<PAGE>
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------

                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                            ------------------------

                                   FORM 10-K

<TABLE>
<C>           <S>
 (MARK ONE)   ANNUAL  REPORT PURSUANT  TO SECTION  13 OR  15(D) OF  THE SECURITIES
    /X/       EXCHANGE ACT OF 1934 [FEE REQUIRED]

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
                                        OR
    / /       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE  SECURITIES
              EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
</TABLE>

       FOR THE TRANSITION PERIOD FROM                 TO

                        COMMISSION FILE NUMBER:  1-3562

                            ------------------------

                             UTILICORP UNITED INC.
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                              <C>
           DELAWARE                 44-0541877
State or other jurisdiction of   (I.R.S. Employer
incorporation or organization     Identification
                                       No.)
</TABLE>

           3000 Commerce Tower, 911 Main, Kansas City, Missouri 64105
                    (Address of principal executive offices)

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (816) 421-6600

          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<TABLE>
<CAPTION>
                    TITLE OF EACH CLASS                               NAME OF EACH EXCHANGE ON WHICH REGISTERED
-----------------------------------------------------------  -----------------------------------------------------------
<S>                                                          <C>
          Common Stock, par value $1.00 per share                   New York, Pacific and Toronto Stock Exchanges
       Preference Stock, no par value, $2.05 Series                            New York Stock Exchange
           Convertible Subordinated Debentures,                                New York Stock Exchange
                  6 5/8%, due July, 2011
  8 7/8% Cumulative Monthly Income Preferred Securities,                       New York Stock Exchange
                Series A, due June 30, 2025
</TABLE>

       SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:  NONE

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

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

    The  aggregate market value of the voting stock held by nonaffiliates of the
registrant on February 12, 1996, was $1,366,366,442.

    Indicate the  number  of shares  outstanding  of each  of  the  registrant's
classes of common stock, as of the latest practicable date.

<TABLE>
<CAPTION>
                        TITLE                                     OUTSTANDING (AT FEBRUARY 12, 1995)
------------------------------------------------------  ------------------------------------------------------
<S>                                                     <C>
Common Stock, par value $1.00 per share                                       46,122,074
--------------------------------------------------------------------------------------------------------------

Documents Incorporated by Reference                                       Where Incorporated
1996 Joint Proxy Statement and Prospectus                                       Part 3
</TABLE>

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>
                                     INDEX

<TABLE>
<CAPTION>
                                                                                                           PAGE NO.
                                                                                                         -------------
<S>                  <C>                                                                                 <C>
PART 1
  Item 1             Business..........................................................................            3
  Item 2             Properties........................................................................           12
  Item 3             Legal Proceedings.................................................................           16
  Item 4             Submission of Matters to a Vote of Security Holders...............................           16

PART 2
  Item 5             Market for Registrant's Common Equity and Related Stockholder Matters.............           17
  Item 6             Selected Financial Data...........................................................           18
  Item 7             Management's Discussion and Analysis of Financial Condition and Results of
                      Operation........................................................................           18
  Item 8             Financial Statements and Supplementary Data.......................................           34
  Item 9             Changes in and Disagreements With Accountants on Accounting and Financial
                      Disclosure.......................................................................           60

PART 3
  Item 10            Directors and Executive Officers of the Registrant................................           60
  Item 11            Executive Compensation............................................................           60
  Item 12            Security Ownership of Certain Beneficial Owners and Management....................           60
  Item 13            Certain Relationships and Related Transactions....................................           60

PART 4
  Item 14            Exhibits, Financial Statements Schedules, and Reports on Form 8-K.................           61

INDEX TO EXHIBITS

SIGNATURES
</TABLE>

                                       2
<PAGE>
                                     PART 1

ITEM 1.  BUSINESS.

    UtiliCorp  United Inc. (the company) is  an energy company which consists of
electric and natural  gas utility operations,  natural gas gathering,  marketing
and  processing  and independent  power projects  managed through  four business
groups. The  business  groups are  UtiliCorp  Energy Delivery  (UED)  consisting
primarily  of transmission and distribution  utility operations, UtiliCorp Power
Services (UPS) consisting  primarily of electricity  generation and  independent
power  projects, UtiliCorp Energy  Resources (UER) consisting  of gas marketing,
processing and  gathering and  electricity  marketing, and  UtiliCorp  Marketing
Services consisting of appliance repair and service contracts, gas marketing and
other  energy related products and services.  The presentation of information in
this report is prepared where  applicable using identified industry segments  as
shown  on page 56 of this Annual Report  on Form 10-K. The company was formed in
1985 under  the laws  of the  State  of Delaware  from Missouri  Public  Service
Company.

    The  company  had  approximately  1.2 million  utility  customers  and 4,700
employees at December 31, 1995. The company's electric utility operations are in
the states  of  Missouri,  Kansas,  Colorado, West  Virginia  and  the  Canadian
province  of British Columbia.  The company's gas utility  operations are in the
states of Missouri,  Kansas, Colorado, Iowa,  Nebraska, Minnesota, Michigan  and
West Virginia. Aquila Energy Corporation (AEC), a wholly-owned subsidiary of the
company,  markets natural gas in 45 states  and Ontario, Canada. AEC's 82% owned
subsidiary Aquila Gas Pipeline  Corporation (AGP) owns  and operates 10  natural
gas  gathering  systems and  four  natural gas  processing  plants in  Texas and
Oklahoma.  The  company  owns  interests  primarily  through  its  UtilCo  Group
subsidiary in 17 independent power projects in seven states and Jamaica.

    The  company has various international  businesses in Australia, Canada, the
United Kingdom  and  New  Zealand.  These businesses  are  managed  through  the
business   groups  as  discussed  in  the  segment  section.  The  international
operations of the company are summarized in the table below.

<TABLE>
<CAPTION>
    COUNTRY                   COMPANY NAME                  OWNERSHIP %                  BUSINESS LINE
----------------  ------------------------------------  --------------------  ------------------------------------
<S>               <C>                                   <C>                   <C>
Australia         UtiliCorp Australia Holding Limited   UtiliCorp owns 100%   Manages United Energy Limited
                   (UAHL)
Australia         Power Partnership Limited (PPL)       UAHL owns 49.9%       Holding company
Australia         United Energy Limited                 PPL owns 100%         Electric distribution utility
Canada            UtiliCorp British Columbia Limited    UtiliCorp owns 100%   Owns West Kootenay Power
                   (UBC)
Canada            West Kootenay Power Limited           UBC owns 100%         Electric utility
United Kingdom    UtiliCorp U.K., Inc. (UKI)            UtiliCorp owns 75%    Holding company
United Kingdom    UtiliCorp U.K., Limited (UKL)         UKI owns 100%         Owns United Gas and minority
                                                                               interests in other U.K. gas
                                                                               marketers
United Kingdom    United Gas Limited                    UKL owns 100%         Gas marketing company
New Zealand       UtiliCorp South Pacific Inc. (USP)    UtiliCorp owns 100%   Holding company
New Zealand       UtiliCorp N.Z., Inc.                  USP owns 79%          Owns minority interests in WEL
                                                                               Energy Ltd. and Power New Zealand
                                                                               Ltd., electric distribution
                                                                               companies
</TABLE>

PROPOSED MERGER WITH KANSAS CITY POWER &AND LIGHT COMPANY (KCPL)

    On January 19,  1996, the company,  KCPL and KC  United Corp. (KCU)  entered
into an Agreement and Plan of Merger (the Merger Agreement) which provides for a
strategic  business combination of the company  and KCPL in a "merger-of-equals"
transaction (the Transaction). Pursuant to the Merger Agreement, the company and
KCPL will merge with and into KCU (which may be renamed at the discretion of the
company and KCPL),  a corporation  formed for  the purpose  of the  Transaction.
Under  the terms  of the  Merger Agreement, each  share of  the company's common
stock will be

                                       3
<PAGE>
exchanged for 1.096 shares  of KCU common  stock and each  share of KCPL  common
stock  will be exchanged for one share of  KCU common stock. Based on the number
of shares of the company's common  stock and KCPL's common stock outstanding  on
the  date  of the  Merger  Agreement, the  company'  s common  shareholders will
receive about 45%  of the common  equity of KCU  and KCPL's common  shareholders
will receive about 55%.

    The  Transaction  is  designed to  qualify  as  a pooling  of  interests for
accounting and financial  reporting purposes. Under  this method of  accounting,
the  recorded assets and  liabilities of the  company and KCPL  would be carried
forward to  the  consolidated financial  statements  of KCU  at  their  recorded
amounts.  The income of KCU would include the combined income of the company and
KCPL as  though the  Transaction occurred  at the  beginning of  the  accounting
period. The Prior periods would be combined and presented as those of KCU.

    The Transaction will create a diversified energy company with total combined
sales  of over $3.5 billion and over $6.5 billion in total assets, serving about
2.5 million customers  in the  United States,  Canada, the  United Kingdom,  New
Zealand,  Australia, China and  Jamaica. The business  of the combined companies
will consist of electric utility operations, gas utility operations and  various
non-utility enterprises including independent power projects, and gas marketing,
gathering and processing operations.

    The  Transaction is subject to approval from each company's shareholders and
a number of regulatory authorities. The regulatory approvals process is expected
to take  about  12 to  18  months.  The Merger  Agreement  includes  termination
provisions  which may require  certain payments to the  party to the Transaction
under  certain  circumstances,  including  a  payment  of  $58  million  if  the
Transaction is terminated by a party and within two and one-half years following
such  termination,  the terminating  party agrees  to consummate  or consummates
certains business combination transactions.

ENERGYONE BRAND/STRATEGY

    In May 1995, the company officially launched the EnergyOne brand.  EnergyOne
is  a unifying  name for  the products  and services  provided to  the company's
customers. Prior  to  the  EnergyOne  brand launch,  the  company  marketed  its
products  and  services  using  the  local  utility  division  name  or separate
subsidiary name.  Now most  company products  and services  carry the  EnergyOne
brand.  EnergyOne is an integral  part of the company's  strategy to bring brand
awareness and value added services to the industry and thereby create a platform
for customer  growth outside  existing service  territories. A  sample of  these
value added services is shown below:

<TABLE>
<CAPTION>
    PRODUCT & SERVICE CATEGORY                   DESCRIPTION                          PRODUCT & SERVICE NAME
-----------------------------------  -----------------------------------  ----------------------------------------------
<S>                                  <C>                                  <C>        <C>
Supply Solutions                     Assessing customers' energy needs        -      AdvisorOneSM Service
                                      and providing customized solutions      -      Fuel and Power Management Services
Utility Solutions                    Helping customers design, finance,       -      Hot SpotSM Service
                                      build and maintain generating           -      Power Services
                                      facilities                              -      Special Utility Services
                                                                              -      Perfect PowerSM Services
Technology & Equipment Solutions     Designing, developing and                -      ProfileOneSM Service
                                      installing emerging and proven          -      Productivity & Efficiency Services
                                      technologies to lower customer                 Environmental Energy Services
                                      energy costs                            -
</TABLE>

    In  addition to developing a new portfolio of products and services in 1995,
the company invested in its  marketing infrastructure and sales organization  to
support and sell EnergyOne products and services.

                                       4
<PAGE>
REGULATION

    The company's consolidated utility businesses are regulated by the following
commissions:

<TABLE>
<CAPTION>
      STATE/JURISDICTION                                  COMMISSION
------------------------------  --------------------------------------------------------------
<S>                             <C>
Kansas                          Kansas Corporation Commission
Michigan                        Michigan Public Service Commission
Missouri                        Public Service Commission of the State of Missouri
Minnesota                       Minnesota Public Utilities Commission
Iowa                            Iowa State Utilities Board
West Virginia                   Public Service Commission of West Virginia
Colorado                        Public Utilities Commission of the State of Colorado
Federal                         Federal Energy Regulatory Commission
British Columbia, Canada        British Columbia Utilities Commission
</TABLE>

    There  is no state regulatory body  in Nebraska. Each municipality served by
the company regulates rates and services.  AGP's pipeline volumes and rates  are
regulated by the Texas Railroad Commission.

    Set out below is a summary of recent rate case activity of the company.

<TABLE>
<CAPTION>
                                                                                      GRANTED
                                              REQUESTED                 -----------------------------------
                                --------------------------------------    AMOUNT
                                   AMOUNT                                   (IN                  EFFECTIVE
JURISDICTION          TYPE      (IN MILLIONS)   % INCREASE     DATE      MILLIONS)   % INCREASE     DATE
----------------  ------------  -------------  ------------  ---------  -----------  ----------  ----------
<S>               <C>           <C>            <C>           <C>        <C>          <C>         <C>
Nebraska          Gas             $     5.2          10.0%        8/95    Pending     Pending     Pending
Michigan          Gas                  10.5           N/A        10/95     "  "         "  "        "  "
Kansas            Gas                   5.1           7.6        12/95     "  "         "  "        "  "
                  Electric
Missouri          Wholesale              .6           N/A        11/95     "  "         "  "        "  "
</TABLE>

ENVIRONMENTAL

    The  company is subject  to various environmental  regulations including air
quality standards and emission limitations,  clean water criteria pertaining  to
certain  facilities  and  the  handling and  disposal  of  hazardous substances.
Compliance with existing regulations, and those which may be promulgated in  the
future,  can  result  in  considerable capital  expenditures  and  operation and
maintenance expense. A discussion  of the environmental  matters of the  company
follows.

MANUFACTURED GAS PLANTS:

    The  company owns or once operated  29 former manufactured gas plants (MGPs)
which may,  or may  not, require  some form  of environmental  remediation.  The
company  has  contacted appropriate  federal and  state agencies  and is  in the
process of determining what, if any,  specific cleanup activities may be  needed
at these sites.

    As  of December 31,  1995, the company has  spent approximately $7.0 million
for investigating and remediating its MGP sites. The company currently estimates
that it will spend a minimum of approximately $6.2 million over the next several
years on  the  company's  identified  MGP  sites.  These  amounts  could  change
materially  based  upon  further investigations,  the  actions  of environmental
agencies and the financial viability of other responsible parties. Additionally,
the ultimate liability  may be  significantly affected  if the  company is  held
responsible for parties not financially able to contribute to these costs. Based
on  prior experience, available facts and existing law, the company has recorded
a liability  of  $6.2  million  representing  its  estimate  of  the  amount  of
environmental costs currently expected to be incurred.

                                       5
<PAGE>
PRICE RISK MANAGEMENT ACTIVITIES

    The  company utilizes certain  types of fixed-price  contracts in connection
with its natural gas, natural gas liquids, and power marketing businesses. These
contracts include contracts that commit the company to purchase or sell  natural
gas  and  other commodities  at fixed  prices in  the future  (i.e., fixed-price
forward purchase and sales contracts),  futures and options contracts traded  on
the  NYMEX and  swaps and  other types  of financial  instruments traded  in the
over-the counter financial markets.

    The availability and use  of these types of  contracts allow the company  to
manage  and hedge  its fixed-price  purchase and  sales commitments,  to provide
fixed-price commitments as a service to its customers and suppliers (i.e., price
risk intermediation services), to reduce its exposure relative to the volatility
of cash  market  prices,  to  take advantage  of  carefully  selected  arbitrage
opportunities  through open positions  and to protect  its investment in storage
inventories. In addition,  by utilizing exchange  for physical transactions,  or
EFP's,  allowed by the NYMEX,  which enable the company  to take delivery of, or
sell, a physical quantity of natural gas in exchange for a futures position, the
company is able to secure additional sources of physical natural gas supply,  or
create  additional markets for  existing supply, through the  use of natural gas
futures contracts. The  company's domestic  natural gas  trading activities  are
referred  to herein as price risk management activities and are reflected in the
accompanying financial statements using the mark-to-market method of accounting.
The company's  foreign  gas marketing,  domestic  non-trading gas,  natural  gas
liquids and power marketing businesses are accounted for on the accrual method.

    Although  the company generally attempts to balance its fixed-price physical
and financial purchase and sales contracts in terms of contract volumes and  the
timing  of performance and delivery obligations,  net open positions often exist
or are established due  to the origination of  new transactions and the  company
assessment  of, and response  to, changing market  conditions. Additionally, the
company will at times create a net open position or allow a net open position to
continue when it believes,  based upon competitive  information gained from  its
energy marketing activities, that future price movements will be consistent with
its  net open position. To the extent that  the company has a net open position,
company is exposed  to the  risk that  fluctuating market  prices may  adversely
impact its financial position or results of operations.

    In addition to the risk associated with price movements, credit risk is also
inherent in the company's risk management activities. Credit risk relates to the
risk  of  loss  resulting  from  the nonperformance  of  a  counterparty  of its
contractual obligations. The  company maintains credit  policies with regard  to
its  counterparties  that the  company  believes significantly  minimize overall
credit  risk.  These   policies  include  the   thorough  review  of   potential
counterparties'  financial  condition,  collateral  requirements  under  certain
circumstances, monitoring of net  exposure to each counterparty  and the use  of
standardized  agreements which  allow for the  netting of  positive and negative
exposures associated with each counterparty.

COMPETITION

DOMESTIC UTILITY OPERATIONS:

    ELECTRIC

    The electric industry  has increasingly become  more competitive as  federal
and  state regulators and legislators continue taking steps toward deregulation.
The anticipation of reduced regulation  triggered some dramatic events in  1995.
Five   major  utility  mergers  were  announced,  including  three  that  affect
competitors close  to  or  next  to the  company's  service  territories.  Other
utilities have implemented cost reduction programs and organizational changes in
preparation  for greater competition. The company began looking at its strengths
and opportunities in respect to future increased competition two years ago  when
the company brought together approximately 100 employees from around the company
to  work on  a strategic  plan that  would be  the foundation  to reposition and

                                       6
<PAGE>
reshape the company.  In 1995  the company began  centralizing business  support
functions  that previously were performed  separately in the operating divisions
and building  its resources  and  capacity to  take advantage  of  opportunities
brought about as competition increases.

    The  company currently  accounts for the  economic effects  of regulation in
accordance with the  provisions of Statement  of Financial Accounting  Standards
(SFAS)  No. 71 "Accounting for the Effects  of Certain Types of Regulation," and
accordingly has recorded  certain costs  as regulatory assets  in the  financial
statements.  The company  expects that  its rates will  continue to  be based on
historical costs  for  the  foreseeable  future.  If  the  company  discontinued
applying  SFAS No. 71, it  would be required to  make adjustment to the carrying
value of certain assets.

    GAS

    The competitive forces affecting the company's electric operations are  also
affecting  the  company's gas  operations.  In addition,  as  competing electric
utilities reduce costs it becomes more difficult to obtain new customers through
fuel switching opportunities and in certain cases the increased competition  may
result in customer losses. The Federal Energy Regulatory Commission (FERC) Order
636  shifted  gas  supply  responsibilities  from  traditional  pipeline company
sources to distribution utilities and  allows customers to bypass the  company's
system  by directly  connecting to  a transportation  pipeline. The  company has
addressed increased competition and industry changes in several ways. First, the
company's natural  gas  is  priced competitively  in  the  company's  respective
service  territories relative to alternative energy sources. Second, the company
established in  1993  a  central  gas  procurement  function  designed  to  take
advantage  of opportunities created by FERC Order 636. Besides offering low cost
natural gas, the company offers its  customers a wide range of energy  solutions
to meet customer demands.

ENERGY RELATED:

    Energy related businesses consist of the two business units of Aquila Energy
Corporation (AEC). AEC has many competitors in the markets its serves, including
other marketing companies, gas pipelines, distribution companies and alternative
fuels.  AEC's ability  to compete successfully  and grow in  this environment is
contingent upon performance and pricing of the natural gas markets.

SEASONAL VARIATIONS OF BUSINESS

    The company's utility and independent  power project businesses are  weather
sensitive.  The company  has both  summer and  winter peaking  utility assets to
reduce dependence on a single peak season. The table below shows peak times  for
its consolidated utility businesses.

