible to receive up to 50% of the total incentive
award or an additional 2.5% of base compensation.

(3) Discretionary Criteria (20%). The select
exempt employee is eligible to receive up to 20% of the
total incentive award or an additional 1% of base
compensation. This criteria is solely at the PC or SMC
contact's discretion.

5. Payment of Awards.

(a) Generally. The incentive compensation award,
if adopted for the year, is payable annually. The
payment shall be made in February following the Plan
year for which the award was approved.

(b) Termination of Employment. A Participant who
ceases to be continually employed by the Company (other
than as a result of a Company-approved leave of absence
or the Participant's death, disability, or retirement
under the Company pension plan's early or normal
retirement provisions) shall forfeit all rights to an
annual incentive award for the year not yet ended.

(c) Payment in the Event of Death, Disability, or
Retirement. If a participant dies, becomes disabled,
or retires under the Company pension plan's early or
normal retirement provisions, his or her actual
incentive compensation award for the year, determined
in accordance with the provisions of the Plan, shall be
reduced to reflect only participation prior to
termination. This reduction is based on the number of
months the individual was an active Participant in the
Plan in the year of termination. In the event of the
Participant's death while the Plan is in effect,
payments of any amounts due under such Plan shall be
made to the Participant's designated beneficiary or to
the Participant's estate.

6. Withholding for Taxes. The Company will provide for
the withholding of any taxes required by any governmental
authority with respect to any payment that is to be made under
the Plan. The amount withheld shall be paid over by the Company
to such governmental authority for the account of the Participant
entitled to the payment.

7. Designation of Beneficiary. A Participant shall
designate a Beneficiary or Beneficiaries on the Beneficiary
Designation form in the appendix (which may be designated
contingently and which may be an entity other than a natural
person) to receive any amounts which under the terms of the Plan
may become payable on or after the Participant's death. Any such
designation may, unless the Participant has waived such right,
from time to time and at any time, be changed or canceled by the
Participant without the consent of a Beneficiary. Any such
designation must be in writing and filed with the Board of
Directors . If a Participant designates more than one
Beneficiary, any payments under the Plan to such Beneficiaries
shall be made in equal shares unless the Participant has
designated otherwise, in which case the payments shall be made in
the shares designated by the Participant. If a Participant does
not designate a beneficiary or there is no proper designation of
a Beneficiary or no person designated as a Beneficiary shall
survive the Participant by 30 days, the Participant's Beneficiary
shall be his or her estate.

8. No Rights to Corporate Assets. Nothing contained herein
shall be construed as giving a Participant, his or her
Beneficiary, or any other person any equity or other interest of
any kind in any assets of the Company or creating a trust of any
kind or a fiduciary relationship of any kind between the Company
and any such person. As to any claim for any unpaid amounts
under the Plan, a Participant, his or her Beneficiary, and any
other person having a claim for payments shall be unsecured
creditors.

9. Non-Assignability. Except as provided in Section 7,
neither a Participant nor a Participant's Beneficiary shall have
the power or right to transfer, assign, anticipate, mortgage, or
otherwise encumber his or her interest in the Plan; nor shall
such interest be subject to seizure for the payment of a
Participant's or Beneficiary's debts, judgments, alimony, or
separate maintenance or be transferable by operation of law in
the event of a Participant's or Beneficiary's bankruptcy or
insolvency.

The Company's obligations under the Plan are not assignable
or transferable except to a Company which acquires all or
substantially all of the assets of the Company or to any
corporation into which the Corporation may be merged or
consolidated.

10. Amendment and Termination. The Board of Directors may
from time to time and at any time alter, amend, suspend,
discontinue, or terminate the Plan. Nothing contained in the
Plan shall be construed to prevent the Company from taking any
corporate action which is deemed by the Company to be appropriate
or in its best interest, whether or not such action would have an
adverse effect on the Plan or any Participant's interest in the
Plan. Neither any Participant nor any other person shall have
any claim against the Company as a result of any such action.
Notwithstanding the foregoing, the Company may not modify (or
terminate) the Plan to the extent doing so would adversely affect
the rights of Participants to an Incentive Award at the time of
the modification.

11. No Right of Employment. Nothing contained in the Plan
shall be construed as conferring upon a Participant the right to
continue in the employ of the Company.

12. Governing Law. All rights and obligations under the
Plan shall be governed by, and the Plan shall be construed in
accordance with the laws of the State of Kansas.

13. Titles and Headings. Titles and headings to sections
herein are for purposes of reference only and shall in no way
limit, define, or otherwise affect the meaning or interpretation
of any provisions of the Plan.

14. Effective Date. The Plan shall become effective
January 1, 1990.

__________________________________
Secretary
<PAGE>
BENEFICIARY DESIGNATION

Pursuant to Section 7 of the Western Resources' Short-Term
Incentive Plan, the Participant hereby designates as Primary
Beneficiary under this Plan:
_________________________________________________________________
_____________
_________________________________________________________________
_____________
and, Participant hereby designates as Secondary Beneficiary under
this Plan:
_________________________________________________________________
_____________
_________________________________________________________________
_____________
The term "Beneficiary" as used herein shall mean the Primary
Beneficiary if such Primary Beneficiary shall survive Participant
by at least 30 days, and shall mean the Secondary Beneficiary if
Primary Beneficiary does not survive Participant by at least 30
days, and shall mean the Estate of the Participant, if neither
Primary nor Secondary Beneficiary survives the Participant by at
least 30 days. Participant shall have the right to change
Participant's designation of Primary and/or Secondary Beneficiary
from time to time in such manner as shall be required by the
Board of Directors or the Committee, it being agreed that no
change in beneficiary shall be effective until acknowledged in
writing by the Company.

