WESTERN RESOURCES INC /KS, 10-K, 1997-03-20

WESTERN RESOURCES INC /KS
10-K, 1997-03-20
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, 1996

[ ] 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. ( )

State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,897,474,000 of Common Stock and $11,398,000
of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which
there is no readily ascertainable market value) at March 18, 1996.

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

Common Stock, $5.00 par value 64,872,146
(Class) (Outstanding at March 19, 1997)

Documents Incorporated by Reference:
Part Document

III Items 10-13 of the Company's Definitive Proxy Statement for
the Annual Meeting of Shareholders to be held May 29, 1997.<page1>
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 1996

TABLE OF CONTENTS

Description Page

PART I
Item 1. Business 3

Item 2. Properties 21

Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of
Security Holders 24

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 24

Item 6. Selected Financial Data 26
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 27

Item 8. Financial Statements and Supplementary Data 39

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 75

PART III
Item 10. Directors and Executive Officers of the
Registrant 75

Item 11. Executive Compensation 75

Item 12. Security Ownership of Certain Beneficial
Owners and Management 75

Item 13. Certain Relationships and Related Transactions 75

PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 76

Signatures 80
<page2>

PART I

ITEM 1. BUSINESS

GENERAL

The company and its wholly-owned subsidiaries, include KPL, a
rate-regulated electric and gas division of the company, KGE, a
rate-regulated electric utility and wholly-owned subsidiary of the company,
Westar Security, Inc., a wholly-owned subsidiary which provides monitored
electronic security services, Westar Energy, Inc., a wholly-owned subsidiary
which provides non-regulated energy services, Westar Capital, Inc., a
wholly-owned subsidiary which holds equity investments in technology,
electronic monitored security and energy-related companies, The Wing Group
Ltd (The Wing Group), a wholly-owned developer of international power projects,
and Mid Continent Market Center, Inc. (Market Center), a regulated gas
transmission service provider. KGE owns 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), 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, 1996, the company had
5,960 employees.

The company is an investor-owned holding company. The company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity and the delivery and sale of natural gas. The company serves
approximately 606,000 electric customers in eastern and central Kansas and
approximately 650,000 natural gas customers in Kansas and northeastern
Oklahoma. The company's non-utility subsidiaries market natural gas primarily
to large commercial and industrial customers, provide electronic monitoring
security services, and provide other energy-related products and services.

On February 7, 1997, Kansas City Power & Light Company (KCPL) and the
company entered into an agreement whereby KCPL would be merged with and into
the company. The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareowners will receive $32 of company common stock per KCPL
share, subject to an exchange ratio collar of not less than 0.917 and no more
than 1.100 common shares. Consummation of the KCPL Merger is subject to
customary conditions including obtaining the approval of KCPL's and the
company's shareowners and various regulatory agencies. See Note 2 of Notes to
Consolidated Financial Statements (Notes) for more information regarding the
proposed merger with KCPL.

On December 12, 1996, the company and ONEOK Inc. (ONEOK) announced an
agreement to form a strategic alliance combining the natural gas assets of
both companies. Under the agreement for the proposed strategic alliance, the
company will contribute its natural gas business to a new company (New ONEOK)
in exchange for a 45% equity interest. The recorded net property value being
contributed at December 31, 1996 is estimated at $600 million. No gain or
loss is expected to be recorded as a result of the proposed transaction. The
proposed transaction is subject to satisfaction of customary conditions,
including approval by ONEOK shareowners and regulatory authorities. The
company is working towards consummation of the transaction during the second
half of 1997. See Note 6 for more information regarding this strategic
alliance.

During 1996, the company purchased approximately 38 million common
shares
<page3>

of ADT Limited, Inc. (ADT) for approximately $589 million. The shares
purchased represent approximately 27% of ADT's common equity making the
company the largest shareowner of ADT. ADT's principal business is providing
electronic security services.

On December 18, 1996, the company announced its intention to offer to
exchange $22.50 in cash ($7.50) and shares ($15.00) of the company's common
stock for each outstanding common share of ADT not already owned by the
company or its subsidiaries (ADT Offer). The value of the ADT Offer, assuming
the company's average stock price prior to closing is above $29.75 per common
share, is approximately $3.5 billion, including the company's existing
investment in ADT. Following completion of the ADT Offer, the company
presently intends to propose and seek to have ADT effect an amalgamation,
pursuant to which a newly created subsidiary of the company incorporated under
the laws of Bermuda will amalgamate with and into ADT (Amalgamation). Based
upon the closing stock price of the company on March 13, 1997, approximately
60.1 million shares of company common stock would be issuable pursuant to the
acquisition of ADT. However, the actual number of shares of company common
stock that would be issuable in connection with the ADT Offer and the
Amalgamation will depend on the exchange ratio and the number of shares
validly tendered prior to the expiration date of the ADT Offer and the number
of shares of ADT outstanding at the time the Amalgamation is completed.

On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10
cash plus 0.41494 of a share of company common stock for each share of ADT
tendered not already owned by the company, based on the closing price of the
company's common stock on March 13, 1997. ADT shareowners would not,
however, receive more than 0.42017 shares of company common stock for each
ADT common share.

On March 17, 1997, ADT announced that it had entered into a definitive
merger agreement pursuant to which Tyco International Ltd. (Tyco), a
diversified manufacturer of industrial and commercial products, would
effectively acquire ADT in a stock for stock transaction valued at $5.6
billion, or approximately $29 per ADT share of common stock.

On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it
would be reviewing the Tyco offer as well as considering its alternatives to
such offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.

On December 31, 1996, the company purchased the assets and assumed
certain liabilities comprising Westinghouse Security Systems, Inc. (WSS), a
monitored security service provider with over 300,000 accounts in the United
States. The company paid $358 million in cash, subject to adjustment. See
Note 4 for further information.
<page4>

In February of 1996 the company purchased The Wing Group. See Note 4
for further information.

The electric utility industry in the United States is rapidly evolving
from an historically regulated monopolistic market to a dynamic and
competitive integrated marketplace. The 1992 Energy Policy Act (Act) began
the process of deregulation of the electricity industry by permitting the
Federal Energy Regulatory Commission (FERC) to order electric utilities to
allow third parties to sell electric power to wholesale customers over their
transmission systems. Since that time, the wholesale electricity market has
become increasingly competitive as companies begin to engage in nationwide
power brokerage. In addition, various states including California and New
York have taken active steps toward allowing retail customers to purchase
electric power from third-party providers. In 1996, the Kansas Corporation
Commission (KCC) initiated a generic docket to study electric restructuring
issues. A retail wheeling task force has been created by the Kansas
Legislature to study competitive trends in retail electric services. During
the 1997 session of the Kansas Legislature, bills have been introduced to
increase competition in the electric industry. Among the matters under
consideration is the recovery by utilities of costs in excess of competitive
cost levels. There can be no assurance at this time that such costs will be
recoverable if open competition is initiated in the electric utility market.

For further discussion regarding competition and the potential impact
on the company, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, Other Information, Competition and
Enhanced Business Opportunities.

On July 1, 1995, the company established Market Center which provides
natural gas transportation, storage, and gathering services, as well as
balancing and title transfer capability. The company contributed certain
natural gas transmission assets having a net book value of approximately $50
million to the Market Center. Market Center provides no notice natural gas
transportation and storage services to the company under a long-term contract.
When the alliance with ONEOK is completed, the Market Center will be
transferred to New ONEOK.

On January 31, 1994, the company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union) for $404 million. The company sold the remaining Missouri
properties to United Cities Gas Company (United Cities) for $665,000 on
February 28, 1994. The properties sold to Southern Union and United Cities
are referred to herein as the "Missouri Properties."

During the first quarter of 1994, the company recognized a gain of
approximately $19.3 million, net of tax, on the sales of the Missouri
Properties. As of the respective dates of the sales of the Missouri
Properties, the company ceased recording the results of operations, and
removed the assets and liabilities from the Consolidated Balance Sheets
related to the Missouri Properties.

The following table reflects the approximate operating revenues and
operating income included in the company's consolidated results of operations
for the year ended December 31, 1994, related to the Missouri Properties:
<page5>

1994
Percent
of Total
Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . . . . . . . $ 77,008 4.8%
Operating income. . . . . . . . . . . 4,997 1.9%

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.

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. Simultaneously, KCA and Kansas Gas and
Electric Company merged and adopted the name Kansas Gas and Electric Company
(KGE).

The following information includes the operations of KGE since March
31, 1992 and excludes the activities related to the Missouri Properties
following the sales of those properties in the first quarter of 1994.

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

Total Operating Income
Operating Revenues Before Income Taxes
Regulated Regulated
Year Electric Natural Gas Electric Natural Gas
1996 69% 31% 90% 10%
1995 73% 27% 98% 2%
1994 69% 31% 97% 3%
1993 58% 42% 85% 15%
1992 57% 43% 89% 11%

The difference between the percentage of electric operating revenues to
total operating revenues and the percentage of electric operating income to
total operating income as compared to the same percentages for regulated
natural gas operations is due to the company's level of investment in plant
and its fuel costs in each of these segments. The reduction in the
percentages for the regulated natural gas operations in 1994 is due to the
sales of the Missouri Properties.

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
(Dollars in Thousands)
1996 $3,669,662 $554,561 $4,224,223
1995 3,676,576 525,431 4,202,007
1994 3,676,347 496,753 4,173,100
1993 3,641,154 759,619 4,400,773
1992 3,645,364 696,036 4,341,400
<page6>

Under the agreement for the proposed strategic alliance with ONEOK, the
company will contribute its natural gas business to New ONEOK in exchange for
a 45% equity interest. See Note 2 for further information.

ELECTRIC OPERATIONS

General

The company supplies electric energy at retail to approximately 606,000
customers in 462 communities in Kansas. These include Wichita, Topeka,
Lawrence, Manhattan, Salina, and Hutchinson. 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 KGE since March 31, 1992):

1996 1995 1994 1993 1992
(Thousands of MWH)
Residential 5,265 5,088 5,003 4,960 3,842
Commercial 5,667 5,453 5,368 5,100 4,473
Industrial 5,622 5,619 5,410 5,301 4,419
Wholesale and
Interchange 5,908 4,012 3,899 4,525 3,028
Other 105 108 106 103 91
Total 22,567 20,280 19,786 19,989 15,853

The company's electric revenues for the last five years were as follows
(includes KGE since March 31, 1992):

1996 1995 1994 1993 1992

(Dollars in Thousands)
Residential $ 403,588 $ 396,025 $ 388,271 $ 384,618 $296,917
Commercial 351,806 340,819 334,059 319,686 271,303
Industrial 262,989 268,947 265,838 261,898 211,593
Wholesale and
Interchange 143,380 104,992 106,243 118,401 98,183
Other 35,670 35,112 27,370 19,934 4,889
Total $1,197,433 $1,145,895 $1,121,781 $1,104,537 $882,885

Capacity

The aggregate net generating capacity of the company's system is
presently 5,312 megawatts (MW). The system comprises interests in 22 fossil
fueled steam generating units, one nuclear generating unit (47% interest),
seven combustion peaking turbines and two diesel generators located at eleven
generating stations. Two units of the 22 fossil fueled units (aggregating 100
MW of capacity) have been "mothballed" for future use (See Item 2.
Properties).

The company's 1996 peak system net load occurred July 19, 1996 and
amounted to 3,997 MW. The company's net generating capacity together with
power available
<page7>

from firm interchange and purchase contracts, provided a capacity margin of
approximately 18% above system peak responsibility at the time of the peak.
The company and twelve companies in Kansas and western Missouri have
agreed to provide capacity (including margin), emergency and economy services
for each other. This arrangement is called the MOKAN Power Pool. The pool
participants also coordinate the planning of electric generating and
transmission facilities.

The company is one of 60 members of the Southwest Power Pool (SPP).
SPP's responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri,
Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi.

In 1994, the company joined the Western Systems Power Pool (WSPP).
Under this arrangement, over 156 electric utilities and marketers throughout the
western United States have agreed to market energy and to provide transmission
services. WSPP's intent is to increase the efficiency of the interconnected
power systems operations over and above existing operations. Services
available include short-term and long-term economy energy transactions, unit
commitment service, firm capacity and energy sales, energy exchanges, and
transmission service by intermediate systems.

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 (42 MW) and transmission charges
through the year 2013.

During 1994, KGE entered into an agreement with Midwest Energy, Inc.
(MWE), whereby KGE will provide MWE with peaking capacity of 61 MW through the
year 2008. KGE also entered into an agreement with Empire District Electric
Company (Empire), whereby KGE will provide Empire with peaking and base load
capacity (20 MW in 1994 increasing to 80 MW in 2000) through the year 2000.
In January 1995, the company entered into another agreement with Empire,
whereby the company will provide Empire with peaking and base load capacity
(10 MW in 1995 increasing to 162 MW in 2000) through the year 2010.

Future Capacity

The company does not contemplate any significant expenditures in
connection with construction of any major generating facilities for the next
five years. (See Item 7. Management's Discussion and Analysis, Liquidity and
Capital Resources).

Fuel Mix

The company's coal-fired units comprise 3,295 MW of the total 5,312 MW
of generating capacity and the company's nuclear unit provides 547 MW of
capacity. Of the remaining 1,470 MW of generating capacity, units that can
burn either natural gas or oil account for 1,386 MW, and the remaining units
which burn only diesel fuel account for 84 MW (See Item 2. Properties).

During 1996, low sulfur coal was used to produce 81% of the company's
electricity. Nuclear produced 16% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1997, based on the company's estimate of the
availability of fuel, coal will be used to produce approximately 80% of the
company's electricity and nuclear will be used to produce approximately 16%.
<page8>

The company's fuel mix fluctuates with the operation of nuclear powered
Wolf Creek which has an 18-month refueling and maintenance schedule. The
18-month schedule permits uninterrupted operation every third calendar year.
Wolf Creek was taken off-line on February 3, 1996 for its eighth refueling and
maintenance outage which lasted approximately 60 days 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 70% of the
uranium requirements for operation of Wolf Creek through the year 2003. The
balance is expected to be obtained through spot market and contract
purchases. The company has four contracts with the following companies for
uranium: Cameco Corporation, Geomex Minerals, Inc., and Power Resources, Inc.

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

The company has two active contracts for uranium enrichment performed
by Urenco and USEC. Contracted arrangements cover 82% of Wolf Creek's uranium
enrichment requirements for operation of Wolf Creek through March 2005. The
balance is expected to be obtained through spot market and term contract
purchases.

The company has entered into all of its uranium, uranium hexaflouride
and uranium enrichment arrangements during the ordinary course of business
and is not substantially dependent upon these agreements. The company
believes there are other suppliers available at reasonable prices to replace,
if necessary, these contracts. In the event that the company were required
to replace these contracts, it would not anticipate a substantial disruption
of its business.

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
2005 while still maintaining full core off-load capability. The company is
currently investigating spent fuel storage options which should provide enough
additional storage space through at least 2020 while still maintaining full
core off-load capability. The company believes adequate additional storage
space can be obtained as necessary.

Additional information with respect to insurance coverage applicable to
the operations of the company's nuclear generating facility is set forth in
Note 8 of the Notes to Consolidated Financial Statements.

Coal

The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 1,824 MW (company's 84% share) (See Item 2. Properties).
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,
<page9>

both located in the Powder River Basin in Campbell County, Wyoming. The
contract expires December 31, 2020. The contract contains a schedule of
minimum annual delivery quantities based on MMBtu provisions. The coal to be
supplied is surface mined and has an average Btu content of approximately
8,300 Btu per pound and an average sulfur content of .43 lbs/MMBtu (See
Environmental Matters). The average delivered cost of coal for JEC was
approximately $1.10 per MMBtu or $18.70 per ton during 1996.

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

The two coal-fired units at La Cygne Station have an aggregate
generating capacity of 678 MW (KGE's 50% share) (See Item 2. Properties). The
operator, KCPL, maintains coal contracts summarized in the following paragraphs.

La Cygne 1 uses low sulfur Powder River Basin coal which is supplied
under a variety of spot market transactions, discussed below. High Btu
Kansas/Missouri coal is blended with the Powder River Basin coal and is
secured from time to time under spot market arrangements. La Cygne 1 uses a
blended fuel mix containing approximately 85% Powder River Basin coal.

La Cygne 2 and additional La Cygne 1 Powder River Basin coal is
supplied through several contracts, expiring at various times through 1999.
This low sulfur coal had an average Btu content of approximately 8,500 Btu per
pound and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with BN and Kansas City Southern Railroad (KCS) through December 31,
2000.

During 1996, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.64 per MMBtu or $13.47
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.68 per MMBtu or $11.49 per ton.

The coal-fired units located at the Tecumseh and Lawrence Energy
Centers have an aggregate generating capacity of 793 MW (See Item 2.
Properties). The company contracted with Cyprus Amax Coal Company's Foidel
Creek Mine located in Routt County, Colorado for low sulfur coal through
December 31, 1998. This coal is transported by Southern Pacific Lines and
Atchison, Topeka and Santa Fe Railway Company under a contract expiring
December 31, 1998. 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 coal
markets in Wyoming, Utah, Colorado and/or New Mexico. Additional spot market
coal for 1997 has been secured from COLOWYO Coal Company on a delivered
basis. During 1996, the average delivered cost of coal for the Lawrence
units was approximately $1.19 per MMBtu or $26.91 per ton and the average
delivered cost of coal for the Tecumseh units was approximately $1.21 per
MMBtu or $27.11 per ton. The coal supplied from Cyprus has an average Btu
content of approximately 11,200 Btu per pound and an average sulfur content
of .47 lbs/MMBtu (See Environmental Matters).

The company has entered into all of its coal and transportation
contracts during the ordinary course of business and is not substantially
dependent upon these contracts. The company believes there are other
suppliers for and
<page10>

plentiful sources of coal available at reasonable prices to replace, if
necessary, fuel to be supplied pursuant to these contracts. In the event that
the company were required to replace its coal or transportation agreements, it
would not anticipate a substantial disruption of the company's business.

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 by readily available gas from the spot market.
Short-term economical spot market purchases will supply the system with the
flexible natural gas supply to meet operational needs for the Gordon Evans
and Murray Gill Energy Centers. Natural gas for the company's Abilene and
Hutchinson stations is supplied from the company's main system (See Natural
Gas Operations).

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 JEC and La Cygne generating stations. All oil burned by
the company during the past several years has been obtained by spot market
purchases. At December 31, 1996, the company had approximately 3 million
gallons of No. 2 and 13 million gallons of No. 6 oil which is believed to be
sufficient to meet emergency requirements and protect against lack of
availability of natural gas and/or the loss of a large generating unit.

Other Fuel Matters

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

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

KPL Plants 1996 1995 1994 1993 1992
Per Million Btu:
Coal $1.14 $1.15 $1.13 $1.13 $1.30
Gas 2.50 1.63 2.66 2.71 2.15
Oil 4.01 4.34 4.27 4.41 4.19

Cents per KWH Generation 1.30 1.31 1.32 1.31 1.49

KGE Plants 1996 1995 1994 1993 1992
Per Million Btu:
Nuclear $0.50 $0.40 $0.36 $0.35 $0.34
Coal 0.88 0.91 0.90 0.96 1.25
Gas 2.30 1.68 1.98 2.37 1.95
Oil 2.74 4.00 3.90 3.15 4.28

Cents per KWH Generation 0.93 0.82 0.89 0.93 0.98
<page11>

Environmental Matters

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

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

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

The Kansas Department of Health and Environment (KDHE) regulations,
applicable to 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. There is sufficient low sulfur coal under contract (See Coal) to allow
compliance with such limits at Lawrence, Tecumseh and La Cygne 1 for the life
of the contracts. All facilities burning coal are equipped with flue gas
scrubbers and/or electrostatic precipitators.

The Clean Air Act Amendments of 1990 (the Act) require a two-phase
reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995
and Phase II effective in 2000 and a probable reduction in toxic emissions by
a future date yet to be determined. To meet the monitoring and reporting
requirements under the Act's acid rain program, the company has installed
continuous monitoring and reporting equipment at a total cost of approximately
$10 million as of December 31, 1996. The company does not expect material
expenditures to be needed to meet Phase II sulfur dioxide requirements.
Although the company currently has no Phase I affected units, the company has
applied for and has been accepted for an early substitution permit to bring
the co-owned La Cygne Unit 1 under the Phase I regulations.