<TABLE>
<CAPTION>
            JURISDICTION                              PEAK
------------------------------------  ------------------------------------
<S>                                   <C>
Gas utility operations                November through March
Missouri electric                     July and August
Kansas electric                       July and August
Colorado electric                     July and August
West Virginia electric                November through March
British Columbia, Canada electric     November through March
</TABLE>

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS

    Segment  information for the three years  ended December 31, 1995 appears on
page 56.

                                       7
<PAGE>
I.  ELECTRIC OPERATING STATISTICS

    The following  table  summarizes the  sales,  volume and  customers  of  the
company's electric transmission and distribution businesses.

<TABLE>
<CAPTION>
                                                           1995       1994       1993       1992       1991
                                                         ---------  ---------  ---------  ---------  ---------
<S>                                                      <C>        <C>        <C>        <C>        <C>
Sales (in millions)
  Residential..........................................  $   252.4  $   245.8  $   236.8  $   212.5  $   173.6
  Commercial...........................................      161.1      157.3      156.2      148.3      102.0
  Industrial...........................................       77.3       75.1       76.0       73.3       46.4
  Other................................................       86.9       78.8       77.9       73.7       57.4
                                                         ---------  ---------  ---------  ---------  ---------
    Total..............................................  $   577.7  $   557.0  $   546.9  $   507.8  $   379.4
                                                         ---------  ---------  ---------  ---------  ---------
                                                         ---------  ---------  ---------  ---------  ---------
Volumes (MWH)
  Residential..........................................      3,678      3,512      3,536      3,176      2,735
  Commercial...........................................      2,676      2,611      2,528      2,367      1,672
  Industrial...........................................      1,927      1,897      1,921      1,800      1,197
  Other................................................      2,264      2,099      1,939      1,748      1,468
                                                         ---------  ---------  ---------  ---------  ---------
    Total..............................................     10,545     10,119      9,924      9,091      7,072
                                                         ---------  ---------  ---------  ---------  ---------
                                                         ---------  ---------  ---------  ---------  ---------
Customers
  Residential..........................................    374,701    367,943    360,429    354,086    346,434
  Commercial...........................................     55,266     54,444     53,475     52,748     51,765
  Industrial...........................................        324        321        302        301        302
  Other................................................      4,575      3,706      3,678      3,691      3,634
                                                         ---------  ---------  ---------  ---------  ---------
    Total..............................................    434,866    426,414    417,884    410,826    402,135
                                                         ---------  ---------  ---------  ---------  ---------
                                                         ---------  ---------  ---------  ---------  ---------
</TABLE>

    The  company  has electric  operations in  the  states of  Missouri, Kansas,
Colorado and  West  Virginia and  in  British Columbia,  Canada.  The  company's
generation  facilities are  outlined on page  13. The following  table shows the
overall fuel and purchased  power mix, and system  capability for the past  five
years.

<TABLE>
<CAPTION>
SOURCE                                                                   1995       1994       1993       1992       1991
---------------------------------------------------------------------  ---------  ---------  ---------  ---------  ---------
                                                                                               (MW)
<S>                                                                    <C>        <C>        <C>        <C>        <C>
Coal.................................................................        875        868        864        863        858
Hydro................................................................        205        205        205        206        206
Gas & Oil............................................................        705        705        700        716        723
                                                                       ---------  ---------  ---------  ---------  ---------
  Total generation...................................................      1,785      1,778      1,769      1,785      1,787
Purchased power......................................................        885        904        840        820        694
                                                                       ---------  ---------  ---------  ---------  ---------
Total system capacity................................................      2,670      2,682      2,609      2,605      2,481
                                                                       ---------  ---------  ---------  ---------  ---------
                                                                       ---------  ---------  ---------  ---------  ---------
</TABLE>

    Changes  in fuel cost are recovered through various fuel recovery mechanisms
in Kansas and  West Virginia.  Changes in fuel  cost in  Missouri, Colorado  and
British Columbia are generally absorbed.

                                       8
<PAGE>
II.  GAS OPERATING STATISTICS

    The  following  table  summarizes the  sales,  volume and  customers  of the
company's gas distribution businesses.

<TABLE>
<CAPTION>
                                                     1995         1994         1993         1992         1991
                                                  -----------  -----------  -----------  -----------  -----------
<S>                                               <C>          <C>          <C>          <C>          <C>
Sales (in millions)
  Residential...................................  $     362.2  $     356.4  $     380.2  $     276.0  $     257.6
  Commercial....................................        153.9        156.9        177.5        130.0        118.8
  Industrial....................................         45.8         66.7         89.8         76.4         90.9
  Other.........................................         54.9         38.6         38.6         33.3         28.7
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................  $     616.8  $     618.6  $     686.1  $     515.7  $     496.0
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Volumes (MCF)
  Residential...................................       76,461       71,208       74,421       58,095       56,383
  Commercial....................................       37,282       35,952       40,232       32,239       30,861
  Industrial....................................       12,901       18,439       26,868       23,841       30,908
  Transportation................................      178,114      135,924      115,877      112,831      108,044
  Other.........................................        1,827        2,420        3,672        2,683        1,928
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................      306,585      263,943      261,070      229,689      228,124
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Customers
  Residential...................................      713,586      698,156      661,930      535,058      519,149
  Commercial....................................       76,430       76,015       73,365       60,054       58,299
  Industrial....................................        3,790        3,878        3,874        3,622        3,666
  Other.........................................        2,815        1,581        1,185          582          539
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................      796,621      779,630      740,354      599,316      581,653
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
</TABLE>

    The company's  gas  operations are  primarily  in the  states  of  Missouri,
Kansas,  Colorado, Nebraska, Iowa, Minnesota, Michigan and West Virginia. Except
for its West  Virginia operations, the  company procures natural  gas through  a
central  gas supply department located in Omaha, Nebraska. For West Virginia the
company procures  its  gas relying  on  local  supplies fed  directly  into  its
distribution system and the spot market.

III.  ENERGY RELATED OPERATING STATISTICS

    A description of AEC's segments is presented below.

    A.  WHOLESALE ENERGY MARKETING

    AEC's wholesale energy marketing business is conducted through Aquila Energy
Marketing and Aquila Gas Pipeline Corporation (AGP), collectively referred to as
Energy  Marketing. Energy Marketing is a gas marketing company with a marketing,
supply and transportation network consisting  of relations with more than  1,000
gas  producers and 500 local distribution companies and end-users throughout the
United States and  in Mexico and  Canada. Through more  than 350  transportation
agreements,  it has over 17,500 gas receiving and delivery points available on a
network of 33 pipelines.  For the five  years in the  period ended December  31,
1995,  Energy Marketing had marketing volumes  of 1,427, 1,002, 1,381, 1,589 and
1,003 MMcf/d, respectively.

    In 1995, Energy Marketing began  selling electricity to wholesale and  other
end  users  similarly  to how  it  markets  natural gas.  AEC  expects  that the
electricity marketing  industry  will  expand  rapidly  as  electricity  futures
trading  is  developed  and  the  infrastructure  of  this  industry  segment is
established. In  1995  its  wholesale  power sales  totaled  more  than  135,000
megawatt hours, ranking it among the nation's 10 largest power marketers.

                                       9
<PAGE>
    B.  GAS GATHERING AND PROCESSING

    AEC  through AGP gathers and processes  natural gas and natural gas liquids.
AGP owns and  operates a  3,311-mile intrastate gas  transmission and  gathering
network  and four processing  plants that extract and  sell natural gas liquids.
Key operating statistics for AGP are presented in the table below.

<TABLE>
<CAPTION>
                                                               1995       1994       1993       1992       1991
                                                             ---------  ---------  ---------  ---------  ---------
<S>                                                          <C>        <C>        <C>        <C>        <C>
Natural gas throughput (MMcf/d)............................        507        372        329        285        142
Natural gas liquids produced (000's barrels/d).............         32         31         31         24          7
Pipeline miles operated....................................      3,311      2,718      2,531      2,014      1,262
</TABLE>

    In October 1993, 18% of  AGP, or 5.4 million common  shares was sold to  the
public  in an  initial public offering.  The offering resulted  in a non-taxable
$47.8 million gain.

    C.  OIL AND GAS PRODUCTION

    On September 27,  1995, substantially  all of  AEC's oil  and gas  producing
properties were sold to another company for $205 million which approximates book
value.

IV.  OTHER BUSINESSES AND EQUITY INVESTMENTS

    A.  AUSTRALIA

    On  September 6, 1995, PPL, of which the company owns 49.9 percent, acquired
United Energy Limited  (UE), an Australian  electric distribution utility,  from
the  State of Victoria for approximately  $1.15 billion. The company's ownership
interest   cost   approximately   $257.9   million   and   was   financed   with
Australian-dollar-denominated bank debt through a consortium of banks.

    UAHL  manages UE on behalf of PPL for a fixed fee plus direct expenses and a
variable fee based on  UE's profitability. UAHL's  management contract with  PPL
has a term of 10 years.

    UE  has approximately 520,000 customers and sales volume of 6,393 MWHs. UAHL
accounts for its ownership interest in PPL by the equity method. As of  December
31, 1995, UAHL's investment in PPL was approximately $257.9 million.

    B.  NEW ZEALAND

    The company has equity investments in two electric distribution utilities in
New  Zealand.  The  company  through UtiliCorp  N.Z.,  Inc.  (UNZ),  a 79%-owned
subsidiary, owns 39% of WEL  Energy Group Limited (WEL)  and 27.5% of Power  New
Zealand Limited (PNZ). PNZ is New Zealand's second largest electric distribution
utility  with  approximately  214,000 customers.  WEL  has  approximately 65,000
customers.  On  November  30,  1995,  UNZ  concluded  a  transaction  with  Todd
Corporation  whereby Todd sold its shares in  PNZ to UNZ for $69.4 million. Todd
Corporation is a  21% shareholder in  UNZ. UNZ's  investment in PNZ  and WEL  at
December 31, 1995, was $107.1 million and $39.1 million, respectively.

    In  February 1995, UNZ  paid $16.1 million  to WEL to  fully pay its capital
commitment to WEL. UNZ now participates in WEL's earnings to the full extent  of
its  ownership. Prior to the remaining capital call payment, UNZ's participation
in WEL's earnings was limited to 5%.

    C.  UNITED KINGDOM

    The company  has various  natural  gas marketing  operations in  the  United
Kingdom  through subsidiaries and equity  interests. The company's principal gas
marketing operations are conducted through United Gas Limited, a subsidiary that
markets natural gas to wholesale and industrial customers. The company also  has
25%  ownership interests in five  marketing joint ventures. See  pages 27 and 54
for more information on the United Kingdom operations.

    D.  UTILCO GROUP

    UtilCo Group invests in various  independent power projects. UtilCo  Group's
strategy includes investing in projects that are geographically diverse and that
use a variety of traditional fuels and

                                       10
<PAGE>
proven generation technologies. UtilCo Group has 17 projects in seven states and
has  committed  to invest  in a  project in  Jamaica. UtilCo  Group's generating
projects have an aggregate capacity of 873 MW.

    In May  1995,  UtilCo  Group and  the  company  acquired an  interest  in  a
co-generation  plant that sells its output to  a paper and pulp plant in Alabama
for $59 million.

    In October 1995, UtilCo  Group entered into a  joint venture agreement  with
Air  Products  and  Chemicals,  Inc. to  develop,  own,  and  operate generation
projects. The projects will consist of gas fired combustion turbine applications
throughout 16 states in the Midwest.

EXECUTIVE OFFICERS OF THE REGISTRANT

<TABLE>
<CAPTION>
           EXECUTIVE OFFICER                                     PROFESSIONAL EXPERIENCE
---------------------------------------  ------------------------------------------------------------------------
<S>                                      <C>
Richard C. Green, Jr.                    TITLES: Chairman of the Board of Directors, and Chief Executive Officer
                                         AGE: 41
                                         5-YEAR HISTORY: Chairman of the Board of Directors since February 1989
                                          and Chief Executive Officer since May 1985. Mr. Green previously was
                                          also President from May 1985 to February 1996.

Robert K. Green                          TITLES: President of the company and Chairman of the Board of Directors
                                          and Chief Executive Officer of United Energy Limited
                                         AGE: 34
                                         5-YEAR HISTORY: President since February 1996. Executive Vice President
                                          from January 1993 to February 1996. Prior to January 1993, Mr. Green
                                          was President of the Missouri Public Service division between 1993 and
                                          1991. Between 1991 and 1989 Mr. Green held various division officer
                                          positions with Missouri Public Service.

B. C. Burgess                            TITLE: Senior Vice President, Marketing Services
                                         AGE: 50
                                         5-YEAR HISTORY: In present position since September 1994. Vice President
                                          of the company from January 1994 to September 1994. Prior to January
                                          1994, Mr. Burgess was employed by Bell Atlantic Corporation as a Vice
                                          President between 1994 and 1993 and was employed as a Vice President
                                          between 1993 and 1990 with Sprint Corporation.

Charles K. Dempster                      TITLE: Chairman of the Board of Directors and Chief Executive Officer of
                                          UtiliCorp U.K., Inc.
                                         AGE: 53
                                         5-YEAR HISTORY: In present position since November 1995. Before current
                                          position Mr. Dempster was Vice President, Energy Resources from
                                          September 1994. From December 1995 to January 1993, Mr. Dempster was
                                          President of Aquila Energy Corporation, a subsidiary of the company.
                                          Prior to being employed by the company, Mr. Dempster was President of
                                          Reliance Pipeline Company since 1987.
</TABLE>

                                       11
<PAGE>
<TABLE>
<CAPTION>
           EXECUTIVE OFFICER                                     PROFESSIONAL EXPERIENCE
---------------------------------------  ------------------------------------------------------------------------
<S>                                      <C>
James G. Miller                          TITLE: Senior Vice President, Energy Delivery
                                         AGE: 47
                                         5-YEAR HISTORY: In present position since September 1994. Prior
                                          positions included various division President posts from 1983.

Harvey J. Padewer                        TITLE: Senior Vice President, Energy Resources and Power Services and
                                          President of Aquita Energy Corporation.
                                         AGE:
                                         5-YEAR HISTORY: Present position since January 1996. From May 1995, Mr.
                                          Padewer was Vice President, Power Services. Prior to being employed by
                                          the company Mr. Padewer was employed by Asea Brown Boveri Power
                                          Generation, Inc., at various officer level positions for over five
                                          years.

James S. Brook                           TITLE: Vice President (Principal Accounting Officer)
                                         AGE: 45
                                         5-YEAR HISTORY: Present position since November 1993. Prior to current
                                          position, Mr. Brook held various Vice President positions at Missouri
                                          Public Service and West Kootenay Power since 1980.

Dale J. Wolf                             TITLE: Vice President Finance, Treasurer and Corporate Secretary
                                          (Principal Financial Officer)
                                         AGE: 56
                                         5-YEAR HISTORY: Held present position for 6 years. Prior position was
                                          Vice President, Finance and Treasurer for four years.
</TABLE>

    All officers are elected annually  by the Board of  Directors for a term  of
one  year. Robert K. Green is the brother  of Richard C. Green, Jr., and Avis G.
Tucker, Director, is the aunt of Richard C. Green, Jr. and Robert K. Green.

ITEM 2.  PROPERTIES.

    The company owns electric production, transmission and distribution  systems
and   gas  transmission   and  distribution   systems  throughout   its  service
territories. The  company  also  owns gas  gathering,  processing  and  pipeline
systems.  Substantially all utility plant assets in Michigan are mortgaged under
terms pursuant to an Indenture of Mortgage and Deed of Trust dated July 1, 1951,
as supplemented. Substantially all  of the company's  Canadian utility plant  is
mortgaged under terms pursuant to a separate indenture.

                                       12
<PAGE>
I.  UTILITY FACILITIES

    The  company's electric generation facilities, as  of December 31, 1995, are
as follows:

<TABLE>
<CAPTION>
                                                                                 UNIT
                                                                 YEAR         CAPABILITY                  NET
           UNIT                       LOCATION                INSTALLED        (KW NET)      FUEL     GENERATION
--------------------------  ----------------------------  ------------------  -----------  ---------  -----------
<S>                         <C>                           <C>                 <C>          <C>        <C>
MISSOURI
Sibley #1                   Sibley                               1960              52,400    Coal         278,606
Sibley #2                   Sibley                               1962              52,400    Coal         269,358
Sibley #3                   Sibley                               1969             387,900    Coal       1,993,865
Ralph Green #3              Pleasant Hill                        1981              60,100     Gas          22,433
Nevada #1                   Nevada                               1974              18,600     Oil              70
Greenwood #1                Greenwood                            1975              46,100     Oil           1,621
Greenwood #2                Greenwood                            1975              44,200     Oil           2,462
Greenwood #3                Greenwood                            1977              47,200     Oil           3,648
Greenwood #4                Greenwood                            1979              45,700     Oil           4,328
KCI #1                      Platte County                        1970              12,600     Gas           1,202
KCI #2                      Platte County                        1970              12,600     Gas           1,573
KANSAS
Judson Large #4             Dodge City                           1969             137,000   Gas/Oil       326,600
Arthur Mullergren #3        Great Bend                           1963              92,000   Gas/Oil       217,036
Cimarron River #1           Liberal                              1963              58,000     Gas          50,548
Cimarron River #2           Liberal                              1967              14,000     Gas             720
Clifton #1                  Clifton                              1974              71,000     Gas
Clifton #2                  Clifton                              1974               2,500     Oil          23,935
Jeffrey #1                  Pottawatomie County                  1978             111,600    Coal         573,544
Jeffrey #2                  Pottawatomie County                  1980             117,600    Coal         789,712
Jeffrey #3                  Pottawatomie County                  1983             112,000    Coal         738,536
COLORADO
W.N. Clark #1               Canon City                           1955              16,580    Coal         101,960
W.N. Clark #2               Canon City                           1959              29,110    Coal         139,444
Pueblo #6                   Pueblo                               1949              19,000   Gas/Oil        54,573
Diesel #'s 1,2,3,4,5        Pueblo                               1964              10,000     Oil
Diesel #'s 1,2,3,4,5        Rocky Ford                           1964              10,000     Oil
CANADA
No. 1                       Lower Bonnington, BC                 1925              41,400    Hydro        331,084
No. 2                       Upper Bonnington, BC            1907/1916/1940         59,400    Hydro        413,827
No. 3                       South Slocan, BC                     1928              53,200    Hydro        423,633
No. 4                       Corra Linn, BC                       1932              51,300    Hydro        339,679
                                                                              -----------             -----------
TOTAL                                                                           1,785,490               7,103,997
                                                                              -----------             -----------
                                                                              -----------             -----------
</TABLE>

                                       13
<PAGE>
    At December 31, 1995, the company had transmission and distribution lines as
follows:

<TABLE>
<CAPTION>
                                                              LENGTH
VOLTAGE                                                    (POLE MILES)
-------------------------------------------------------  -----------------
<S>                                                      <C>
345 KV.................................................             58
230 KV.................................................            276
161 KV.................................................            624
138 KV.................................................             74
115 KV.................................................            924
69 KV..................................................          1,393
34.5 KV................................................          1,860
Less than 34.5 KV......................................             --
Overhead distribution lines............................         16,403
Underground distribution lines.........................          2,509
</TABLE>

    At December 31,  1995, the company  owned substations aggregating  9,562,993
KVA.

    At  December 31, 1995, the company's  gas utility operations had 3,188 miles
of gas gathering  and transmission  pipelines and 20,406  miles of  distribution
mains and service lines located throughout its service territories.