IN WITNESS WHEREOF, Participant has executed this
designation this __________ day of _______________________,
19____.

PARTICIPANT:

_________________________________
(signature)

_________________________________
(type or print name)

Exhibit 10(k)
WESTERN RESOURCES, INC.

OUTSIDE DIRECTORS' DEFERRED COMPENSATION PLAN

Amended and Restated November 20, 1991

I. ESTABLISHMENT

The Board of Directors of Western Resources, Inc.
(hereinafter called the "Company") on September 15, 1990,
established a Non-Qualified Deferred Compensation Plan
pursuant to which Outside Directors of the Company who are
in a position to contribute to its continued growth,
development and future financial success may be offered an
opportunity to defer all or a portion of their compensation
under terms and conditions that will represent a meaningful
compensation benefit to them. The Plan is amended and
restated according to the terms herein, effective November
20, 1992, and all deferred amounts shall be subject to the
terms hereof.

II. PURPOSE

The purpose of the Plan is to improve the Company's ability
to attract and retain Outside Directors who will contribute
to the overall success of the Company.

III. DEFINITIONS

BENEFICIARY shall mean any person designated by the
Participant on a form supplied by the Plan Administrator and
if no beneficiary is designated, then the Participant's
estate.

BOARD shall mean the Board of Directors of the Company.

COMPANY shall mean Western Resources, Inc., a Kansas
corporation, or any successor thereto.

OUTSIDE DIRECTOR shall mean any director of the Company who
is not also an employee of the Company.

PARTICIPANT shall mean any Outside Director of the Company
who elects to defer fees hereunder.

PLAN shall mean Western Resources, Inc. Outside Directors'
Deferred Compensation Plan as set forth in its entirety in
this document as it may be amended from time to time.

PLAN ADMINISTRATOR shall mean the Human Resources Committee
of the Company's Board of Directors or any other committee
appointed by the Board of Directors to act in said capacity.

PLAN YEAR shall mean the calendar year.

PRONOUNS Masculine pronouns used herein shall refer to men
or women or both and nouns and pronouns when stated in the
singular shall include the plural and when stated in the
plural shall include the singular, wherever appropriate.

IV. EFFECTIVE DATE

The Plan, as amended and restated herein, will become
effective on November 20, 1991.

V. HISTORY

The Outside Directors of the Company are paid an annual
retainer and a per meeting fee. The Plan allows the Outside
Directors to elect to defer all, part, or none of their
retainer and/or meeting fees. The Outside Directors have
two investment alternatives from which to choose: Cash
Deferral and Phantom Stock.

VI. ADMINISTRATION OF THE PLAN

The Plan shall be administered by the Compensation Committee
of the Board of Directors of the Company or by such other
Committee as may be appointed by the Board from time to
time. Each designated Plan Participant shall enter into a
written agreement (including the execution of the
appropriate exhibits thereto) with the Company which
contains the detailed provisions of the Plan.

VII. ELIGIBILITY

All Outside Directors of the Company shall be eligible to
participate.

VIII. ELECTION TO DEFER

The Plan is a voluntary participation plan. The Outside
Director must irrevocably elect to defer the designated
portion of his annual retainer and/or meeting fees. Such
election is made by entering into a written agreement with
the Company prior to the Director providing service to the
Company as Director. All deferrals must be for a minimum of
six months.

Directors are elected in early May of each year. To be
eligible to defer amounts during his initial year, the
Director must make the election to defer the amounts as soon
as elected but no later than May 21. This election is
effective until December 31 of the first year of the
Director's term.

If during a year, it becomes necessary to replace a
Director, the new Director must make the election as soon as
possible after his appointment but not later than fourteen
(14) days after appointment.

For subsequent years, the agreement must be entered into on
or before December 31 of the year preceding the year for
which the deferral is to be effective. In years subsequent
to the execution of the above agreement, a new election to
defer shall be evidenced by the execution and delivery on or
before December 31 immediately prior to the year it is to be
effective, of a deferral election form prescribed for that
purpose by the Human Resources Committee.

The Director must elect the amount, if any, to be deferred,
the deferral option and timing of payments. All of the
above are defined below.

IX. AMOUNT TO BE DEFERRED

The Director may defer all, a portion or none of the annual
retainer, designated as a percentage of the retainer. The
Director may also defer all, a portion or none of the per
meeting fee, designated as a percentage of the fee.

X. DEFERRAL PLAN OPTIONS

The Director may choose one of the following deferral
options: cash deferral or phantom stock. All amounts
deferred are subject to terms of the option elected. The
election is made as part of the election process of part
VIII.

(a) Cash Deferral

Under the cash deferral option, the Director elects to
defer the receipt of the cash payment of all or a
portion of his annual retainer and/or meeting fee.
Interest will accrue at the rate defined in Part XI.