The NOx and toxic limits, which were not set in the law, were
proposed by the EPA in January 1996. The company is currently evaluating the
steps it will need to take in order to comply with the proposed new rules.
The company will have three years from the date the limits were proposed to
comply with the new NOx rules.

All of the company's generating facilities are in substantial
compliance with the Best Practicable Technology and Best Available Technology
regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most
EPA regulations are administered in Kansas by the KDHE.
<page12>

Additional information with respect to Environmental Matters is
discussed in Note 8 of the Notes to Consolidated Financial Statements
included herein.

NATURAL GAS OPERATIONS

General

The company's natural gas operations are comprised primarily of the
following four components: a local natural gas distribution division which is
subject to rate-regulation; Market Center, a Kansas subsidiary of the company
that engages primarily in intrastate gas transmission, as well as gas
wheeling, parking, balancing and storage services, and is also subject to
rate-regulation; Westar Gas Marketing, Inc., (Westar Gas Marketing) a Kansas
non-regulated indirect subsidiary of the company that engages primarily in
marketing and selling natural gas to small and medium-sized commercial and
industrial customers; and Westar Gas Company, a Delaware non-regulated
subsidiary of Westar Gas Marketing that engages in extracting, processing and
selling natural gas liquids.

At December 31, 1996, the company supplied natural gas at retail to
approximately 650,000 customers in 362 communities and at wholesale to eight
communities and two utilities in Kansas and Oklahoma. The natural gas systems
of the company consist of distribution systems in both states purchasing
natural gas from various suppliers and transported by 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 which purchase gas on the spot market.
The company earns approximately the same margin on the volume of gas
transported as on volumes sold except where discounting occurs in order to
retain the customer's load.

As discussed under General, above, 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 sales of the Missouri Properties is set forth in Note 19 of
the Notes to Consolidated Financial Statements.

The percentage of total natural gas deliveries, including
transportation and operating revenues for 1996, by state were as follows:

Total Natural Total Natural Gas
Gas Deliveries Operating Revenues
Kansas 96.6% 95.7%
Oklahoma 3.4% 4.3%
<page13>

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

1996 1995 1994(2) 1993 1992
(Thousands of MCF)
Residential 62,728 55,810 64,804 110,045 93,779
Commercial 22,841 21,245 26,526 47,536 40,556
Industrial 450 548 605 1,490 2,214
Other 21,067 17,078(1) 43 41 94
Transportation 45,947 48,292 51,059 73,574 68,425
Total 153,033 142,973 143,037 232,686 205,068

The company's natural gas revenues related to deliveries for the last
five years were as follows:

1996 1995 1994(2) 1993 1992
(Dollars in Thousands)
Residential $352,905 $274,550 $332,348 $529,260 $440,239
Commercial 120,927 94,349 125,570 209,344 169,470
Industrial 2,885 3,051 3,472 7,294 7,804
Other 48,643 31,860 11,544 30,143 27,457
Transportation 23,354 22,366 23,228 28,781 28,393
Total $548,714 $426,176 $496,162 $804,822 $673,363

(1) The increase in other gas sales reflects an increase in
as-available gas sales.

(2) Information reflects the sales of the Missouri Properties
effective January 31, and February 28, 1994.

As-available gas is excess natural gas under contract that the
company did not require for customer sales or storage that is typically sold
to gas marketers. According to the company's tariff, the nominal margin made on
as-available gas sales, is returned 75% to customers through the cost of gas
rider and 25% is reflected in wholesale revenues of the company.

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 System

The company distributes natural gas at retail to approximately 520,000
customers located in central and eastern Kansas and northeastern Oklahoma.
The largest cities served in 1996 were Wichita and Topeka, Kansas and
Bartlesville, Oklahoma. The company has transportation agreements for
delivery of this gas which have terms varying in length from one to twenty
years, with the following non-affiliated pipeline transmission companies:
Williams Natural Gas Company (WNG), Kansas Pipeline Company (KPP), Panhandle
Eastern Pipeline Company (Panhandle), and various other intrastate suppliers.
The volumes transported under these agreements in 1996 and 1995 were as
follows:
<page14>
Transportation Volumes (BCF's)

1996 1995
WNG 79.4 61.8
KPP 7.3 7.1
Panhandle 1.2 1.0
Others 2.1 8.0

The company purchases this gas from various producers and marketers
under contracts expiring at various times. The company purchased approximately
78.4 BCF or 91.9% of its natural gas supply from these sources in 1996 and
61.7 BCF or 79.3% during 1995. Approximately 85.3 BCF of natural gas is made
available annually under these contracts which extend for various terms
through the year 2005.

In October 1994, the company executed a long-term gas purchase contract
(Base Contract) and a peaking supply contract with Amoco Production Company
for the purpose of meeting the requirements of the customers served from the
company's interstate system over the WNG pipeline system. The company
anticipates that the Base Contract will supply between 50% and 65% of the
company's demand served by the WNG pipeline system. Amoco is one of various
suppliers over the WNG pipeline system and if this contract were canceled, the
company could replace gas supplied by Amoco with gas from other suppliers.
Gas available under the Amoco contract is also available for sale by the
company to other parties and sales are recorded as wholesale revenues of the
company.

The company also purchases natural gas from KPP under contracts
expiring at various times. These purchases were approximately 5.2 BCF or
5.8% of its natural gas supply in 1996 and 5.3 BCF or 6.7% during 1995. The
company purchases natural gas for the interstate system from intrastate
pipelines and from spot market suppliers under short-term contracts. These
sources totaled 0.6 BCF and 3.6 BCF for 1996 and 1995 representing 0.7% and
4.6% of the system requirements, respectively.

During 1996 and 1995, approximately 1.5 BCF and 7.3 BCF, respectively,
were transferred from the company's main system to serve a portion of the
demand for the interstate system representing 1.6% and 9.4%, 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)

1996 1995 1994 1993 1992
WNG $ - $ - $ - $3.57 $3.64
Other 3.09 2.78 3.32 3.01 2.30
Total Average Cost 3.09 2.78 3.32 3.23 2.88

Main System

The company serves approximately 130,000 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 and Hutchinson, Kansas.
<page15>

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 natural gas marketers and production companies.
Such purchases are transported entirely through company owned transmission
lines in Kansas.

Natural gas purchased for the company's main system customer
requirements is transported and/or stored by the Market Center. The company
retains a priority right to capacity on the Market Center necessary to serve
the main system customers. The company has the opportunity to negotiate for
the purchase of natural gas with producers or marketers utilizing Market Center
services, which increases the potential supply available to meet main system
customer demands.

During 1996, the company purchased approximately 7.6 BCF of natural gas
through the spot market which allowed the company to avoid minimum take
requirements associated with long-term contracts. This purchase represents
approximately 45.5% of the company's main system requirements during 1996.

Spivey-Grabs field in south-central Kansas supplied approximately
4.2 BCF of natural gas in both 1996 and 4.8 BCF in 1995, constituting 25.1%
and 20.2%, 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.
Based on a reserve study performed by an independent petroleum engineering
firm in 1995, significant quantities of gas will be available from the
Spivey-Grabs field until at least the year 2015.

Other sources of gas for the main system of 2.7 BCF or 16.0% of the
system requirements were purchased from or transported through interstate
pipelines during 1996. The remainder of the supply for the main system
during 1996 and 1995 of 2.2 BCF and 2.2 BCF representing 13.4% and 9.9%,
respectively, was purchased directly from producers or gathering systems.

During 1996 and 1995, approximately 1.5 BCF and 7.3 BCF,
respectively, of the total main system supply was transferred to the company's
interstate system (See Interstate System).

The company believes there is adequate natural gas available under
contract or otherwise available to meet the currently anticipated needs of the
main system customers.

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)

1996 1995 1994 1993 1992
Mesa-Hugoton Contract $ - $1.44 $1.81 $1.78(1) $1.47(2)
Other 2.48 2.47 2.92 2.69 2.66
Total Average Cost 2.48 2.06 2.23 2.20 2.00

(1) Includes 2.5 BCF @ $1.31/MCF of make-up deliveries.
(2) Includes 2.1 BCF @ $1.31/MCF of make-up deliveries.

The load characteristics of the company's natural gas customers creates
relatively high volume demand on the main system during cold winter days. To
<page16>

assure peak day service to high priority customers the company owns and
operates
and has under contract natural gas storage facilities (See Item 2.
Properties).

WESTAR GAS MARKETING

Westar Gas Marketing was formed in 1988 to pursue natural gas marketing
opportunities. Westar Gas Marketing purchases and markets natural gas to
approximately 925 customers located in Kansas, Missouri, Nebraska, Colorado,
Oklahoma, Iowa, Wyoming and Arkansas. Westar Gas Marketing purchases natural
gas under both long-term and short-term contracts from producers and operators
in the Hugoton, Arkoma and Anadarko gas basins. Westar Gas Marketing engages
in certain transactions to hedge natural gas prices in its gas marketing
activities.

WESTAR GAS COMPANY

Westar Gas Company owns and operates the Minneola Gas Processing Plant
(Minneola) in Ford County, Kansas. Minneola extracts liquids from natural gas
provided by outside producers and sells the residue gas to third-party
marketers. A portion of the residue gas is sold to Westar Gas Marketing.

Westar Gas Company, through its participation in various joint ventures
owns a 41.4% beneficial interest in the Indian Basin Processing Plant (Indian
Basin) near Artesia, New Mexico. Indian Basin is operated by Marathon Oil and
extracts natural gas liquids for third party producers.

SEGMENT INFORMATION

Financial information with respect to business segments is set forth in
Note 18 of the 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 (formerly KPL) and KGE.

Western Resources' mortgage prohibits additional Western Resources
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, 1996,
approximately $772 million principal amount of additional first mortgage bonds
could be issued (7.75% interest rate assumed).

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, 1996, the company had approximately $1.0 billion of net bondable
property additions not subject to an unfunded prior lien entitling the company
<page17>

to issue up to $618 million principal amount of additional bonds. As of
December 31, 1996, $3 million in first mortgage bonds could be issued on the
basis of retired bonds.

KGE's mortgage prohibits additional KGE first mortgage bonds from being
issued (except in connection with certain refundings) unless KGE'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 KGE first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on KGE's results for the 12 months ended December 31, 1996,
approximately $1.0 billion principal amount of additional KGE first mortgage
bonds could be issued (7.75% interest rate assumed).

KGE bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1996, KGE had approximately $1.4 billion of net bondable property additions
not subject to an unfunded prior lien entitling KGE to issue up to $950
million principal amount of additional KGE bonds. As of December 31, 1996,
$17 million in additional bonds could be issued 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
plus 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, 1996,
such ratio was 1.96 for the 12 months ended December 31, 1996.

KCPL has outstanding first mortgage bonds (the "KCPL Bonds") which are
secured by a lien on substantially all of KCPL's fixed property and franchises
purported to be conveyed by the General Mortgage Indenture and Deed of Trust
and the various Supplemental Indentures creating the KCPL Bonds (collectively,
the "KCPL Mortgage"). If the company consummates its planned merger with KCPL,
the company, as the successor corporation to such merger, would be required
pursuant to the terms of the KCPL Mortgage to confirm the liens thereunder and
to keep the mortgaged property with respect thereto as far as practicable
identifiable. In the absence of an express grant, however, the KCPL Mortgage
will not constitute or become a lien on any property or franchises owned by
the company prior to such merger or on any property or franchises which may be
purchased, constructed or otherwise acquired by the company except for such as
form an integral part of the mortgage property under the KCPL Mortgage. Upon
consummation of the KCPL Merger, the after-acquired property clauses of the
company's mortgage would cause the lien of the Mortgage to attach (But in a
subordinate position to the prior lien of the KCPL Mortgage) to the property
of KCPL at the date of combination.

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 and the Corporation Commission of the State of Oklahoma (OCC), which
have general
<page18>

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 FERC and KCC 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.

The company is exempt as a public utility holding company pursuant to
Section 3(a)(1) of the Public Utility Holding Company Act of 1935 from all
provisions of that Act, except Section 9(a)(2). 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. KGE 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 9 of Notes to Consolidated Financial Statements is included
herein.

EMPLOYEE RELATIONS

As of December 31, 1996, the company had 5,960 employees. The
company did not experience any strikes or work stoppages during 1996. The
company's current contract with the International Brotherhood of Electrical
Workers extends through June 30, 1997 and is currently being negotiated. The
contract covers approximately 1,933 employees. The company has contracts
with three gas unions representing approximately 586 employees. These
contracts were negotiated in 1996 and will expire June 4, 1998. Upon
consummation of the strategic alliance with ONEOK, approximately 1,500 company
employees will be transferred to New ONEOK.
<page19>

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

John E. Hayes, Jr. 59 Chairman of the Board President
and Chief Executive
Officer

David C. Wittig 41 President Executive Vice President,
(since March 1996) Corporate Strategy (since

May 1995)

Salomon Brothers Inc -
Managing Director, Co-Head of

Mergers and Acquisitions

Norman E. Jackson 59 Executive Vice President, Executive Vice President,
Electric Operations Electric Transmission and
(since November 1996) Engineering Services
(May 1995 to November 1996)

Executive Vice President,
Electric Engineering and Field
Operations (1992 to 1995)

Steven L. Kitchen 51 Executive Vice President
and Chief Financial
Officer

Carl M. Koupal, Jr. 43 Executive Vice President Executive Vice President
and Chief Administrative Corporate Communications,
Officer (since July 1995) Marketing, and Economic
Development
(January 1995 to July 1995)

Vice President, Corporate
Marketing,And Economic
Development, (1992 to
1994)

Director, Economic Development,
(1985 to 1992) Jefferson City,
Missouri

John K. Rosenberg 51 Executive Vice President
and General Counsel

Jerry D. Courington 51 Controller
</TABLE>

Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the officers, nor any arrangements or
understandings between any officer and other persons pursuant to which he was
appointed as an officer.
<page20>

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 and Oklahoma.

During the five years ended December 31, 1996, the company's gross
property additions totaled $1,109,037,000 and retirements were $238,434,000.

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

Abilene Energy Center:
Combustion Turbine 1 1973 Gas 66

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

Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18
2 1950 Gas 17
3 1951 Gas 28
4 1965 Gas 197
Combustion Turbines 1 1974 Gas 51
2 1974 Gas 49
3 1974 Gas 54
4 1975 Diesel 78
Diesel Generator 1 1983 Diesel 3

Jeffrey Energy Center (84%)(2):
Steam Turbines 1 1978 Coal 616
2 1980 Coal 617
3 1983 Coal 591

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

Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (3)
3 1954 Coal 58
4 1960 Coal 115
5 1971 Coal 384

Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106
<page21>

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

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

Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 88
8 1962 Coal 148
Combustion Turbines 1 1972 Gas 19
2 1972 Gas 20

Wichita Plant:
Diesel Generator 5 1969 Diesel 3

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

Total 5,312

(1) Based on MOKAN rating.
(2) The company jointly owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).

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

NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES

The company's transmission and storage facility compressor stations,
all located in Kansas, as of December 31, 1996, 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 17,430 6,667
Yaggy Storage . . 3 1993 Electric 7,500 5,000
<page22>

The company has contracted with the Market Center for underground
storage of working storage capacity of 2.08 BCF. This contract enables the
company to supply customers up to 85 million cubic feet per day of gas supply
to meet winter peaking requirements.

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

ITEM 3. LEGAL PROCEEDINGS

The company has requested that the District Court for the Southern
District of Florida require that ADT hold a special shareowners meeting no
later than March 20, 1997. In its filing, the company claims that the ADT
board of directors has breached its fiduciary and statutory duties and that
there is no reason to delay the special meeting until July 8, 1997 as
established by ADT. See Note 3 for additional information regarding the
proposed acquisition of ADT.

On December 26, 1996, an ADT shareowner filed a purported class action
complaint against ADT, ADT's board of directors, the company and the company's
wholly-owned subsidiary, Westar Capital in the Civil Division of the Circuit
Court of the Fifteenth Judicial Circuit in Palm Beach County, Florida.
(Charles Gachot v. ADT, Ltd., Western Resources, Inc., Westar Capital, Inc.,
Michael A. Ashcroft, et al., Case No. 96-10912-AN) The complaint alleges,
among other things, that the company and Westar Capital are breaching their
fiduciary duties to ADT's shareowners by failing to offer "an appropriate
premium for the controlling interest" in ADT and by holding "an effective
blocking position" that prevents independent parties from bidding for ADT.
The complaint seeks preliminary and permanent relief enjoining the company
from acquiring the outstanding shares of ADT and unspecified damages. The
company believes it has good and valid defenses to the claims asserted and
does not anticipate any material adverse effect upon its overall financial
condition or results of operations.

Subject to the approval of the KCC, the company entered into five
new gas supply contracts with certain entities affiliated with The Bishop
Group, Ltd. (Bishop entities) which are currently regulated by the KCC. A
contested hearing was held for the approval of those contracts. While the
case was under consideration by the KCC, the FERC issued an order under which it
extended jurisdiction over the Bishop entities. On November 3, 1995, the KCC
stayed its consideration of the contracts between the company and the Bishop
entities until the FERC takes final appealable action on its assertion of
jurisdiction over the Bishop entities.

On June 28, 1996, the KCC issued its order by dismissing the company's
application for approval of the contracts and of recovery of the related costs
from its customers. The company appealed this ruling and on January 24, 1997,
the Kansas Court of Appeals reversed the KCC order and upheld the contracts
and the company's recovery of related costs from its customers were approved
by operation of law.

Definite Statement by Staff of the Issues to be addressed in this Docket. On
March 3, 1997, the Staff issued a More Definite Statement specifying which
charges from KPP it asserts are inappropriate for inclusion in the company's
COGR. The company responded to the More Definite Statement stating that it
does not believe any of the charges from KPP should be disallowed from its
COGR. The company does not expect this proceeding to have a material adverse
effect on its results of operations.

As part of the acquisition of WSS on December 31, 1996, WSS assigned to
WestSec, a wholly-owned subsidiary of Westar Capital established to acquire
the assets of WSS, a software license with Innovative Business Systems (IBS)
which is integral to the operation of its security business. On January 8,
1997, IBS filed litigation in Dallas County, Texas in the 298th Judicial
District Court concerning the assignment of the license to WestSec,
(Innovative Business Systems (Overseas) Ltd., and Innovative Business
Software, Inc. v. Westinghouse Electric Corporation, Westinghouse Security
Systems, Inc., WestSec, Inc., Western Resources, Inc., et al., Cause
No. 97-00184). The company and Westar Capital have demanded Westinghouse
Electric Corporation defend and indemnify them. While the loss of use of
the license may have a material impact on the operations of WestSec,
management of the company currently does not believe that the ultimate
disposition of this matter will have a material adverse effect upon the
company's overall financial condition or results of operations

Additional information on legal proceedings involving the company is
set forth in Notes 7, 8, and 9 of Notes to Consolidated Financial Statements
included herein. See also Item 1. Business, Environmental Matters, and
Regulation and Rates.

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

No matter was submitted during the fourth quarter of the fiscal year
covered by this report to a vote of the company's 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 3, 1997, there were
62,840 common shareholders of record. For information regarding quarterly
common stock price ranges for 1996 and 1995, see Note 20 of Notes to
Consolidated Financial Statements included herein.