II.  GAS PROCESSING AND GATHERING ASSETS

    AGP  owns or  has an  interest in  14 natural  gas pipeline  systems with an
aggregate length of approximately  3,311 miles. These pipelines  do not form  an
interconnected  system. Set  forth below  is information  with respect  to AGP's
pipeline systems as of December 31, 1995:

<TABLE>
<CAPTION>
                                                                                              GAS
                                                                                          THROUGHPUT    AVG. DAILY GAS
                                                                                           CAPACITY       THROUGHPUT
                                                                             MILES OF      (MMCF/D)        (MMCF/D)
GATHERING SYSTEMS                                            LOCATION       PIPELINE (1)      (1)             (2)
------------------------------------------------------  ------------------  -----------  -------------  ---------------
<S>                                                     <C>                 <C>          <C>            <C>
Southeast Texas Pipeline System (SETPS)...............       SE Texas            2,138           710             427
Mentone...............................................       W. Texas               13            60              --
Gomez.................................................       W. Texas               11            40               1
Menard County.........................................       W. Texas              118            30               4
Maverick County.......................................       W. Texas              118            20               3
Rhoda Walker..........................................       W. Texas               21            20               6
Panola County.........................................       E. Texas               24             8               1
Elk City..............................................     SW Oklahoma             154           115              73
Mooreland.............................................     NW Oklahoma             313            40              16
Tristar entities:
  Borado-40%..........................................       S. Texas               57            40              18
  Warwink-35%.........................................       W. Texas               44           100              22
  Benedum/Wilshire-5%.................................       W. Texas              204           125               4
Brooks-Hidalgo........................................       S. Texas               96            75               9
                                                                                 -----         -----             ---
                                                                                 3,311         1,383             584
Fuel and Shrinkage....................................                                            --             (78)
                                                                                 -----         -----             ---
Total.................................................                           3,311         1,383             506
                                                                                 -----         -----             ---
                                                                                 -----         -----             ---
</TABLE>

------------------------
(1) All capacity,  volume  and  mileage  information  is  approximate.  Capacity
    figures  are  management's estimates  based  on existing  facilities without
    regard to the present availability of natural gas.

(2) Excludes off-system sales with average daily volumes of 360 MMcf/d sold from
    other companies' facilities.

                                       14
<PAGE>
    AGP  owns or has an interest in 4 natural gas processing and treating plants
with aggregate  gas  throughput capacity  of  495  MMcf/d. Set  forth  below  is
information about AGP's processing plants as of December 31, 1995.

<TABLE>
<CAPTION>
                                                                                        NATURAL GAS
                                               GAS THROUGHPUT                             LIQUIDS
PLANT                                             CAPACITY          GAS THROUGHPUT      PRODUCTION       GATHERING SYSTEM
-------------------------------------------  -------------------  -------------------  -------------  ----------------------
<S>                                          <C>                  <C>                  <C>            <C>
La Grange, Texas...........................             230                  213              23.0    SETPS
Somerville, Texas..........................              25                   27               2.9    SETPS
Katy, Texas (3)............................              --                   55               2.3    SETPS
Bendum Plant-5%............................             125                    4                --    Benedum/Wilshire
Elk City, Oklahoma.........................             115                   73               3.4    Elk City
                                                        ---                  ---               ---
Total......................................             495                  372              31.6
                                                        ---                  ---               ---
                                                        ---                  ---               ---
</TABLE>

------------------------

(1)  All capacity  and volume information  is approximate.  Capacity figures are
    management's estimates based  on existing facilities  without regard to  the
    present availability of natural gas.

(2) Volumes from joint venture have been included at the AGP ownership interest.

(3)  This  plant is  owned and  operated by  a  third party  from which  the AGP
    receives a portion of  the NGLs produced  from gas the  AGP delivers to  the
    plant.

    The availability of natural gas reserves to AGP depends on their development
in  the  area served  by  its pipelines  and on  AGP's  ability to  purchase gas
currently sold to  or transported  through other pipelines.  The development  of
additional gas reserves will be affected by many factors including the prices of
natural gas and crude oil, exploration and development costs and the presence of
natural gas reserves in the areas served by AGP's systems.

                                       15
<PAGE>
III.  INDEPENDENT POWER PROJECTS

    Information  regarding  the company's  UtilCo Group  subsidiary's generating
projects is set forth below.

<TABLE>
<CAPTION>
                                                       TYPE OF
                PROJECT & LOCATION                   INVESTMENT     OWNED     (MEGAWATTS)      FUEL         DATE IN SERVICE
---------------------------------------------------  -----------  ----------  -----------  -------------  -------------------
<S>                                                  <C>          <C>         <C>          <C>            <C>
Mega Renewables G.P., 4 projects in California       General          49.75%        12.2   Hydro          Spring 1987(b)
                                                     partnership
Topsham Hydro Partners, Maine                        Leveraged           50%        13.9   Hydro          October 1987
                                                     lease
Stockton CoGen Company, California                   General             50%        49.9   Coal           March 1988(c)
                                                     partnership
Westwood Energy Properties, Pennsylvania             Limited             38%       29.25   Waste coal     July 1988
                                                     partnership
BAF Energy L.P., California                          Limited           23.1%         111   Natural Gas    May 1989
                                                     partnership
Rumford Cogeneration Company L.P., Maine             Limited           24.3%          75   Coal and       May 1990
                                                     partnership                           waste wood
Koma Kulshan Associates, Washington                  Limited          49.75%        13.7   Hydro          October 1990
                                                     partnership
Badger Creek Limited, California                     Limited          49.75%        46.6   Natural gas    April 1991
                                                     partnership
McKittrick Limited, California                       Limited          49.75%        45.4   Natural gas    October 1991
                                                     partnership
Live Oak Limited, California                         Limited             50%        45.8   Natural gas    April 1992
                                                     partnership
Lockport Energy Associates, L.P., New York           Limited          22.56%       168.8   Natural gas    December 1992
                                                     partnership
Orlando Cogen Limited, L.P., Florida                 Limited             50%         120   Natural gas    September 1993
                                                     partnership
Naheola Cogeneration LP, Alabama                     Limited             50%        81.2   Black liquor   March 1993(d)
                                                     partnership                           solids, coal,
                                                                                           gas, wood
Jamaica Private Power Company, Jamaica               Limited             22%          60   Diesel         June 1996 Est.
                                                     liability
                                                     Company
</TABLE>

------------------------------
(a) Total capacity, net of power consumed in generation.

(b) Interest acquired by UtilCo Group in June 1989.

(c) Interest acquired by UtilCo Group in December 1988.

(d) Interest acquired by UtilCo Group and the company in May 1995.

ITEM 3.  LEGAL PROCEEDINGS.

    On June  17, 1992,  a  class action  suit was  filed  in the  United  States
District Court for the Western District of Missouri by a stockholder against the
Company  and certain  unnamed employees  of the  Company and/or  its subsidiary,
Aquila Energy Corporation. Plaintiff  subsequently dismissed its claims  against
all  defendants  except the  Company.  The case  caption  is WILLIAM  ALPERN VS.
UTILICORP UNITED INC.. In this case, plaintiff alleges that the Company violated
various securities laws, including Section 10(b) of the Securities Exchange  Act
of  1934, as amended, and Rule 10b-5  of the Securities and Exchange Commission,
both by  making  misrepresentations and  omitting  to state  material  facts  in
connection with public disclosures. Plaintiff also alleges a claim under Section
11  of the  Securities Act  of 1933, as  amended. Among  other relief, plaintiff
seeks unspecified compensatory  damages. The  District Court  has dismissed  the
case  by granting summary  judgment to UtiliCorp. The  plaintiffs have asked the
District Court to reconsider that decision and they have appealed that  decision
to the United States Court of Appeals for the Eighth Circuit.

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

    None.

                                       16
<PAGE>
PART 2
ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

    The  company's common stock (par $1) is  listed on the New York, Pacific and
Toronto stock exchanges under the symbol UCU. At December 31, 1995, the  company
had  38,136 common shareholders of record. Information relating to market prices
of common stock and  cash dividends on  common stock is set  forth in the  table
below.

                                  MARKET PRICE

<TABLE>
<CAPTION>
                                                      HIGH        LOW      CASH DIVIDENDS
                                                    ---------  ---------  -----------------
<S>                                                 <C>        <C>        <C>
1995 QUARTERS
  First...........................................      29.50      26.25            .43
  Second..........................................      29.00      27.25            .43
  Third...........................................      28.50      26.63            .43
  Fourth..........................................      29.63      27.50            .43
1994 QUARTERS
  First...........................................      31.63      29.00            .42
  Second..........................................      31.38      28.00            .42
  Third...........................................      29.75      26.25            .43
  Fourth..........................................      27.75      25.38            .43
</TABLE>

    Cash  dividends on the common stock of  the company and its predecessor have
been paid each year since 1939.

    Cash dividends  on  and  acquisition  of the  company's  capital  stock  are
restricted  by  provisions of  the  MGU Indenture  and  by the  Preference Stock
provisions of the Certificate  of Incorporation. Under  the most restrictive  of
these provisions, contained in the MGU Indenture, the company may not declare or
pay any dividend (other than a dividend payable in shares of its capital stock),
whether  in cash, stock or otherwise, or make any other distribution, on or with
respect to any class of its capital stock, or purchase or otherwise acquire  any
shares  of, any class of its capital  stock if, after giving effect thereto, the
sum of  (i)  the  aggregate amount  of  all  dividends declared  and  all  other
distributions  made  (other than  dividends  declared or  distributions  made in
shares of its  capital stock)  on shares  of its  capital stock,  of any  class,
subsequent  to December 31,  1984, plus (ii)  the excess, if  any, of the amount
applied to or set apart for the  purchase or other acquisition of any shares  of
its  capital stock,  of any  class, subsequent to  December 31,  1984, over such
amounts as shall have been received by  the company as the net cash proceeds  of
sales  of shares of its capital stock,  of any class, subsequent to December 31,
1984, would exceed the  sum of the  net income of the  company since January  1,
1985,  plus $50 million. In addition, the company may not declare such dividends
unless it  maintains a  tangible net  worth of  at least  $250 million  and  the
aggregate  principal amount of its outstanding  indebtedness does not exceed 70%
of its capitalization. None of the company's retained earnings was restricted as
to payment of cash dividends on its capital stock as of December 31, 1995.

    In addition, cash  dividends on,  and acquisition of,  the company's  common
stock  will be restricted by provisions of the Indenture of the company dated as
of June 1, 1995 relating to  its 8 7/8% Junior Subordinated Deferrable  Interest
Debentures,  Series  A, due  2025.  In the  event  the company  elects  to defer
interest on such Debentures then the company may not declare any dividend on  or
acquire any shares of its capital stock during such deferral period.

                                       17
<PAGE>
ITEM 6.  SELECTED FINANCIAL DATA.

<TABLE>
<CAPTION>
                                                         1995        1994        1993        1992        1991
                                                      ----------  ----------  ----------  ----------  ----------
<S>                                                   <C>         <C>         <C>         <C>         <C>
Sales...............................................  $  2,798.5  $  2,398.1  $  2,746.1  $  2,339.0  $  1,726.2
Income from operations..............................       225.1       228.0       144.0       165.4       192.7
Net income..........................................        79.8        94.4        86.4        52.9        77.6
Earnings available for common shares................        77.7        91.4        79.5        46.0        69.8
Primary earnings per common share...................        1.72        2.08        1.95        1.32        2.37
Fully diluted earnings per common share.............        1.71        2.06        1.92        1.31        2.27
Cash dividends per common share.....................        1.72        1.70        1.62        1.60        1.54
Total assets........................................     3,885.9     3,111.1     2,850.5     2,552.8     2,387.3
Short-term debt (including current maturities)......       303.7       321.2        71.8       236.8       114.5
Long-term debt......................................     1,355.4       976.9     1,009.7       890.8       928.1
Company-obligated mandarorily redeemable preferred
 securities of a partnership........................       100.0          --          --          --          --
Preference and preferred stock......................        25.4        25.4        83.9        95.1        97.1
Common shareholders' equity.........................       946.3       906.8       851.7       661.1       660.7
Book value per common share.........................       20.59       20.24       20.27       18.66       19.18
</TABLE>

------------------------
(1)  In 1995,  the company  recorded a  $34.6 million  pretax charge  related to
    impaired assets.

(2) In 1995, the company changed  its method of accounting for domestic  natural
    gas  trading  operations  to  the  mark-to-market  method.  This  change  in
    accounting increased sales and income from operations by $29.8 million,  net
    income  by $18.3 million and total assets  by $201.9 million. This change in
    accounting has been reflected from January 1, 1995. The pro forma effect  on
    prior periods is not material.

(3)  In  1993,  AEC, a  subsidiary  of  the company,  recorded  a  $69.8 million
    restructuring  charge  against  pretax  earnings  related  to  a  change  in
    strategic direction.

(4)  In 1993, AEC sold 18%  of AGP in an initial  public offering resulting in a
    non-taxable gain of $47.8 million.

(5) In 1992, AEC recorded a $17.7 million charge against pretax earnings related
    to improper payments by former  employees of AER, a wholly-owned  subsidiary
    of Aquila.

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

KEY EVENTS OF 1995

    - In  May 1995 the company launched a national marketing campaign to promote
      EnergyOne, the industry's first nationwide  brand for energy products  and
      services.

    - In  May 1995  UtiliCorp and  its UtilCo  Group subsidiary  purchased a $59
      million, 50% ownership interest in a partnership that owns and operates  a
      cogeneration facility in Alabama.

    - In  September  1995 the  company acquired  a  49.9% ownership  interest in
      United  Energy,   an  Australian   electric  distribution   utility,   for
      approximately $257.9 million. The company manages the utility which serves
      approximately 520,000 customers in metropolitan Melbourne.

    - In  September 1995 UtiliCorp  and Novell, Inc.  announced a partnership to
      jointly develop smart networking technologies to better manage energy  use
      by communicating over power lines.

    - In  September 1995 the company  sold substantially all of  its oil and gas
      production assets  for  approximately $205  million  cash, or  about  book
      value.

    - In the fourth quarter of 1995, the company recorded a $34.6 million pretax
      provision  for  asset impairments  and adopted  a new  accounting standard
      regarding long-lived assets.

                                       18
<PAGE>
    - In late 1995  the company changed  its accounting method  for natural  gas
      trading  activities  to the  mark-to-market  method, effective  January 1,
      1995. This change increased 1995 net  income by $18.3 million and  primary
      earnings per share by $.41.

    - In  January 1996 UtiliCorp and Kansas City  Power & Light Company signed a
      definitive agreement to merge into a new company. The merger will create a
      diversified energy company with sales of  more $3.5 billion and over  $6.5
      billion in total assets.

OVERVIEW

    Except  where  noted, the  following discussion  refers to  the consolidated
entity, UtiliCorp United Inc., including its three principal operating segments:
electric operations, gas operations and energy related businesses (Aquila Energy
Corporation [Aquila]). The company  has other operations  that effect sales  and
income  from operations which  are discussed in the  Other Businesses and Equity
Investments section. Significant events and trends are presented which have  had
an  effect on the operations  of the company during  the three-year period ended
December 31, 1995. Also presented are  factors that may affect future  operating
results,  financial position  and liquidity. This  discussion should  be read in
conjunction  with   the   company's  consolidated   financial   statements   and
accompanying notes.

1995 RESULTS

    UtiliCorp's  1995 earnings available for common shares were $77.7 million or
15% below earnings available in 1994.  The 1995 financial results were  affected
by certain adjustments recorded in the third and fourth quarters of 1995. First,
financial  results  were favorably  affected by  a  change in  accounting method
related to price risk management activities. This change increased net income by
$18.3 million and  income from  operations by $29.8  million. Second,  financial
results  were reduced  by a provision  for asset impairments  that decreased net
income by $19.6 million and income from operations by $34.6 million. And  third,
financial  results were  affected negatively  by an  $11 million  pretax reserve
established for financial guarantees provided by  the company and to certain  of
its  partners  in  United Kingdom  gas  marketing ventures.  The  reserve became
necessary due to a sharp decline  in British natural gas prices. Also  impacting
the  1995 financial  results was  higher interest  expense than  in 1994  due to
acquisition opportunities primarily financed through long- and short-term  debt.
The  company also  absorbed approximately  $11.5 million  (pretax) of  costs for
restructuring,  including   early  retirements,   severance,  recruitments   and
relocations.

                                       19
<PAGE>
                              ELECTRIC OPERATIONS

    The  company's electric segment includes  the electric utility operations of
Missouri Public Service, West Kootenay Power, West Virginia Power and WestPlains
Energy.

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                             -------------------------------------
THREE-YEAR REVIEW -- ELECTRIC OPERATIONS                                        1995         1994         1993
---------------------------------------------------------------------------  -----------  -----------  -----------
                                                                                      DOLLARS IN MILLIONS
<S>                                                                          <C>          <C>          <C>
Sales......................................................................  $     577.7  $     557.0  $     546.9
                                                                             -----------  -----------  -----------
Cost of sales -- fuel and purchased power..................................        193.1        190.7        197.3
                                                                             -----------  -----------  -----------
Gross profit...............................................................        384.6        366.3        349.6
                                                                             -----------  -----------  -----------
Expenses:
  Other operating..........................................................        116.9        101.9         97.8
  Maintenance..............................................................         35.3         38.8         38.5
  Taxes, other than income taxes...........................................         51.3         50.4         48.0
  Depreciation and amortization............................................         53.7         49.9         45.9
                                                                             -----------  -----------  -----------
  Total expenses...........................................................        257.2        241.0        230.2
                                                                             -----------  -----------  -----------
Income from operations.....................................................  $     127.4  $     125.3  $     119.4
                                                                             -----------  -----------  -----------
                                                                             -----------  -----------  -----------
Identifiable assets........................................................  $   1,200.2  $   1,164.6  $   1,162.0
Capital expenditures.......................................................         69.5         81.3         87.4
                                                                             -------------------------------------
Electric sales (MWH 000's).................................................       10,545       10,119        9,924
Number of customers........................................................      434,866      426,414      417,884
                                                                             -------------------------------------
</TABLE>

SALES

    Electric sales in 1995 increased $20.7 million or 4% compared to 1994 due to
more favorable weather,  continued growth in  the number of  customers, and  new
rates  at West  Kootenay Power effective  January 1, 1995.  Extremely hot summer
temperatures in 1995 benefited the  company's domestic electric operations.  The
electric  operations in Missouri, Colorado and  Kansas, which represent over 80%
of total electric sales,  peak during the summer  months. Sales increased  $10.1
million or 2% in 1994 compared to 1993 primarily due to additional customers.

COST OF SALES

    Fuel  and  purchased power  expenses, collectively  referred  to as  cost of
sales, increased $2.4 million or 1% in  1995 compared to 1994. The increase  was
primarily  due  to favorable  weather and  increased customers  discussed above,
offset by reduced  fuel costs.  Cost of  sales decreased  significantly in  1994
compared  to 1993  due to lower-priced  contracts for purchased  power, coal and
rail transportation.

EXPENSES

    Operating expenses increased $15.0 million or  15% in 1995 compared to  1994
due  to additional sales staff expenses and costs of repositioning and reshaping
the businesses.  In  1995,  the  company  began  centralizing  business  support
functions  such as human resources, accounting and information technology, among
others, which  previously  were located  in  the company's  individual  business
units.  This centralization process combined with building a sales force are the
main causes of  the increase.  The company  expects that  its repositioning  and
reshaping  activities will  continue in 1996.  The increase  in depreciation and
amortization expense  for  all  periods  shown  is  due  to  additional  capital
improvements made to utility assets.

                                       20
<PAGE>
CAPITAL EXPENDITURES

    The capital budget for the next five years is shown below.

<TABLE>
<CAPTION>
                                    GENERATION   TRANSMISSION   DISTRIBUTION     OTHER      TOTAL
                                    -----------  -------------  -------------  ---------  ---------
<S>                                 <C>          <C>            <C>            <C>        <C>
1996..............................   $    33.8     $    20.3      $    35.2    $    24.8  $   114.1
1997..............................        69.4          14.8           31.6         26.2      142.0
1998..............................        21.0          11.0           32.8         27.1       91.9
1999..............................        14.4           6.7           34.1         29.4       84.6
2000..............................        15.0           5.7           33.2         25.4       79.3
</TABLE>

ENVIRONMENTAL MATTERS

    The  company has been named as a potentially responsible party (PRP) at five
PCB disposal facilities. The company's combined clean-up expenditures have  been
less  than $1  million to  date and it  anticipates that  future expenditures on
these sites will not  be significant. The company  is in compliance with  sulfur
dioxide  emission requirements  established by the  Clean Air  Act Amendments of
1990.  The  company's  environment  related  expenditures  generally  are  being
recovered or deferred pending expected recovery through rates.