(b) Phantom Stock

Under the phantom stock option, the Director elects to
defer all or a portion of his annual retainer and/or
meeting fee. The Director receives credit for "stock
units" that represent shares of the Company's common
stock equal to the amount deferred.

(1) The number of "stock units" received is dependent
on the fair market value of the Company's common stock
on the measurement date.

(2) "Fractional stock units" will be accounted for as
non-interest bearing cash.

(3) The measurement date is the regular payment date
of the retainer and/or meeting fee. The "stock units"
will be measured at the closing price on the date the
deferred amount would have been paid.

(4) Dividend reinvestment is discussed in Part XI.

XI. DEFERRED COMPENSATION ACCOUNT

The Company will establish a separate "account" for each
Participant and will credit to said account the compensation
deferred by the Participant. The amount deferred under the
cash deferral option will earn interest at the New York
prime rate and will be credited quarterly (March 15, June
15, September 15, and December 15).

The Director's account is deemed to receive "dividends" on
the "units" of phantom stock equal to the dividends paid on
the Company's common stock. The dividend received will be
treated similar to the Company's Dividend Reinvestment
Program and will be used to purchase additional "units" of
the Company's stock at the closing price of the stock on the
date the common stock dividend is paid. Any fractional
stock units will be accounted for as non-interest bearing
cash. The account is also adjusted for any stock dividends,
stock splits, etc. In the event the Company's Dividend
Reinvestment Program is modified in any way, dividends paid
through this Plan will be made in accordance with said
modification. If the Company's Dividend Reinvestment
Program is terminated, dividends made through this Plan will
continue to be reinvested in accordance with the provisions
of the terminated Dividend Reinvestment Program.

The amount equal to the balance in the account of the
Participant, taking into account all credits, shall be the
Participant's deferred compensation benefit available from
time to time under the terms hereof.

XII. DISTRIBUTION FROM THE DEFERRED COMPENSATION ACCOUNT

By written irrevocable election made at the time of each
deferral election, the Director must select one of the
following methods for receipt of the balance in his deferred
compensation account:

(a) lump sum at termination; or

(b) paid monthly over a specified number of years
determined by the irrevocable election.

The balance in the deferred compensation account becomes
measurable at the end of the Director's term.

The balance to be distributed in the deferred compensation
account under the cash deferral option is the cash balance
of the account. The balance to be distributed in the
deferred compensation account under the phantom stock option
is an amount equal to the credited "stock units'" fair
market value at the time the account becomes measurable.

At the time the account balance becomes measurable, the
account balance is valued. From that date forward, any
remaining balance (i.e., balance during time of installment
payments) shall bear interest at the New York prime rate.

Distribution in the form elected by the Director shall
commence immediately upon the occurrence of any of the
following events: death, retirement, disability, or
termination, if such event occurs prior to the distribution
date elected by the Director.

The Director shall also designate a beneficiary to receive
the unpaid balance of the value of his account in the event
of his death prior to complete distribution of such unpaid
balance. If no beneficiary is designated, then his estate
will be deemed his beneficiary. Distribution after the
death of a Participant shall be in the form selected by the
Participant.

XIII. STATE LAWS GOVERNING PLAN

This Plan shall be governed by the laws of the State of
Kansas.

AMENDMENT OR TERMINATION

This Plan shall continue in effect until amended or terminated by
the Company's Board of Directors. Any such amendment or
termination shall not adversely affect any agreement theretofore
entered into with a designated Director.

This Amended and Restated Plan was adopted by the Board on
November 20, 1991.

Western Resources, Inc.

________________________________
John K. Rosenberg
Executive Vice President and
General Counsel

<PAGE>
DEFERRED COMPENSATION AGREEMENT

THIS AGREEMENT, made as of the ______ day of ______________,
19____, by and between Western Resources, Inc. with executive and
general offices at 818 Kansas Avenue, Post Office Box 889,
Topeka, Kansas 66601 (hereinafter called the "Company"), and
_________________________ residing at ___________________________
hereinafter called "Director").

WITNESSETH in consideration of the premises, and the mutual
promises and agreements herein contained, the parties hereto
agree as follows, intending to be legally bound hereby:

1. Agreement Incorporates Plan

The terms of Western Resources, Inc. Outside Directors'
Deferred Compensation Plan (hereinafter referred to as
"Plan") effective _______________, 199___, are hereby
incorporated herein and made a part hereof as if set out
verbatim. Said Plan and this Agreement set forth the terms
which govern and control Director's participation in the
Plan.

2. Exhibits A and B are Incorporated Herein

Exhibit A, which is the Election Deferring Compensation
described in the Plan, is attached hereto and made a part
hereof. Exhibit B, which is Director's Designation of
Beneficiary, is attached hereto and made a part hereof.

3. Agreement to Participate

By execution of this Agreement, Director hereby agrees to
participate in the Plan pursuant to the terms hereof, elect
to defer compensation pursuant to Exhibit A, and designates
his Beneficiary pursuant to Exhibit B.

4. Restrictions Against Alienation

Neither the Director nor his Beneficiary shall have any
right to commute, sell, assign, transfer, or otherwise
convey or encumber the rights to receive any payments
hereunder, which payments and all the rights thereto are
expressly declared to be nonassignable and nontransferable.