Dividends

Western Resources common stock is entitled to dividends when and as
declared by the Board of Directors. At December 31, 1996, 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.
<page24>

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 or about the third day of the preceding month. Dividends
increased four cents per common share in 1996 to $2.06 per share. In January
1997, the Board of Directors declared a quarterly dividend of 52 1/2 cents per
common share, an increase of one cent over the previous quarter. Future
dividends depend upon future earnings, the financial condition of the company
and other factors. For information regarding quarterly dividend declarations
for 1996 and 1995, see Note 20 of Notes to Consolidated Financial Statements
included herein.
<page25>

ITEM 6. SELECTED FINANCIAL DATA
<TABLE>

<S>
Year Ended December 31, 1996 1995 1994(1) 1993 1992(2)
<C> <C> <C> <C> <C>
(Dollars in Thousands)
Income Statement Data:
Operating revenues:
Electric . . . . . .. . . . $1,197,433 $1,145,895 $1,121,781 $1,104,537 $ 882,885
Natural gas . . . . . . . 849,386 597,405 642,988 923,874 756,537
Total operating revenues . . 2,046,819 1,743,300 1,764,769 2,028,411 1,639,422
Operating expenses . . . . . 1,742,826 1,464,591 1,489,719 1,736,051 1,399,701
Allowance for funds used during
construction . . . . . . . 3,225 4,227 2,667 2,631 2,002
Net income . . . . . . . . . 168,950 181,676 187,447 177,370 127,884
Earnings applicable to common
stock. . . . . . . . . . . 154,111 168,257 174,029 163,864 115,133

December 31, 1996 1995 1994(1) 1993 1992(2)
(Dollars in Thousands)
Balance Sheet Data:
Gross plant in service . . . $6,370,586 $6,128,527 $5,963,366 $6,222,483 $6,033,023
Construction work in progress 93,834 100,401 85,290 80,192 68,041
Total assets . . . . . . . . 6,647,781 5,490,677 5,371,029 5,412,048 5,438,906
Long-term debt, preference
stock, and other mandatorily
redeemable securities . .. . 1,951,583 1,641,263 1,507,028 1,673,988 2,077,459

Year Ended December 31, 1996 1995 1994(1) 1993 1992(2)

Common Stock Data:
Earnings per share . . . . . . . $ 2.41 $ 2.71 $ 2.82 $ 2.76 $ 2.20
Dividends per share. . . . . . . $ 2.06 $ 2.02 $ 1.98 $ 1.94 $ 1.90
Book value per share . . . . . . $25.14 $24.71 $23.93 $23.08 $21.51
Average shares outstanding(000's) 63,834 62,157 61,618 59,294 52,272
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 2.67 3.14 3.42 2.79 2.27
Ratio of Earnings to Fixed Charges 2.16 2.41 2.65 2.36 2.02
Ratio of Earnings to Combined
Fixed Charges and Preferred
and Preference Dividend
Requirements . . . . . . . . . 1.96 2.18 2.37 2.14 1.84

(1) Information reflects the sales of the Missouri Properties (Note 19).
(2) Information reflects the merger with KGE on March 31, 1992.
</TABLE>
<page26>

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

FINANCIAL CONDITION

GENERAL: Earnings were $2.41 per share of common stock based on
63,833,783 average common shares for 1996, a decrease from $2.71 in 1995 on
62,157,125 average common shares. Net income for 1996 decreased to $169.0
million compared to $181.7 million in 1995. The decrease in net income and
earnings per share is primarily due to the impact of an $11.8 million or $0.19
per share charge, net of tax, attributable to one-time restructuring and other
charges recorded by ADT Limited (ADT), in which the company owns approximately
27% of the common stock. Abnormally cool summer weather during the third
quarter of 1996 compared to 1995 and the $8.7 million electric rate reduction
to Kansas Gas and Electric Company (KGE) customers implemented on an interim
basis on May 23, 1996 and made permanent on January 15, 1997 also adversely
affected earnings.

Dividends for 1996 increased four cents per common share to $2.06 per
share. On January 24, 1997, the Board of Directors declared a dividend of 52 1/2
cents per common share for the first quarter of 1997, an increase of one cent
over the previous quarter.

The book value per share was $25.14 at December 31, 1996, compared to
$24.71 at December 31, 1995. The 1996 closing stock price of $30.875 was 123%
of book value. There were 64,625,259 common shares outstanding at December
31, 1996.

1996 HIGHLIGHTS

PROPOSED MERGER WITH KANSAS CITY POWER & LIGHT COMPANY: On
April 14,
1996, in a letter to Mr. A. Drue Jennings, Chairman of the Board, President
and Chief Executive Officer of Kansas City Power & Light Company (KCPL), the
company proposed an offer to merge with KCPL (KCPL Merger).

On November 15, 1996, the company and KCPL announced that
representatives of their respective boards and managements met to discuss the
proposed merger transaction. On February 7, 1997, KCPL and the company entered
into an agreement whereby KCPL would be merged with and into the company.

The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareowners will receive $32 of company common stock per KCPL
share, subject to an exchange ratio collar of not less than 0.917 and no more
than 1.100 common shares. Consummation of the KCPL Merger is subject to
customary conditions including obtaining the approval of KCPL's and the
company's shareowners and various regulatory agencies.

The KCPL Merger, will create a company with more than two million
security and energy customers, 9.5 billion in assets, $3.0 billion in annual
revenues and more than 8,000 megawatts of electric generation resources. As a
result of the merger agreement, the company terminated its exchange offer that
had been effective since July 3, 1996. See Note 2 of Notes to Consolidated
Financial Statements (Notes) for more information regarding the proposed merger
with KCPL.

PROPOSED STRATEGIC ALLIANCE WITH ONEOK INC.: On December 12, 1996,
the
company and ONEOK Inc. (ONEOK) announced an agreement to form a strategic
alliance combining the natural gas assets of both companies. Under the
agreement for the proposed strategic alliance, the company will contribute its
natural gas business to a new company (New
<page27>

ONEOK) in exchange for a 45% equity interest. The recorded net property value
being contributed at December 31, 1996 is estimated at $600 million. No gain
or loss is expected to be recorded as a result of the proposed transaction.
The proposed transaction is subject to satisfaction of customary conditions,
including approval by ONEOK shareowners and regulatory authorities. The
company is working towards consummation of the transaction during the second
half of 1997.

The equity interest would be comprised of approximately 3.0 million
common shares and 19.3 million convertible preferred shares. Upon consummation
of the proposed alliance, the company will record its common equity interest in
New ONEOK's earnings using the equity method of accounting. Earnings for the
convertible preferred shares held will be recognized and recorded based upon
preferred dividends paid. The convertible preferred shares are expected to
pay an initial dividend rate of $1.80 per share. For its fiscal year ended
August 31, 1996, ONEOK reported operating revenues of $1.2 billion and net
income of $52.8 million.

The structure of the proposed alliance is not expected to have any
immediate income tax consequences to either company or to either company's
shareowners.
See Note 6 for more information regarding this strategic alliance.

PROPOSED ACQUISITION OF ADT LIMITED, INC.: During 1996, the company
purchased approximately 38 million common shares of ADT Limited, Inc. (ADT)
for approximately $589 million. The shares purchased represent approximately
27% of ADT's common equity making the company the largest shareowner of ADT.

On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10 cash
plus 0.41494 of a share of company common stock for each share of ADT
tendered, based on the closing price of the company's common stock on March
13, 1997. ADT shareowners would not, however, receive more than 0.42017
shares of company common stock for each ADT common share.

subject to the approval of ADT and company shareowners. On January 23, 1997,
the waiting period for the Hart-Scott-Rodino Antitrust Improvement Act
expired. On February 7, 1997, the company received regulatory approval from
the KCC to issue company common stock and debt necessary for the ADT Offer.
On March 17, 1997, ADT announced that it had entered into a definitive
merger agreement pursuant to which Tyco International Ltd. (Tyco), a
diversified manufacturer of industrial and commercial products, would
effectively acquire ADT in a stock for stock transaction valued at $5.6
billion, or approximately $29 per ADT share of common stock. ADT is engaged
in the electronic security services business providing continuous monitoring
of commercial and residential security systems for approximately 1.2 million
customers in North America and abroad.

On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it would
be reviewing the Tyco offer as well as considering its alternatives to such
offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.

ACQUISITION OF WESTINGHOUSE SECURITY SYSTEMS, INC.: On December 31,
1996, the company purchased the assets and assumed certain liabilities
comprising Westinghouse Security Systems, Inc. (WSS), a monitored security
service provider with over 300,000 accounts in the United States. The company
paid $358 million in cash, subject to adjustment. As the acquisition was
consummated on December 31, 1996, the assets of WSS are included in the
Consolidated Balance Sheets, but the results of operations are not included in
the Consolidated Statements of Income. For the year ended December 31, 1996,
WSS reported $110 million in revenues. See Note 4 for further information.

ACQUISITION OF THE WING GROUP LTD: In February of 1996 the company
purchased The Wing Group Ltd (The Wing Group), an international power
developer.

As a consequence of consummated acquisitions and investments, the
company's investments and other property increased by approximately $1.1
billion in 1996, These investments represents approximately 18% of the
company's consolidated assets at December 31, 1996. The impact of the
consummated acquisition and investment transactions on the company's 1997
financial results is expected to be accretive to earnings.

1994 SALES OF MISSOURI GAS 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." For
additional information regarding the sales of the Missouri Properties see
Note 19.

FORWARD LOOKING INFORMATION: Certain matters discussed in this annual
report are "forward-looking statements" intended to qualify for the safe
harbors from liability established by the Private Securities Litigation Reform
Act of 1995. Such statements address future plans, objectives, expectations
and events or conditions concerning various matters such as capital
expenditures, earnings, litigation, rate and other regulatory matters,
pending transactions, liquidity and capital resources, and accounting matters.
Actual results in each case could differ materially from those currently
anticipated in such statements, by reason of factors such as electric utility
restructuring, including ongoing state and federal activities; future economic
<page29>

conditions; legislation; regulation; competition; and other circumstances
affecting anticipated rates, revenues and costs.

LIQUIDITY AND CAPITAL RESOURCES: The company's liquidity is a
function of its ongoing construction and maintenance program designed to improve
facilities which provide electric and natural gas service and meet future
customer service requirements. Acquisitions and subsidiary investments also
significantly affect the company's liquidity.

During 1996, construction expenditures for the company's electric
system were approximately $138 million and nuclear fuel expenditures were
approximately $3 million. It is projected that adequate capacity margins will
be maintained without the addition of any major generating facilities for the
next five years. The construction expenditures for improvements on the
natural gas system, including the company's service line replacement program,
were approximately $59 million during 1996.

Capital expenditures for current utility operations for 1997 through
1999 are anticipated to be as follows:

Electric Nuclear Fuel Natural Gas
(Dollars in Thousands)
1997. . . . . $122,900 $21,300 $50,600
1998. . . . . 126,600 21,500 52,100
1999. . . . . 130,400 3,800 53,700

These expenditures are estimates prepared for planning purposes and are
subject to revisions (See Note 8). Electric expenditures would be
significantly more in years after 1997 following consummation of the merger
with KCPL (See Note 2). Natural gas expenditures will be significantly less
in 1997 and subsequent years upon the consummation of the alliance with ONEOK
(see Note 6).

The company expects to improve cash flow in 1997 and subsequent years
when it begins receiving annual dividends from New ONEOK upon consummation of
the alliance with ONEOK.

Cash provided by operating activities has decreased compared to 1995,
but continues to be the primary source for meeting cash requirements. The
company believes that internally generated funds and new and existing credit
agreements will be sufficient to meet its debt service, dividend payment and
capital expenditure requirements for its utility operations.

The company, through its wholly-owned subsidiary The Wing Group, has
committed to investing at least $136 million through June 1998 for power
generation projects in the People's Republic of China, Turkey and Colombia.
See Notes 4 and 8.

The company will be required to issue a significant number of its
common shares to consummate the transactions discussed above. The company will
also be required to raise a significant amount of funds to consummate the
proposed transactions and to repay short-term debt incurred in connection with
completed transactions. The company expects to raise the required funds from
internally generated funds and from the issuance of debt and equity
securities. See Notes 2 and 3 for additional discussion regarding the
proposed transactions of KCPL and ADT.

The company's capital needs through 2001 for bond maturities are
approximately $200 million. This capital will be provided from internal and
external sources available
<page30>

under then existing financial conditions. There are no cash sinking fund
requirements for bonds or preference stock through the year 2001.

On July 1, 1996, all shares of the company's 8.50% Preference Stock due
2016 were redeemed.

On July 31, 1996 Western Resources Capital II, a wholly-owned trust, of
which the sole asset is subordinated debentures of the company, sold in a
public offering 4.8 million shares of 8-1/2% Cumulative Quarterly Income
Preferred Securities, Series B, for $120 million. The trust interests
represented by the preferred securities are redeemable at the option of
Western Resources Capital II, on or after July 31, 2001, at $25 per preferred
security plus accumulated and unpaid distributions. Holders of the securities
are entitled to receive distributions at an annual rate of 8-1/2% of the
liquidation preference value of $25. Distributions are payable quarterly, and
in substance are tax deductible by the company. These distributions are
recorded as interest charges on the Consolidated Statements of Income. The
sole asset of the trust is $124 million principal amount of 8-1/2% Deferrable
Interest Subordinated Debentures, Series B due July 31, 2036. These preferred
securities are included under Western Resources Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts holding solely company
Subordinated Debentures (Other Mandatorily Redeemable Securities) on the
Consolidated Balance Sheets and Consolidated Statements of Capitalization (See
Note 11).

The company's short-term financing requirements are satisfied, as
needed, through the sale of commercial paper, short-term bank loans and
borrowings under lines of credit maintained with banks. At December 31, 1996,
short-term borrowings amounted to $981 million, of which $293 million was
commercial paper (See Notes 14 and 15). At December 31, 1996, the company had
committed credit arrangements available of $973 million.

The company's short-term debt balance at December 31, 1996, increased
approximately $777 million from December 31, 1995. The increase was primarily
a result of the company's purchases of an approximate 27% common equity
interest in ADT and its purchase of WSS. See Notes 3 and 4 for further
discussion of these purchases.

On February 12, 1997, the company filed an application with the KCC to
issue $550 million in first mortgage bonds or senior unsecured debt to
refinance short-term and long-term debt and for other corporate purposes.

The embedded cost of long-term debt, excluding the revolving credit
facility, was 7.6% at December 31, 1996, a decrease from 7.7% at December 31,
1995. Lower interest rates on the company's variable rate pollution control
bonds resulted in this decrease.

The company has a Dividend Reinvestment and Stock Purchase Plan
(DRIP). Shares issued under the DRIP may be either original issue shares or
shares purchased on the open market. The company has been issuing original
issue shares since January 1, 1995 with 935,461 shares issued in 1996 under the
DRIP.

The company's capital structure at December 31, 1996, was 45% common
stock equity, 2% preferred and preference stock, 6% other mandatorily redeemable
securities, and 47% long-term debt. The capital structure at December 31,
1996, including short-term debt and current maturities of long-term debt, was
35% common stock equity, 2% preferred and preference stock, 5% other
mandatorily redeemable securities, and 58% debt.
<page31>

As of December 31, 1996, the company's bonds were rated "A3" by Moody's
Investors Service, "A-" by Fitch Investors Service, and "A-" by Standard &
Poor's Ratings Group (S&P). In January of 1997, reflecting S&P's increased
financial rating standards and as a result of the company's increased
short-term debt related to its acquisitions, S&P regraded the company's bond
rating to BBB+. Pending the resolution of the ADT Offer, the company remains on
CreditWatch with negative implications with S&P.

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 exclude the activities related to the
Missouri Properties following the sales of those properties in the first
quarter of 1994. For additional information regarding the sales of the Missouri
Properties, see Note 19.

REVENUES

The operating revenues of the company are based on sales volumes and
rates authorized by certain state regulatory commissions and the Federal Energy
Regulatory Commission (FERC). Future electric and natural gas sales will be
affected by weather conditions, the electric rate reduction which was
implemented on February 1, 1997, changes in the industry, changes in the
regulatory environment, competition from other sources of energy, competing
fuel sources, customer conservation efforts, and the overall economy of the
company's service area.

Electric fuel costs are included in base rates. Therefore, if the
company wished to recover an increase in fuel costs, it would have to file a
request for recovery in a rate filing with the Kansas Corporation Commission
(KCC) which could be denied in whole or in part. The company's fuel costs
represented 17% of its total operating expenses for the years ended December
31, 1996 and 1995. Any increase in fuel costs from the projected average
which the company did not recover through rates would reduce the company's
earnings. The degree of any such impact would be affected by a variety of
factors, however, and thus cannot be predicted.

1996 Compared to 1995: Electric revenues were five percent higher in
1996 compared to 1995 due to higher sales in the residential and commercial
customer classes as a result of colder winter and warmer spring temperatures
experienced during the first six months of 1996 compared to 1995. The
company's service territory experienced a 17% increase in heating degree days
during the first quarter and cooling degree days more than doubled during the
second quarter of 1996 compared to the same periods in 1995. Wholesale and
interchange sales were also higher due to an increased number of customers.
Partially offsetting this increase was abnormally cool summer weather during
the third quarter of 1996 compared to 1995 and the $8.7 million electric rate
reduction to KGE customers implemented on an interim basis on May 23, 1996 and
made permanent on January 15, 1997. For more information related to electric
rate decreases, see Note 9.

Regulated natural gas revenues increased 29% for 1996 as compared to
1995 as a result of colder winter temperatures, higher gas costs passed on to
customers through the cost of gas rider (COGR), and increased as-available gas
sales. Regulated natural gas revenues for the last six months of 1996 were
also higher due to the gas revenue increase ordered by the KCC on July 11,
1996. For additional information on the gas rate increase, see Note 9.
<page32>

As-available gas is excess natural gas under contract that the company
did not require for customer sales or storage that is typically sold to gas
marketers. According to the company's tariff, the nominal margin made on
as-available gas sales, is returned 75% to customers through the COGR and 25%
is reflected in wholesale revenues of the company.

Natural gas revenues will be significantly less in 1997 and subsequent
years following consummation of the alliance with ONEOK (see Note 6).

Non-regulated gas revenues increased from approximately $170 million to
approximately $250 million, or 47%, for 1996 as compared to 1995 as a result
of a 12% increase in sales volumes of the company's wholly-owned subsidiary
Westar Gas Marketing, Inc. (Westar Gas Marketing). When the alliance with
ONEOK is complete, Westar Gas Marketing will be transferred to New ONEOK.

1995 Compared to 1994: Electric revenues increased two percent in
1995 as a result of increased sales in all customer classes. The increase is
primarily attributable to a higher demand for air conditioning load during the
summer months of 1995 compared to 1994. The company's service territory
experienced normal temperatures during the summer of 1995, but were more than
20% warmer, based on cooling degree days, compared to the summer of 1994.

Natural gas revenues decreased in 1995 primarily as a result of the
sales of Missouri Properties in the first quarter of 1994. The Consolidated
Statements of Income include revenues of $77 million related to the Missouri
Properties for the first quarter of 1994.

Excluding natural gas sales related to the Missouri Properties, natural
gas revenues increased six percent due to an increase in non-regulated gas
revenues. Non-regulated gas revenues increased from approximately $145
million to approximately $170 million, or 17%, for 1995 as compared to 1994 as
a result of a 44% increase in sales volumes of Westar Gas Marketing.

OPERATING EXPENSES

1996 Compared to 1995: A 19% increase in total operating expenses in
1996 compared to 1995 is primarily due to a full year of amortization of the
acquisition adjustment related to the acquisition of KGE in 1992 and
increased fuel expense, purchased power, and natural gas purchases for
electric generating stations due to Wolf Creek having been taken off-line for
its eighth refueling and maintenance outage during the first quarter of 1996.
Also contributing to the increases in fuel and purchased power expenses was
the increased net generation due to the increase in customer demand for air
conditioning load during the second quarter of 1996. The increase in
operating expenses was partially offset by decreased maintenance expense and
income tax expense.

1995 Compared to 1994: Total operating expenses decreased two percent
in 1995 compared to 1994. The decrease is largely due to the sales of the
Missouri Properties, lower natural gas purchases resulting from lower sales,
and lower fuel expense resulting from a lower unit cost of fuel used for
generation.

Partially offsetting this decrease were expenses related to an early
retirement program. In the second quarter of 1995, $7.6 million related to
early retirement programs was recorded as an expense.
<page33>

OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of
taxes, decreased for the year ended December 31, 1996 compared to 1995
primarily as a result of a decrease in certain miscellaneous regulated gas
revenues which ceased during 1996 in accordance with a KCC order.

Other income and deductions, net of taxes, decreased for the twelve
months ended December 31, 1995 compared to 1994 as a result of the gain on the
sales of the Missouri Properties recorded in the first quarter of 1994.

INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND
REQUIREMENTS:
Total interest charges increased 22% for the twelve months ended December 31,
1996 as compared to 1995 due to increased interest expense on higher balances of
the mandatorily redeemable preferred securities and increases in short-term
borrowings to finance the purchase of the investment in ADT. Total interest
charges increased three percent for the twelve months ended December 31, 1995
as compared to 1994, primarily due to higher debt balances and higher interest
rates on short-term borrowings and variable long-term debt.