COMPETITION

    The  electric industry has  increasingly become more  competitive as federal
and state regulators and legislators continue taking steps toward  deregulation.
The  anticipation of reduced regulation triggered  some dramatic events in 1995.
Five  major  utility  mergers  were  announced,  including  three  that   affect
competitors  close  to  or  next to  the  company's  service  territories. Other
utilities have implemented cost reduction programs and organizational changes in
preparation for greater competition.

    The company began looking at its  strengths and opportunities in respect  to
future  increased competition  two years ago  when the  company brought together
approximately 100 employees from around the company to work on a strategic  plan
that  would be the foundation to reposition and reshape the company. In 1995 the
company began  centralizing  business  support functions  that  previously  were
performed  separately in the operating divisions  and building its resources and
capacity to  take  advantage  of  opportunities  brought  about  as  competition
increases.

    The  company currently  accounts for the  economic effects  of regulation in
accordance with the  provisions of Statement  of Financial Accounting  Standards
No.  71  (SFAS  No.  71),  "Accounting  for  the  Effects  of  Certain  Types of
Regulation," and accordingly has recorded certain costs as regulatory assets  in
the financial statements. The company expects that its rates will continue to be
based   on  historical  costs  for  the   foreseeable  future.  If  the  company
discontinued applying SFAS No. 71, it  would be required to make adjustments  to
the carrying value of certain assets.

                                       21
<PAGE>
                                 GAS OPERATIONS

    The  company's gas segment  includes the gas  utility operations of Missouri
Public Service, Kansas Public Service,  Peoples Natural Gas, Northern  Minnesota
Utilities, Michigan Gas Utilities and West Virginia Power.

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                                   -------------------------------------
THREE-YEAR REVIEW -- GAS OPERATIONS                                   1995         1994         1993
-----------------------------------------------------------------  -----------  -----------  -----------
                                                                            DOLLARS IN MILLIONS
<S>                                                                <C>          <C>          <C>
Sales............................................................  $     616.8  $     618.6  $     686.1
Cost of sales -- Gas purchased for resale........................        348.9        381.1        443.4
                                                                   -----------  -----------  -----------
Gross profit.....................................................        267.9        237.5        242.7
                                                                   -----------  -----------  -----------
Expenses:
  Other operating................................................        129.8        113.7        115.7
  Maintenance....................................................          9.1          8.8          8.8
  Taxes, other than income taxes.................................         26.4         23.1         23.9
  Depreciation and amortization..................................         34.3         30.1         28.6
                                                                   -----------  -----------  -----------
  Total expenses.................................................        199.6        175.7        177.0
                                                                   -----------  -----------  -----------
Income from operations...........................................  $      68.3  $      61.8  $      65.7
                                                                   -----------  -----------  -----------
                                                                   -----------  -----------  -----------
Identifiable assets..............................................  $     900.0  $     819.9  $     716.9
Capital expenditures.............................................         39.9         50.7         53.1
                                                                   -------------------------------------
Gas sales (BCF)..................................................          128          128          145
Gas transportation (BCF).........................................          178          136          116
                                                                   -----------  -----------  -----------
Total volume (BCF)...............................................          306          264          261
                                                                   -----------  -----------  -----------
Number of customers..............................................      796,621      779,630      740,354
                                                                   -------------------------------------
</TABLE>

SALES

    Sales  in 1995  declined by $2.0  million compared to  1994. Several factors
significantly affected sales  in 1995  compared to  1994. Lower  gas prices  and
customers  switching to transportation services decreased sales by approximately
$33.8 million. This was offset by  favorable weather, a full year of  operations
at  the Kansas gas property acquired in September 1994 and the Missouri pipeline
system acquired in January 1995, and additional customers throughout the service
territories. Sales in 1994 compared to 1993  were lower by $67.5 million or  10%
due  to  unfavorable  weather,  lower  gas  prices  and  customer  switching  to
transportation services. Customer switching does not effect net income.

COST OF SALES

    The cost of sales changes generally  with sales, since all of the  company's
gas operations contain gas cost adjustment mechanisms that pass through gas cost
changes periodically to customers.

EXPENSES

    Operating  expenses increased $15.9 million or 14% in 1995 compared to 1994.
This is primarily due to additional sales and repositioning and reshaping  costs
discussed  in the  electric expenses  section on page  20. In  addition the 1995
expenses reflect the full year activities of the Kansas gas system and  Missouri
pipeline  acquisitions.  Taxes  and  depreciation increased  in  1995  over 1994
primarily due  to the  addition  of acquired  assets and  capital  improvements.
Expenses in 1994 were about the same as in 1993.

                                       22
<PAGE>
CAPITAL EXPENDITURES

    The capital budget for the next five years is shown below.

<TABLE>
<CAPTION>
                                                                 DISTRIBUTION     OTHER      TOTAL
                                                                 -------------  ---------  ---------
                                                                             IN MILLIONS
<S>                                                              <C>            <C>        <C>
1996...........................................................    $    42.6    $    18.5  $    61.1
1997...........................................................         42.4          6.6       49.0
1998...........................................................         41.0          5.3       46.3
1999...........................................................         40.2          5.3       45.5
2000...........................................................         36.5          4.2       40.7
</TABLE>

ENVIRONMENTAL MATTERS

    The  company owns or  once operated 29 former  manufactured gas plants which
may or  may  not require  some  form  of environmental  remediation.  These  are
discussed in Note 14 to the Consolidated Financial Statements.

COMPETITION AND OUTLOOK

    The  competitive forces affecting the company's electric operations are also
affecting the  company's  gas operations.  In  addition, as  competing  electric
utilities reduce costs it becomes more difficult to obtain new customers through
fuel switching opportunities and in certain cases may result in customer losses.
The  Federal Energy  Regulatory Commission (FERC)  Order 636  shifted gas supply
responsibilities from  traditional  pipeline  company  sources  to  distribution
utilities  and  allows  customers to  bypass  the company's  system  by directly
connecting to a transportation pipeline.

    The company  has addressed  increased competition  and industry  changes  in
several  ways. First, its natural gas  is priced competitively in our respective
service territories relative to alternative energy sources. Second, the  company
established  in 1993  a central gas  procurement function  designed, among other
reasons, to take advantage of opportunities  created by FERC Order 636.  Besides
offering  low cost natural gas, the company offers its customers a wide range of
energy solutions to meet  customer demands and in  some ways raise the  standard
for its potential competitors.

                                       23
<PAGE>
                           ENERGY RELATED BUSINESSES

    The  energy related businesses  segment consists solely  of the consolidated
operations of the company's Aquila Energy subsidiary, including 82%-owned Aquila
Gas Pipeline (AGP). Aquila provides natural gas risk management services and  is
involved  in the gathering, processing and marketing of natural gas and the sale
of natural gas liquids. Its Aquila  Power subsidiary began operations to  market
wholesale electricity in 1995.

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                                   -------------------------------------
THREE-YEAR REVIEW -- ENERGY RELATED BUSINESS                          1995         1994         1993
-----------------------------------------------------------------  -----------  -----------  -----------
                                                                            DOLLARS IN MILLIONS
<S>                                                                <C>          <C>          <C>
Sales:
  Gas marketing (a)..............................................  $     835.7  $     613.2  $     949.3
  Gas sales, transmission and processing.........................        284.7        245.7        267.9
  Gas and oil production.........................................         50.6         76.9         74.8
                                                                   -----------  -----------  -----------
  Total sales....................................................      1,171.0        935.8      1,292.0
                                                                   -----------  -----------  -----------
Cost of sales:
  Cost of gas marketing..........................................        774.8        596.8        953.4
  Cost of gas transmission and processing........................        193.8        166.6        177.1
                                                                   -----------  -----------  -----------
  Total cost of sales............................................        968.6        763.4      1,130.5
                                                                   -----------  -----------  -----------
Gross profit.....................................................        202.4        172.4        161.5
                                                                   -----------  -----------  -----------
Expenses:
  Operating and maintenance......................................         71.2         69.4         63.8
  Depreciation, depletion and amortization.......................         49.6         59.6         60.8
  Provision for asset impairments................................         13.2           --           --
  Restructuring charge (b).......................................           --           --         69.8
                                                                   -----------  -----------  -----------
Total expenses...................................................        134.0        129.0        194.4
                                                                   -----------  -----------  -----------
Income (loss) from operations, before minority interests.........  $      68.4  $      43.4  $     (32.9)
                                                                   -----------  -----------  -----------
                                                                   -----------  -----------  -----------
Gain on sale of subsidiary stock.................................  $        --  $        --  $      47.8
Net income.......................................................         24.0          9.3         10.7
Identifiable assets..............................................        873.1        717.1        604.2
Capital expenditures and investments.............................        144.0        113.6         94.5
                                                                   -------------------------------------
Marketing volumes (million cubic feet per day)...................        1,427        1,002        1,381
Natural gas throughput (million cubic feet per day)..............          507          372          329
Natural gas liquids produced (thousand barrels per day)..........           32           31           31
Pipelines operated (miles).......................................        3,311        2,718        2,531
Proven reserves (billion cubic feet)(c)..........................           --          162          119
Production volumes (billion cubic feet)(c).......................           17           27           30
                                                                   -------------------------------------
</TABLE>

------------------------

(a)  Prior years  have been  reclassified to  conform to  the 1995 presentation.
    Sales were previously reported net of gas cost.

(b) Includes write-off of  $3.7 million related to  certain assets owned by  the
    company on behalf of Aquila.

(c)  Includes barrels of  oil expressed as gas  equivalent, assuming 6,000 cubic
    feet of gas per barrel of oil.

                                       24
<PAGE>
SEGMENT HIGHLIGHTS

    For the years ended  December 31, 1995, 1994  and 1993, Aquila reported  net
income  of  $24.0 million,  $9.3 million  and  $10.7 million,  respectively. Net
income in  1995 as  compared to  1994 and  1993 was  158% and  124% higher.  The
increase  in 1995 reflects significant increases in operating results, favorable
impact  of  a  change  in  accounting  principle  and  a  provision  for   asset
impairments. Significant items affecting the comparability of Aquila's financial
results are described below.

    CHANGE  IN ACCOUNTING  PRINCIPLE.   Effective January  1, 1995,  the company
changed its method of accounting for its domestic natural gas trading activities
to the mark-to-market method.  Under this method, changes  in the fair value  of
Aquila's  physical  and financial  transactions are  reflected currently  in the
Consolidated Financial Statements.  Aquila's prior method  recognized gains  and
losses  when  the  underlying  physical  commodity  was  sold  or  produced. The
accounting change increased Aquila's  1995 sales and  income from operations  by
$29.8  million and net income by $18.3 million. The cumulative effect on periods
prior to 1995 was not material.

    PROVISION FOR ASSET  IMPAIRMENTS.  In  1995, AGP completed  a review of  the
carrying  value of its assets, including  the adoption of 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),  and  recorded  a
non-cash, pretax charge of $13.2 million.

    SALE  OF ASSETS.   In  September 1995, Aquila  sold all  of its  oil and gas
production assets  and reserves  for  approximately $205  million. Oil  and  gas
production activities had a loss of $5.0 million in 1995.

    RESTRUCTURING  AND SETTLEMENTS.  In 1993,  Aquila implemented a new business
strategy and recorded a  $69.8 million restructuring  charge against income  for
the disposal of certain natural gas contracts, impairment of offshore assets and
other  restructuring costs. In 1995 and 1994 Aquila's income from operations was
favorably affected by $5.0 million and $5.4 million related to settling  certain
loss  contracts  more favorably  than originally  anticipated  in 1993  when the
contracts were included in the restructuring charge.

    In 1993, AGP completed  an initial public offering  and sale of 5.4  million
shares of its common stock, resulting in a tax-free gain of $47.8 million.

REVIEW OF OPERATIONS

    Sales  and  cost  of  sales increased  $235.2  million  and  $205.2 million,
respectively, in  1995 compared  to 1994  due  to a  39% increase  in  marketing
volumes  and a  34% increase in  gas pipeline throughput.  Gas marketing volumes
increased due to the acquisition in  January 1995 of Tristar Gas Company,  which
had  volumes  of  approximately 42  million  cubic  feet per  day  in  1995. Gas
marketing volumes also increased due to further implementation of a new strategy
developed in 1994.  Sales from  net trading  activities added  $29.8 million  to
sales  and income from operations in 1995.  See Price Risk Management section on
page 32 for further discussion. Gas  marketing sales decreased in 1994  compared
to 1993 primarily due to a strategic change at Aquila that was the result of and
followed  the restructuring charge in 1993.  Gas throughput volumes increased in
1995 due to expanded drilling in AGP's gathering region. In 1995 AGP constructed
a new pipeline  to increase  volumes that can  be processed  from its  gathering
system.  Sales and cost of  sales are directly affected  by the price of natural
gas and natural gas liquids.

    Sales from oil and gas production activities decreased primarily due to  the
sale  of all production  assets, which also  lowered depreciation, depletion and
amortization expense in 1995. The sale resulted in no gain or loss for financial
reporting purposes.

OUTLOOK

    The company has  adopted a  plan to provide  both natural  gas and  electric
power commodity services to its wholesale customers from an integrated wholesale
marketing  staff.  This  will allow  the  company  to fully  meet  the  needs of
customers who  will have  an ever-increasing  portfolio of  energy options  from
which  to choose in the future. A number of recent mergers and consolidations of
entities in  the natural  gas marketing  industry have  increased the  focus  on
controlling marketing share

                                       25
<PAGE>
on  a  volumetric  basis. The  company  expects  the gas  marketing  industry to
consolidate into a few mega-marketing  companies. Electric power marketing  will
be  impacted  by the  regulatory environment  of the  industry. It  is currently
unclear as to when the various regulatory agencies will open access to all power
customers, including  retail  users.  These  regulatory  decisions  may  have  a
significant impact on the future economics of the power marketing sector.

    The  gas processing and gathering business will be influenced by natural gas
and oil  commodity  prices  and  the drilling  activity  surrounding  its  major
pipeline asset in Southeast Texas. Continued exploration success in this area by
oil and gas companies will bolster this unit's future. Many pipeline acquisition
opportunities also exist in this operational area.

                    OTHER BUSINESSES AND EQUITY INVESTMENTS

UTILCO GROUP

    The  table below  summarizes selected  financial and  operating data  of the
UtilCo Group subsidiary.

<TABLE>
<CAPTION>
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Equity in earnings (a).............................................................  $    21.9  $    19.2  $    15.0
Net income (loss)(b)...............................................................        (.2)       6.4        3.2
Equity investment..................................................................      170.3      122.8      100.2
Share of project assets............................................................      535.3      379.8      363.1
Share of project liabilities.......................................................      394.3      291.8      282.9
                                                                                     -------------------------------
Aggregate capacity (megawatts).....................................................        873        792        732
Operating projects.................................................................         16         15         15
Projects under construction........................................................          1          1         --
                                                                                     -------------------------------
</TABLE>

------------------------
(a) Includes both the company and UtilCo  Group's ownership interest in a  power
    project.

(b) Includes a $15.4 million non-cash charge against income for an impairment of
    a project investment.

    UtilCo  Group had a net loss of $.2 million in 1995 after recording a pretax
$15.4 million non-cash  charge relating to  an impairment of  a project.  UtilCo
Group  reported net  income of $6.4  million in  1994 and $3.2  million in 1993.
Equity in earnings from partnerships increased $2.7 million or 14%. The increase
was due primarily to earnings from a project acquired in May 1995, offset by  an
unplanned  curtailment of a project due to availability of excess hydro power in
the region. The increase in 1994 net income compared to 1993 is due to increased
sales at  two projects  that operated  near  capacity. Net  income in  1993  was
reduced due to the increase in the corporate tax rate.

    UtilCo  Group  has  equity  ownership  interests  in  17  independent  power
projects, 16 of which are in commercial operation. In May 1995, the company  and
UtilCo  Group purchased a 50%  ownership interest in an  81 MW chemical recovery
and cogeneration  facility at  the James  River Corporation's  Naheola pulp  and
paper  mill in Pennington,  Alabama. The plant, which  began operations in 1993,
suppplies the Naheola mill  with all its black  liquor solids processing,  steam
and compressed air needs, as well as approximately 60% of the mill's electricity
needs.  In October 1994, UtilCo Group agreed  to acquire an equity interest in a
60-megawatt electric generating project now being built in Kingston, Jamaica. It
is scheduled to begin  commercial operation in 1996.  The $138 million  facility
will  sell its  electric capacity and  output to Jamaica  Public Service Company
under a 20-year contract.  The company will  hold a 22  percent interest in  the
project and expects to contribute approximately $11.6 million in equity.

    In  October 1995, UtilCo  Group entered into a  joint venture agreement with
Air Products  and  Chemicals,  Inc.  to develop,  own,  and  operate  generation
projects. The projects will consist of gas-fired combustion turbine applications
throughout the Midwest.

                                       26
<PAGE>
    Consistent  with UtiliCorp's strategy  of spreading risks,  UtilCo Group has
invested in generating projects located in seven states and one foreign country.
Each  project  uses  traditional  fuels  and  proven  technologies,  and  is   a
competitive,  low-cost  producer of  wholesale  power. The  projects  sell their
electric output  under long-term  contracts with  terms ranging  from 15  to  40
years.

INTERNATIONAL EQUITY INVESTMENTS

    AUSTRALIA

    On  September 6, 1995, Power Partnership Limited (PPL), of which the company
owns  49.9%,  acquired  United  Energy  Limited  (UE),  an  Australian  electric
distribution  utility,  from  the  State  of  Victoria  for  approximately $1.15
billion. The company's ownership interest cost approximately $257.9 million  and
was   financed  primarily  with  Australian  denominated  bank  debt  through  a
consortium of banks. UtiliCorp Australia Holdings Limited (UAHL), a wholly-owned
subsidiary of the company, manages  UE on behalf of  PPL. In 1995 the  company's
Australian investments contributed $2.9 million to the company's net income.

    NEW ZEALAND

    On  November 30,  1995, UtiliCorp N.Z.  Inc. (UNZ),  a 79%-owned subsidiary,
completed a transaction that resulted in UNZ owning approximately 27.5% of Power
New Zealand Limited (PNZ). PNZ is an electric utility distribution company  that
provides  service to approximately 214,000 customers. Prior to this transaction,
UNZ owned approximately 7.5% of PNZ.

    In late February 1995,  UNZ paid $16.1 million  to WEL Energy Group  Limited
(WEL)  to satisfy its capital  commitment to WEL. UNZ  now participates in WEL's
earnings to the full  extent of its ownership.  Before paying the final  capital
commitment,  UNZ's participation in  WEL's earnings was limited  to 5%. UNZ held
39% of WEL at the end of  1995. WEL is an electric distribution utility  serving
approximately 65,000 customers.

    The  company's  New  Zealand  investments contributed  $.7  million  to 1995
consolidated net income. For 1994 and 1993 the results from New Zealand were not
material.

    UNITED KINGDOM

    Net income  (loss) from  the United  Kingdom businesses  for the  three-year
period  ended  December  31, 1995  were  $(2.5)  million, $2.4  million  and $.5
million, respectively. The company has  several business ventures in the  United
Kingdom  that market natural  gas to wholesale  and industrial customers. United
Gas Limited (UGL) is the company's primary  subsidiary. At the end of 1995,  UGL
had approximately 27,000 gas marketing customers.

    In  addition  to UGL,  the  company has  five  gas marketing  joint ventures
(collectively referred to as Regional  Gas Companies or RGCs)  in which it is  a
25%  equity partner. The decline  in 1995 results compared  to 1994 is primarily
due to the decline in spot market prices and its effects on margins at the  RGCs
and  certain commitments the company or  subsidiaries have with its partners. In
the fourth  quarter  1995,  the  company reserved  $11.0  million  (pretax)  for
probable  funding  requirements  the  company expects  to  make  to  support its
investments in RGCs and recognized $1.6 million as its share of RGC net  losses.
Results  in 1995 were favorably affected by a gain on the sale of one of its RGC
investments and  by  a  favorable  gas  settlement.  See  Note  14  for  further
discussion on financial commitments.