5. Termination of the Agreement by the Company

The Company may terminate this Agreement at any time. If
the Company terminates this Agreement, the Company shall pay
Director or his Beneficiary an amount equal to the value of
his account as described in the Plan in the amount(s) and at
the time(s) elected by the Director hereunder.
<PAGE>
6. What Constitutes Notice to the Director

Any notice to Director hereunder may be given either by hand
delivering it to Director or by depositing it in the United
States Mail, postage prepaid, return receipt requested,
addressed to his last known address.

7. Advance Disclaimer of Any Waiver on the Part of the Company

Failure to insist upon strict compliance with any of the
terms, covenants, or conditions hereof shall not be deemed a
waiver of such term, covenant, or condition, nor shall any
waiver or relinquishment of any right or power hereunder at
any one or more times be deemed a waiver or relinquishment
of such right or power at any other time or times.

8. Effect of Invalidity of Any Part of the Agreement Upon the
Whole Agreement

The invalidity or unenforceability of any provision hereof
shall in no way affect the validity or enforceability of any
other provision.

9. Agreement Binding on Any Successor Owner

Except as otherwise provided herein, this Agreement shall
inure to the benefit of and be binding upon Director, his
heirs, executors, and administrators and upon the Company,
its successors and assigns, including but not limited to any
corporation which may acquire all or substantially all of
the Company's assets and business or with or into which the
Company may be consolidated or merged.

10. State Laws Governing this Agreement

This Agreement shall be governed by the laws of the State of
Kansas.

11. Counterparts of this Agreement and Director's
Acknowledgement that he has Read and Understands all parts
of this Agreement

This Agreement has been executed in several counterparts,
each of which shall be an original, but such counterparts
shall together constitute but one (1) instrument. Director
acknowledges that he has read all parts of the Plan and this
Agreement, including Exhibits A and B annexed hereto and
made a part of this Agreement and has sought and obtained
satisfactory answer(s) to any question(s) he had as to his
rights, obligations, and potential liabilities under this
Agreement prior to affixing his signature and initials to
any part of this Agreement.

IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.

ATTEST: WESTERN RESOURCES, INC.

____________________________ By: __________________________
Name: ________________________
WITNESS: Title: _______________________

_________________________ __________________________
Director
Name: ________________________
(Please Print)

Exhibit 12
<TABLE>

WESTERN RESOURCES, INC.
Computations of Ratio of Earnings to Fixed Charges and
Computations of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend Requirements
(Thousands of Dollars)
<CAPTION>

Year Ended December 31,
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
Net Income. . . . . . . . . . . . . . $177,370 $127,884 $ 89,645 $ 79,619 $ 72,778
Taxes on Income . . . . . . . . . . . 78,755 46,099 42,527 36,736 35,171
Net Income Plus Taxes. . . . . . 256,125 173,983 132,172 116,355 107,949

Fixed Charges:
Interest on Long-Term Debt. . . . . 123,551 117,464 51,267 51,542 46,378
Interest on Other Indebtedness. . . 19,255 20,009 10,490 11,022 8,742
Interest on Corporate-owned
Life Insurance Borrowings . . . . 16,252 5,294 - - -
Interest Applicable to
Rentals . . . . . . . . . . . . . 28,827 27,429 5,089 4,426 4,673
Total Fixed Charges . . . . . . 187,885 170,196 66,846 66,990 59,793

Preferred and Preference Dividend
Requirements:
Preferred and Preference Dividends. 13,506 12,751 6,377 1,744 1,857
Income Tax Required . . . . . . . . 5,997 4,596 3,025 805 897
Total Preferred and Preference
Dividend Requirements . . . . . . 19,503 17,347 9,402 2,549 2,754
Total Fixed Charges and Preferred and
Preference Dividend Requirements. . 207,388 187,543 76,248 69,539 62,547

Earnings (1). . . . . . . . . . . . . $444,010 $344,179 $199,018 $183,345 $167,742

Ratio of Earnings to Fixed Charges. . 2.36 2.02 2.98 2.74 2.81

Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements . . . . . . . 2.14 1.84 2.61 2.64 2.68

(1) Earnings are deemed to consist of net income to which has been added income taxes
(including net deferred investment tax credit) and fixed charges. Fixed charges consist
of all interest on indebtedness, amortization of debt discount and expense, and the
portion of rental expense which represents an interest factor. Preferred and preference
dividend requirements consist of an amount equal to the pre-tax earnings which would be
required to meet dividend requirements on preferred and preference stock.

</TABLE>

Exhibit 23(a)

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation
of our report included in this Form 10-K, into the Company's previously filed
Registration Statements File Nos. 33-23021, 33-23022, 33-23023, and 33-47344
on Form S-8 and Nos. 33-49467, 33-49505, 33-49553, and 33-50069 on Form S-3.

ARTHUR ANDERSEN & CO.
Kansas City, Missouri,
March 18, 1994

Exhibit 23(b)

INDEPENDENT AUDITORS' CONSENT

We consent to the use in this Annual Report on Form 10-K of Western Resources,
Inc. for the year ended December 31, 1993 of our report dated January 29, 1993
appearing in the Annual Report on Form 10-K of Kansas Gas and Electric Company
for the year ended December 31, 1993.