KGE MERGER IMPLEMENTATION: In accordance with the KCC KGE merger
order, amortization of the acquisition adjustment commenced August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. The company is recovering the amortization of the acquisition
adjustment through cost savings under a sharing mechanism approved by the KCC.

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

On January 15, 1997, the KCC fixed the annual merger savings level at
$40 million which provides complete recovery of the acquisition premium
amortization expense and a return on the acquisition premium. See Note 9 for
further information relating to rate matters and regulation.

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

OTHER INFORMATION

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

ENVIRONMENTAL: The company has taken a proactive position with
respect to the potential environmental liability associated with former
manufactured gas sites and has an agreement with the Kansas Department of
Health and Environment to systematically
<page34>

evaluate these sites in Kansas. In accordance with the terms of the ONEOK
agreement, ownership of twelve of the fifteen aforementioned sites will be
transferred to New ONEOK upon consummation of the ONEOK alliance. The ONEOK
agreement limits the company's liabilities to an immaterial amount for future
remediation of these sites.

The company is one of numerous potentially responsible parties at a
groundwater contamination site in Wichita, Kansas which is listed by the
Environmental Protection Agency (EPA) as a Superfund site.

The nitrogen oxides (NOx) and toxic limits, which were not set in the
law, were proposed by the EPA in January 1996. The company is currently
evaluating the steps it will need to take in order to comply with the proposed
new. The company will have three years from the date the limits were proposed
to comply with the new NOx rules. See Note 8 for more information regarding
environmental matters.

DECOMMISSIONING: The staff of the SEC has questioned certain current
accounting practices used by nuclear electric generating station owners
regarding the recognition, measurement, and classification of decommissioning
costs for nuclear electric generating stations. In response to these
questions, the Financial Accounting Standards Board is expected to issue new
accounting standards for closure and removal costs, including decommissioning,
in 1997. The company is not able to predict what effect such changes would
have on its results of operations, financial position, or related regulatory
practices until the final issuance of revised accounting guidance, but such
effect could be material. Refer to Note 8 for additional information relating
to new accounting standards for decommissioning.

On August 30, 1996, Wolf Creek Nuclear Operating Corporation submitted
the 1996 Decommissioning Cost Study to the KCC for approval. Approval of this
study was received from the KCC on February 28, 1997. Based on the study, the
company's share of these decommissioning costs, under the immediate
dismantlement method, is estimated to be approximately $624 million during the
period 2025 through 2033, or approximately $192 million in 1996 dollars.
These costs were calculated using an assumed inflation rate of 3.6% over the
remaining service life from 1996 of 29 years. Refer to Note 8 for additional
information relating to the 1996 Decommissioning Cost Study.

CORPORATE-OWNED LIFE INSURANCE: A regulatory asset totaling $41
million and $35 million is outstanding at December 31, 1996 and 1995,
respectively related to deferred postretirement and postemployment costs. In
order to offset these costs, the company purchased corporate-owned life
insurance (COLI) policies on its employees in 1992 and 1993. On August 2, 1996,
Congress passed legislation that will phase out tax benefits associated with
the 1992 and 1993 COLI contracts. The loss of tax benefits will significantly
reduce the COLI earnings. The company is evaluating other methods to replace
the 1992 and 1993 COLI contracts. The company also has the ability to seek
recovery of postretirement and postemployment costs through the ratemaking
process. Regulatory precedents established by the KCC are expected to permit
the accrued costs of postretirement and postemployment benefits to be
recovered in rates. If these costs cannot be recovered in rates, the company
will be required to expense the regulatory asset. (See Notes 1 and 12.)

COMPETITION AND ENHANCED BUSINESS OPPORTUNITIES: The electric and
natural gas utility industry in the United States is rapidly evolving from an
historically regulated monopolistic market to a dynamic and competitive
integrated marketplace. The 1992 Energy Policy Act (Act) began the process of
deregulation of the electricity industry by permitting the FERC to order
electric utilities to allow third parties to sell electric power to wholesale
customers over their transmission systems. As part
<page35>

of the KGE merger, the company agreed to open access of its transmission
system for wholesale transactions. During 1996, wholesale electric revenues
represented approximately 12% of the company's total electric revenues.

Since that time, the wholesale electricity market has become
increasingly competitive as companies begin to engage in nationwide power
brokerage. In addition, various states including California and New York have
taken active steps toward allowing retail customers to purchase electric power
from third-party providers. In 1996, the KCC initiated a generic docket to
study electric restructuring issues. A retail wheeling task force has been
created by the Kansas Legislature to study competitive trends in retail electric
services. During the 1997 session of the Kansas Legislature, bills have been
introduced to increase competition in the electric industry. Among the
matters under consideration is the recovery by utilities of costs in excess of
competitive cost levels. There can be no assurance at this time that such
costs will be recoverable if open competition is initiated in the electric
utility market.

The natural gas industry has been substantially deregulated, with
FERC and many state regulators requiring local natural gas distribution
companies to allow wholesale and retail customers to purchase gas from
third-party providers.

The successful providers of energy in a deregulated market will not
only provide electric or natural gas service but also a variety of other
services, including security. The company believes that in the newly
deregulated environment, more sophisticated consumers will continue to demand
new and innovative options and insist on the development of more efficient
products and services to meet their energy-related needs. The company believes
that its strong core utility business provides it with the platform to offer
the more efficient products and energy services that customers will desire.
Furthermore, the company believes it is necessary to continuously seek new
ways to add value to its customers' lives and businesses. Recognizing that
its current customer base must expand beyond its existing service area, the
company views every person, whether in the United States or abroad, as a
potential customer. The company also recognizes that its potential to emerge
as a leading national energy and energy-related services provider is enhanced
by having a strong brand name. The company has been establishing its brand
identity through the Westar Security name. The combination of the company and
ADT would immediately provide an ideal brand name to capitalize on the
emerging security and energy marketplaces.

Although the company has been planning for the deregulation of the
energy market, increased competition for retail electricity sales may in the
future reduce the company's earnings from its formerly regulated business.
During 1995, however, the company's average retail electric rates were over
9% below the national average and continue to be competitive within the
midwestern United States. In 1997, the company further reduced its retail rates
and expects to be able to retain a substantial portion of its current sales
volume in a competitive environment. Finally, the company believes that the
deregulation of the energy market may prove beneficial to the company, since
any potential competitive pressure in its formerly regulated business is
expected to be more than offset by the nationwide markets which the company
expects to enter by offering energy and security services to customers.

Operating in this competitive environment will place pressure on
utility profit margins and credit quality. Wholesale and industrial customers
may threaten to pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to
obtain reduced energy costs. Increasing competition has resulted in credit
rating agencies applying more stringent guidelines
<page36>

when making utility credit rating determinations. See discussion of Statement
of Financial Accounting Standards No. 71 "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71) in "Regulatory" below.

The company is providing competitive electric rates for industrial
expansion projects and economic development projects in an effort to maintain
and increase electric load. During 1996, the company lost a major industrial
customer to cogeneration resulting in a reduction to pre-tax earnings of $8.6
million annually. This customer's decision to develop its own cogeneration
project was based largely on factors unique to the customer, other than energy
cost.

In light of these developments, the company is pursuing the following
strategic plan: 1) maintain a strong core energy business; 2) build a national
branded presence; and 3) become a leader in the international energy business.
In order to be better positioned for the competitive environment in the energy
industry, the company is pursuing a merger with KCPL (see Note 2), seeking to
acquire ADT (see Note 3), planning a strategic alliance with ONEOK (see Note
6), and developing international power projects through its wholly-owned
subsidiary, The Wing Group (see Note 4).
REGULATORY: On April 24, 1996, FERC issued its final rule on Order No.
888, "Promoting Wholesale Competition Through Open Access Non-discriminatory
Transmission Services by Public Utilities; Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities". The company does not presently
expect the order to have a material effect on its operations in large part
because it is already operating in substantially the required manner due to
its agreement with the KCC during the merger with KGE (See discussion above in
"Competition and Enhanced Business Opportunities").

On May 23, 1996, the company implemented an $8.7 million electric rate
reduction to KGE customers on an interim basis. On October 22, 1996, the
company, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement at the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC. This
agreement was approved by the KCC on January 15, 1997. Under the agreement,
on February 1, 1997, KGE's rates were reduced by $36.3 million and the May,
1996 interim reduction became permanent. KGE's rates will be reduced by
another $10 million effective June 1, 1998, and again on June 1, 1999. KPL's
rates were reduced by $10 million effective February 1, 1997. Two one-time
rebates of $5 million will be credited to the company's customers in January
1998 and 1999. The agreement also fixed annual savings from the merger with
KGE at $40 million. This level of merger savings provides for complete
recovery of the acquisition premium amortization expense and a return on the
acquisition premium. See Note 9 for additional information regarding rate
matters.

On August 22, 1996, the company filed with the FERC an application for
approval of its proposed merger with KCPL. On December 18, 1996, the FERC
issued a Merger Policy Statement (Policy Statement) which articulates three
principal factors the FERC will apply for analyzing mergers: (1) effect on
competition, (2) customer protection, and (3) effect on regulation. The FERC
has requested the company to and pursuant to the FERC request, the company
will revise its filing to comply with the specific requirements of the Policy
Statement.

STRANDED COSTS: The company currently applies accounting standards
that recognize the economic effects of rate regulation, SFAS 71, and,
accordingly, has recorded regulatory assets and liabilities related to its
generation, transmission and distribution operations. In the event the company
determines that it no longer meets the criteria set forth in SFAS 71, the
accounting impact would be an extraordinary
<page37>

non-cash charge to operations of an amount that would be material. Criteria
that give rise to the discontinuance of SFAS 71 include: (1) increasing
competition that restricts the company's ability to establish prices to
recover specific costs, and (2) a significant change in the manner in which
rates are set by regulators from a cost-based regulation to another form of
regulation. The company periodically reviews these criteria to ensure the
continuing application of SFAS 71 is appropriate. Based on current evaluation
of the various factors and conditions that are expected to impact future cost
recovery, the company believes that its net regulatory assets are probable of
future recovery. Any regulatory changes that would require the company to
discontinue SFAS 71 based upon competitive or other events may significantly
impact the valuation of the company's net regulatory assets and its utility
plant investments, particularly the Wolf Creek facility. At this time, the
effect of competition and the amount of regulatory assets which could be
recovered in such an environment cannot be predicted. See discussion of
"Competition and Enhanced Business Opportunities" above for initiatives taken
to restructure the electric industry in Kansas.

The term "stranded costs" as it relates to capital intensive utilities
has been defined as investment in and carrying costs associated with property,
plant and equipment and other regulatory assets in excess of the level which
can be recovered in the competitive market in which the utility operates.
Regulatory changes, including the introduction of competition, could adversely
impact the company's ability to recover its costs in these assets. As of
December 31, 1996, the company has recorded regulatory assets which are
currently subject to recovery in future rates of approximately $458 million.
Of this amount, $217 million represents a receivable for income tax benefits
flow-through to customers. The remainder of the regulatory assets represent
items that may give rise to stranded costs including debt issuance costs,
deferred post employment/retirement benefits and deferred contract settlement
costs. Finally, the company's ability to fully recover its utility plant
investments in, and decommissioning cost for, generating facilities,
particularly Wolf Creek, may be at risk in a competitive environment. This
risk will become more significant as a result of the proposed KCPL Merger as
KCPL presently owns a 47% undivided interest in Wolf Creek. Amounts
associated with the company's recovery of environmental remediation costs and
long-term fuel contract costs cannot be estimated with any certainty, but also
represent items that could give rise to "stranded costs" in a competitive
environment. In the event that the company was not allowed to recover its
investment in these assets, the accounting impact would be a charge to its
results of operations that would be material. If completed, the proposed KCPL
Merger and the proposed strategic alliance with ONEOK will increase the
company's exposure to potential stranded costs.
<page38>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS PAGE

Report of Independent Public Accountants 40

Financial Statements:

Consolidated Balance Sheets, December 31, 1996 and 1995 41
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994 42
Consolidated Statements of Cash Flows for the years ended
1996, 1995 and 1994 43
Consolidated Statements of Taxes for the years ended
December 31, 1996, 1995 and 1994 44
Consolidated Statements of Capitalization, December 31, 1996
and 1995 45
Consolidated Statements of Common Stock Equity for the years
ended December 31, 1996, 1995 and 1994 46
Notes to Consolidated Financial Statements 47

SCHEDULES OMITTED

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

I, II, III, IV, and V.
<page39>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareowners 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, 1996 and 1995, 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, 1996. These financial statements are the
responsibility of the company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Western
Resources, Inc., and subsidiaries as of December 31, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles.

As explained in Note 12 to the consolidated financial statements,
effective January 1, 1994, the company changed its method of accounting for
postemployment benefits.

ARTHUR ANDERSEN
LLP
Kansas City, Missouri,
January 24, 1997
(February 7, 1997 with
respect to Note 2 of
the Notes to Consolidated
Financial Statements.)
<page40>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)

<CAPTION>
December 31,
1996 1995
<S> <C> <C>
ASSETS
UTILITY PLANT (Notes 1 and 17):
Electric plant in service . . . . . . . . . . . . . . . . $5,536,256 $5,341,074
Natural gas plant in service. . . . . . . . . . . . . . . 834,330 787,453
6,370,586 6,128,527
Less - Accumulated depreciation . . . . . . . . . . . . . 2,146,363 1,926,520
4,224,223 4,202,007
Construction work in progress . . . . . . . . . . . . . . 93,834 100,401
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 38,461 53,942
Net utility plant. . . . . . . . . . . . . . . . . . . 4,356,518 4,356,350

INVESTMENTS AND OTHER PROPERTY:
Investment in ADT (net) . . . . . . . . . . . . . . . . . 590,102 -
Security business and other property. . . . . . . . . . . 584,647 99,269
Decommissioning trust (Note 8). . . . . . . . . . . . . . 33,041 25,070
1,207,790 124,339
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 3,724 2,414
Accounts receivable and unbilled revenues (net) (Note 1). 318,966 257,292
Fossil fuel, at average cost. . . . . . . . . . . . . . . 39,061 54,742
Gas stored underground, at average cost . . . . . . . . . 30,027 28,106
Materials and supplies, at average cost . . . . . . . . . 66,167 57,996
Prepayments and other current assets. . . . . . . . . . . 36,503 20,426
494,448 420,976
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 10). . . . . . . . . . 217,257 282,476
Corporate-owned life insurance (net) (Notes 1 and 12) . . 86,179 44,143
Regulatory assets (Note 9). . . . . . . . . . . . . . . . 241,039 262,393
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 44,550 -
589,025 589,012

TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $6,647,781 $5,490,677

CAPITALIZATION AND LIABILITIES

CAPITALIZATION (See statements):
Common stock equity . . . . . . . . . . . . . . . . . . . $1,624,680 $1,553,110
Cumulative preferred and preference stock . . . . . . . . 74,858 174,858
Western Resources obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely company subordinated debentures. . . . . . . . . 220,000 100,000
Long-term debt (net). . . . . . . . . . . . . . . . . . . 1,681,583 1,391,263
3,601,121 3,219,231
CURRENT LIABILITIES:
Short-term debt (Note 15) . . . . . . . . . . . . . . . . 980,740 203,450
Long-term debt due within one year (Note 14). . . . . . . - 16,000
Accounts payable. . . . . . . . . . . . . . . . . . . . . 180,540 149,194
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 83,813 68,569
Accrued interest and dividends. . . . . . . . . . . . . . 70,193 62,157
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 36,806 40,266
1,352,092 539,636
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 10) . . . . . . . . . . . . . 1,110,372 1,167,470
Deferred investment tax credits (Note 10) . . . . . . . . 125,528 132,286
Deferred gain from sale-leaseback (Note 16) . . . . . . . 233,060 242,700
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 225,608 189,354
1,694,568 1,731,810
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $6,647,781 $5,490,677

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page41>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<CAPTION>

Year Ended December 31,
1996 1995 1994(1)

OPERATING REVENUES (Notes 1 and 9):
Electric. . . . . . . . . . . . . . . . . . . . . . . $1,197,433 $1,145,895 $1,121,781
Natural gas . . . . . . . . . . . . . . . . . . . . . 849,386 597,405 642,988
Total operating revenues. . . . . . . . . . . . . . 2,046,819 1,743,300 1,764,769

OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 245,990 211,994 220,766
Nuclear fuel (net). . . . . . . . . . . . . . . . . 19,962 19,425 13,562
Power purchased . . . . . . . . . . . . . . . . . . . 27,592 15,739 15,438
Natural gas purchases . . . . . . . . . . . . . . . . 354,755 263,790 312,576
Other operations. . . . . . . . . . . . . . . . . . . 607,995 479,136 438,945
Maintenance . . . . . . . . . . . . . . . . . . . . . 99,122 108,641 113,186
Depreciation and amortization . . . . . . . . . . . . 183,722 160,285 157,398
Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 17,544
Taxes (See Statements):
Federal income. . . . . . . . . . . . . . . . . . . 70,057 72,314 76,477
State income. . . . . . . . . . . . . . . . . . . . 19,035 18,883 19,145
General . . . . . . . . . . . . . . . . . . . . . . 97,052 96,839 104,682
Total operating expenses. . . . . . . . . . . . . 1,742,826 1,464,591 1,489,719

OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 303,993 278,709 275,050

OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (2,249) (2,668) (5,354)
Gain on sales of Missouri Properties (Note 19). . . . - - 30,701
Special charges from ADT (Note 3) . . . . . . . . . . (18,181) - -
Equity in earnings of investees and other (net) . . . 31,723 19,925 10,296
Income taxes (net) (See Statements) . . . . . . . . . 2,990 7,805 (4,329)
Total other income and deductions . . . . . . . . 14,283 25,062 31,314

INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 318,276 303,771
306,364

INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 105,741 95,962 98,483
Other . . . . . . . . . . . . . . . . . . . . . . . . 46,810 30,360 23,101
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . . . . . . (3,225) (4,227) (2,667)
Total interest charges. . . . . . . . . . . . . . 149,326 122,095 118,917

NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 168,950 181,676 187,447

PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 14,839 13,419
13,418

EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . $ 154,111 $ 168,257
$ 174,029

AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 63,833,783 62,157,125
61,617,873

EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING . . . . . $ 2.41 $
2.71 $ 2.82

DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 2.06 $ 2.02 $
1.98

(1) Information reflects the sales of the Missouri Properties (Note 19).

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page42>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<CAPTION>

Year Ended December 31,
1996 1995 1994(1)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 168,950 $ 181,676 $ 187,447
Depreciation and amortization . . . . . . . . . . . . . . 190,628 160,285 157,398
Amortization of nuclear fuel. . . . . . . . . . . . . . . 15,685 14,703 10,437
Gain on sale of utility plant (net of tax). . . . . . . . - (951) (19,296)
Amortization of phase-in revenues . . . . . . . . . . . . 17,544 17,545 17,544
Corporate-owned life insurance policies . . . . . . . . . (29,713) (28,548) (17,246)
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640)
Deferred acquisition costs. . . . . . . . . . . . . . . . (31,518) - -
Equity in earnings of investees . . . . . . . . . . . . . (9,373) - -
Changes in other working capital items (net of effects
from acquisitions):
Accounts receivable and unbilled revenues (net)(Note 1) (47,474) (37,532) (75,630)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . 15,681 (15,980) (7,828)
Gas stored underground. . . . . . . . . . . . . . . . (1,921) 17,116 (5,403)
Accounts payable. . . . . . . . . . . . . . . . . . . 15,353 18,578 (41,682)
Accrued taxes . . . . . . . . . . . . . . . . . . . . 26,709 (19,024) 20,756
Other . . . . . . . . . . . . . . . . . . . . . . . . 18,325 8,179 41,309
Changes in other assets and liabilities . . . . . . . . . (63,950) 537 9,625
Net cash flows from operating activities. . . . . . . . 275,286 306,944 267,791

CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 199,509 236,827 237,696
Sales of utility plant. . . . . . . . . . . . . . . . . . - (1,723) (402,076)
Purchase of ADT common stock. . . . . . . . . . . . . . . 589,362 - -
Security business acquisitions. . . . . . . . . . . . . . 368,535 - -
Non-utility investments (net) . . . . . . . . . . . . . . 6,563 15,408 9,041
Corporate-owned life insurance policies . . . . . . . . . 54,007 55,175 54,914
Death proceeds of corporate-owned life insurance policies (10,653) (11,187) (1,251)
Net cash flows used in (from) investing activities. . . 1,207,323 294,500 (101,676)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 777,290 (104,750) (132,695)
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - - 235,923
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (16,135) (105) (223,906)
Revolving credit agreements (net) . . . . . . . . . . . . 225,000 50,000 (115,000)
Other long-term debt retired. . . . . . . . . . . . . . . - - (67,893)
Other mandatorily redeemable securities . . . . . . . . . 120,000 100,000 -
Borrowings against life insurance policies. . . . . . . . 45,978 49,279 70,633
Repayment of borrowings against life insurance policies . (4,963) (5,384) (225)
Common stock issued (net) . . . . . . . . . . . . . . . . 33,212 36,161 -
Preference stock redeemed . . . . . . . . . . . . . . . . (100,000) - -
Dividends on preferred, preference, and common stock. . . (147,035) (137,946)
(134,806)
Net cash flows from (used in) financing activities. . . 933,347 (12,745) (367,969)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 1,310
(301) 1,498

CASH AND CASH EQUIVALENTS:
Beginning of the period . . . . . . . . . . . . . . . . . 2,414 2,715 1,217
End of the period . . . . . . . . . . . . . . . . . . . . $ 3,724 $ 2,414 $ 2,715

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized). . . . . . . . . . . . . . . . . . . . . . $ 169,713 $ 136,548 $ 134,785
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 66,692 84,811 90,229

(1) Information reflects the sales of the Missouri Properties (Note 19).