OTHER

    NOVELL PARTNERSHIP

    On  September 13,  1995, the company  and Novell, Inc.  (Novell) announced a
partnership to  jointly  develop certain  technologies  and products  to  better
manage  energy consumption in home and business environments. Under the terms of
this alliance the company and Novell will co-develop, co-own and jointly  market
applications  that allow customers to optimize their use of energy on a 24-hour,
real-time basis. In October an initial cash  payment was made by the company  to
Novell for related license

                                       27
<PAGE>
rights.  The  two companies  also  announced the  founding  of the  Smart Energy
Network Alliance, an open  industry consortium that  will provide leadership  in
defining  the standards for future energy programs, network management and other
smart energy network solutions.

                        LIQUIDITY AND CAPITAL RESOURCES

    The company's cash  requirements arise primarily  from its growth  strategy,
electric  and  gas utility  construction  programs and  non-regulated investment
opportunities. UtiliCorp's ability to attract the necessary financial capital at
reasonable terms is  critical to  the company's overall  plan. Acquisitions  and
investments  have  been  initially  financed  with  short-term  debt  and  later
permanently funded  with various  long-term debt  securities or  common  equity,
depending on market conditions.

    OPERATING CASH FLOWS

    Cash flows from operating activities were $261.2 million, $229.3 million and
$289.3  million for the three-year period ended December 31, 1995, respectively.
Cash flow from  operating activities  increased $31.9 million  between 1995  and
1994.  This increase was  primarily due to  a net favorable  increase in working
capital and other changes  in assets and  liabilities. Working capital  accounts
were  significantly affected by  volume increases and  higher natural gas prices
compared to  the  prior  year. Taken  together,  accounts  receivable  including
accrued revenues less accounts payable reduced working capital by $73.5 million,
primarily  due to cash being used to  pay energy cost related obligations before
cash is collected  from customers.  Partially offsetting  this use  of cash  was
increased  net  borrowings  from  the  company's  accounts  receivable financing
program which  provided $50.8  million of  additional operating  cash flow.  The
change  to  the  mark-to-market  method  of  accounting  for  certain  financial
instruments (more  fully explained  on  page 32)  and  the provision  for  asset
impairments did not affect cash flows.

    Cash flow from operating activities decreased $60.0 million between 1994 and
1993  due  to  unfavorable  changes  in  working  capital.  As  discussed above,
operating cash flows are  affected by the timing  of cash payments and  accounts
receivable collections.

    INVESTING CASH FLOWS

    Over  the past three years, cash  used (provided) by the company's investing
activities was as follows:

<TABLE>
<CAPTION>
                                                                                      1995       1994       1993
                                                                                    ---------  ---------  ---------
                                                                                              IN MILLIONS
<S>                                                                                 <C>        <C>        <C>
Electric capital expenditures.....................................................  $    69.5  $    81.3  $    87.4
Gas capital expenditures..........................................................       39.9       50.7       53.1
Acquired businesses:
  Nebraska gas system.............................................................         --         --       99.0
  Kansas gas system...............................................................         --       22.1         --
  Missouri pipeline system........................................................       78.0         --         --
  Australia electric utility......................................................      257.9         --         --
  New Zealand electric utilities..................................................      121.4         --         --
  Other acquisitions..............................................................       22.9        6.1
Oil and gas reserve development and purchases.....................................       39.3       80.4       39.1
Gas transmission and processing additions.........................................      104.7       33.2       55.4
Independent power projects........................................................       59.0       22.2       28.8
Sale of oil and gas properties....................................................     (204.5)        --         --
Sale of subsidiary stock..........................................................         --         --      (74.6)
Other.............................................................................       46.8       50.3        6.5
                                                                                    ---------  ---------  ---------
Net cash invested.................................................................  $   634.9  $   346.3  $   294.7
                                                                                    ---------  ---------  ---------
                                                                                    ---------  ---------  ---------
</TABLE>

                                       28
<PAGE>
    CAPITAL EXPENDITURES

    The company's utility expenditures are  primarily made to extend service  to
new  customers, upgrade existing distribution systems and pipe and make periodic
improvements to  generation assets.  Gas transmission  and processing  additions
consists  of expenditures from  AGP. The increase  in 1995 compared  to 1994 and
1993 is  primarily due  to construction  in mid-1995  of a  30-inch pipeline  to
connect AGP's gathering system to a processing plant.

    BUSINESS ACQUISITIONS

    In  May 1995, the company and UtilCo Group paid $59 million to acquire a 50%
ownership interest in a partnership that  owns and operates a chemical  recovery
and  cogeneration  facility in  Alabama. This  is  the company's  largest single
investment in  an independent  power project  to date.  The facility  sells  its
electric output to a pulp and paper mill.

    In  January  1995,  the  company completed  its  acquisition  of  a 218-mile
intrastate gas pipeline  and gas  distribution system for  $78.0 million.  These
businesses now operate as UtiliCorp Pipeline Systems, Inc. (UPL), a wholly-owned
subsidiary of the company. UPL had sales of $14.3 million in 1995.

    In  January 1995, the company acquired Broad Street Oil & Gas Company, a gas
marketing company based in Ohio, and  AGP acquired Tristar Gas Company, a  Texas
gas   processing,  gathering  and  marketing  firm.   Broad  Street  Oil  &  Gas
concentrates on  marketing  natural  gas  to small  to  medium  size  commercial
businesses  through  a network  of contract  sales representatives.  Tristar Gas
Company sold approximately  156 million  cubic feet per  day of  natural gas  in
1995.  Tristar focuses  its marketing  efforts on  Texas intrastate  natural gas
markets.

    In September 1994, the  company spent $22.1 million  cash to acquire  Kansas
gas  distribution and selected  transmission assets from  NorAm Energy Corp. The
Kansas  system  serves  about  22,000  customers  in  Wichita  and   surrounding
communities.  In February 1993, the company  spent $99.0 million cash to acquire
NorAm's Nebraska gas distribution system serving approximately 124,000 customers
in 63 eastern Nebraska communities.

    See page 27  for discussion  of the company's  international investments  in
Australia and New Zealand and page 25 for disposition of oil and gas properties.

    The company's operating cash flow provided approximately 41%, 66% and 98% of
the needed funds for the three years ended December 31, 1995, applying operating
cash flows to investing activities first. Additional cash needs are derived from
various financing activities discussed below.

                                       29
<PAGE>
    FINANCING CASH FLOWS

    Cash  inflow (outflow) related  to financing activities  of the company over
the last three years is presented in the table below.

<TABLE>
<CAPTION>
                                                                                     1995       1994       1993
                                                                                   ---------  ---------  ---------
                                                                                             IN MILLIONS
<S>                                                                                <C>        <C>        <C>
COMMON STOCK ISSUES:
  Various stock ownership and option plans.......................................  $    29.5  $     2.8  $    34.1
  Issue--5.2 million shares......................................................         --         --      144.7
  Dividends......................................................................      (80.0)     (77.6)     (74.4)
  Treasury Stock.................................................................        6.6       (6.6)        --
SENIOR NOTE ISSUES:
  8.45% Series...................................................................         --       99.5         --
  6.0% Series....................................................................         --         --       63.5
  8.0% Series....................................................................         --         --      123.3
  6.875% Series..................................................................       99.3         --         --
  9.3% Series (retirement).......................................................     (125.0)        --         --
Monthly income securities........................................................      100.0         --         --
Mortgage bonds, Series 1.........................................................         --         --      (63.5)
Australian denominated debt......................................................      222.8         --         --
New Zealand denominated debt.....................................................       63.6         --         --
8.8% secured debentures..........................................................         --         --       18.8
Net change in short-term debt....................................................      106.2      112.4     (160.9)
Other long-term debt activities, net.............................................       (5.8)       4.6      (24.5)
Preference stock.................................................................         --       (6.8)      (9.0)
                                                                                   ---------  ---------  ---------
Net cash from financing activities...............................................  $   417.2  $   128.3  $    52.1
                                                                                   ---------  ---------  ---------
                                                                                   ---------  ---------  ---------
</TABLE>

    To supplement the company's internally generated cash flows, the company has
various short-term  credit programs.  A primary  source of  cash has  been  bank
borrowing  from  uncommitted  bank lines.  In  addition, the  company  can issue
commercial paper  aggregating  $150 million.  To  support the  commercial  paper
program,  the company  has a $250  million committed  revolving credit agreement
with a consortium of  banks. The credit agreement  expires in December 2000  and
allows the issuance of notes that bear interest at rates based on the prime rate
or various money market rates.

    The  company also  has two accounts  receivable sale programs.  The level of
funding available from these programs varies depending on the level of  eligible
accounts  receivable,  which fluctuates  seasonally.  Under these  programs, the
company may borrow another $37 million.

    On December 8,  1995, the company  obtained an extended  grace period for  a
long-term  debt to capitalization ratio covenant  from its creditor on its 9.21%
senior notes. The grace period extends to June 30, 1996. The company  classified
this  debt as long-term as  management believes it is  probable that the company
will meet  the  covenant ratio  by  June 30,  1996  and for  foreseeable  future
periods.

    FUTURE CASH REQUIREMENTS

    Future  cash requirements  include utility  plant additions,  dividends, and
required redemptions of long-term securities and acquisition opportunities.

                                       30
<PAGE>
    The company's estimated required funds for capital expenditures and maturing
long-term debts are shown below for the next five years.

<TABLE>
<CAPTION>
                                                                  1996       1997       1998       1999       2000
                                                                ---------  ---------  ---------  ---------  ---------
                                                                                     IN MILLIONS
<S>                                                             <C>        <C>        <C>        <C>        <C>
Electric......................................................  $   114.1  $   142.0  $    91.9  $    84.6  $    79.3
Gas...........................................................       61.1       49.0       46.3       45.5       40.7
Energy related................................................       54.6       35.6       39.5       34.2       35.9
Corporate and other...........................................       42.1       27.7        9.1        2.5        2.4
Maturing long-term debt.......................................       15.1       25.8      147.7      165.9      270.1
                                                                ---------  ---------  ---------  ---------  ---------
Total.........................................................  $   287.0  $   280.1  $   334.5  $   332.7  $   428.4
                                                                ---------  ---------  ---------  ---------  ---------
                                                                ---------  ---------  ---------  ---------  ---------
</TABLE>

    See the sections of this report  on electric operations, gas operations  and
energy related businesses for further details on capital expenditures.

    The  amounts shown for  corporate are primarily  the estimated investment in
software related  projects. The  company is  in the  process of  developing  new
integrated  financial management, materials  management and customer information
systems. These are  designed to  meet its  expanding informational  needs as  it
implements the Energy One-SM- strategy.

PENDING MERGER WITH KANSAS CITY POWER & LIGHT COMPANY (KCPL)

    On  January 19, 1996,  the company, KCPL  and KC United  Corp. (KCU) entered
into an Agreement and Plan of Merger (the Merger Agreement) which provides for a
strategic business combination of the  company and KCPL in a  "merger-of-equals"
transaction (the Transaction). Pursuant to the Merger Agreement, the company and
KCPL will merge with and into KCU (which may be renamed at the discretion of the
company  and KCPL),  a corporation  formed for  the purpose  of the Transaction.
Under the terms  of the  Merger Agreement, each  share of  the company's  common
stock  will be exchanged for 1.096 shares of  KCU common stock and each share of
KCPL common stock will be exchanged for one share of KCU common stock. Based  on
the  number of  shares of  the company's  common stock  and KCPL's  common stock
outstanding on  the  date  of  the  Merger  Agreement,  the  company'  s  common
shareholders  will receive  about 45%  of the  common equity  of KCU  and KCPL's
common shareholders will receive about 55%.

    The Transaction  is  designed to  qualify  as  a pooling  of  interests  for
accounting  and financial reporting  purposes. Under this  method of accounting,
the recorded assets  and liabilities of  the company and  KCPL would be  carried
forward  to  the  consolidated financial  statements  of KCU  at  their recorded
amounts. The income of KCU would include the combined income of the company  and
KCPL  as  though the  Transaction occurred  at the  beginning of  the accounting
period. The Prior periods would be combined and presented as those of KCU.

    The Transaction will create a diversified energy company with total combined
sales of over $3.5 billion and over $6.5 billion in total assets, serving  about
2.5  million customers  in the  United States,  Canada, the  United Kingdom, New
Zealand, Australia, China and  Jamaica. The business  of the combined  companies
will  consist of electric utility operations, gas utility operations and various
non-utility enterprises including independent power projects, and gas marketing,
gathering and processing operations.

    The Transaction is subject to approval from each company's shareholders  and
a number of regulatory authorities. The regulatory approvals process is expected
to  take  about  12 to  18  months.  The Merger  Agreement  includes termination
provisions which may require  certain payments to the  party to the  Transaction
under  certain  circumstances,  including  a  payment  of  $58  million  if  the
Transaction is terminated by a party and within two and one-half years following
such termination,  the terminating  party agrees  to consummate  or  consummates
certains business combination transactions.

                                       31
<PAGE>
PRICE RISK MANAGEMENT

    Effective  January 1, 1995, the company adopted the mark-to-market method of
accounting (MTM) for its  non-price regulated gas  trading business. Under  MTM,
natural  gas forwards, futures,  swaps, options and  other financial instruments
are recorded at  fair value,  net of future  servicing costs  and reserves,  and
recognized  as revenue upon contract execution in the Consolidated Statements of
Income. The resulting  unrealized gains and  losses are recorded  as Price  Risk
Management  Assets  and  Liabilities in  the  accompanying  Consolidated Balance
Sheets. The change  to MTM resulted  in an  increase in pretax  income of  $29.8
million  ($18.3  million after  tax) for  the  year ended  December 31,  1995 as
compared to  the  results under  the  previous accounting  method.  The  company
previously  accounted for this activity by the accrual method of accounting. The
company has not  shown the  pro forma  effect of the  adoption of  MTM on  prior
periods since the cumulative impact on prior period earnings was immaterial.

    The  impact in the current year primarily results from the effect of certain
contractual sales commitments which had been  designated as hedges of a  portion
of  the company's natural gas reserves. As discussed in Note 4, the company sold
its oil and gas reserves in September  1995. The resulting open position of  the
commitments   created  a  change  in  the   price  risk  management  assets  and
liabilities.

    Current period changes in  the assets and  liabilities from risk  management
activities  are recognized as revenues in the Consolidated Statements of Income.
The changes in the assets and liabilities primarily result from newly originated
transactions, changes in  the price of  natural gas, the  timing of  settlements
related  to these contracts and changes in the various risk reserves. The market
prices used to value  these transactions reflect  management's best estimate  of
market  prices  considering  various  factors,  including  closing  exchange and
over-the-counter quotations. The reserves are established for a number of  risks
and costs associated with the company's future commitments, including the credit
risks  of its counterparties, the time value of money, the impact of liquidating
the portfolio  in an  orderly manner  over  a reasonable  period of  time  under
present market conditions, and other identifiable contingencies.

    The  company  generally attempts  to  balance its  fixed-price  physical and
financial purchase  and sales  contracts  both volumetrically  and in  terms  of
future timing of the commitments. However, net open positions often exist or are
established  due  to  the  origination of  new  transactions  and  the company's
assessment, based upon information gained from its gas marketing activities,  of
future  price movements. As a result, the  company is to some extent affected by
fluctuating market prices. At  December 31, 1995, a  price movement of $.10  per
MCF  for natural gas would have impacted income from operations by approximately
$1.7 million.

    The change in accounting method does not impact the company's gas  marketing
activities  in the U.K. or its financial instruments associated with its natural
gas liquids hedging or electricity  brokering. The company enters into  futures,
forwards,  swaps and options  in order to hedge  purchase and sales commitments,
inventories and anticipated production of these products. Changes in the  market
value  of such transactions are deferred until the gain or loss is recognized on
the hedged commitment.

INCOME TAXES

    The level  of income  tax expense  during the  three-year period  fluctuated
generally  with  the level  of pretax  accounting income,  except for  1993. The
effective tax rate in 1993 was significantly affected by the non-taxable gain on
the sale of subsidiary stock and the passage of the Budget Reconciliation Act of
1993 (the Act.)

    As a result of the Act, the company made a retroactive adjustment to reflect
the increase in the  corporate tax rate  from 34% to  35%, effective January  1,
1993.  The rise in the tax rate  increased 1993 income tax expense approximately
$4.0 million, or $.10 per average common share. Deferred income tax  liabilities
from   regulated  operations  were  also   increased.  However,  because  it  is
anticipated these

                                       32
<PAGE>
additional taxes  would  be recovered  through  rates, a  regulatory  asset  was
established  and included in deferred charges in the accompanying balance sheet.
See Note 12 to the Consolidated Financial Statements for further discussion.

    The company has available approximately  $88 million of alternative  minimum
tax (AMT) credits. AMT credits have an indefinite life.

NEW ACCOUNTING STANDARD

    In  October 1995, the Financial  Accounting Standards Board issued Statement
of  Financial  Accounting  Standards   No.  123,  "Accounting  for   Stock-based
Compensation"  (SFAS  123).  SFAS 123  requires  companies to  either  record or
disclose pro forma information on the fair value of certain stock-based programs
including stock options and employee stock purchase plans. The company currently
provides stock options to certain employees  and has an employee stock  purchase
program  whereby employees may purchase company  common stock at a 15% discount.
Under SFAS 123, these  plans will require either  the recording of  compensation
expense  or pro forma disclosures  of net income and  earnings per share had the
company elected  to  record  compensation  expense.  The  company  has  not  yet
evaluated  the accounting  and reporting implications  of SFAS 123  and does not
have an estimate  of additional  compensation expense  associated with  affected
plans.  SFAS  123 is  required to  be  adopted in  fiscal years  beginning after
December 15, 1995.

EFFECTS OF INFLATION

    In the next few years, the company anticipates that the level of  inflation,
if  moderate, will  not have a  significant effect on  operations or acquisition
activity.

FORWARD-LOOKING INFORMATION

    This report contains  forward-looking information.  Such statements  involve
risks and uncertainties and there are certain important factors that could cause
actual  results  to  differ  materially  from  those  anticipated.  Some  of the
important factors which  could cause  actual results to  differ materially  from
those  anticipated include, but are not limited to, future national and regional
economic  and  competition  conditions,  inflation  rates,  regulatory  changes,
weather conditions, financial market conditions, interest rates, future business
decisions,  and other uncertainties,  all of which are  difficult to predict and
many of which are beyond the control of the company.