DELOITTE & TOUCHE

Kansas City, Missouri
March 18, 1994

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

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

For the fiscal year ended December 31, 1993

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

Commission file number 1-7324

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

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

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

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

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

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

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

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

Common Stock, No par value 1,000 Shares
(Title of each class) (Outstanding at March 18, 1994)

Registrant meets the conditions of General Instruction J(2)(c) to Form 10-K
for certain wholly-owned subsidiaries and is therefore filing an abbreviated
form.
<PAGE>
KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1993

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 11

Item 3. Legal Proceedings 12

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

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

Item 6. Selected Financial Data 12

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

Item 8. Financial Statements and Supplementary Data 19

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

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

Item 11. Executive Compensation 46

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

Item 13. Certain Relationships and Related Transactions 46

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

Signatures 56

<PAGE>
PART I

ITEM 1. BUSINESS

ACQUISITION AND MERGER

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

GENERAL

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

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

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

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

ELECTRIC OPERATIONS

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

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

1993 1992 1991 1990 1989
(Thousands of MWH)

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

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

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

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

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

Capacity. The aggregate net generating capacity of the Company's system
is presently 2,472 megawatts (MW). The system comprises interests in twelve
fossil fueled steam generating units, one nuclear generating unit (47%
interest) and one diesel generator, located at seven generating stations. One
of the twelve fossil fueled units has been "mothballed" for future use (see
Item 2. Properties).

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

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

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

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

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

Coal. Western Resources, the operator of Jeffrey Energy Center (JEC) and
KG&E (20% interest in JEC), have a long-term coal supply contract with Amax
Coal West, Inc. (AMAX), a subsidiary of Cyprus Amax Coal Company, to supply
low sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine
source of AMAX's Belle Ayr Mine, both located in the Powder River Basin in
Campbell County, Wyoming. The contract expires December 31, 2020. The
contract contains a schedule of minimum annual delivery quantities with
deficient mmBTU provisions applicable to deficiencies in the scheduled
delivery. The coal to be supplied is surface mined and has an average BTU
content of approximately 8,300 BTU per pound and an average sulfur content of
.43 lbs/mmBTU (see Environmental Matters). The average delivered cost of coal
for JEC was approximately $1.045 per mmBTU or $17.35 per ton during 1993.

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

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.

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

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

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

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

Cents per KWH Generation 0.93 0.98 1.09 1.01 0.96

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

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

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

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

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

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

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

FINANCING

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

The Company's mortgage prohibits additional first mortgage bonds from
being issued (except in connection with certain refundings) unless the
Company's net earnings before income taxes and before provision for retirement
and depreciation of property for a period of 12 consecutive months within 15
months preceding the issuance are not less than two and one-half times the
annual interest charges on, or 10% of the principal amount of, all first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on the Company's results for the 12 months ended December 31, 1993,
approximately $1 billion principal amount of additional first mortgage bonds
could be issued (7.5 percent interest rate assumed).

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

REGULATION AND RATES

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

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

Additional information with respect to Regulation and Rates is discussed
in Notes 1 and 4 of the Notes to Financial Statements.
<PAGE>

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

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

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

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

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

ITEM 2. PROPERTIES

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

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

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

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

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

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

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

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

Wichita Plant:
Diesel Generator 5 1969 Diesel 3

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

Total 2,472

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

(2) Based on MOKAN rating.

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

<PAGE>
ITEM 3. LEGAL PROCEEDINGS

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

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

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

PART II

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

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

<TABLE>
ITEM 6. SELECTED FINANCIAL DATA
<CAPTION>

1993 1992 1991 1990(1) 1989
(Dollars in Thousands)
<S> <C> <C> <C> <C>
Income Statement Data:

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

Balance Sheet Data:

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

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

(1) See Note 4 of the Notes to Financial Statements for impact of rate refund orders.
</TABLE>
<PAGE>

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

FINANCIAL CONDITION

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

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

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

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

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

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

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

On November 22, 1993, the Company redeemed three series of first mortgage
bonds, $25 million principal amount of First Mortgage Bonds, 7 3/8% Series due
2002, $25 million principal of First Mortgage Bonds, 8 3/8% Series due 2006,
and $25 million principal of First Mortgage Bonds, 8 1/2% Series due 2007.
<PAGE>
On September 20, 1993, the Company terminated a long-term revolving credit
agreement which provided for borrowings of up to $150 million. The loan
agreement, which was effective through October 1994, was repaid without
penalty.

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

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

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

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

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

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

RESULTS OF OPERATIONS

The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, and
interest charges. Additional information relating to changes between years is
provided in the Notes to Financial Statements.
<PAGE>
Revenues: The operating revenues of the Company are based on sales
volumes and rates, authorized by the Kansas Corporation Commission (KCC) and
the FERC, charged for the sale and delivery of electricity. Rates are
designed to recover the cost of service and allow investors a fair rate of
return. Future electric sales will continue to be affected by weather
conditions, competing fuel sources, customer conservation efforts and the
overall economy of the Company's service area.