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page43>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES
(Dollars in Thousands)
<CAPTION>

Year Ended December 31,
1996 1995 1994(1)

<S> <C> <C> <C>
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 61,602 $ 51,218 $ 98,748
Deferred taxes arising from:
Alternative minimum tax credit. . . . . . . . . . . . . 18,491 23,925 -
Depreciation and other property related items . . . . . (1,386) (1,813) 29,506
Energy and cost of gas riders . . . . . . . . . . . . . (2,095) 5,239 9,764
Natural gas line survey and replacement program . . . . (466) 1,192 (313)
Missouri property sales . . . . . . . . . . . . . . . . - - (36,343)
Prepaid power sale. . . . . . . . . . . . . . . . . . . 376 (23) (13,759)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (2,301) (7,046) (800)
Amortization of investment tax credits. . . . . . . . . . (6,652) (6,789) (6,739)
Total Federal income taxes. . . . . . . . . . . . . . 67,569 65,903 80,064
Less:
Federal income taxes applicable to non-operating items:
Missouri property sales . . . . . . . . . . . . . . . . - - 9,485
Other . . . . . . . . . . . . . . . . . . . . . . . . . (2,488) (6,411) (5,898)
Total Federal income taxes applicable to
non-operating items . . . . . . . . . . . . . . . . (2,488) (6,411) 3,587
Total Federal income taxes charged to operations. . 70,057 72,314 76,477

STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 18,885 17,203 17,758
Deferred (net). . . . . . . . . . . . . . . . . . . . . . (352) 286 2,129
Total State income taxes. . . . . . . . . . . . . . . 18,533 17,489 19,887
Less:
State income taxes applicable to non-operating items. . . (502) (1,394) 742
Total State income taxes charged to operations. . . 19,035 18,883 19,145

GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 84,776 83,738 86,687
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 32 26 5,116
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 12,244 13,075 12,879
Total general taxes charged to operations . . . . . 97,052 96,839 104,682

TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $186,144 $188,036
$200,304

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, 1996 1995 1994(1)

EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . 32.8% 31.8% 35.3%

EFFECT OF:
State income taxes. . . . . . . . . . . . . . . . . . . . (5.1) (4.3) (4.6)
Amortization of investment tax credits. . . . . . . . . . 2.7 2.5 2.4
Corporate-owned life insurance policies . . . . . . . . . 3.7 3.2 2.1
Flow through and amortization, net. . . . . . . . . . . . (.2) (.2) (.7)
Other differences . . . . . . . . . . . . . . . . . . . . 1.1 2.0 .5

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

(1) Information reflects the sales of the Missouri Properties (Note 19).

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page44>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
<CAPTION>

December 31,
1996 1995
<S> <C> <C>

COMMON STOCK EQUITY (See Statements):
Common stock, par value $5 per share,
authorized 85,000,000 shares, outstanding
64,625,259 and 62,855,961 shares, respectively . . $ 323,126 $ 314,280
Paid-in capital. . . . . . . . . . . . . . . . . . . 739,433 697,962
Retained earnings. . . . . . . . . . . . . . . . . . 562,121 540,868
1,624,680 45% 1,553,110 48%

CUMULATIVE PREFERRED AND PREFERENCE STOCK (Note 11):
Preferred stock 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
Preference stock subject to mandatory redemption,
Without par value, $100 stated value,
authorized 4,000,000 shares,
outstanding -
7.58% Series, 500,000 shares. . . . . . . . . 50,000 50,000
8.50% Series, 1,000,000 shares. . . . . . . . - 100,000
50,000 150,000
74,858 2% 174,858 6%

WESTERN RESOURCES OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY
TRUSTS HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (Note 11): 220,000 6% 100,000 3%

LONG-TERM DEBT (Note 14):
First mortgage bonds . . . . . . . . . . . . . . . . 825,000 841,000
Pollution control bonds. . . . . . . . . . . . . . . 521,682 521,817
Revolving credit agreement . . . . . . . . . . . . . 275,000 50,000
Other long-term debt . . . . . . . . . . . . . . . . 65,190 -
Less:
Unamortized premium and discount (net) . . . . . . 5,289 5,554
Long-term debt due within one year . . . . . . . . - 16,000
1,681,583 47% 1,391,263 43%
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . $3,601,121 100% $3,219,231 100%

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page45>
<TABLE>

WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY
(Dollars in Thousands)
<CAPTION>

Common Paid-in Retained
Stock Capital Earnings

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

Net income. . . . . . . . . . . . . . . . . . . . . . 187,447

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,418)
Common stock, $1.98 per share . . . . . . . . . . . (122,003)

Expenses on common stock. . . . . . . . . . . . . . . (228)
Distribution of common stock under the Dividend
Reinvestment and Stock Purchase Plan. . . . . . . . 482

BALANCE DECEMBER 31, 1994, 61,617,873 shares. . . . . 308,089 667,992 498,374

Net income. . . . . . . . . . . . . . . . . . . . . . 181,676

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,419)
Common stock, $2.02 per share . . . . . . . . . . . (125,763)

Expenses on common stock. . . . . . . . . . . . . . . (772)

Issuance of 1,238,088 shares of common stock. . . . . 6,191 30,742

BALANCE DECEMBER 31, 1995, 62,855,961 shares. . . . . 314,280 697,962 540,868

Net income. . . . . . . . . . . . . . . . . . . . . . 168,950

Cash dividends:
Preferred and preference stock. . . . . . . . . . . (14,839)
Common stock, $2.06 per share . . . . . . . . . . . (131,611)

Issuance of 1,769,298 shares of common stock. . . . . 8,846 41,471 (1,247)

BALANCE DECEMBER 31, 1996, 64,625,259 shares. . . . . $323,126 $739,433
$562,121

The Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
<page46>

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) and its wholly-owned subsidiaries, include KPL, a rate-regulated
electric and gas division of the company, Kansas Gas and Electric Company
(KGE), a rate-regulated electric utility and wholly-owned subsidiary of the
company, Westar Security, Inc. (Westar Security) a wholly-owned subsidiary
which provides monitored electronic security services, Westar Energy, Inc. a
wholly-owned subsidiary which provides non-regulated energy services, Westar
Capital, Inc. (Westar Capital) a wholly-owned subsidiary which holds equity
investments in technology and energy-related companies, The Wing Group Limited
(The Wing Group), a wholly-owned developer of international power projects,
and Mid Continent Market Center, Inc. (Market Center), a regulated gas
transmission service provider. KGE owns 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), the operating company for Wolf Creek Generating Station
(Wolf Creek). The company records its proportionate share of all transactions
of WCNOC as it does other jointly-owned facilities. All significant
intercompany transactions have been eliminated.

The company is an investor-owned holding company. The company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity, the delivery and sale of natural gas, and electronic security
services. The company serves approximately 606,000 electric customers in
eastern and central Kansas and approximately 650,000 natural gas customers in
Kansas and northeastern Oklahoma. The company's non-utility subsidiaries
provide electronic security services to approximately 400,000 customers
throughout the United States, market natural gas primarily to large commercial
and industrial customers, develop international power projects, and provide
other energy-related products and services.

The company prepares its financial statements in conformity with
generally accepted accounting principles as applied to regulated public
utilities. The accounting and rates of the company are subject to requirements
of the Kansas Corporation Commission (KCC), the Oklahoma Corporation Commission
(OCC), and the Federal Energy Regulatory Commission (FERC). The financial
statements require management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, to disclose contingent assets and
liabilities at the balance sheet dates, and to report amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

The company currently applies accounting standards that recognize the
economic effects of rate regulation Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation",
(SFAS 71) and, accordingly, has recorded regulatory assets and liabilities
related to its generation, transmission and distribution operations. In 1996,
the KCC initiated a generic docket to study electric restructuring issues. A
retail wheeling task force has been created by the Kansas Legislature to study
competitive trends in retail electric services. During the 1997 session of
the Kansas Legislature, bills have been introduced to increase competition in
the electric industry. Among the matters under consideration is the recovery
by utilities of costs in excess of competitive cost levels. There can be no
assurance at this time that such costs will be recoverable if open competition
is initiated in the electric utility market. In the event the company
determines that it no longer meets the criteria set forth in SFAS 71, the
accounting impact would be an extraordinary
<page47>

non-cash charge to operations of an amount that would be material. Criteria
that give rise to the discontinuance of SFAS 71 include, (1) increasing
competition that restricts the company's ability to establish prices to
recover specific costs, and (2) a significant change in the manner in which
rates are set by regulators from a cost-based regulation to another form of
regulation. The company periodically reviews these criteria to ensure the
continuing application of SFAS 71 is appropriate. Based on current evaluation
of the various factors and conditions that are expected to impact future cost
recovery, the company believes that its net regulatory assets are probable of
future recovery. Any regulatory changes that would require the company to
discontinue SFAS 71 based upon competitive or other events may significantly
impact the valuation of the company's net regulatory assets and its utility
plant investments, particularly the Wolf Creek facility. At this time, the
effect of competition and the amount of regulatory assets which could be
recovered in such an environment cannot be predicted. See Note 9 for further
discussion on regulatory assets.

In January, 1996, the company adopted Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS 121). This Statement imposes
stricter criteria for regulatory assets by requiring that such assets be
probable of future recovery at each balance sheet date. Based on the current
regulatory structure in which the company operates, the adoption of this
standard did not have a material impact on the financial position or results
of operations of the company. This conclusion may change in the future as
competitive factors influence wholesale or retail pricing in the electric
industry.

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 5.7%
in 1996, 6.31% in 1995, and 4.08% in 1994. The cost of additions to utility
plant and replacement units of property are capitalized. Maintenance costs and
replacement of minor items of property are charged to expense as incurred.
When units of depreciable property are retired, they are removed from the
plant accounts and the original cost plus removal charges less salvage are
charged to accumulated depreciation.

In accordance with regulatory decisions made by the KCC, amortization
of the acquisition premium of approximately $801 million resulting from the KGE
purchase began in August of 1995. The premium is being amortized over 40
years and has been classified as electric plant in service. Accumulated
amortization through December 31, 1996 totaled $27.5 million. See Note 9 for
further information concerning the amortization of this premium.

Depreciation: Depreciation is provided on the straight-line method
based on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.97% during 1996, 2.84% during 1995, and 2.87%
during 1994 of the average original cost of depreciable property. In the
past, the methods and rates have been determined by depreciation studies and
approved by the various regulatory bodies. The company periodically evaluates
its depreciation rates considering the past and expected future experience in
the operation of its facilities.

Environmental Remediation: Effective January 1, 1997, the company
adopted the provisions of Statement of Position (SOP) 96-1, "Environmental
Remediation Liabilities". This statement provides authoritative guidance for
recognition, measurement, display, and disclosure of environmental remediation
liabilities in financial statements. The company is currently evaluating and
in the process of
<page48>

estimating the potential liability associated with environmental remediation.
Management does not expect the amount to be significant to the company's
results of operations as the company will seek recovery of these costs through
rates as has been permitted by the KCC in the case of another Kansas utility.
Additionally, the adoption of this statement is not expected to have a
material impact on the company's financial position. To the extent that such
remediation costs are not recovered through rates, the costs may be material
to the company's operating results, depending on the degree of remediation
required and number of years over which the remediation must be completed.

Cash and Cash Equivalents: For purposes of the Consolidated
Statements of Cash Flows, the company considers highly liquid collateralized
debt instruments purchased with a maturity of three months or less to be cash
equivalents.

Income Taxes: The company accounts for income taxes in accordance with
the provisions of Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets
and liabilities are recognized based on temporary differences in amounts
recorded for financial reporting purposes and their respective tax bases.
Investment tax credits previously deferred are being amortized to income over
the life of the property which gave rise to the credits (See Note 10).

Revenues: Operating revenues for both electric and natural gas services
include estimated amounts for services rendered but unbilled at the end of
each year. Revenues for security services are recognized in the period
earned. Unbilled revenues of $83 million and $66 million are recorded as a
component of accounts receivable and unbilled revenues (net) on the
Consolidated Balance Sheets as of December 31, 1996 and 1995, respectively.

The company's recorded reserves for doubtful accounts receivable
totaled $6.3 million and $4.9 million at December 31, 1996 and 1995,
respectively.

Debt Issuance and Reacquisition Expense: Debt premium, discount, and
issuance expenses are amortized over the life of each issue. Under regulatory
procedures, debt reacquisition expenses are amortized over the remaining life
of the reacquired debt or, if refinanced, the life of the new debt. See Note
9 for more information regarding regulatory assets.

Risk Management: The company is exposed to fluctuations in price on the
portfolio of natural gas transactions resulting from marketing activities of a
non-regulated subsidiary. To minimize the risk from market fluctuations, the
company enters into natural gas futures, swaps and options in order to hedge
existing physical natural gas purchase or sale commitments. These financial
instruments are designated as hedges of the underlying physical commitments
and as such, gains or losses resulting from changes in market value of the
various derivative instruments are deferred and recognized in income when the
underlying physical transaction is closed. See Note 5 for further
information.

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, 1996 and 1995, was $25.3 million and $28.5
million, respectively.
<page49>

Cash Surrender Value of Life Insurance Policies: The following amounts
related to corporate-owned life insurance policies (COLI) are recorded in
Corporate-owned life insurance (net) on the Consolidated Balance Sheets:

At December 31,
1996 1995
(Dollars in Millions)
Cash surrender value of policies (1) . $ 563.0 $ 479.9
Borrowings against policies. . . . . . (476.8) (435.8)
COLI (net). . . . . . . . . . $ 86.2 $ 44.1

(1) Cash surrender value of policies as presented represents the value of the
policies as of the end of the respective policy years and not as of December
31, 1996 and 1995.

Income is recorded for increases in cash surrender value and net death
proceeds. Interest expense is recognized for COLI borrowings except for
certain policies entered into in 1992 and 1993. The net income generated from
COLI contracts purchased prior to 1992 including the tax benefit of the
interest deduction and premium expenses are recorded as Corporate-owned life
insurance (net) on the Consolidated Statements of Income. The income from
increases in cash surrender value and net death proceeds was $25.4 million in
1996, $22.7 million in 1995, and $15.6 million in 1994. The interest expense
deduction taken was $27.6 million for 1996, $25.4 million for 1995, and $21.0
million for 1994.

The COLI policies entered into in 1992 and 1993 were established to
mitigate the cost of postretirement and postemployment benefits. As approved
by the KCC, the company is using the net income stream generated by these COLI
policies to offset the costs of postretirement and postemployment benefits. A
regulatory asset totaling $41 million and $35 million is outstanding at
December 31, 1996 and 1995, respectively, related to deferred postretirement
and postemployment costs.

On August 2, 1996, Congress passed legislation that will phase out tax
benefits associated with the 1992 and 1993 COLI policies. The loss of tax
benefits will significantly reduce the COLI earnings. The company is
evaluating other methods to replace the 1992 and 1993 COLI policies. The
company also has the ability to seek recovery of postretirement and
postemployment costs through the rate making process. Regulatory precedents
established by the KCC are expected to permit the accrued costs of
postretirement and postemployment benefits to be recovered in rates. If a
suitable COLI replacement product cannot be found, or these costs cannot be
recovered in rates, the company may be required to expense the regulatory
asset. The company currently expects to be able to find a suitable COLI
replacement. The legislation had minimal impact on the Company's COLI
policies entered into prior to 1992. (See Notes 9 and 12).

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

2. PROPOSED MERGER WITH KANSAS CITY POWER & LIGHT COMPANY

On April 14, 1996, in a letter to Mr. A. Drue Jennings, Chairman of the
Board, President and Chief Executive Officer of Kansas City Power & Light
Company (KCPL), the company proposed an offer to merge with KCPL (KCPL
Merger).
<page50>

The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareowners will receive $32 of company common stock per KCPL
common share, subject to an exchange ratio collar of not less than 0.917 to no
more than 1.100 common shares. Consummation of the KCPL Merger is subject to
customary conditions including obtaining the approval of KCPL's and the
company's shareowners and various regulatory agencies. The company expects to
be able to close the KCPL Merger in the first half of 1998. See Note 9 for
discussion of rate proceedings.

The KCPL Merger, will create a company with more than two million
security and energy customers, $9.5 billion in total assets, $3.0 billion in
annual revenues and more than 8,000 megawatts of electric generation resources.
As a result of the merger agreement, the company terminated its exchange offer
that had been effective since July 3, 1996.

The KCPL Merger is designed to qualify as a pooling of interests for
financial reporting purposes. Under this method, the recorded assets and
liabilities of the company and KCPL would be carried forward at historical
amounts to a combined balance sheet. Prior period operating results and the
consolidated statements of financial position, cash flows and capitalization
would be restated to effect the combination for all periods presented.

KCPL is a public utility company engaged in the generation,
transmission, distribution, and sale of electricity to approximately 430,000
customers in western Missouri and eastern Kansas. KCPL and the company have
joint interests in certain electric generating assets, including Wolf Creek.

As of December 31, 1996, the company has incurred approximately $32
million of transaction costs associated with the KCPL Merger. The company
anticipates expensing these costs in the first reporting period subsequent to
closing the KCPL Merger. As of December 31, 1996, costs incurred have been
included in Deferred Charges and Other Assets, Other on the Consolidated
Balance Sheets.

3. ADT LIMITED, INC.

Investment in ADT Limited, Inc.: During 1996, the company purchased
approximately 38 million common shares of ADT Limited, Inc. (ADT) for
approximately $589 million. The shares purchased represent approximately 27%
of ADT's common shares making the company the largest shareowner of ADT.
These purchases were financed entirely with short-term borrowings. ADT is
North America's largest monitored security services company with $1.8 billion
in annual revenues. ADT has approximately 1.2 million customers in North
America and abroad and has approximately 18,000 employees. The company uses
the equity method of accounting for this investment. Goodwill of
approximately $369 million is associated with this investment and is being
amortized over 40 years and is presented net in Equity in earnings of
investees and other on the Consolidated Statements of Income. Accumulated
amortization approximates $6.5 million at December 31, 1996.

ADT recently announced that it would record a net charge to income of
approximately $60 million during 1996. This charge is primarily related to
<page51>

one-time restructuring charges resulting from its merger with another security
company, partially offset by a gain on the sale of non-strategic assets. The
company recognized its share of this charge equal to $11.8 million or
approximately $0.19 per share, net of tax, as a component of Equity in
earnings of investees and other on the Consolidated Statements of Income.