                                       33
<PAGE>
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1995        1994        1993
                                                                               ----------  ----------  ----------
                                                                                 IN MILLIONS, EXCEPT PER SHARE
<S>                                                                            <C>         <C>         <C>
Sales........................................................................  $  2,798.5  $  2,398.1  $  2,746.1
Cost of sales................................................................     1,881.8     1,575.8     1,960.6
                                                                               ----------  ----------  ----------
Gross profit.................................................................       916.7       822.3       785.5
                                                                               ----------  ----------  ----------
Operating, administrative and maintenance expense............................       511.6       448.8       430.9
Depreciation, depletion and amortization.....................................       145.4       145.5       140.8
Provision for asset impairments..............................................        34.6          --          --
Restructuring charge.........................................................          --          --        69.8
                                                                               ----------  ----------  ----------
Income from operations.......................................................       225.1       228.0       144.0
                                                                               ----------  ----------  ----------
Interest expense -- long-term debt...........................................       110.2        89.5        89.0
Interest expense -- short-term debt and other interest, net..................         3.2         6.9         1.5
Equity in earnings of investments and partnerships...........................       (23.8)      (18.3)      (16.4)
Gain on sale of subsidiary stock.............................................          --          --       (47.8)
Minority interests...........................................................         3.7         3.4         1.3
                                                                               ----------  ----------  ----------
Earnings before income taxes.................................................       131.8       146.5       116.4
                                                                               ----------  ----------  ----------
Income taxes.................................................................        52.0        52.1        30.0
                                                                               ----------  ----------  ----------
Net income...................................................................        79.8        94.4        86.4
                                                                               ----------  ----------  ----------
Preference dividends.........................................................         2.1         3.0         6.9
                                                                               ----------  ----------  ----------
Earnings Available for Common Shares.........................................  $     77.7  $     91.4  $     79.5
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
Weighted Average Common Shares Outstanding:
  Primary....................................................................       45.08       43.97       40.74
  Fully diluted..............................................................       45.47       45.18       44.27
                                                                               ----------------------------------
Earnings Per Common Share:
  Primary....................................................................  $     1.72  $     2.08  $     1.95
  Fully diluted..............................................................        1.71        2.06        1.92
                                                                               ----------------------------------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       34
<PAGE>
                          CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                                          DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1995        1994        1993
                                                                               ----------  ----------  ----------
                                                                                      DOLLARS IN MILLIONS
<S>                                                                            <C>         <C>         <C>
Current Assets:
  Cash and cash equivalents..................................................  $    110.7  $     67.2  $     55.9
  Funds on deposit...........................................................        41.2        44.8        14.4
  Accounts receivable, net...................................................       332.2       215.6       234.6
  Inventories and supplies, at average cost..................................       112.5       134.3       101.8
  Price risk management assets...............................................        26.4          --          --
  Prepayments and other......................................................        53.0        51.9        31.4
                                                                               ----------  ----------  ----------
Total current assets.........................................................       676.0       513.8       438.1
                                                                               ----------  ----------  ----------
Property, plant and equipment, net...........................................     2,279.6     2,266.4     2,159.1
                                                                               ----------  ----------  ----------
Investments in subsidiaries and partnerships.................................       574.4       148.5       102.7
                                                                               ----------  ----------  ----------
Price risk management assets.................................................       175.5          --          --
                                                                               ----------  ----------  ----------
Deferred charges.............................................................       180.4       182.4       150.6
                                                                               ----------  ----------  ----------
Total Assets.................................................................  $  3,885.9  $  3,111.1  $  2,850.5
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>

                      LIABILITIES AND SHAREOWNERS' EQUITY

<TABLE>
<S>                                                             <C>        <C>        <C>
Current Liabilities:
  Current maturities of long-term debt........................  $    15.1  $   138.8  $     1.8
  Short-term debt.............................................      288.6      182.4       70.0
  Accounts payable............................................      434.3      340.3      392.5
  Accrued liabilities.........................................       34.8       43.1       48.4
  Price risk management liabilities...........................       67.9         --         --
  Other.......................................................      107.1       89.0       52.1
                                                                ---------  ---------  ---------
Total current liabilities.....................................      947.8      793.6      564.8
                                                                ---------  ---------  ---------
Long-term liabilities:
  Long-term debt, net.........................................    1,355.4      976.9    1,009.7
  Deferred income taxes and credits...........................      279.2      300.4      235.0
  Price risk management liabilities...........................       94.6         --         --
  Other deferred credits......................................      137.2      108.0      105.4
                                                                ---------  ---------  ---------
Total long-term liabilities...................................    1,866.4    1,385.3    1,350.1
                                                                ---------  ---------  ---------
Company-obligated mandatorily redeemable preferred securities
 of partnership...............................................      100.0         --         --
                                                                ---------  ---------  ---------
Preferred and preference stock................................       25.4       25.4       83.9
                                                                ---------  ---------  ---------
Common shareowners' equity....................................      946.3      906.8      851.7
                                                                ---------  ---------  ---------
Commitments and contingencies.................................
                                                                ---------  ---------  ---------
Total Liabilities and Shareowners' Equity.....................  $ 3,885.9  $ 3,111.1  $ 2,850.5
                                                                ---------  ---------  ---------
                                                                ---------  ---------  ---------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       35
<PAGE>
           CONSOLIDATED STATEMENTS OF PREFERRED AND PREFERENCE STOCK

<TABLE>
<CAPTION>
                                                                                                  DECEMBER 31,
                                                                                         -------------------------------
                                                                                           1995       1994       1993
                                                                                         ---------  ---------  ---------
                                                                                         DOLLARS IN MILLIONS, EXCEPT PER
                                                                                                      SHARE
<S>                                                                                      <C>        <C>        <C>
Preference Stock, not mandatorily redeemable:
  $2.05 series, 1,000,000 shares.......................................................  $    25.0  $    25.0  $    25.0
Preference Stock, convertible and mandatorily redeemable:
  $1.775 series (2,885,000 shares outstanding at December 31, 1993)....................         --         --       58.5
Preferred Stock of Subsidiary, retractable.............................................         .4         .4         .4
                                                                                         ---------  ---------  ---------
Total Preferred and Preference Stock...................................................  $    25.4  $    25.4  $    83.9
                                                                                         ---------  ---------  ---------
                                                                                         ---------  ---------  ---------
</TABLE>

             CONSOLIDATED STATEMENTS OF COMMON SHAREOWNERS' EQUITY

<TABLE>
<CAPTION>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                                     -------------------------------
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                       DOLLARS IN MILLIONS, EXCEPT
                                                                                                PER SHARE
<S>                                                                                  <C>        <C>        <C>
Common Stock: authorized 100,000,000 shares, par value $1 per share, 45,965,952
 shares outstanding (44,827,135 at December 31, 1994 and 42,021,160 at December 31,
 1993)
  Balance beginning of year........................................................  $    44.8  $    42.0  $    35.4
  Issuance of common stock.........................................................        1.2        2.8        6.6
                                                                                     ---------  ---------  ---------
Balance end of year................................................................       46.0       44.8       42.0
                                                                                     ---------  ---------  ---------
Premium on Capital stock:
  Balance beginning of year........................................................      774.2      722.4      545.7
  Issuance of common stock.........................................................       26.4       51.8      177.1
  Other............................................................................         --         --        (.4)
                                                                                     ---------  ---------  ---------
Balance end of year................................................................      800.6      774.2      722.4
                                                                                     ---------  ---------  ---------
Retained Earnings:
  Balance beginning of year........................................................      107.0       93.4       81.5
  Net income.......................................................................       79.8       94.4       86.4
  Dividends on preference stock....................................................       (2.1)      (3.0)      (6.9)
  Dividends on common stock -- $1.72 per share in 1995, $1.70 in 1994, and $1.62 in
   1993............................................................................      (77.9)     (74.6)     (67.1)
  Reissuance of common stock.......................................................        (.6)      (3.2)       (.5)
                                                                                     ---------  ---------  ---------
Balance end of year................................................................      106.2      107.0       93.4
                                                                                     ---------  ---------  ---------
Treasury stock, at cost (227,587 shares at December 31, 1994)......................         --       (6.6)        --
                                                                                     ---------  ---------  ---------
Currency Translation Adjustment....................................................       (6.5)     (12.6)      (6.1)
                                                                                     ---------  ---------  ---------
Total Common Shareowners' Equity...................................................  $   946.3  $   906.8  $   851.7
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       36
<PAGE>
                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                                     -------------------------------
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Cash Flows From Operating Activities:
  Net income.......................................................................  $    79.8  $    94.4  $    86.4
  Adjustments to reconcile net income to net cash provided:
    Depreciation, depletion and amortization.......................................      155.6      147.1      146.0
    Gain on sale of subsidiary stock...............................................         --         --      (47.8)
    Restructuring charge...........................................................         --         --       69.8
    Provision for asset impairments................................................       34.6         --         --
    Net changes in price risk management assets and liabilities....................      (39.4)        --         --
    Deferred taxes and investment tax credits......................................      (21.2)      65.4      (14.8)
    Equity in earnings from investments and partnerships...........................      (23.8)     (18.3)     (16.4)
    Dividends from investments and partnerships....................................       18.6       13.7       16.4
    Changes in certain current assets and liabilities, net of effects of
     acquisitions and restructuring --
      Accounts receivable and accrued revenues.....................................     (167.4)      40.6       46.8
      Accounts receivable sold.....................................................       50.8      (21.5)     (10.9)
      Fuel and materials...........................................................       21.9      (32.6)      (7.6)
      Accounts payable.............................................................       93.9      (52.2)      13.9
      Accrued taxes................................................................       (6.7)      (7.3)      10.0
      Other........................................................................       29.7       18.4       11.4
    Changes in other assets and liabilities, net...................................       34.8      (18.4)     (13.9)
                                                                                     ---------  ---------  ---------
Cash provided from operating activities............................................      261.2      229.3      289.3
                                                                                     ---------  ---------  ---------
Cash Flows From Investing Activities:
  Additions to utility plant.......................................................     (109.4)    (132.0)    (140.5)
  Purchase of utility and other businesses.........................................     (100.9)     (28.2)     (99.0)
  Investments in international businesses..........................................     (379.3)        --         --
  Sale of subsidiary stock.........................................................         --         --       74.6
  Investments in non-regulated generating assets...................................      (59.0)     (22.2)     (28.8)
  Proceeds on sale of oil and gas properties.......................................      204.5         --         --
  Investments in energy related properties.........................................     (144.0)    (113.6)     (94.5)
  Other............................................................................      (46.8)     (50.3)      (6.5)
                                                                                     ---------  ---------  ---------
Cash used for investing activities.................................................     (634.9)    (346.3)    (294.7)
                                                                                     ---------  ---------  ---------
Cash Flows From Financing Activities:
  Issuance of common stock.........................................................       29.5        2.8      178.8
  Issuance of company-obligated mandatorily redeemable preferred securities of
   partnership.....................................................................      100.0         --         --
  Retirements of preference stock..................................................         --       (6.8)      (9.0)
  Treasury stock sold (acquired)...................................................        6.6       (6.6)        --
  Issuance of long-term debt, net of premium paid..................................      415.2      104.1      217.4
  Retirement of long-term debt.....................................................     (160.3)        --      (99.8)
  Short-term borrowings (repayments), net..........................................      106.2      112.4     (160.9)
  Cash dividends paid..............................................................      (80.0)     (77.6)     (74.4)
                                                                                     ---------  ---------  ---------
Cash provided from financing activities............................................      417.2      128.3       52.1
                                                                                     ---------  ---------  ---------
Increase in cash and cash equivalents..............................................       43.5       11.3       46.7
Cash and cash equivalents at beginning of year.....................................       67.2       55.9        9.2
                                                                                     ---------  ---------  ---------
Cash and Cash Equivalents at End of Year...........................................  $   110.7  $    67.2  $    55.9
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       37
<PAGE>
               NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    The consolidated financial statements of UtiliCorp United Inc. (the company,
a  Delaware corporation) include all  operating divisions and all majority-owned
subsidiaries. The company's  principal lines  of business are  electric and  gas
utility   operations,  gas  marketing,  gas  processing  and  independent  power
generation. The North American  utility businesses operate  in eight states  and
one  province of Canada. Natural gas is  marketed in 45 states and the company's
gas processing operations  are in Texas  and Oklahoma. In  addition to U.S.  and
Canadian  businesses,  the company  has  various investments  in  Australia, the
United Kingdom, New Zealand and  Jamaica. All significant intercompany  accounts
and transactions have been eliminated.

    The  preparation  of  financial  statements  in  conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported amounts  of  assets and  liabilities and
disclosure of contingent  assets and liabilities  at the date  of the  financial
statements  and  the  reported  amounts  of  revenues  and  expenses  during the
reporting  period.  Actual  results  could  differ  from  those  estimates.  The
company's   accounting  policies   conform  to   generally  accepted  accounting
principles which, in the case of the company's utility operations, consider  the
impact of rate regulation.

    MINORITY INTERESTS.  Minority interests represent the minority stockholders'
proportionate share of the stockholders' equity and net income, primarily Aquila
Gas Pipeline Corporation (AGP). The company also owns majority interest in a gas
marketing  company in the  United Kingdom and  in a company  that invests in New
Zealand electric utilities.

    REGULATION.  The company's utility  operations are subject to regulation  by
various   regulatory  authorities.  The  company  currently  applies  accounting
standards  that  recognize  the  economic   effects  of  rate  regulation   and,
accordingly,  has  recorded regulatory  assets related  to the  company's energy
generation, transmission and distribution  operations. The table below  presents
the  amount of regulatory assets  recorded at December 31,  1995, 1994 and 1993,
respectively.

<TABLE>
<CAPTION>
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Income taxes.......................................................................  $    53.7  $    72.3  $    66.2
Environmental liabilities..........................................................       10.4       10.9        9.3
Debt related costs.................................................................       23.8       21.9       24.0
Regulatory accounting orders.......................................................        7.8        8.3        8.8
Demand side management programs....................................................        8.6        5.0        3.3
Post-retirement benefits...........................................................        8.5        7.9        5.4
Purchased gas and related costs....................................................        3.3        4.2        5.8
Other (including FERC Order No. 636)...............................................       30.3       31.6       14.8
                                                                                     ---------  ---------  ---------
Total..............................................................................  $   146.4  $   162.1  $   137.6
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>

    UTILITY PLANT AND DEPRECIATION.  Utility  plant is stated at original  cost.
Repair  and  maintenance  costs  are  expensed  as  incurred.  When  property is
replaced, removed or  abandoned, its cost,  together with the  costs of  removal
less salvage, is charged to accumulated depreciation.

    For   financial   statement  purposes,   depreciation   is  provided   on  a
straight-line basis over the estimated lives of depreciable property by applying
composite average  annual rates,  ranging  from 3.0%  to  4.6%, as  approved  by
regulatory authorities.

    The  excess of total acquisition costs over the aggregate regulated value of
net assets acquired to date is included in utility plant ($164.7 million, net of
$32.0 million in  accumulated amortization at  December 31, 1995)  and is  being
amortized on a straight-line basis over periods ranging from 15 to 40 years.

                                       38
<PAGE>
    OIL AND GAS PROPERTIES.  Oil and gas properties were accounted for using the
full  cost method. Under the full cost method, all costs associated with gas and
oil property acquisition, exploration and development, including  non-productive
costs,  were capitalized. See Note 4 for discussion of the sale of substantially
all of the company's oil and gas production assets.

    The provision for  depreciation, depletion and  amortization was  determined
using  the units of production method over  the estimated lives of the producing
properties based on  estimated quantities of  proved reserves. Amortization  per
MCF  equivalent  averaged  $1.27,  $1.44  and  $1.27  in  1995,  1994  and 1993,
respectively.  Gathering,  processing  and  other  energy  related  property  is
depreciated using a composite average annual rate of 5.0%.

    SALES   RECOGNITION,  PURCHASED   GAS  ADJUSTMENTS   AND  ENERGY  ADJUSTMENT
CLAUSES.   Sales are  generally recognized  when the  products or  services  are
delivered,  except price  risk management activities.  See below  for price risk
management policy. Gas sales and the company's electric utility sales in  Kansas
and West Virginia are subject to adjustment clauses. Differences between amounts
collected and allowable costs are recorded as over- or under-recovered gas costs
and fuel and purchased power costs in accordance with the ratemaking policies of
regulatory authorities.

    Beginning  with the 1995  annual financial statements,  the company began to
present gas marketing sales  and cost of gas  separately. Previously net  margin
was  included in sales.  The effect of  this change is  reflected in all periods
presented. A comparison of previously reported amounts to 1995's presentation is
presented below:

<TABLE>
<CAPTION>
                                                                                              1994        1993
                                                                                           ----------  ----------
                                                                                            DOLLARS IN MILLIONS
<S>                                                                                        <C>         <C>
Total sales as previously reported.......................................................  $  1,514.6  $  1,571.6
Aquila's gas marketing sales.............................................................       596.8       953.4
Reclassification of businesses from other income, net to respective income statement
 captions................................................................................       286.7       221.1
                                                                                           ----------  ----------
Total Sales..............................................................................  $  2,398.1  $  2,746.1
                                                                                           ----------  ----------
                                                                                           ----------  ----------
</TABLE>

    Effective January 1, 1995, the company adopted the mark-to-market method  of
accounting   for  its  domestic  natural  gas  trading  activities,  principally
conducted by  Aquila  Energy  Corporation,  a  wholly-owned  subsidiary  of  the
company.  Under mark-to-market  accounting, the  company's domestic  natural gas
trading  contracts,   including  both   physical  transactions   and   financial
instruments,  are  recorded at  fair value,  net of  future servicing  costs and
reserves, and recognized as sales or expense upon contract execution. Changes in
the market  value of  this contract  portfolio (resulting  primarily from  newly
originated  transactions and  the impact of  price movements)  are recognized as
gains or losses  in the  period of change.  The resulting  unrealized gains  and
losses are recorded as price risk management assets and liabilities.

    The  company's prior method recognized gains  and losses when the underlying
physical commodity was  sold. The  change was made  to more  fairly present  the
current  results of  the company's  operations related  to this  business and to
recognize that value is created and  the earnings process is completed when  the
contractual  commitments are finalized. The effect of this change was immaterial
for prior periods and increased 1995  sales and income from operations by  $29.8
million ($18.3 million after tax).

    The  impact in the current year primarily results from the effect of certain
contractual sales commitments which had been  designated as hedges of a  portion
of  the company's natural gas reserves. As discussed in Note 4, the company sold
its oil and gas reserves in September  1995. The resulting open position of  the
commitments   created  a  change  in  the   price  risk  management  assets  and
liabilities.

                                       39
<PAGE>
    ACCOUNTING FOR  FINANCIAL  INSTRUMENTS.   As  indicated above,  the  company
accounts  for  financial instruments  associated with  its domestic  natural gas
trading activities using the mark-to-market method.

    Activities for non-trading purposes consist of transactions entered into  by
the  company's other  businesses to hedge  the impact of  market fluctuations on
assets, liabilities, or  other contractual  commitments. Changes  in the  market
value  of these transactions are  deferred until the gain  or loss on the hedged
item is recognized.

    INCOME TAXES.   The company accounts  for income taxes  using the  liability
method. Under this method, deferred tax assets and liabilities are determined by
applying  tax  regulations existing  at the  end  of a  reporting period  to the
cumulative temporary differences between the tax bases of assets and liabilities
and their reported amounts in the financial statements. Deferred investment  tax
credits  are amortized over the lives of the related properties. No provision is
made  for  U.S.  income  taxes  on  undistributed  earnings  of  the   company's
international  businesses  ($9.5 million  at December  31,  1995) because  it is
management's  intention  to  reinvest  such  earnings  in  those   international
operations. Consolidated income before income taxes for the years ended December
31,  1995, 1994 and 1993, included  $11.2, $9.1 and $10.7 million, respectively,
from international operations.

    CASH EQUIVALENTS AND CASH FLOW INFORMATION.  Cash equivalents are defined as
temporary cash  investments with  a maturity  of  three months  or less.  As  of
December  31, 1995, 1994 and 1993, the  company had cash of $77.5 million, $58.5
million and $52.2 million, respectively, held in foreign countries.

    Cash payments for interest and taxes and supplemental disclosure relating to
acquisition activities are presented below:

<TABLE>
<CAPTION>
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Cash paid during the year for --
  Interest, net of amount capitalized..............................................  $   135.4  $   100.3  $    94.5
  Income taxes.....................................................................       46.9       11.4       24.5
                                                                                     -------------------------------
Liabilities assumed in acquisitions --
  Fair value of assets acquired....................................................  $   114.0  $    35.9  $   106.3
  Cash paid for acquisitions.......................................................      100.9       28.2       99.0
  Liabilities assumed..............................................................       13.1        7.7        7.3
                                                                                     -------------------------------
</TABLE>

    EARNINGS PER COMMON SHARE.  Primary  earnings per common share are  computed
on the basis of the weighted average number of common shares outstanding.

    Fully  diluted earnings  per common  share assume  conversion of convertible
subordinated debentures and  convertible preference stock  for the periods  they
were outstanding and dilutive.