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

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

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

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

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

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

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

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

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

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

As permitted under the La Cygne 2 generating station lease agreement, in
1992, KG&E requested the Trustee Lessor to refinance $341.1 million of secured
facility bonds of the Trustee and owner of La Cygne 2. The transaction was
requested to reduce the Company's recurring future net lease expense. To
accomplish this transaction, a one-time payment of approximately $27 million
was made which will be amortized over the remaining life of the lease and will
be included in operating expense as part of the future lower lease expense.
On September 29, 1992 the Trustee Lessor refinanced bonds having a coupon rate
of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
<PAGE>

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

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

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

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

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

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

OTHER INFORMATION

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

Environmental: The Company has recognized the importance of environmental
responsibility and has taken a proactive position with respect to the
potential environmental liability associated with former manufactured gas
sites. The Company has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (see Note 3).
<PAGE>
The Company currently has no Phase I affected units under the Clean Air
Act of 1990. Until such time that additional regulations become final the
Company will be unable to determine its compliance options or related
compliance costs. (see Note 3).

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

Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112
(SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on
the Company see Note 8 of the Notes to Financial Statements.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Independent Auditors' Report 20

Financial Statements:

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

Financial Statement Schedules:

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

SCHEDULES OMITTED

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

I, II, III, IV, VII, VIII, IX, X, XI, XII and XIII.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying balance sheet and statement of capitalization
of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western
Resources, inc.) as of December 31, 1993, and the related statements of
income, cash flows, taxes, and common stock equity for the year then ended.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements
based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 1993, and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.

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

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

Kansas City, Missouri, ARTHUR ANDERSEN &
CO.
January 28, 1994
<PAGE>
INDEPENDENT AUDITORS' REPORT

Kansas Gas and Electric Company:

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 1992 and
the results of its operations and its cash flows for the periods indicated in
conformity with generally accepted accounting principles. Also, in our
opinion, such financial statement schedules, when considered in relation to
the basic financial statements taken as a whole, present fairly in all
material respects the information shown therein.

DELOITTE & TOUCHE

Kansas City, Missouri
January 29, 1993

<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of Dollars)
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
ASSETS

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

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

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

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

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

CAPITALIZATION AND LIABILITIES

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

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

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

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
</TABLE>

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

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

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
</TABLE>

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

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
</TABLE>

<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF TAXES
(Thousands of Dollars)
<CAPTION>

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

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

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

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
</TABLE>

<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
COMMON STOCK EQUITY (Note 1):
(see statement)
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 56.1% $1,065,634 53.0%
Retained earnings . . . . . . . . . . . . . . . . . . . . . 180,044 9.5 71,941 3.6
Total common stock equity . . . . . . . . . . . . . . . . 1,245,678 65.6 1,137,575 56.6
</TABLE>

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

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

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

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

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

</TABLE>
<PAGE>

<TABLE>

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

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

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

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

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

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

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

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

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

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

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

The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
</TABLE>
<PAGE>

KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

1. ACQUISITION AND MERGER

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

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

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

In the November 1991 KCC order approving the Merger, a mechanism was
approved to share equally between the shareholders and ratepayers the cost
savings generated by the Merger in excess of the revenue requirement needed to
allow recovery of the amortization of a portion of the acquisition adjustment,
including income tax, calculated on the basis of a purchase price of KG&E's
common stock at $29.50 per share. The order provides an amortization period
<PAGE>
for the acquisition adjustment of 40 years commencing in August 1995, at which
time the full amount of cost savings is expected to have been implemented.
Merger savings will be measured by application of an inflation index to
certain pre-merger operating and maintenance costs at the time of the next
Kansas rate case. While the Company has achieved savings from the Merger,
there is no assurance that the savings achieved will be sufficient to, or the
cost savings sharing mechanism will operate as to fully offset the
amortization of the acquisition adjustment. The order further provides a
moratorium on increases, with certain exceptions, in the Company's Kansas
electric rates until August 1995. The KCC ordered refunds totalling $32
million to the combined companies' (Western Resources and the Company)
customers to share with customers the Merger-related cost savings achieved
during the moratorium period. The first refund was made in April 1992 and
amounted to approximately $4.9 million for the Company. A refund of
approximately $4.9 million was made in December 1993 and an additional refund
of approximately $8.7 million will be made in September 1994.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: The financial statements of KG&E include, through March 31,
1992, its 80% owned subsidiary, CIC Systems, Inc. (CIC). In April 1992, the
Company disposed of its 80% interest in CIC. KG&E owns 47 percent of Wolf
Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf
Creek Generating Station (Wolf Creek). The Company records its proportionate
share of all transactions of WCNOC as it does other jointly-owned facilities.
The accounting policies of the Company are in accordance with generally
accepted accounting principles as applied to regulated public utilities. The
accounting and rates of the Company are subject to requirements of the KCC and
the Federal Energy Regulatory Commission (FERC).

Utility Plant: Utility plant (including plant acquisition adjustment) is
stated at cost. For constructed plant, cost includes contracted services,
direct labor and materials, indirect charges for engineering, supervision,
general and administrative costs, and an allowance for funds used during
construction (AFUDC). The AFUDC rate was 4.41% for 1993, 6.51% for the nine
months ended December 31, 1992, 6.70% for the three months ended March 31,
1992, and 7.74% for 1991. The cost of additions to utility plant and
replacement units of property is capitalized. Maintenance costs and
replacement of minor items of property are charged to expense as incurred.
<PAGE>
When units of depreciable property are retired, they are removed from the
plant accounts and the original cost plus removal charges less salvage are
charged to accumulated depreciation.