Proposed Acquisition of ADT: On December 18, 1996, the company
announced its intention to offer to exchange $22.50 in cash ($7.50) and shares
($15.00) of the company's common stock for each outstanding common share of ADT
not already owned by the company or its subsidiaries (ADT Offer). The value of
the ADT Offer, assuming the company's average stock price prior to closing is
above $29.75 per common share, is approximately $3.5 billion, including the
company's existing investment in ADT. Following completion of the ADT Offer,
the company presently intends to propose and seek to have ADT effect an
amalgamation, pursuant to which a newly created subsidiary of the company
incorporated under the laws of Bermuda will amalgamate with and into ADT
(Amalgamation). Based upon the closing stock price of the company on March
13, 1997, approximately 60.1 million shares of company common stock would be
issuable pursuant to the acquisition of ADT. However, the actual number of
shares of company common stock that would be issuable in connection with the
ADT Offer and the Amalgamation will depend on the exchange ratio and the
number of shares validly tendered prior to the expiration date of the ADT
Offer and the number of shares of ADT outstanding at the time the Amalgamation
is completed.

On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10 cash
plus 0.41494 of a share of company common stock for each share of ADT
tendered, based on the closing price of the company's common stock on March
13, 1997. ADT shareowners would not, however, receive more than 0.42017
shares of company common stock for each ADT common share.

Concurrent with the announcement of the ADT Offer on December 18, 1996,
the company filed a registration statement on Form S-4 with the Securities and
Exchange Commission (SEC) related to the ADT Offer. On March 14, 1997, the
registration statement was declared effective by the SEC. The expiration date
of the ADT Offer is 5 p.m., EDT, April 15, 1997, and may be extended from time
to time by the company until the various conditions to the ADT Offer have been
satisfied or waived. The ADT Offer will be subject to the approval of ADT and
company shareowners. On January 23, 1997, the waiting period for the
Hart-Scott-Rodino Antitrust Improvement Act expired. On February 7, 1997, the
company received regulatory approval from the KCC to issue company common
stock and debt necessary for the ADT Offer. See Note 5 for summary financial
information concerning ADT.

On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it would
be reviewing the Tyco offer as well as considering its alternatives to such
offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.
<page52>

4. ACQUISITIONS

On December 31, 1996, Westar Capital bought the assets of Westinghouse
Security Systems, Inc. (WSS). This acquisition, which was accounted for as a
purchase, significantly expands the scope of the company's security service
operations. Westar Capital paid approximately $358 million in cash, subject
to adjustment, to purchase the assets and assume certain liabilities of WSS.
Based on a preliminary estimate of the purchase price allocation, the company
recorded approximately $275 million of goodwill to be amortized over 40 years.
This balance is included in Security business and other property on the
accompanying Consolidated Balance Sheets. Since the transaction closed on
December 31, 1996, no operating results are reflected on the Consolidated
Statements of Income. For the year ended December 31, 1996, WSS reported $110
million in revenues. As of December 31, 1996, the company consolidated WSS'
financial position in the accompanying Consolidated Balance Sheets. The
company financed this acquisition with short-term borrowings.

During 1996, the company also acquired The Wing Group and three small
security system companies. The Wing Group develops international power
projects. In connection with these acquisitions, the company gave
consideration of approximately $33.8 million in cash and 683,333 shares of
common stock. In connection with the acquisitions, liabilities were assumed
as follows:

(Dollars in Millions)
Fair value of assets acquired $ 38.8
Consideration paid $(33.8)
Liabilities assumed $ 5.0

Each acquisition was accounted for as a purchase. Goodwill related to
these acquisitions of approximately $32.9 million is presented in the
Consolidated Balance Sheets as Security business and other property and is
being amortized over 20 years. Accumulated amortization of approximately
$943,000 has been recognized to date.

The purchase agreement related to The Wing Group allows the company, at
its option, to purchase ownership interests in power projects in which the
former owners of The Wing Group have rights. In 1996, the company gave shares
of common stock to the former owners of The Wing Group in return for a nine
percent equity interest in a power project in Turkey. See Note 8 for
information with respect to investment commitments made by the company on
behalf of The Wing Group.

5. NON-REGULATED SUBSIDIARIES

Certain non-regulated subsidiaries use natural gas futures, swaps and
options contracts to reduce the effects of natural gas commodity price
volatility on operating results which include price risk and basis risk.
Price risk is the difference in price between the physical commodity being
hedged and the price of the futures contracts used for hedging. Natural gas
options held to hedge price risk provide the right, but not the requirement,
to buy or sell natural gas at a fixed price. Basis risk is the risk that an
adverse change in the futures market will not be completely offset by an equal
and opposite change in the cash price of the commodity being hedged. Basis
risk exists in natural gas primarily due to the geographical price
differentials between cash market locations and futures contract delivery
locations. In general, the company's risk management policy requires that
positions taken with derivatives be offset by positions in physical
transactions or other derivatives. All of the company's financial instruments
are held for purposes other than trading.
<page53>

The derivative instruments used to hedge commodity transactions have
historically had a high correlation with commodity prices and are expected to
continue to do so. The correlation of indices and prices is regularly
evaluated by management to ensure that the instruments continue to be
effective hedges. In the event that the correlation falls below allowable
levels, the gains or losses associated with hedging instruments are recognized
in the current period to the extent that correlation was lost. The maturity
of the derivative instruments is timed to coincide with the hedged
transaction. If the hedged transaction is terminated early or if an
anticipated transaction fails to occur, the deferred gain or loss associated
with the derivative instrument is recognized in the period and the hedge is
closed.

The company has historically used natural gas futures and options
contracts traded on the New York Mercantile Exchange and natural gas financial
swaps with various third parties to reduce exposure to price risk when gas is
not bought and sold simultaneously. At December 31, 1996, the company had a
deferred gain of $3.4 million representing unrealized gains on forward
commitments that will mature through the year 2000.

The consolidated financial statements include the company's investments
in ADT and Hanover Compressor Company (Hanover) each accounted for under the
equity method of accounting. The company's investments (not including the
amortization of goodwill) in these entities are as follows:
1996 1995
(Dollars in Thousands)
Ownership
Interest
ADT 27% $596,598 $ -
Hanover 24% 64,166 55,963

The company's equity in earnings of these entities is as follows:

Year Ended December 31 1996 1995
(Dollars in Thousands)

ADT $ 7,236 $ -
Hanover 2,137 33

Summarized combined financial information of ADT and Hanover is presented
below:

As of and for the year ended December 31, 1996(1) 1995(1)
(Dollars in Thousands)

Balance Sheet:
Current assets $ 531,275 $ 43,603
Noncurrent assets 2,295,824 207,316
Current liabilities 433,845 20,333
Noncurrent liabilities 1,493,900 64,390
Equity 899,354 166,196

Income Statement:
Revenues 1,887,180 95,964
Operating expenses 2,559,707 90,350
Net income (loss) (670,326)(2) 5,614
<page54>

(1) Information presented for ADT is based on ADT's quarterly report on Form
10-Q. ADT's balance sheet information and results of operations represent the
twelve months ended September 30, 1996, based on publicly available
information. Hanover's financial information is presented as of November 30,
1996, the most recent information available. The company cannot give any
assurance of the accuracy of the information so obtained.

(2) ADT's net income through September 30, 1996 as reported in its Form 10-Q
for the nine months ended September 30, 1996, includes a one-time charge
related to the adoption of SFAS 121. This charge for approximately $745
million was incurred prior to the company's investment in ADT. The company
cannot give any assurance of the accuracy of the information so obtained.

6. PROPOSED STRATEGIC ALLIANCE

On December 12, 1996, the company and ONEOK Inc. (ONEOK) announced an
agreement to form a strategic alliance combining the natural gas assets of
both companies. Under the agreement for the proposed strategic alliance, the
company will contribute its natural gas business to a new company (New ONEOK)
in exchange for a 45% equity interest. The recorded net property value being
contributed at December 31, 1996 is estimated at $600 million (unaudited). No
gain or loss is expected to be recorded as a result of the proposed
transaction. The proposed transaction is subject to satisfaction of customary
conditions, including approval by ONEOK shareowners and regulatory
authorities. The company is working towards consummation of the transaction
during the second half of 1997.

The structure of the proposed alliance is not expected to have any
immediate income tax consequences to either company or to either company's
shareowners.

7. LEGAL PROCEEDINGS

controlling interest" in ADT and by holding "an effective blocking position"
that prevents independent parties from bidding for ADT. The complaint seeks
preliminary and permanent relief enjoining the company from acquiring the
outstanding shares of ADT and unspecified damages. The company believes it
has good and valid defenses to the claims asserted and does not anticipate any
material adverse effect upon its overall financial condition or results of
operations.

Subject to the approval of the KCC, the company entered into five new
gas supply contracts with certain entities affiliated with The Bishop Group,
Ltd. (Bishop entities) which are currently regulated by the KCC. A contested
hearing was held for the approval of those contracts. While the case was
under consideration by the KCC, the FERC issued an order under which it
extended jurisdiction over the Bishop entities. On November 3, 1995, the KCC
stayed its consideration of the contracts between the company and the Bishop
entities until the FERC takes final appealable action on its assertion of
jurisdiction over the Bishop entities.

As part of the acquisition of WSS on December 31, 1996, WSS assigned to
WestSec, a wholly-owned subsidiary of Westar Capital established to acquire
the assets of WSS, a software license with Innovative Business Systems (IBS)
which is integral to the operation of its security business. On January 8,
1997, IBS filed litigation in Dallas County, Texas in the 298th Judicial
District Court concerning the assignment of the license to WestSec,
(Innovative Business Systems (Overseas) Ltd., and Innovative Business
Software, Inc. v. Westinghouse Electric Corporation, Westinghouse Security
Systems, Inc., WestSec, Inc., Western Resources, Inc., et al., Cause
No. 97-00184). The company and Westar Capital have demanded Westinghouse
Electric Corporation defend and indemnify them. While the loss of use of the
license may have a material impact on the operations of WestSec, management of
the company currently does not believe that the ultimate disposition of this
matter will have a material adverse effect upon the company's overall
financial condition or results of operations

The company and its subsidiaries are involved in various other legal,
environmental, and regulatory proceedings. Management believes that adequate
provision has been made and accordingly believes that the ultimate
dispositions of these matters will not have a material adverse effect upon the
company's overall financial position or results of operations.

8. 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 $69.9 million at December 31, 1996. Approximately
$12.8 million is attributable to modifications to upgrade the three turbines
at Jeffrey Energy Center to be completed by December 31, 1998.

In January 1994, the company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA). Under the agreement, the company received a
prepayment
<page56>

of approximately $41 million for which the company will provide capacity and
transmission services to OMPA through the year 2013.

Manufactured Gas Sites: The company has been associated with 15 former
manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials. The company and the Kansas Department of
Health and Environment (KDHE) entered into a consent agreement governing all
future work at the 15 sites. The terms of the consent agreement will allow
the company to investigate these sites and set remediation priorities based
upon the results of the investigations and risk analyses. The prioritized
sites will be investigated over a ten year period. The agreement will allow
the company to set mutual objectives with the KDHE in order to expedite
effective response activities and to control costs and environmental impact.
The costs incurred for site investigation and risk assessment in 1996 and 1995
were minimal. In accordance with the terms of the ONEOK agreement, ownership
of twelve of the aforementioned sites will be transferred to New ONEOK upon
closing. The ONEOK agreement limits the company's liabilities to an
immaterial amount for future remediation of these sites.

Superfund Sites: The company is one of numerous potentially
responsible parties at a groundwater contamination site in Wichita, Kansas
(Wichita site) which is listed by the EPA as a Superfund site. The company has
previously been associated with other Superfund sites of which the company's
liability has been classified as de minimis and any potential obligations have
been settled at minimal cost. In 1994, the company settled Superfund
obligations at three sites for a total of $57,500. No Superfund obligations have
been settled since 1994. The company's obligation at the Wichita site appears to
be limited based on this experience. In the opinion of the company's
management, the resolution of this matter is not expected to have a material
impact on the company's financial position or results of operations.

Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require
a two-phase reduction in certain emissions. To meet the monitoring and
reporting requirements under the acid rain program, the company has installed
continuous monitoring and reporting equipment at a total cost of approximately
$10 million as of December 31, 1996. The company does not expect material
expenditures to be needed to meet Phase II sulfur dioxide requirements.

The nitrogen oxides(NOx) and toxic limits, which were not set in the
law, were proposed by the EPA in January 1996. The company is currently
evaluating the steps it would need to take in order to comply with the proposed
new rules. The company will have three years from the date the limits were
proposed to comply with the new NOx rules.

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

On August 30, 1996, WCNOC submitted the 1996 Decommissioning Cost Study
to the KCC for approval. Approval of this study was received from the KCC on
February 28, 1997. Based on the study, the company's share of these
decommissioning costs, under the immediate dismantlement method, is estimated
to be approximately $624 million during the period 2025 through 2033, or
approximately $192 million in 1996 dollars. These costs were calculated using
an assumed inflation rate of 3.6% over the remaining service life from 1996 of
29 years.
<page57>

Decommissioning costs are currently being charged to operating expenses
in accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf
Creek. Amounts expensed approximated $3.7 million in 1996 and will increase
annually to $5.6 million in 2024. These expenses are deposited in an external
trust fund. The average after tax expected return on trust assets is 5.7%.
Approval of this funding schedule is still pending with the KCC.

The company's investment in the decommissioning fund, including
reinvested earnings approximated $33.0 million and $25.1 million at December 31,
1996 and December 31, 1995, respectively. Trust fund earnings accumulate in the
fund balance and increase the recorded decommissioning liability. These amounts
are reflected in Investments and Other Property, Decommissioning trust, and
the related liability is included in Deferred Credits and Other Liabilities,
Other, on the Consolidated Balance Sheets.

The staff of the SEC has questioned certain current accounting
practices used by nuclear electric generating station owners regarding the
recognition, measurement, and classification of decommissioning costs for
nuclear electric generating stations. In response to these questions, the
Financial Accounting Standards Board is expected to issue new accounting
standards for removal costs, including decommissioning, in 1997. If current
electric utility industry accounting practices for such decommissioning costs
are changed: (1) annual decommissioning expenses could increase, (2) the
estimated present value of decommissioning costs could be recorded as a
liability rather than as accumulated depreciation, and (3) trust fund income
from the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense. When revised
accounting guidance is issued, the company will also have to evaluate its
effect on accounting for removal costs of other long-lived assets. The company
is not able to predict what effect such changes would have on results of
operations, financial position, or related regulatory practices until the final
issuance of revised accounting guidance, but such effect could be material.

The company carries premature decommissioning insurance which 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 NRC, and to pay for on-site property damages.
This decommissioning insurance will only be available if the insurance funds
are not needed to implement the NRC-approved plan for stabilization and
decontamination.

Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $8.9 billion for a single
nuclear incident. If this liability limitation is insufficient, the U.S.
Congress will consider taking whatever action is necessary to compensate the
public for valid claims. The Wolf Creek owners (Owners) have purchased the
maximum available private insurance of $200 million and the balance is
provided by an assessment plan mandated by the NRC. Under this plan, the
Owners are jointly and severally subject to a retrospective assessment of up
to $79.3 million ($37.3 million, company's share) in the event there is a
major nuclear incident involving any of the nation's licensed reactors. This
assessment is subject to an inflation adjustment based on the Consumer Price
Index and applicable premium taxes. There is a limitation of $10 million
($4.7 million, company's share) in retrospective assessments per incident, per
year.

The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion, company's share). This insurance is provided by a
<page58>

combination of "nuclear insurance pools" ($500 million) and Nuclear Electric
Insurance Limited (NEIL) ($2.3 billion). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination. The company's share of any remaining proceeds can be used
for property damage or premature decommissioning costs up to $1.3 billion
(company's share). Premature decommissioning insurance cost recovery is the
excess of funds previously collected for decommissioning (as discussed under
"Decommissioning").

The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves, and other NEIL resources, the company may be subject to
retrospective assessments under the current policies of approximately $8
million per year.

Although the company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or an
extended outage, the company's insurance coverage may not be adequate to cover
the costs that could result from a catastrophic accident or extended outage at
Wolf Creek. Any substantial losses not covered by insurance, to the extent
not recoverable through rates, would have a material adverse effect on the
company's financial condition and results of operations.

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 and coal. Some of these contracts contain provisions for price
escalation and minimum purchase commitments. At December 31, 1996, WCNOC's
nuclear fuel commitments (company's share) were approximately $15.4 million
for uranium concentrates expiring at various times through 2001, $59.4 million
for enrichment expiring at various times through 2003, and $70.3 million for
fabrication through 2025. At December 31, 1996, the company's coal contract
commitments in 1996 dollars under the remaining terms of the contracts were
approximately $2.6 billion. The largest coal contract expires in 2020, with
the remaining coal contracts expiring at various times through 2013.

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.

Investment Commitments: During 1996, The Wing Group obtained ownership
interests in independent power generation projects under construction in
Turkey and Colombia. The Wing Group or other non-regulated company
subsidiaries are committed to future funding of equity interests in these
projects. In 1997, commitments are not expected to exceed $31 million.
Currently, equity commitments beyond 1997 are approximately $3 million. The
company has also committed $105 million through June of 1998 to power
generation projects in the People's Republic of China.

9. RATE MATTERS AND REGULATION

Utility expenses and credits recognized as regulatory assets and
liabilities on the Consolidated Balance Sheets are recognized in income as the
related amounts are included in service rates and recovered from or refunded
to customers in utility revenues. The company expects to recover the
following regulatory assets in rates:
<page59>

December 31, 1996 1995
(Dollars in Thousands)
Coal contract settlement costs $ 21,037 $ 27,274
Service line replacement 12,921 14,164
Post employment/retirement benefits (See
Note 12) 40,834 35,057
Deferred plant costs 31,272 31,539
Phase-in revenues 26,317 43,861
Debt issuance costs (See Note 1) 78,532 80,354
Deferred cost of gas purchased 21,332 20,318
Other regulatory assets 8,794 9,826
Total regulatory assets $241,039 $262,393

Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KGE 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 and is included in Deferred Charges
and Other Assets, Regulatory assets, on the Consolidated Balance Sheets. The
settlement resulted in the termination of a long-term coal contract. The KCC
permitted KGE to recover this settlement as follows: 76% of the settlement
plus a return over the remaining term of the terminated contract (through
2002) and 24% to be amortized to expense with a deferred return equivalent to
the carrying cost of the asset.

In September 1994, the FERC issued an order allowing the company to
defer $24.5 million in costs associated with the buy-out of a long-term coal
supply contract with American Metal Climax (AMAX) to supply the Lawrence and
Tecumseh Energy Centers. The deferred costs are included in the Deferred
Charges and Other Assets, Regulatory assets, section of the Consolidated Balance
Sheets and are amortized monthly to expense over the life of the original AMAX
contract (through 2013).

Service Line Replacement: 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. As part of the natural gas
distribution rate case settlement on July 11, 1996 (See discussion of natural
gas distribution rate case above), the company was permitted to begin
amortizing these costs in July 1996. Approximately $431,000 will be amortized
each month through June 1999. At December 31, 1996, approximately $12.9
million of these deferrals have been included in Deferred Charges and Other
Assets, Regulatory assets, on the Consolidated Balance Sheets. These
deferrals will become a responsibility of New ONEOK, when the alliance with
ONEOK is consummated.

Deferred Plant Costs: In 1986, KGE recognized the effects of Wolf Creek
related disallowances in accordance with Statement of Financial Accounting
Standards No. 90 "Regulated Enterprises - Accounting for Abandonments and
Disallowances of Plant Costs".

Phase-in Revenues: In 1988, the KCC ordered the accrual of phase-in
revenues to be discontinued by KGE effective December 31, 1988. KGE began
amortizing the phase-in revenue asset on a straight-line basis over 9 l/2
years beginning January 1, 1989. At December 31, 1996, approximately $26
million of deferred phase-in revenues remain to be recovered.

Deferred Cost of Gas Purchased: The company, under rate orders from
the KCC, OCC, and FERC, recovers increases in fuel and natural gas costs through
fuel adjustment clauses for wholesale and certain retail electric customers
and various cost of gas riders (COGR) for natural gas customers. The KCC and
the OCC
<page60>

require the annual difference between actual gas cost incurred and cost
recovered through the application of the COGR be deferred and amortized
through rates in subsequent periods.