    CONCENTRATION    OF    FOREIGN   OPERATIONS    AND    CURRENCY   TRANSLATION
ADJUSTMENTS.  As of  December 31, 1995,  1994 and 1993,  the company had  18.5%,
9.5%  and 10.0%, respectively, of its  assets denominated in foreign currencies.
Management believes the economies in which its international businesses  operate
are  stable. Changes in the  value of these foreign  currencies affect asset and
liability value, and income and loss contributions.

    The financial statements  of foreign  operations have  been translated  into
U.S.  dollars using  the weighted  average exchange  rates for  income statement
items and  year-end  exchange  rates  for balance  sheet  items.  The  resulting
translation adjustments increase or decrease common shareowners' equity.

    RECLASSIFICATIONS.  Certain prior year amounts in the consolidated financial
statements  have  been  reclassified  where necessary  to  conform  to  the 1995
presentation.

                                       40
<PAGE>
                        NOTE 2: MERGER AND ACQUISITIONS

PROPOSED MERGER -- KANSAS CITY POWER & LIGHT COMPANY (KCPL)

    On January 19,  1996, the company,  KCPL and KC  United Corp. (KCU)  entered
into an Agreement and Plan of Merger (the Merger Agreement) which provides for a
strategic  business combination of the company  and KCPL in a "merger-of-equals"
transaction (the Transaction). Pursuant to the Merger Agreement, the company and
KCPL will merge with and into KCU (which may be renamed at the discretion of the
company and KCPL),  a corporation  formed for  the purpose  of the  Transaction.
Under  the terms  of the  Merger Agreement, each  share of  the company's common
stock will be exchanged for 1.096 shares  of KCU common stock and each share  of
KCPL  common stock will be exchanged for one share of KCU common stock. Based on
the number  of shares  of the  company's common  stock and  KCPL's common  stock
outstanding   on  the  date  of  the  Merger  Agreement,  the  company's  common
shareholders will  receive about  45% of  the common  equity of  KCU and  KCPL's
common shareholders will receive about 55%.

    The  Transaction  is  designed to  qualify  as  a pooling  of  interests for
accounting and financial  reporting purposes.  Under this  method, the  recorded
assets  and liabilities of the company and  KCPL would be carried forward to the
consolidated financial statements of KCU  at their recorded amounts. The  income
of  KCU would include the combined income of  the company and KCPL as though the
merger occurred  at  the  beginning  of  the  accounting  period.  Prior  period
financial statements would be combined and presented as KCU.

    The Transaction will create a diversified energy company with total combined
sales  of over  $3.5 billion, over  $6.5 billion  in total assets  and about 2.5
million customers in the United States, Canada, the United Kingdom, New Zealand,
Australia, China  and  Jamaica. The  business  of the  combined  companies  will
consist  of electric utility operations, gas utility operations and various non-
utility enterprises  including independent  power  projects and  gas  marketing,
gathering and processing operations.

    The  Transaction is subject to approval from each company's shareholders and
a number of regulatory authorities. The regulatory approvals process is expected
to take  about  12 to  18  months.  The Merger  Agreement  includes  termination
provisions  which may require  certain payments to the  party to the Transaction
under  certain  circumstances,  including  a  payment  of  $58  million  if  the
Transaction is terminated by a party and within two and one-half years following
such  termination,  the terminating  party agrees  to consummate  or consummates
certains business combination transactions.

INTEREST IN AUSTRALIAN ELECTRIC UTILITY

    On September 6,  1995, Power  Partnership Pty  Limited (PPL),  of which  the
company owns 49.9 %, acquired United Energy Limited (UE), an Australian electric
distribution utility, from the State of Victoria. The company paid approximately
$257.9 million for its 49.9 % ownership interest in PPL. The company manages the
operations  of  UE  on behalf  of  PPL  and receives  an  annual  management fee
consisting of a base amount indexed to  the consumer price index and a  variable
amount based on UE's financial performance. The management agreement extends for
10 years from date of acquisition.

    The  company financed its ownership interest primarily through two five-year
Australian-dollar-based revolving  credit  facilities.  See  Note  10  for  more
information  regarding financing arrangements  and interest rate  swaps used for
risk management purposes.

    The acquisition was recorded as a  purchase and PPL's results are  accounted
for  using the  equity method  of accounting.  The purchase  price was allocated
based on estimated fair  values at the  date of the  acquisition. The excess  of
purchase  price over  the fair  value of  assets was  approximately $634 million
including approximately $450 million related to a license fee, and is  reflected
as  various intangible assets on PPL's  financial records. The equity investment
is included in Investments in Subsidiaries and Partnerships on the  Consolidated
Balance  Sheet. See  Note 8 for  more information  regarding year-end investment
balance and equity in  earnings. Pro forma unaudited  results of operations  for
the  company, assuming the acquisition occurred  at the beginning of the period,
are shown below. For the

                                       41
<PAGE>
1994 period, the pro forma results include UE's results for the 12 months  ended
June  30,  1995. UE  began  operations on  July 1,  1994,  and the  1995 amounts
represent the most comparable figures for the pro forma table.

<TABLE>
<CAPTION>
                                                                                                 YEAR ENDED
                                                                                                DECEMBER 31,
                                                                                           ----------------------
                                                                                              1995        1994
                                                                                           ----------  ----------
                                                                                            IN MILLIONS, EXCEPT
                                                                                                 PER SHARE
<S>                                                                                        <C>         <C>
Sales....................................................................................  $  2,798.5  $  2,398.1
Income from operations...................................................................       225.1       228.0
Net income...............................................................................        81.7        89.9
Earnings available for common shares.....................................................        79.6        86.9
                                                                                           ----------------------
Primary earnings per share...............................................................  $     1.76  $     1.98
Fully diluted earnings per share.........................................................        1.75        1.96
                                                                                           ----------------------
</TABLE>

INTEREST IN NEW ZEALAND ELECTRIC UTILITIES

    On November  30, 1995,  UtiliCorp  N.Z., Inc.  (UNZ),  a subsidiary  of  the
company,  acquired 20.0% of the common stock of Power New Zealand Limited (PNZ),
a  New  Zealand  electric  distribution  utility,  from  Todd  Corporation   for
approximately  $69.4  million.  This  acquisition  was  financed  through  a New
Zealand-dollar-denominated credit facility. PNZ is New Zealand's second  largest
electric  distribution  utility,  serving approximately  214,000  customers. UNZ
owned 7.5% of PNZ prior to completing the transaction with Todd Corporation  and
owned  approximately 27.5% of PNZ as of December 31, 1995. Todd Corporation is a
21% shareholder in UNZ.

    In February 1995, UNZ paid $16.1  million to WEL Energy Group Limited  (WEL)
to satisfy its capital commitment. UNZ now participates in WEL's earnings to the
full  extent of  its ownership.  Prior to the  payment of  the remaining capital
commitment, UNZ's participation in WEL's earnings  was limited to 5%. WEL is  an
electric distribution utility serving approximately 65,000 customers.

OTHER ACQUISITIONS

    On  May 22, 1995,  the company and UtilCo  Group, a wholly-owned subsidiary,
acquired a  50% interest  in an  independent power  project in  Alabama for  $59
million. The project sells its generation output to a paper processing plant.

    On  January 5, 1995, the company purchased a 218-mile intrastate natural gas
pipeline system in Missouri from Edisto Resources Corporation for $78 million.

    On January 17, 1995,  the company acquired Broad  Street Oil and Gas  (Broad
Street),  a gas marketing company, for  $7.0 million. Broad Street sells natural
gas to approximately 10,000 commercial customers in nine states.

    On January 17, 1995, AGP acquired  Tristar Gas Company for $16.3 million  in
cash.  Based in Texas,  Tristar gathers, processes, and  markets natural gas and
natural gas liquids.

    In September  1994, the  company acquired  the Kansas  gas distribution  and
selected  pipeline properties of  NorAm Energy Corp.  (NorAm) for $23.0 million.
The Kansas system serves approximately 22,000 customers.

    In February 1993, the  company acquired a  Nebraska gas distribution  system
from  NorAm  for $106  million, including  $21 million  in working  capital. The
Nebraska system serves approximately 124,000 customers.

                         NOTE 3: PRICE RISK MANAGEMENT

    PRICE RISK MANAGEMENT ACTIVITIES.  The company offers price risk  management
services primarily for the commodity of natural gas. These services are provided
through a variety of financial

                                       42
<PAGE>
instruments, including forward contracts which commit the company to purchase or
sell  natural gas in the future; swap  agreements, which require payments to (or
receipt of payments from) counterparties  based on the differential between  two
prices  for the commodity  specified by the swap;  futures and options contracts
traded on  the  New York  Mercantile  Exchange (NYMEX);  and  other  contractual
arrangements.

    The  availablity and use  of these types  of contracts allow  the company to
manage and hedge its  contractual commitments, reduce  its exposure relative  to
the  volatility  of cash  market prices,  take  advantage of  selected arbitrage
opportunities  via  open  positions  and  protect  its  investment  in   storage
inventories.  The company is also able  to secure additional sources of physical
natural gas supply or create additional markets for existing supply through  the
use of exchange for physical (EFP) transactions allowed by NYMEX. The management
of  these types of transactions  is referred to herein  as price risk management
activities.

    MARKET RISK.    The  company's  price  risk  management  activities  involve
offering fixed price commitments into the future. At December 31, 1995, the term
of  the natural gas  portfolio extended to  the year 2008.  Although the company
generally attempts  to balance  its  physical and  financial purchase  and  sale
contracts  in terms of  quantities and contract  performance, net open positions
often exist or are  established due to the  origination of new transactions  and
the  company's assessment of,  and response to,  changing market conditions. The
company will at times create a net open position or allow a net open position to
continue when it believes, based upon competitive information acquired from  its
energy marketing activities, that future price movements will be consistent with
its  net open position. To the extent that  the company has an open position, it
is exposed to the risk that  fluctuating market prices may adversely impact  its
financial  position  or results  from  operations. The  company  has established
trading policies and exposure  limits that are monitored  and reviewed. A  price
movement  of  $.10 per  MCF  for natural  gas at  December  31, 1995  would have
impacted income from operations by approximately $1.7 million.

    MARKET VALUATION.    The market  prices  used to  value  these  transactions
reflect  management's best estimate of market prices considering various factors
including closing exchange and over-the-counter quotations, time value of  money
and price volatility factors underlying the commitments. These market prices are
adjusted  to reflect the potential impact  of liquidating the company's position
in an  orderly manner  over a  reasonable period  of time  under present  market
conditions.

    The  company has considered a number of  risks and costs associated with the
future commitments that are included in the market valuation of the natural  gas
portfolio,  including credit  risks associated  with the  financial condition of
counterparties, product  location (basis)  differentials and  other risks  which
management  policy dictates. A  calculation of the  time value of  money is also
applied to all  contracts. The  company continuously monitors  the valuation  of
identified risks and adjusts them based on present market conditions.

    The counterparties in the company's portfolio consist primarily of financial
institutions,  oil  and  gas  companies  and  independent  power  producers. The
creditworthiness of the company's counterparties may impact its overall exposure
to   credit   risk,    either   positively   or    negatively.   However,    the

                                       43
<PAGE>
company  maintains  credit  policies  with  regard  to  its  counterparties that
management believes minimizes overall credit risk. The following table  displays
the mark-to-market results of the company's natural gas transactions at December
31, 1995 and the average value for the year ended December 31, 1995:

<TABLE>
<CAPTION>
                                                                         PRICE RISK                  PRICE RISK
                                                                     MANAGEMENT ASSETS         MANAGEMENT LIABILITIES
                                                                 --------------------------  --------------------------
                                                                  AVERAGE VALUE   12/31/95    AVERAGE VALUE   12/31/95
                                                                 ---------------  ---------  ---------------  ---------
                                                                                  DOLLARS IN MILLIONS
<S>                                                              <C>              <C>        <C>              <C>
Independent power producers....................................     $    93.6     $   187.6     $      --     $      --
Financial institutions.........................................           2.9           9.1          30.6          38.6
Oil and gas producers..........................................            .6           2.0          12.0          30.7
Gas transmission...............................................            .9           2.4           4.8          19.7
Other..........................................................           1.2           3.3           0.7           2.9
                                                                        -----     ---------         -----     ---------
Gross value....................................................          99.2         204.4          48.1          91.9
Reserves.......................................................            --            --          36.2          70.6
                                                                        -----     ---------         -----     ---------
Total..........................................................     $    99.2     $   204.4     $    84.3     $   162.5
                                                                        -----     ---------         -----     ---------
                                                                        -----     ---------         -----     ---------
Net value......................................................                   $    41.9
                                                                                  ---------
                                                                                  ---------
</TABLE>

    Three independent power producers comprise the majority of the Company's net
price  risk management assets. The  concentration of customers, which fluctuates
with changes in market conditions, may impact the company's overall exposure  to
credit  risk,  either positively  or negatively,  in that  the customers  may be
similarly affected by changes in economic, regulatory or other conditions.

                             NOTE 4: RESTRUCTURINGS

AQUILA RESTRUCTURING

    In the fourth quarter  of 1993, the Aquila  Energy subsidiary implemented  a
new  business strategy and  recorded a $69.8 million  charge against income ($45
million after tax) for disposal of  selected gas sales contracts, impairment  of
certain  offshore assets, and other restructuring  costs. Since then, Aquila has
been settling various contracts and reducing this reserve. In the first  quarter
of  1995, Aquila completed its restructuring  plan. The net contract settlements
were more favorable  than originally anticipated  in 1993, resulting  in a  $5.0
million  and $5.4 million positive adjustment  to income from operations for the
years ended December 31, 1995 and 1994.

AGP PUBLIC OFFERING

    In October 1993, AGP  completed an initial public  offering and sale of  5.4
million  shares of  common stock,  representing approximately  18% of  its total
shares outstanding. Net proceeds  of the offering were  about $74.6 million  and
were  used to reduce short-term debt incurred for working capital purposes. This
transaction resulted  in a  gain  of $47.8  million, recorded  as  non-operating
income  in the Consolidated Statement of  Income. Consistent with U.S. tax laws,
no income tax expense was recorded related to this gain.

SALE OF OIL AND GAS ASSETS

    On September 27, 1995,  the company sold assets  of Aquila Energy  Resources
Corporation,  a wholly-owned subsidiary of Aquila Energy, for approximately $205
million in  cash,  which approximated  their  carrying value.  The  assets  sold
consisted of substantially all of the company's oil and gas reserves.

                                       44
<PAGE>
                          NOTE 5: ACCOUNTS RECEIVABLE

    The  components  of accounts  receivable,  net on  the  Consolidated Balance
Sheets are:

<TABLE>
<CAPTION>
                                                                                    1995       1994       1993
                                                                                  ---------  ---------  ---------
<S>                                                                               <C>        <C>        <C>
                                                                                            IN MILLIONS
Accounts receivable, net........................................................  $   405.1  $   261.7  $   297.1
Unbilled revenue................................................................       95.5       71.5       76.6
Financing program...............................................................     (168.4)    (117.6)    (139.1)
                                                                                  ---------  ---------  ---------
Total...........................................................................  $   332.2  $   215.6  $   234.6
                                                                                  ---------  ---------  ---------
                                                                                  ---------  ---------  ---------
</TABLE>

    The company  has  agreements  with  financial institutions  to  sell,  on  a
continuing  basis,  up to  $205  million of  eligible  accounts receivable  on a
limited recourse basis. Fees associated with these sales were approximately  (in
millions)  $8.6 in  1995, $6.9  in 1994  and $5.4  in 1993  and are  included in
interest expense in the accompanying Consolidated Statements of Income.

                     NOTE 6: PROPERTY, PLANT AND EQUIPMENT

    The components of property, plant and equipment, net are as follows:

<TABLE>
<CAPTION>
                                                                                  1995        1994        1993
                                                                               ----------  ----------  ----------
                                                                                          IN MILLIONS
<S>                                                                            <C>         <C>         <C>
Electric utility.............................................................  $  1,645.0  $  1,578.7  $  1,526.6
Gas utility..................................................................     1,064.8       954.6       896.3
Gas gathering and pipeline systems...........................................       547.0       440.0       419.8
Oil and gas properties.......................................................      --           416.7       337.2
Other non-regulated plant....................................................       106.2        88.3        80.9
Construction in process......................................................        47.6        23.3        22.3
                                                                               ----------  ----------  ----------
                                                                                  3,410.6     3,501.6     3,283.1
Less -- depreciation, depletion and amortization.............................     1,131.0     1,235.2     1,124.0
                                                                               ----------  ----------  ----------
Net Property, Plant and Equipment............................................  $  2,279.6  $  2,266.4  $  2,159.1
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>

    JOINTLY OWNED ELECTRIC  UTILITY PLANT.   The company holds  an 8%  ownership
interest  in  three  coal-fired,  approximately  600-megawatt  generating  units
(Jeffrey Energy Center or JEC) and leases  another 8% of JEC energy output.  The
JEC is operated by another utility. At December 31, 1995, electric utility plant
and   accumulated  depreciation  included  $100.8  million  and  $43.2  million,
respectively, related to the company's investment in JEC. The pro rata share  of
JEC expenses is reflected in the Consolidated Statements of Income.

                           NOTE 7: ASSET IMPAIRMENTS

    In  1995 the company  reviewed its long-lived asset  carrying value and also
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). In  the fourth  quarter of  1995, the  company recorded  a non-cash
charge of  approximately  $34.6 million  for  long-term asset  impairments.  The
assets related to this charge are summarized below:

<TABLE>
<CAPTION>
                                                                    PRETAX WRITEDOWN
                                                                    -----------------
                                                                       IN MILLIONS
<S>                                                                 <C>
Investment in an independent
 power project (UtilCo Group).....................................      $    15.4
Gas gathering systems (AGP).......................................           13.2
Gas processing plants.............................................            6.0
                                                                            -----
Total.............................................................      $    34.6
                                                                            -----
                                                                            -----
</TABLE>

                                       45
<PAGE>
    The  impairment loss related to UtilCo Group's investment in a power project
was primarily caused  by a change  in the  projected cash flows  of the  project
after  considering updated projections of future energy prices. This resulted in
the write-off of the remaining investment balance.

    The impairment loss  relating to AGP's  gas gathering systems  stems from  a
review of cash flows on a system-by-system basis. Prior to adoption of SFAS 121,
AGP  assessed  asset realization  at  a cash  flow  level higher  than  SFAS 121
requires. In preparing  cash flow  projections related to  AGP's assets  certain
assumptions  were  used.  The  more  significant  assumptions  included constant
throughput flow based on 1994 actual throughput for an estimated remaining  life
of  20 years. Cash flows were discounted based on AGP's weighted average cost of
capital.

    The impairment loss  relating to gas  processing plants relate  to a  review
conducted after the sale of Aquila's oil and gas properties. These company-owned
plants were managed as part of Aquila's properties, but were not part of Aquila.
In  assessing these plants separately under the principles of SFAS 121, the cash
flows from these assets were not sufficient to recover the carrying value of the
plants.