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

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

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

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

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

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

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

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

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

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

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

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

3. COMMITMENTS AND CONTINGENCIES

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

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

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

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.

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

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

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

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

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

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

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

4. RATE MATTERS AND REGULATION

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

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

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

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

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

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

5. SHORT-TERM BORROWINGS

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

6. LONG-TERM DEBT

The amount of first mortgage bonds authorized by the KG&E Mortgage and
Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a
maximum of $2 billion. Amounts of additional bonds which may be issued are
subject to property, earnings, and certain restrictive provisions of the
Mortgage. Electric plant is subject to the lien of the Mortgage except for
transportation equipment. During 1993, the Company refinanced $65 million of
first mortgage bonds by issuing $65 million of First Mortgage Bonds, 6 1/2%
Series due 2005. In 1992, the Company refinanced $125 million of first
mortgage bonds by issuing $135 million of First Mortgage Bonds, 7.6% Series
due 2003.

Debt discount and expenses are being amortized over the remaining lives
of each issue. The improvement and maintenance fund requirements for certain
first mortgage bond series can be met by bonding additional property. The
sinking fund requirements for certain pollution control series bonds can be
met only through the acquisition and retirement of outstanding bonds.

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

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

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

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

Maturing Retiring
Year Bonds Bonds
(Dollars in Thousands)

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

7. SALE-LEASEBACK OF LA CYGNE 2

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

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

The gain of approximately $322 million realized at the date of the sale
has been deferred for financial reporting purposes, and is being amortized
over the initial lease term in proportion to the related lease expense. The
Company's lease expense, net of amortization of the deferred gain and a one-
time payment, was approximately $22.5 million for 1993, $20.6 million for the
nine months ended December 31, 1992, $7.5 million for the three months ended
March 31, 1992, and $30 million for 1991.

8. EMPLOYEE BENEFIT PLANS

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

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

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

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

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

Year Ended December 31, 1993 1992

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

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

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

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

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

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

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

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

9. INCOME TAXES

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

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

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

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

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

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

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

10. LEGAL PROCEEDINGS

The Company is involved in various other legal and environmental
proceedings. Management believes that adequate provision has been made within
the financial statements for these matters and accordingly believes their
ultimate dispositions will not have a material adverse effect upon the
financial position or results of operations of the Company.
<PAGE>
A provision of $12 million was recorded in miscellaneous expenses on the
1991 statement of income with respect to various legal matters.

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

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

12. JOINT OWNERSHIP OF UTILITY PLANTS

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

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

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

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

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

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

14. RELATED PARTY TRANSACTIONS

Subsequent to the Merger, the cash management function, including cash
receipts and disbursements, for KG&E has been assumed by Western Resources.
As a result, the proceeds of cash collections, including short-term
borrowings, less disbursements related to KG&E transactions have been recorded
by the Companies through an intercompany account which, at December 31, 1993,
resulted in a net advance by KG&E to Western Resources of $192.8 million.
Certain of the Company's operating expenses have been allocated from Western
Resources. These expenses are allocated, depending on the nature of the
expense, based on allocation
studies, net investment, number of customers, and/or other appropriate
allocators. Management believes such allocation procedures are reasonable.
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

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

<PAGE>
PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

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

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

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

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

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

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

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

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

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

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

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

(a) Member of the Audit Committee of which Mr. Johnston is Chairman.
The Audit Committee has responsibility for the investigation and
review of the financial affairs of the Company and its relations
with independent accountants.
(b) Mr. Crain, Mr. Johnston, Mr. Koester, Mr. Noone, and Mr. Newton
Smith were directors of the former Kansas Gas & Electric Company
since 1981, 1980, 1986, 1986, and 1985, respectively.

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

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

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

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

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

The following financial statements are included herein under Item 8.

FINANCIAL STATEMENTS

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

The following supplemental schedules are included herein.

SCHEDULES

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

REPORTS ON FORM 8-K

Form 8-K dated January 31, 1994
<PAGE>

EXHIBIT INDEX

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

Description

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

10(c) Outside Directors' Deferred Compensation Plan

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

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

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

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

<TABLE>
KANSAS GAS AND ELECTRIC COMPANY

Schedule V - Utility Plant

(Successor)
<CAPTION>

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

For the Year Ended December 31, 1993
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $ 469,258 $ 26,648 $ 2,710 $ - $ 493,196
Nuclear Production. . . . . . . . 1,355,678 11,324 614 - 1,366,388
Transmission. . . . . . . . . . . 215,898 1,422 141 - 217,179
Distribution. . . . . . . . . . . 371,714 19,630 1,872 - 389,472
General . . . . . . . . . . . . . 62,110 6,839 1,846 - 67,103
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 29,634 (1,198) - - 28,436
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,458 5 129 - 15,334
Nuclear Fuel. . . . . . . . . . . 59,305 6,764 19,381 - 46,688
Plant Acquisition Adjustment. . . 796,265 - - (12,089) 784,176
$3,382,304 $ 71,434 $ 26,693 $ (12,089) $3,414,956