KCC Rate Proceedings: On August 17, 1995, the company and KGE filed
three proceedings with the KCC. The first sought a $36 million increase in
revenues from the company's natural gas distribution business. In separate
dockets, the company and KGE filed with the KCC a request to more rapidly
recover KGE's investment in its assets of Wolf Creek over the next seven years
by increasing depreciation by $50 million each year and a request to reduce
annual depreciation expense by approximately $11 million for electric
transmission, distribution and certain generating plant assets to reflect the
useful lives of these properties more accurately. The company sought to reduce
electric rates for KGE customers by approximately $8.7 million annually in each
of the seven years of accelerated Wolf Creek depreciation.

On April 15, 1996, the KCC issued an order allowing a revenue increase
of $33.8 million in the company's natural gas distribution business. On May 3,
1996, the company filed a Petition for Reconsideration and on July 11, 1996,
the KCC issued its Order on Reconsideration allowing the revenue to be
increased to $34.4 million.

On May 23, 1996, the company implemented an $8.7 million electric rate
reduction to KGE customers on an interim basis. On October 22, 1996, the
company, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement with the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC. This
agreement was approved on January 15, 1997. Under the agreement, on February
1, 1997, KGE's rates were reduced by $36.3 million and, in addition, the May
1996 interim reduction became permanent. KGE's rates will be reduced by
another $10 million effective June 1, 1998, and again on June 1, 1999. KPL's
rates were reduced by $10 million effective February 1, 1997. Two one-time
rebates of $5 million will be credited to the company's customers in January
1998 and 1999. The agreement also fixed annual savings from the merger with
KGE at $40 million. This level of merger savings provides for complete
recovery of and a return on the acquisition premium.

On April 15, 1996, the company filed an application with the KCC
requesting an order approving its proposal to merge with KCPL and for other
related relief. On July 29, 1996, the company filed its First Amended
Application with the KCC in its proceeding for approval to merge with KCPL.
The amended application proposed an incentive rate mechanism requiring all
regulated earnings in excess of the merged company's 12.61% return on equity
to be split among customers, shareowners, and additional depreciation on Wolf
Creek.

On November 27, 1996, the KCC issued a Suspension Order and on December
3, 1996, an order was issued which suspended, subject to refund, costs related
to purchases from Kansas Pipeline Partnership included in the company's COGR.
On December 12, 1996, the company filed a Petition for Reconsideration or For
More Definite Statement by Staff of the Issues to be addressed in this Docket.
On March 3, 1997, the Staff issued a More Definite Statement specifying which
charges from Kansas Pipeline Partnership (KPP) it asserts are inappropriate
for inclusion in the company's COGR. The company responded to the More
Definite Statement stating that it does not believe any of the charges from
KPP should be disallowed from its COGR. The company does not expect this
proceeding to have a material adverse effect on its results of operations.
<page61>
MPSC Proceedings: On May 3, 1996, the company filed an application
with the MPSC requesting an order approving its proposal to merge with KCPL.
The application includes the same regulatory plan as proposed before the KCC and
includes an annual rate reduction of $21 million for KCPL retail electric
customers.

FERC Proceedings: On August 22, 1996, the company filed with the FERC
an application for approval of its proposed merger with KCPL. On December 18,
1996, the FERC issued a Merger Policy Statement (Policy Statement) which
articulates three principal factors the FERC will apply for analyzing mergers:
(1) effect on competition, (2) customer protection, and (3) effect on
regulation. The FERC has requested the company to and the company will revise
its filing to comply with the specific requirements of the Policy Statement.

10. INCOME TAXES

Under SFAS 109, temporary differences gave rise to deferred tax assets
and deferred tax liabilities at December 31, 1996 and 1995, respectively, as
follows:

1996 1995
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . $ 99,466 $ 105,007
Alternative minimum tax carryforwards. . 250 18,740
Other. . . . . . . . . . . . . . . . . . 29,945 30,789
Total deferred tax assets. . . . . . . $ 129,661 $ 154,536
Deferred Tax Liabilities:
Accelerated depreciation and other . . . $ 654,102 $ 653,134
Acquisition premium. . . . . . . . . . . 307,242 315,513
Deferred future income taxes . . . . . . 217,257 282,476
Other. . . . . . . . . . . . . . . . . . 61,432 70,883
Total deferred tax liabilities . . . . $1,240,033 $1,322,006
Accumulated deferred
income taxes, net. . . . . . . . . . . . $1,110,372 $1,167,470

In accordance with various rate orders received from the KCC and the OCC,
the company has not yet collected through rates the amounts necessary to pay a
significant portion of the net accumulated deferred income tax liabilities.
As management believes it is probable that the net future increases in income
taxes payable will be recovered from customers, it has recorded a deferred
asset for these amounts. These assets are also a temporary difference for
which deferred income tax liabilities have been provided.

11. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK,
AND OTHER MANDATORILY REDEEMABLE SECURITIES

The company's Restated Articles of Incorporation, as amended, provide
for 85,000,000 authorized shares of common stock. At December 31, 1996,
64,625,259 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 July 1, 1996, all shares of the
company's 8.50% Preference Stock due 2016 were redeemed.

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 $104.55,
$103.79, and $103.03 per share beginning April 1, 1996, 1997, and 1998,
respectively.

Other Mandatorily Redeemable Securities: On December 14, 1995, Western
Resources Capital I, a wholly-owned trust, issued four million preferred
securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series
A, for $100 million. The trust interests represented by the preferred
securities are redeemable at the option of Western Resources Capital I, on or
after December 11, 2000, at $25 per preferred security plus accrued interest
and unpaid dividends. Holders of the securities are entitled to receive
distributions at an annual rate of 7-7/8% of the liquidation preference value
of $25. Distributions are payable quarterly, and in substance are tax
deductible by the company. These distributions are recorded as interest
charges on the Consolidated Statements of Income. The sole asset of the trust
is $103 million principal amount of 7-7/8% Deferrable Interest Subordinated
Debentures, Series A due December 11, 2025 (the Subordinated Debentures).

On July 31, 1996, Western Resources Capital II, a wholly-owned trust,
of which the sole asset is subordinated debentures of the company, sold in a
public offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income
Preferred Securities, Series B, for $120 million. The trust interests
represented by the preferred securities are redeemable at the option of
Western Resources Capital II, on or after July 31, 2001, at $25 per preferred
security plus accumulated and unpaid distributions. Holders of the securities
are entitled to receive distributions at an annual rate of 8-1/2% of the
liquidation preference value of $25. Distributions are payable quarterly, and
in substance are tax deductible by the company. These distributions are
recorded as interest charges on the Consolidated Statements of Income. The
sole asset of the trust is $124 million principal amount of 8-1/2% Deferrable
Interest Subordinated Debentures, Series B due July 31, 2036.

The preferred securities are included under Western Resources obligated
mandatorily redeemable preferred securities of subsidiary trusts holding
solely company subordinated debentures (Other Mandatorily Redeemable
Securities) on the Consolidated Balance Sheets and Consolidated Statements of
Capitalization.

In addition to the company's obligations under the Subordinated
Debentures, the company has agreed, pursuant to guarantees issued to the
trusts, the provisions of the trust agreements establishing the trusts and
related expense agreements, to guarantee, on a subordinated basis, payment of
distributions on the preferred securities (but not if the applicable trust
does not have sufficient funds to pay such distributions) and to pay all of
the expenses of the trusts (collectively, the "Back-up Undertakings").
Considered together, the Back-up Undertakings constitute a full and
unconditional guarantee by the company of the trusts obligations under the
preferred securities.
<page63>

12. EMPLOYEE BENEFIT PLANS

Pension: The company maintains qualified 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.

Salary Continuation: The company maintains a non-qualified Executive
Salary Continuation Program for the benefit of certain management employees,
including executive officers.

The following tables provide information on the components of pension
and salary continuation costs under Statement of Financial Accounting Standards
No. 87 "Employers' Accounting for Pension Plans" (SFAS 87), funded status and
actuarial assumptions for the company:

Year Ended December 31, 1996 1995 1994
(Dollars in Thousands)
SFAS 87 Expense:
Service cost. . . . . . . . . . $ 11,644 $ 11,059 $ 10,197
Interest cost on projected
benefit obligation. . . . . . 34,003 32,416 29,734
(Gain) loss on plan assets. . . (65,799) (102,731) 7,351
Deferred investment gain (loss) 30,119 70,810 (38,457)
Net amortization. . . . . . . . 2,140 1,132 245
Net expense . . . . . . . . $ 12,107 $ 12,686 $ 9,070

December 31, 1996 1995 1994
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $347,734 $331,027 $278,545
Non-vested . . . . . . . . . 23,220 21,775 19,132
Total. . . . . . . . . . . $370,954 $352,802 $297,677
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $495,993 $444,608 $375,521
Projected benefit obligation . . . 483,862 456,707 378,146
Funded status. . . . . . . . . . . 12,131 (12,099) (2,625)
Unrecognized transition asset. . . (448) (527) (2,205)
Unrecognized prior service costs . 62,434 57,087 47,796
Unrecognized net (gain). . . . . . (103,132) (75,312) (56,079)
Accrued liability. . . . . . . . $(29,015) $(30,851) $(13,113)

Year Ended December 31, 1996 1995 1994
Actuarial Assumptions:
Discount rate. . . . . . . . . . 7.5% 7.5% 8.0-8.5%
Annual salary increase rate. . . 4.75% 4.75% 5.0%
Long-term rate of return . . . . 8.5-9.0% 8.5-9.0% 8.0-8.5%

Postretirement: The company follows the provisions of Statement of
Financial Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). This statement
requires the accrual of
<page64>

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, postretirement benefits expenses approximated $16.4 million, $15.0
million, and $12.4 million for 1996, 1995, and 1994, respectively. The
company's total postretirement benefit obligation approximated $123.0 million
and $123.2 million at December 31, 1996 and 1995, respectively. In addition,
the company received an order from the KCC permitting the initial deferral of
SFAS 106 expense in excess of amounts previously recognized. The following
table summarizes the status of the company's postretirement benefit plans for
financial statement purposes and the related amounts included in the
Consolidated Balance Sheets:

December 31, 1996 1995 1994
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . $ 76,588 $ 81,402 $68,570
Active employees fully eligible . 10,060 7,645 13,549
Active employees not fully eligible 36,345 34,144 32,484
Total . . . . . . . . . . . . 122,993 123,191 114,603
Fair value of plan assets . . . . . 78 46 -
Funded status . . . . . . . . . . . (122,915) (123,145) (114,603)
Unrecognized prior service cost . . (8,157) (8,900) ( 9,391)
Unrecognized transition obligation. 104,920 111,443 117,967
Unrecognized net (gain) . . . . . . (8,137) (7,271) ( 14,489)
Accrued postretirement benefit costs $(34,289) $(27,873) $(20,516)

Year Ended December 31, 1996 1995 1994
Actuarial Assumptions:
Discount rate . . . . . . . . . . 7.5 % 7.5 % 8.0-8.5%
Annual salary increase rate . . . 4.75 % 4.75 % 5.0 %
Expected rate of return . . . . . 9.0 % 9.0 % 8.5 %

For measurement purposes, an annual health care cost growth rate of 10%
was assumed for 1996, decreasing one percent per year to five percent in 2001
and thereafter. The health care cost trend rate has a significant effect on
the projected benefit obligation. Increasing the trend rate by one percent
each year would increase the present value of the accumulated projected
benefit obligation by $5.5 million and the aggregate of the service and
interest cost components by $0.5 million.

Postemployment: The company adopted Statement of Financial Accounting
Standards No. 112 "Employers' Accounting for Postemployment Benefits" (SFAS
112) in the first quarter of 1994, which established accounting and reporting
standards for postemployment benefits. The statement requires the company to
recognize the liability to provide postemployment benefits when the liability
has been incurred. The company received an order from the KCC permitting the
initial deferral of SFAS 112 expense.

In accordance with the provision of an order from the KCC, the company
has deferred postretirement and postemployment expenses representing the excess
expense incurred upon adoption of SFAS 106 and SFAS 112. In 1992 and 1993,
the company purchased COLI policies whose associated income stream was
intended to offset actual
<page65>

postretirement and postemployment costs incurred. See Note 1 regarding
legislative action related to COLI. As of December 31, 1996 and 1995, the
company recognized a regulatory asset for postretirement expense of
approximately $31.6 million and $25.3 million and for postemployment expense
of approximately $9.3 million and $9.8 million, respectively.

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 $4.6
million, $5.1 million, and $5.1 million for 1996, 1995, and 1994,
respectively.

Stock Based Compensation Plans: The company has two stock-based
compensation plans, a long term incentive and share award plan (LTISA Plan)
and a long term incentive program (LTI Program). The company accounts for
these plans under Accounting Principles Board Opinion No. 25 and the related
Interpretations. Had compensation cost been determined pursuant to Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS 123), the company would have recognized compensation costs
during 1996 and 1995. However, recognition of the compensation costs would
not have been material to the Consolidated Statements of Income nor would
these costs have affected earnings per share.

The LTISA Plan was implemented to help ensure that managers and board
members (Plan Participants) were properly incented to increase shareowner
value. It was established to replace the company's LTI Program, discussed
below. Under the LTISA Plan, the company may grant awards in the form of
stock options, dividend equivalents, share appreciation rights, restricted
shares, restricted share units, performance shares, and performance share
units to Plan Participants. Up to three million shares of common stock may be
granted under the LTISA Plan.

In 1996, the LTISA Plan granted 205,700 stock options and 205,700
dividend equivalents to Plan Participants. The exercise price of the stock
options granted was $29.25. These options vest in nine years. Accelerated
vesting allows stock options to vest within three years, dependent upon certain
company performance factors. The options expire in approximately ten years.
The weighted-average grant-date fair value of the dividend equivalent was
$5.82. The value of each dividend equivalent is calculated as a percentage of
the accumulated dividends that would have been paid or payable on a share of
company common stock. This percentage ranges from zero to 100%, based upon
certain company performance factors. The dividend equivalents expire after
nine years from the date of grant. All stock options and dividend equivalents
granted were outstanding at December 31, 1996.

The fair value of stock options and dividend equivalents were estimated
on the date of grant using the Black-Scholes option-pricing model. The model
assumed a dividend yield of 6.33%, expected volatility of 14.12%; and an
expected life of 8.7 years. Additionally, the stock option model assumed a
risk-free interest rate of 6.45%. The dividend equivalent model assumed a
risk-free interest rate of 6.61%, an award percentage of 100% and a dividend
accumulation period of five years.

The LTI Program is a performance-based stock plan which awards
performance shares to executive officers (Program Participants) of the company
equal in value to 10% of the officer's annual base compensation. Each
performance share is equal in value to one share of the company's common stock.
Each Program Participant may be entitled to receive a common stock distribution
based on the value of performance shares awarded multiplied by a distribution
percentage not to exceed 110%. This distribution percentage is based upon the
Program Participants' and the company's
<page66>

performance. Program Participants also receive cash equivalent to dividends
on common stock for performance shares awarded.

In 1995, the company granted 14,756 performance shares, with a
weighted-average fair value of $28.81. The fair value of each performance share
is based on market price at the date of grant. No performance shares were
granted in 1996. As of December 31, 1996, shares granted in 1995 have a
remaining contractual life of one year.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Cash and cash equivalents, short-term borrowings and variable-rate debt
are carried at cost which approximates fair value. The decommissioning trust
is recorded at fair value and is based on the quoted market prices at December
31, 1996 and 1995. The fair value of fixed-rate debt, redeemable preference
stock, and other mandatorily redeemable securities is estimated based on
quoted market prices for the same or similar issues or on the current rates
offered for instruments of the same remaining maturities and redemption
provisions. The estimated fair values of contracts related to commodities
have been determined using quoted market prices of the same or similar
securities.

The carrying values and estimated fair values of the company's financial
instruments are as follows:

Carrying Value Fair Value
December 31, 1996 1995 1996 1995
(Dollars in Thousands)

Decommissioning trust. . .$ 33,041 $ 25,070 $ 33,041 $ 25,070
Fixed-rate debt. . . . . . 1,224,743 1,240,877 1,260,722 1,294,365
Redeemable preference
stock. . . . . . . . . . 50,000 150,000 52,500 160,405
Other mandatorily
redeemable securities. . 220,000 100,000 214,800 102,000

December 31, 1996 1995
Notional Notional
Volumes Estimated Gain/ Volumes Estimated Gain/
(mmbtu's) Fair Value (loss) (mmbtu's) Fair Value (loss)
Natural gas
futures 6,540,000 $16,032 $2,061 7,440,000 $16,380 $2,678
Natural gas
swaps 2,344,000 $ 5,500 $1,315 2,624,000 $ 3,406 $ 18

The recorded amount of accounts receivable and other current financial
instruments approximate fair value.

The fair value estimates presented herein are based on information
available as of December 31, 1996 and 1995. These fair value estimates have
not been comprehensively revalued for the purpose of these financial
statements since that date, and current estimates of fair value may differ
significantly from the amounts
<page67>

presented herein. Because a substantial portion of the company's operations
are regulated, the company believes that any gains or losses related to the
retirement of debt or redemption of preferred securities would not have a
material effect on the company's financial position or results of operations.

14. LONG-TERM DEBT

The amount of the company's first mortgage bonds authorized by its
Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited.
The amount of KGE's first mortgage bonds authorized by the KGE 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.

Debt discount and expenses are being amortized over the remaining lives
of each issue. During the years 1997 through 2001, $125 million of bonds will
mature in 1999 and $75 million of bonds will mature in 2000. No other bonds
will mature and there are no cash sinking fund requirements for preference
stock or bonds during this time period.

The company maintains a $350 million revolving credit agreement that
expires on October 5, 1999. Under the terms of this agreement, the company
may, at its option, borrow at different market-based interest rates and is
required, among other restrictions, to maintain a total debt to total
capitalization ratio of not greater than 65% at all times. A facility fee is
paid on the $350 million commitment. The unused portion of the revolving
credit facility may be used to provide support for commercial paper. At
December 31, 1996, the company had $275 million borrowed under the facility
and had available $75 million of unused capacity under the facility.
<page68>

Long-term debt outstanding at December 31, 1996 and 1995, was as follows:

1996 1995
(Dollars in Thousands)
Western Resources
First mortgage bond series:
7 1/4% due 1999. . . . . . . . . . . . . $ 125,000 $ 125,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000
8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000
7.65% due 2023. . . . . . . . . . . . . 100,000 100,000
525,000 525,000
Pollution control bond series:
Variable due 2032 (1). . . . . . . . . . 45,000 45,000
Variable due 2032 (2). . . . . . . . . . 30,500 30,500
6% due 2033. . . . . . . . . . . . . 58,420 58,420
133,920 133,920
KGE
First mortgage bond series:
5 5/8% due 1996. . . . . . . . . . . . . - 16,000
7.60 % due 2003. . . . . . . . . . . . . 135,000 135,000
6 1/2% due 2005. . . . . . . . . . . . . 65,000 65,000
6.20 % due 2006. . . . . . . . . . . . . 100,000 100,000
300,000 316,000
Pollution control bond series:
5.10 % due 2023. . . . . . . . . . . . . 13,822 13,957
Variable due 2027 (3). . . . . . . . . . 21,940 21,940
7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500
Variable due 2032 (4). . . . . . . . . . 14,500 14,500
Variable due 2032 (5). . . . . . . . . . 10,000 10,000
387,762 387,897

Revolving credit agreement . . . . . . . . . 275,000 50,000
Other long-term agreements . . . . . . . . . 65,190 -

Less:
Unamortized debt discount. . . . . . . . 5,289 5,554
Long-term debt due within one year . . . - 16,000
Long-term debt (net). . . . . . . . . . . . $1,681,583 $1,391,263

Rates at December 31, 1996: (1) 3.68%, (2) 3.582%, (3) 3.55%,
(4) 3.60% and (5) 3.52%

15. SHORT-TERM DEBT

The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling $973 million. The
agreements provide the company with the ability to borrow at different
market-based interest rates. The company pays commitment or facility fees in
support of these lines of credit. Under the terms of the agreements, the
company is required, among other restrictions, to maintain a total debt to
total capitalization ratio of not greater than 65% at all times. The unused
portion of these lines of credit are used to provide support for commercial
paper.

In addition, the company has agreements with several banks to borrow on
an uncommitted, as available, basis at money-market rates quoted by the banks.
There
<page69>

are no costs, other than interest, for these agreements. The company also
uses commercial paper to fund its short-term borrowing requirements.