</TABLE>
<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY

Schedule V - Utility Plant
<CAPTION>

Balance at Transfers, Balance at
Beginning Additions Retire- Reclassi- End
Classification of Period at Cost ments fications of Period
(Thousands of Dollars)
(Pro Forma) (2)
For the Year Ended December 31, 1992
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $ 463,198 $ 8,420 $ 2,354 $ (6) $ 469,258
Nuclear Production. . . . . . . . 1,358,428 4,283 7,033 - 1,355,678
Transmission. . . . . . . . . . . 213,928 2,328 358 - 215,898
Distribution. . . . . . . . . . . 357,486 15,764 1,536 - 371,714
General . . . . . . . . . . . . . 62,295 1,933 762 (1,356) 62,110
Electric Plant Leased to Others . 6,984 - - - 6,984
Construction Work in Progress . . 13,612 16,024 - (2) 29,634
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,433 - - 25 15,458
Nuclear Fuel. . . . . . . . . . . 42,731 16,661 - (87) 59,305
Plant Acquisition Adjustment. . . - 796,265(1) - - 796,265
$2,534,095 $861,678 $12,043 $ (1,426) $3,382,304

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

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

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

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

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

Schedule V - Utility Plant

(Predecessor)
<CAPTION>

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

For the Year Ended December 31, 1991
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $ 450,753 $13,746 $ 1,300 $ (1) $ 463,198
Nuclear Production. . . . . . . . 1,363,312 11,032 15,916 - 1,358,428
Transmission. . . . . . . . . . . 208,705 6,356 1,129 (4) 213,928
Distribution. . . . . . . . . . . 340,458 19,206 2,178 - 357,486
General . . . . . . . . . . . . . 58,353 5,286 1,342 (2) 62,295
Electric Plant Leased to Others . 6,980 - - 4 6,984
Construction Work in Progress . . 14,760 (1,148) - - 13,612
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 15,370 88 28 3 15,433
Nuclear Fuel. . . . . . . . . . . 28,152 19,782 5,203 - 42,731
$2,486,843 $74,348 $27,096 $ - $2,534,095
</TABLE>
<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY

Schedule VI - Accumulated Depreciation of Utility Plant

(Successor)
<CAPTION>

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

For the Year Ended December 31, 1993
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $242,596 $16,486 $ 3,159 $ - $255,923
Nuclear Production. . . . . . . . 247,370 35,465 832 31 282,034
Transmission. . . . . . . . . . . 74,167 5,244 20 - 79,391
Distribution. . . . . . . . . . . 120,897 11,324 2,449 - 129,772
General . . . . . . . . . . . . . 29,100 4,576 1,359 1,260 33,577
Electric Plant Leased to Others . 1,239 174 - 1,413
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,819 - 86 - 8,733
Nuclear Fuel. . . . . . . . . . . 25,993 10,805 19,381 - 17,417
$750,181 $84,074 $27,286 $1,291 $808,260
</TABLE>
<PAGE>
<TABLE>
KANSAS GAS AND ELECTRIC COMPANY

Schedule VI - Accumulated Depreciation of Utility Plant
<CAPTION>

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

(Pro Forma) (1)
For the Year Ended December 31, 1992
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $228,538 $16,433 $ 2,374 $ (1) $242,596
Nuclear Production. . . . . . . . 219,311 35,361 7,302 - 247,370
Transmission. . . . . . . . . . . 69,355 5,199 387 - 74,167
Distribution. . . . . . . . . . . 111,961 10,835 1,899 - 120,897
General . . . . . . . . . . . . . 25,003 4,369 745 473 29,100
Electric Plant Leased to Others . 1,065 174 - - 1,239
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,793 - - 26 8,819
Nuclear Fuel. . . . . . . . . . . 16,132 9,850 - 11 25,993
$680,158 $82,221 $12,707 $ 509 $750,181

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

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

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

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

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

Schedule VI - Accumulated Depreciation of Utility Plant

(Predecessor)
<CAPTION>

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

For the Year Ended December 31, 1991
<S> <C> <C> <C> <C> <C>
Electric Plant:
Steam Production. . . . . . . . . $212,421 $17,305 $ 1,207 $ 19 $228,538
Nuclear Production. . . . . . . . 199,938 35,460 16,087 - 219,311
Transmission. . . . . . . . . . . 65,463 5,107 1,215 - 69,355
Distribution. . . . . . . . . . . 104,043 10,396 2,478 - 111,961
General . . . . . . . . . . . . . 21,582 4,127 1,278 572 25,003
Electric Plant Leased to Others . 891 174 - - 1,065
Electric Plant Held for Future
Use . . . . . . . . . . . . . . 8,841 - 29 (19) 8,793
Nuclear Fuel. . . . . . . . . . . 15,607 5,728 5,203 - 16,132
$628,786 $78,297 $27,497 $ 572 $680,158

</TABLE>
<PAGE>
SIGNATURE

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

KANSAS GAS AND ELECTRIC COMPANY

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

Signature Title Date

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

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

ROBERT T. CRAIN
(Robert T. Crain)

(Anderson E. Jackson)

DONALD A. JOHNSTON
(Donald A. Johnston)

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

GLENN L. KOESTER
(Glenn L. Koester)

JAMES J. NOONE
(James J. Noone)

(Marilyn B. Pauly)

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

RICHARD SMITH
(Richard Smith)