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

December 31, 1996 1995 1994

(Dollars in Thousands)

Borrowings outstanding at year end:
Lines of credit $525,000 $ - $ -
Bank loans 162,300 177,600 151,000
Commercial paper notes 293,440 25,850 157,200
Total $980,740 $203,450 $308,200

Weighted average interest rate on
debt outstanding at year end
(including fees) 5.94% 6.02% 6.25%

Weighted average short-term debt
outstanding during the year $491,136 $301,871 $214,180

Weighted daily average interest
rates during the year
(including fees) 5.72% 6.15% 4.63%

Unused lines of credit supporting
commercial paper notes $447,850 $121,075 $145,000

16. LEASES

At December 31, 1996, the company had leases covering various property
and equipment. The company currently has no capital leases.

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

Operating
Year Ended December 31, Leases
(Dollars in Thousands)
1994 $ 55,076
1995 63,353
1996 66,181
Future Commitments:
1997 60,247
1998 52,643
1999 47,276
2000 43,877
2001 42,592
Thereafter 688,231
Total $ 934,866

In 1987, KGE sold and leased back its 50% undivided interest in the La
Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29
years, with various options to renew the lease or repurchase the 50% undivided
interest. KGE remains responsible for its share of operation and maintenance
costs and other related
<page70>

operating costs of La Cygne 2. The lease is an operating lease for financial
reporting purposes.

As permitted under the La Cygne 2 lease agreement, the company in 1992
requested the Trustee Lessor to refinance $341.1 million of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested
to reduce recurring future net lease expense. In connection with the
refinancing on September 29, 1992, a one-time payment of approximately $27
million was made by the company which has been deferred and is being amortized
over the remaining life of the lease and included in operating expense as part
of the future lease expense. At December 31, 1996, approximately $22.5
million of this deferral remained on the Consolidated Balance Sheets.

Future minimum annual lease payments, included in the table above,
required under the La Cygne 2 lease agreement are approximately $34.6 million
for each year through 2001 and $611 million over the remainder of the lease.

The gain realized at the date of the sale of La Cygne 2 has been
deferred for financial reporting purposes, and is being amortized ($9.7 million
per year) over the initial lease term in proportion to the related lease
expense. KGE's lease expense, net of amortization of the deferred gain and a
one-time payment, was approximately $22.5 million for 1996, 1995, and 1994.

17. JOINT OWNERSHIP OF UTILITY PLANTS

Company's Ownership at December 31, 1996
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 160,541 $ 105,043 343 50
Jeffrey 1 (b) Jul 1978 290,617 121,307 616 84
Jeffrey 2 (b) May 1980 289,944 115,025 617 84
Jeffrey 3 (b) May 1983 389,350 152,579 591 84
Wolf Creek (c) Sep 1985 1,382,000 369,182 547 47

(a) Jointly owned with KCPL
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

Amounts and capacity presented above represent the company's share.
The company's share of operating expenses of the plants in service above, as
well as such expenses for a 50% undivided interest in La Cygne 2 (representing
335 MW capacity) sold and leased back to the company in 1987, are included in
operating expenses on the Consolidated 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.

18. SEGMENTS OF BUSINESS

The company is a public utility principally engaged in the generation,
transmission, distribution, and sale of electricity in Kansas and the
transportation, distribution, and sale of natural gas in Kansas and Oklahoma.
<page71>

Substantially all of the results of operations and financial position
of the natural gas segment will be exchanged for an equity interest in New ONEOK
in the strategic alliance which is expected to close in the second half of
1997. Upon contribution of the natural gas net assets to New ONEOK, the
company will record its equity investment in New ONEOK.

Year Ended December 31, 1996 1995 1994(1)
(Dollars in Thousands)
Operating revenues:
Electric. . . . . . . . . . . $1,197,433 $1,145,895 $1,121,781
Natural gas(2). . . . . . . . 849,386 597,405 642,988
2,046,819 1,743,300 1,764,769
Operating expenses excluding
income taxes:
Electric. . . . . . . . . . . 843,672 788,900 768,317
Natural gas . . . . . . . . . 810,062 584,494 625,780
1,653,734 1,373,394 1,394,097
Income taxes:
Electric. . . . . . . . . . . 84,108 96,719 100,078
Natural gas . . . . . . . . . 4,984 (5,522) (4,456)
89,092 91,197 95,622
Operating income:
Electric. . . . . . . . . . . 269,653 260,245 253,386
Natural gas . . . . . . . . . 34,340 18,464 21,664
$ 303,993 $ 278,709 $ 275,050
Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,379,435 $4,470,359 $4,346,312
Natural gas . . . . . . . . . 769,417 712,858 654,483
Other corporate assets(3) . . 1,498,929 307,460 370,234
$6,647,781 $5,490,677 $5,371,029
Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 152,549 $ 133,452 $ 123,696
Natural gas . . . . . . . . . 31,173 26,833 33,702
183,722 $ 160,285 $ 157,398
Maintenance:
Electric. . . . . . . . . . . $ 81,972 $ 87,942 $ 88,162
Natural gas . . . . . . . . . 17,150 20,699 25,024
$ 99,122 $ 108,641 $ 113,186
Capital expenditures:
Electric. . . . . . . . . . . $ 138,361 $ 153,931 $ 152,384
Nuclear fuel. . . . . . . . . 2,629 28,465 20,590
Natural gas . . . . . . . . . 58,519 54,431 64,722
$ 199,509 $ 236,827 $ 237,696

(1) Information reflects the sales of the Missouri Properties (Note 19).

(2) For the years ended December 31, 1996 and 1995, operating revenues
associated with the natural gas segment include immaterial amounts of revenues
related to operations of non-regulated subsidiaries in non-gas related
businesses.

(3) As of December 31, 1996, this balance principally represents the equity
investment in ADT, security business and other property, non-utility assets
and deferred charges. As of December 31, 1995 and 1994, this balance
represents primarily cash, non-utility assets and deferred charges.
<page72>

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

1994
(Dollars in Thousands, Unaudited)
Natural gas revenues. . . . . . . . . $ 77,008
Operating expenses excluding
income taxes. . . . . . . . 69,114
Income taxes. . . . . . . . . . . . . 2,897
Operating income. . . . . . . . . . . 4,997
Identifiable assets . . . . . . . . . -
Depreciation and amortization . . . . 1,274
Maintenance . . . . . . . . . . . . . 1,099
Capital expenditures. . . . . . . . . 3,682

19. SALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES

1994
Percent
of Total
Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . . . . . . . $ 77,008 4.8%
Operating income. . . . . . . . . . . 4,997 1.9%

20. 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.
<page73>

First Second Third Fourth
(Dollars in Thousands, except Per Share Amounts)
1996
Operating revenues. . . . . . . $555,622 $436,121 $490,172 $564,904
Operating income. . . . . . . . 75,273 59,020 93,587 76,113
Net income. . . . . . . . . . . 44,789 28,746 62,949 32,466
Earnings applicable to
common stock. . . . . . . . . 41,434 25,392 56,049 31,236
Earnings per share. . . . . . . $ 0.66 $ 0.40 $ 0.87 $ 0.48
Dividends per share . . . . . . $ 0.515 $ 0.515 $ 0.515 $ 0.515
Average common shares
outstanding . . . . . . . . . 63,164 63,466 64,161 64,523
Common stock price:
High. . . . . . . . . . . . . $ 34.875 $ 30.75 $ 30.75 $ 31.75
Low . . . . . . . . . . . . . $ 29.25 $ 28.00 $ 28.25 $ 28.625

1995
Operating revenues. . . . . . . $443,375 $372,295 $470,289 $457,341
Operating income. . . . . . . . 69,441 49,891 99,481 59,896
Net income. . . . . . . . . . . 41,575 21,716 71,905 46,480
Earnings applicable to
common stock. . . . . . . . . 38,220 18,362 68,550 43,125
Earnings per share. . . . . . . $ 0.62 $ 0.30 $ 1.10 $ 0.69
Dividends per share . . . . . . $ 0.505 $ 0.505 $ 0.505 $ 0.505
Average common shares
outstanding . . . . . . . . . 61,747 61,886 62,244 62,712
Common stock price:
High. . . . . . . . . . . . . $ 33.375 $ 32.50 $ 32.875 $ 34.00
Low . . . . . . . . . . . . . $ 28.625 $ 30.25 $ 29.75 $ 31.00
<page74>

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 1997 Annual
Meeting of Shareholders to be filed with the SEC. 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 SEC. See EXECUTIVE OFFICERS OF THE COMPANY on page 19 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 1997 Annual Meeting of Shareholders to be
filed with the SEC. 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
SEC.

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 1997 Annual Meeting of Shareholders to be
filed with the SEC. 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 SEC.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.
<page75>

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, 1996 and 1995
Consolidated Statements of Income, for the years ended December 31, 1996,
1995 and 1994
Consolidated Statements of Cash Flows, for the years ended December 31,
1996, 1995 and 1994
Consolidated Statements of Taxes, for the years ended December 31, 1996,
1995 and 1994
Consolidated Statements of Capitalization, December 31, 1996 and
1995
Consolidated Statements of Common Stock Equity, for the years ended
December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements

SCHEDULES

Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, II, III, IV, and V

REPORTS ON FORM 8-K
Form 8-K filed April 15, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 23, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 25, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 26, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 29, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 3, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 6, 1996 - Press release regarding the company's
offer to merge with KCPL.
Forms 8-K filed May 7, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 13, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 24, 1996 - Press release about the company filing
testimony to the electric rate case at the KCC.
Form 8-K filed June 17, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed July 23, 1996 - 6/30/96 earnings release.
Form 8-K filed July 26, 1996 - Press release regarding KCC Staff and
the company reaching agreement in rate case.
Form 8-K filed October 24, 1996 - Press release regarding KCC Staff
and the company reaching an amended agreement in rate case.
<page76>

Form 8-K filed December 18, 1996 - Press release regarding the
company's strategic alliance with ONEOK, including Agreement between the company
and ONEOK dated as of December 12, 1996 and Form of Shareholder Agreement
between New ONEOK and the company.

Form 8-K filed February 10, 1997 - Press release regarding the
company's merger with KCPL, including Agreement and Plan of Merger between the
company and KCPL, dated as of February 7, 1997.

EXHIBIT INDEX

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

Description

3(a) -Agreement and Plan of Merger between the company and KCPL, I
dated as of February 7, 1997. (filed as Exhibit 99.2 to the
February 10, 1997 Form 8-K)
3(b) -Agreement between the company and ONEOK dated as of I
December 12, 1996. (filed as Exhibit 99.2 to the December 12,
1997 Form 8-K)
3(c) -Form of Shareholder Agreement between New ONEOK and the I
company. (filed as Exhibit 99.3 to the December 12, 1997
Form 8-K)
3(d) -Restated Articles of Incorporation of the Company, as amended I
May 7, 1996. (filed as Exhibit 3(a) to June, 1996 Form 10-Q)
3(e) -Restated Articles of Incorporation of the company, as amended I
May 25, 1988. (filed as Exhibit 4 to Registration Statement
No. 33-23022)
3(f) -Certificate of Correction to Restated Articles of Incorporation. I
(filed as Exhibit 3(b) to the December 1991 Form 10-K)
3(g) -Amendment to the Restated Articles of Incorporation, as amended I
May 5, 1992. (filed as Exhibit 3(c) to the December 31, 1995

Form 10-K)
3(h) -Amendments to the Restated Articles of Incorporation of the I
Company (filed as Exhibit 3 to the June 1994 Form 10-Q)
3(i) -By-laws of the Company. (filed as Exhibit 3(e) to the I
December 31, 1995 Form 10-K)
3(j) -Certificate of Designation of Preference Stock, 8.50% Series, I
without par value. (filed as Exhibit 3(d) to the December
1993 Form 10-K)
3(k) -Certificate of Designation of Preference Stock, 7.58% Series, I
without par value. (filed as Exhibit 3(e) to the December
1993 Form 10-K)
4(a) -Deferrable Interest Subordinated Debentures dated November 29, I
1995, between the company and Wilmington Trust Delaware, Trustee
(filed as Exhibit 4(c) to Registration Statement No. 33-63505)
4(b) -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(c) -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(d) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
<page77>

4(e) -Seventeenth Supplemental Indenture dated February 1, 1978. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(f) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(g) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(h) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(i) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)

4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986. I
(filed as Exhibit 4(j) to Registration Statement No. 33-12054)
4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. I
(filed as Exhibit 4(k) to Registration Statement No. 33-21739)
4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)
4(r) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(s) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Registration Statement No. 33-50069)
4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994,
(filed as Exhibit 4(s) to the December 31, 1994 Form 10-K)

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) -Long-term Incentive and Share Award Plan (filed as Exhibit I
10(a) to the June 1996 Form 10-Q)
10(b) -Form of Employment Agreement with officers of the Company I
(filed as Exhibit 10(b) to the June 1996 Form 10-Q)
10(c) -A Rail Transportation Agreement among Burlington Northern I
Railroad Company, the Union Pacific Railroad Company and the
Company (filed as Exhibit 10 to the June 1994 Form 10-Q)
10(d) -Agreement between the Company and AMAX Coal West Inc. I
effective March 31, 1993. (filed as Exhibit 10(a) to the
December 31, 1993 Form 10-K)
10(e) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed as Exhibit 10(b) to the
December 31, 1993 Form 10-K)
10(f) -Letter of Agreement between The Kansas Power and Light Company I
and John E. Hayes, Jr., dated November 20, 1989. (filed as
Exhibit 10(w) to the December 31, 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)
<page78>

10(h) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 31, 1993 Form 10-K)
10(i) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I
December 31, 1993 Form 10-K)
10(j) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 31, 1993 Form 10-K)
10(k) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 31, 1993 Form 10-K)
10(l) -Executive Salary Continuation Plan of Western Resources, Inc., I
as revised, effective September 22, 1995. (filed as Exhibit
10(j)to the December 31, 1995 Form 10-K)
10(m) -Executive Salary Continuation Plan for John E. Hayes, Jr., I
Dated March 15, 1995. (filed as Exhibit 10(k) to the
December 31, 1995 Form 10-K)
10(n) -Stock Purchase Agreement between the company and Laidlaw I
Transportation Inc., dated December 21, 1995. (filed as
Exhibit 10(l) to the December 31, 1995 Form 10-K)
10(o) -Equity Agreement between the company and Laidlaw Transportation I
Inc., dated December 21, 1995. (filed as Exhibit 10(l)1 to the
December 31, 1995 Form 10-K)
10(p) -Letter Agreement between the Company and David C. Wittig, I
dated April 27, 1995. (filed as Exhibit 10(m) to the
December 31, 1995 Form 10-K)
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
21 -Subsidiaries of the Registrant. (filed electronically)
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
(filed electronically)
27 -Financial Data Schedule (filed electronically)
<page79>

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 19, 1997
By /s/ JOHN E. HAYES, JR.

John E. Hayes, Jr., Chairman of the Board
and Chief Executive Officer
<page80>

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,
/s/ JOHN E. HAYES, JR. and Chief Executive Officer March 19,
1997
(John E. Hayes, Jr.) (Principal Executive Officer)

Executive Vice President and
/s/ S. L. KITCHEN Chief Financial Officer March 19,
1997
(S. L. Kitchen) (Principal Financial and
Accounting Officer)

/s/ FRANK J. BECKER
(Frank J. Becker)

/s/ GENE A. BUDIG
(Gene A. Budig)

/s/ C. Q. CHANDLER
(C. Q. Chandler)

/s/ THOMAS R. CLEVENGER
(Thomas R. Clevenger)

/s/ JOHN C. DICUS Directors March 19,
1997
(John C. Dicus)

/s/ DAVID H. HUGHES
(David H. Hughes)

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

/s/ JOHN H. ROBINSON
(John H. Robinson)

/s/ SUSAN M. STANTON
(Susan M. Stanton)

/s/ LOUIS W. SMITH
(Louis W. Smith)

/s/ KENNETH J. WAGNON
(Kenneth J. Wagnon)

/s/ DAVID C. WITTIG
(David C. Wittig)
<page81>

Exhibit 12

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
(Dollars in Thousands)

<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
Net Income. . . . . . . . . . . . . . $168,950 $181,676 $187,447 $177,370 $127,884
Taxes on Income . . . . . . . . . . . 86,102 83,392 99,951 78,755 46,099
Net Income Plus Taxes. . . . . . 255,052 265,068 287,398 256,125 173,983

Fixed Charges:
Interest on Long-Term Debt. . . . . 105,741 95,962 98,483 123,551 117,464
Interest on Other Indebtedness. . . 34,685 27,487 20,139 19,255 20,009
Interest on Other Mandatorily
Redeemable Securities . . . . . . 12,125 372 - - -
Interest on Corporate-owned
Life Insurance Borrowings . . . . 35,151 32,325 26,932 16,252 5,294
Interest Applicable to
Rentals . . . . . . . . . . . . . 32,965 31,650 29,003 28,827 27,429
Total Fixed Charges . . . . . . 220,667 187,796 174,557 187,885 170,196

Preferred and Preference Dividend
Requirements:
Preferred and Preference Dividends. 14,839 13,419 13,418 13,506 12,751
Income Tax Required . . . . . . . . 7,562 6,160 7,155 5,997 4,596
Total Preferred and Preference
Dividend Requirements . . . . . . 22,401 19,579 20,573 19,503 17,347
Total Fixed Charges and Preferred and
Preference Dividend Requirements. . 243,068 207,375 195,130 207,388 187,543

Earnings (1). . . . . . . . . . . . . $475,719 $452,864 $461,955 $444,010 $344,179

Ratio of Earnings to Fixed Charges. . 2.16 2.41 2.65 2.36 2.02

Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements . . . . . . . 1.96 2.18 2.37 2.14 1.84

(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 21

WESTERN RESOURCES, INC.
Subsidiaries of the Registrant

State of Date
Subsidiary Incorporation Incorporated

1) Kansas Gas and Electric Company Kansas October 9, 1990

2) Mid Continent Market Center, Inc. Kansas December 13, 1994

3) Westar Energy, Inc. Kansas April 14, 1995

4) Westar Security, Inc. Kansas April 14, 1995

5) Westar Capital, Inc. Kansas October 8, 1990

6) The Wing Group Limited Co. Delaware February 21, 1996

Exhibit 23

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. 33-49467, 33-49553, 333-02023, 33-50069, and
33-62375 of Western Resources, Inc. on Form S-3; Nos. 333-18097 and 333-02711
of Western Resources, Inc. on Form S-4; Nos. 33-57435, 333-13229, 333-06887,
333-20393, and 333-20413 of Western Resources, Inc. on Kansas Gas and
Electric Company on Form S-3.

ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 24, 1997
(February 7, 1997 with
respect to Note 2 of
the Notes to Consolidated
Financial Statements.)

<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE
SHEET AT DECEMBER 31, 1996 AND THE STATEMENT OF INCOME AND THE STATEMENT OF CASH
FLOWS FOR THE YEAR ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,356,518
<OTHER-PROPERTY-AND-INVEST> 1,207,790
<TOTAL-CURRENT-ASSETS> 494,448
<TOTAL-DEFERRED-CHARGES> 589,025
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6,647,781
<COMMON> 323,126
<CAPITAL-SURPLUS-PAID-IN> 739,433
<RETAINED-EARNINGS> 562,121
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,624,680
50,000
24,858
<LONG-TERM-DEBT-NET> 1,681,583
<SHORT-TERM-NOTES> 687,300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 293,440
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,285,920
<TOT-CAPITALIZATION-AND-LIAB> 6,647,781
<GROSS-OPERATING-REVENUE> 2,046,819
<INCOME-TAX-EXPENSE> 86,102
<OTHER-OPERATING-EXPENSES> 1,653,734
<TOTAL-OPERATING-EXPENSES> 1,742,826
<OPERATING-INCOME-LOSS> 303,993
<OTHER-INCOME-NET> 14,283
<INCOME-BEFORE-INTEREST-EXPEN> 318,276
<TOTAL-INTEREST-EXPENSE> 149,326
<NET-INCOME> 168,950
14,839
<EARNINGS-AVAILABLE-FOR-COMM> 154,111
<COMMON-STOCK-DIVIDENDS> 131,611
<TOTAL-INTEREST-ON-BONDS> 105,741
<CASH-FLOW-OPERATIONS> 275,286
<EPS-PRIMARY> 2.41
<EPS-DILUTED> 0

</TABLE>