              NOTE 8: INVESTMENTS IN SUBSIDIARIES AND PARTNERSHIPS

    The consolidated financial statements  include the company's investments  in
electric  distribution utilities  in Australia (via  UtiliCorp Australia Holding
Limited [UAHL])  and  New Zealand  (via  UNZ),  five U.K.  gas  marketing  joint
ventures  (via UtiliCorp U.K., Limited) and 17 power projects (via UtilCo Group)
accounted  for  under  the  equity  method.  For  the  company's   international
businesses,  adjustments for all significant  differences between U.S. generally
accepted accounting principles and local accounting standards have been made  to
the amounts included in the company's consolidated financial statements.
<TABLE>
<CAPTION>
                                                                            INVESTMENT DECEMBER 31, (A)      SHARE OF PRETAX
                                                                                                                 EARNINGS
                                                                          -------------------------------  --------------------
                                            OWNERSHIP       COUNTRY         1995       1994       1993       1995       1994
                                           -----------  ----------------  ---------  ---------  ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                        <C>          <C>               <C>        <C>        <C>        <C>        <C>
UAHL investment..........................       49.9%   Australia.......  $   257.9  $      --  $      --  $     1.3  $      --
UNZ investments:
  WEL Energy Group Ltd. (d)..............         39%        New Zealand       39.1       24.3         --        2.2         .2
  PNZ....................................       27.5%        New Zealand      107.1         --         --         --         --
UtiliCorp U.K., Limited investments
 (c).....................................         25%     United Kingdom         --        1.4        2.5       (1.6)      (1.1)
UtilCo Group partnerships (b)(c).........     22%-50%     U.S. & Jamaica      170.3      122.8      100.2       21.9       19.2
                                                                          ---------  ---------  ---------  ---------  ---------
                                                                          $   574.4  $   148.5  $   102.7  $    23.8  $    18.3
                                                                          ---------  ---------  ---------  ---------  ---------
                                                                          ---------  ---------  ---------  ---------  ---------

<CAPTION>

                                             1993
                                           ---------

<S>                                        <C>
UAHL investment..........................  $      --
UNZ investments:
  WEL Energy Group Ltd. (d)..............         --
  PNZ....................................         --
UtiliCorp U.K., Limited investments
 (c).....................................        1.4
UtilCo Group partnerships (b)(c).........       15.0
                                           ---------
                                           $    16.4
                                           ---------
                                           ---------
</TABLE>

------------------------
(a) Investment  exceeds interest  in the  underlying company  or partnership net
    assets.  Acquisition  and  transaction  costs  included  in  the  investment
    balances  are being  amortized on a  straight-line basis  over the remaining
    lives of the related assets.

(b) Investment and share of pretax earnings include the James River project, 49%
    owned by the company and 1% owned by UtilCo.

(c) Investments are aggregated. Individual investments are not significant.

(d) Prior to February  1995, the  company's participation in  WEL's results  was
    limited to 5%.

                                       46
<PAGE>
    Summarized  combined financial information of unconsolidated material equity
investments is presented below.

<TABLE>
<CAPTION>
                                                                                             DECEMBER 31,
                                                                                   --------------------------------
                                                                                      1995       1994       1993
                                                                                   ----------  ---------  ---------
                                                                                         DOLLARS IN MILLIONS
<S>                                                                                <C>         <C>        <C>
Assets
  Current assets.................................................................  $    336.5  $   115.7  $   111.2
  Non-current assets.............................................................     2,785.3      855.5      881.0
                                                                                   ----------  ---------  ---------
  Total assets...................................................................  $  3,121.8  $   971.2  $   992.2
                                                                                   ----------  ---------  ---------
                                                                                   ----------  ---------  ---------
Liabilities and Equity
  Current liabilities............................................................  $    276.5  $    93.7  $    92.3
  Non-current liabilities........................................................     2,125.6      694.8      735.8
  Equity.........................................................................       719.7      182.7      164.1
                                                                                   ----------  ---------  ---------
  Total liabilities and equity...................................................  $  3,121.8  $   971.2  $   992.2
                                                                                   ----------  ---------  ---------
                                                                                   ----------  ---------  ---------
Operating Results
  Revenues.......................................................................  $    729.6  $   352.8  $   313.1
  Costs and expenses.............................................................       657.3      299.7      269.2
                                                                                   ----------  ---------  ---------
  Net income.....................................................................  $     72.3  $    53.1  $    43.9
                                                                                   ----------  ---------  ---------
                                                                                   ----------  ---------  ---------
</TABLE>

                            NOTE 9: SHORT-TERM DEBT

    Short-term debt outstanding at December 31, 1995, 1994 and 1993 is comprised
of the following items:

<TABLE>
<CAPTION>
                                                                                  1995        1994        1993
                                                                               ----------  ----------  ----------
                                                                                      DOLLARS IN MILLIONS
<S>                                                                            <C>         <C>         <C>
Bank borrowing (uncommitted).................................................  $    153.1  $    155.4  $     70.0
Commercial paper.............................................................       135.5        27.0          --
                                                                               ----------  ----------  ----------
Total........................................................................  $    288.6  $    182.4  $     70.0
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
Weighted average interest rate at year end...................................        6.14%       6.20%       3.51%
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>

    The company  has  commercial paper  programs  aggregating $150  million.  To
support  the  programs, the  company  has a  revolving  credit agreement  with a
consortium of banks  aggregating $250  million. The  revolving credit  agreement
allows  the issuance of  notes which bear  interest at rates  based on the prime
rate or  various money  market rates.  The revolving  credit agreement  contains
restrictive  covenants and the company pays an  annual commitment fee of .17% on
the revolving credit agreement.

       NOTE 10: LONG-TERM DEBT AND COMPANY-OBLIGATED PREFERRED SECURITIES

    The company's long-term debt is summarized below.

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                               ----------------------------------
DOLLARS IN MILLIONS                                                               1995        1994        1993
                                                                               ----------  ----------  ----------
<S>                                                                            <C>         <C>         <C>
First Mortgage Bonds:
  Various, 9.92%*, due 1996-2008.............................................  $     23.0  $     23.0  $     36.1
Senior Notes:
  9.30% Series, due December 1, 1995.........................................          --       125.0       125.0
  6.0% Series, due April 1, 1998.............................................        70.0        70.0        70.0
  9.21% Series, due October 11, 1999.........................................        50.0        50.0        50.0
  8.45% Series, due November 15, 1999........................................       100.0       100.0          --
</TABLE>

                                       47
<PAGE>
<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                               ----------------------------------
DOLLARS IN MILLIONS                                                               1995        1994        1993
                                                                               ----------  ----------  ----------
  Aquila Southwest Energy 8.29% Series, due September 15, 2002...............        87.5       100.0       100.0
<S>                                                                            <C>         <C>         <C>
  6.375% Series, due June 1, 2005............................................       100.0          --          --
  8.2% Series, due January 15, 2007..........................................       130.0       130.0       130.0
  10.5% Series, due December 1, 2020.........................................       125.0       125.0       125.0
  9.0% Series, due November 15, 2021.........................................       150.0       150.0       150.0
  8.0% Series, due March 1, 2023.............................................       125.0       125.0       125.0
Secured Debentures of West Kootenay Power:
  9.98%*, due 1995-2023......................................................        50.3        54.0        57.9
Subordinated Debentures:
  6.625%, due July 1, 2011...................................................         8.0        20.7        23.9
New Zealand Denominated Credit Facility......................................        63.6          --          --
Australian Denominated Credit Facility.......................................       222.8          --          --
Other Notes and Obligations..................................................        65.3        43.0        18.6
                                                                               ----------  ----------  ----------
Total Long-Term Debt (including current maturities)..........................  $  1,370.5  $  1,115.7  $  1,011.5
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>

------------------------
*Weighted average interest rate.

    The amount  of long-term  debt maturing  in  each of  the next  five  years,
including  sinking fund provisions, is as  follows (in millions): 1996 -- $15.1;
1997 -- $25.8; 1998 -- $147.7; 1999 -- $165.9; and 2000 -- $270.1.

    In June 1995, the company issued $100 million of 6.375% Senior Notes due  in
2005.  Net proceeds of  $99.3 million were  used to reduce  short-term debt. The
Notes are the initial securities issued under a $200 million shelf  registration
of debt securities.

    In  November 1994, the company issued $100 million of 8.45% Senior Notes due
in 1999. The net proceeds of $99.5  million were used to reduce short-term  debt
incurred for construction and acquisitions, and for general corporate purposes.

    In  June 1995, UtiliCorp  Capital L.P. (UC), a  limited partnership of which
the company is the general partner, issued 4,000,000 shares of 8.875% Cumulative
Monthly Income Preferred  Securities, Series  A, for $100  million. The  limited
partnership  interests represented by the preferred securities are redeemable at
the option  of UC,  after June  12, 2000,  at $25  per preferred  security  plus
accrued interest and unpaid dividends. Holders of the securities are entitled to
receive  dividends at  an annual  rate of  8.875% of  the liquidation preference
value of $25. Dividends are payable monthly and in substance are tax  deductible
by  the  company.  The  securities are  shown  as  Company-Obligated Mandatorily
Redeemable Preferred Securities  of a  Partnership on  the Consolidated  Balance
Sheet. The net proceeds were used to reduce short-term debt.

    UtiliCorp   South   Pacific,   Inc.   (USP)   has   a   $135   million   New
Zealand-dollar-denominated credit facility with a  consortium of banks that  was
utilized  to finance a portion of the  investment made by UNZ. The interest rate
floats with changes  in the New  Zealand bank  bill rate. The  interest rate  at
December  31, 1995, was 8.98% and matures February 28, 1998. A commitment fee of
 .20% applies to the unused portion of the credit facility.

    UAHL has  two  5-year  credit  facilities ($225  million  and  $100  million
[Australian])  with  a consortium  of banks  that were  utilized to  finance the
ownership interest  in  UE.  The  interest  rate  floats  with  changes  in  the
Australian  bank bill rate.  The weighted average interest  rate at December 31,
1995 was 7.91%. A commitment  fee of .20% applies to  the unused portion of  the
credit facility. Borrowings from this facility are considered long-term as it is
the  company's intention to  repay borrowed funds  over periods extending beyond
one year.

                                       48
<PAGE>
    On November 6, 1995, UAHL entered into an interest rate swap agreement  with
Deutsche Bank with a contractual amount of $100 million (Australian) whereby the
company exchanges variable Australian debt interest for fixed rate interest. The
fixed interest rate is 7.77% for a period extending to September 7, 1998.

    On  December 8, 1995,  the company obtained  an extended grace  period for a
long-term debt to capitalization ratio covenant  from its creditor on its  9.21%
senior  notes. The grace period extends to June 30, 1996. The debt obligation is
classified as long-term debt  in the Consolidated  Balance Sheet, as  management
believes  it is probable that  the company will meet  the covenant ratio by June
30, 1996 and for the foreseeable future periods.

    Substantially all of  the domestic  utility plant  owned by  the company  is
subject  to the  lien of various  mortgage indentures. The  company cannot issue
additional mortgage  bonds  under  these mortgage  indentures  without  directly
securing  the 6.0%, 8.45%, 8.2%,  9.0%, 8.0% and 6.375%  Senior Notes equally as
any mortgage bond issue.  Currently the company has  no plans to issue  mortgage
bonds.

    The  company executed an  Indenture in 1990 (Indenture)  for the issuance of
senior  notes.  Notes  issued  pursuant  to  the  Indenture  will  be  unsecured
obligations  of the company and  will rank on a  parity with all other unsecured
and subordinate indebtedness of the company.

    At December 31,  1995, 6.625% convertible  subordinated debentures  totaling
$8.0  million  remained  outstanding.  The  debentures  can  be  converted  into
approximately 340,000 shares  of common stock,  based on a  conversion price  of
$23.68,  subject to an annual maximum limitation. The debentures are subordinate
to the  prior payment,  when due,  of the  principal and  premium, if  any,  and
interest on all the company's debt outstanding, except debt that by its terms is
not senior in right of payment to the debentures.

                             NOTE 11: CAPITAL STOCK

    As  of December 31,  1995, the company  was not restricted  as to payment of
cash dividends.

    The Board of Directors of the  company (the Board) is authorized to  approve
the  issuance of  up to  20 million shares  of Class  A common  stock, $1.00 par
value. No shares of Class A common stock are issued or outstanding.

    DIVIDEND REINVESTMENT AND COMMON STOCK PURCHASE PLAN.  On February 16, 1995,
the company  registered 3  million shares  of  common stock  to initiate  a  new
Dividend  Reinvestment  and Common  Stock Purchase  Plan  (New Plan).  Under the
provisions of this New Plan, current and potential shareholders can purchase  up
to  $10,000 per month of the company's common stock at a five-day average market
price and without  sales commissions. The  New Plan allows  members to  reinvest
dividends into additional common stock at a 5% discount. The New Plan amends the
previous  plan and all members in the previous plan automatically became members
in the New Plan.

    EMPLOYEE STOCK  PURCHASE PLAN.   Participants  have the  opportunity to  buy
shares  of the company's common stock at a reduced price through regular payroll
deductions and/or lump sum deposits of up to 20% of the employee's base  salary.
Contributions  are credited  to the  participant's account  throughout an option
period. At the end of the option period, the participant's total account balance
is applied to  the purchase  of common  shares of  the company.  The shares  are
purchased  at 85% of the lower of the market  price on the first day or the last
day of the option period.  Participants must be enrolled in  the Plan as of  the
first day of an option period in order to participate in that option period.

    RESTATED  SAVINGS PLAN.   A defined contribution  plan, the Restated Savings
Plan (Savings Plan) covers all full-time and eligible part-time employees of the
company. Participants may generally elect

                                       49
<PAGE>
to contribute up  to 12% of  their annual pay  on a before-  or after-tax  basis
subject  to certain limitations. The  company generally matches contributions up
to  6%.  Participants  may  direct  their  contributions  into  five   different
investment  options.  All company  matching contributions  are in  the company's
common stock. In addition, the Savings  Plan also includes a stock  contribution
fund  whereby the company can contribute  an additional amount of company common
stock to participants.

    STOCK AWARDS AND STOCK OPTIONS.  The company's Stock Incentive Plan provides
for the  granting of  common shares  to certain  employees as  restricted  stock
awards and as stock options.

    Shares  issued  as restricted  stock awards  are held  by the  company until
certain restrictions lapse, generally on the third award anniversary. The market
value of the stock, when awarded, is amortized to compensation expense over  the
three-year period.

    Stock  options granted under the Plan allow the purchase of common shares at
a price  not less  than fair  market value  at the  date of  grant. Options  are
generally  exercisable commencing  with the first  anniversary of  the grant and
expire after 10 years from the date of grant.

    Subject to regulatory and  shareholder approval, on  September 8, 1995,  the
company  granted up to 619,325  shares of the company's  common stock to certain
key individuals at an exercise price of $27.25 per share.

    The Board approved  the establishment of  an Employee Stock  Option Plan  in
1991.  This Plan provides for  the granting of up to  1 million stock options to
full-time employees other than those eligible to receive options under the Stock
Incentive Plan. Stock options granted under the Employee Stock Option Plan carry
the same provisions as those issued under the Stock Incentive Plan. During 1992,
options for 742,900  shares were  granted to  employees. The  exercise price  of
these  options is $27.3125.  No options have  been issued under  this Plan since
1992.

    At December 31, 1995, restricted stock  awards and stock options which  were
exercisable totaled 165,735 shares.

    Stock options as of December 31, 1995, 1994 and 1993 are summarized below:

<TABLE>
<CAPTION>
                                                                  1995              1994              1993
                                                            ----------------  ----------------  ----------------
                                                                                   SHARES
<S>                                                         <C>               <C>               <C>
Beginning balance.........................................         1,273,797         1,188,007         1,061,857
Granted...................................................           858,975           203,650           221,650
Exercised.................................................           (11,900)          (98,910)          (82,400)
Cancelled.................................................           (55,500)          (18,950)          (13,100)
                                                            ----------------  ----------------  ----------------
Ending balance............................................         2,065,372         1,273,797         1,188,007
                                                            ----------------  ----------------  ----------------
                                                            ----------------  ----------------  ----------------
Grant price range.........................................     $17.40-$31.63     $17.40-$31.63     $17.40-$28.69
Exercise price range......................................  $   21.88-$28.56  $   21.50-$28.69  $   21.50-$18.69
</TABLE>

    MANDATORILY  REDEEMABLE CONVERTIBLE PREFERENCE STOCK.  In February 1994, the
Board authorized the redemption of all  outstanding shares of the $1.775  Series
Convertible  Preference  Stock.  During  the  1994  first  and  second quarters,
approximately 1.3  million and  1.5  million shares  of  the $1.775  stock  were
converted  into approximately 2.7 million shares  of common stock. The remaining
approximately 100,000 shares were redeemed on May 26, 1994 at a price of  $21.60
per share plus accrued dividends.

                                       50
<PAGE>
                             NOTE 12: INCOME TAXES

    Income tax expense consists of the following components:

<TABLE>
<CAPTION>
                                                                                          YEAR ENDED DECEMBER 31,
                                                                                      -------------------------------
                                                                                        1995       1994       1993
                                                                                      ---------  ---------  ---------
                                                                                            DOLLARS IN MILLIONS
<S>                                                                                   <C>        <C>        <C>
Currently Payable:
  Federal...........................................................................  $    35.4  $    15.3  $    23.1
  Foreign...........................................................................       10.6        5.2        4.9
  State.............................................................................       11.3       (1.5)      (2.2)
Deferred:
  Federal
    Accelerated depreciation........................................................        6.0       14.3       27.0
    Alternative minimum tax.........................................................       (4.7)     (20.4)     (23.2)
    Restructuring charge............................................................        2.8        7.9      (23.7)
    Intangible drilling costs.......................................................      (27.3)      15.2       10.0
    Purchased gas adjustment clauses................................................        2.8        (.6)       1.9
    Federal tax rate increase.......................................................         --         --        2.7
    Provision for asset impairments.................................................      (12.4)        --         --
    Price risk management assets and liabilities....................................       11.5         --         --
    Other...........................................................................       17.7        9.8        5.1
  State.............................................................................        (.4)       8.2        5.7
Investment Tax Credit Amortization..................................................       (1.3)      (1.3)      (1.3)
                                                                                      ---------  ---------  ---------
Total Income Tax Expense............................................................  $    52.0  $    52.1  $    30.0
                                                                                      ---------  ---------  ---------
                                                                                      ---------  ---------  ---------
</TABLE>

    In  August 1993, passage of the Budget  Reconciliation Act of 1993 (the Act)
increased the statutory federal income tax rate  from 34% to 35%. This tax  rate
change increased income tax expense by approximately $4.0 million, of which $2.7
million  represented a non-cash adjustment  to increase deferred tax liabilities
as of January 1, 1993.

    The  company  has  an  alternative   minimum  tax  credit  carryforward   of
approximately  $88 million at December 31, 1995. Alternative minimum tax credits
can be carried forward indefinitely and the company has not recorded a valuation
allowance against its tax credit carryforwards.

    The principal components of the  company's deferred income taxes consist  of
the following:

<TABLE>
<CAPTION>
                                                                                              DECEMBER 31,
                                                                                     -------------------------------
                                                                                       1995       1994       1993
                                                                                     ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Deferred Tax Assets:
  Alternative minimum tax credit carryforward......................................  $    88.2  $    83.5  $    73.8
  Net operating loss carryforward..................................................         --       26.3       19.0
  Restructuring charges............................................................         --       16.0       25.0
                                                                                     ---------  ---------  ---------
Total deferred tax assets..........................................................       88.2      125.8      117.8
                                                                                     ---------  ---------  ---------
Deferred Tax Liabilities:
  Accelerated depreciation and other plant differences
    Regulated......................................................................      160.9      176.5      163.1
    Non-regulated..................................................................      140.2      168.7      128.4
  Regulatory asset -- SFAS 109.....................................................       33.8       32.8       25.8
  Other, net.......................................................................       32.5       27.2       13.4
                                                                                     ---------  ---------  ---------
Total deferred tax liabilities.....................................................      367.4      405.2      330.7
                                                                                     ---------  ---------  ---------
Deferred income taxes, net.........................................................  $   279.2  $   279.4  $   212.9
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>

                                       51
<PAGE>
    The company's effective income tax rates differed from the statutory federal
income tax rates primarily due to the following:

<TABLE>
<CAPTION>
                                                                                             YEAR ENDED DECEMBER 31,
                                                                                      -------------------------------------
                                                                                         1995         1994         1993
                                                                                      -----------  -----------  -----------
<S>                                                                                   <C>          <C>          <C>
Statutory Federal Income Tax Rate...................................................       35.0%        35.0%        35.0%
Tax effect of:
  Temporary differences passed through, primarily removal costs.....................        (.5)        (1.3)         (.8)
  Investment tax credit amortization................................................       (1.0)         (.9)        (1.1)
  Gain on sale of subsidiary stock..................................................         --           --        (14.4)
  State income taxes, net of federal benefit........................................        4.3          3.1          2.4
  Federal tax rate increase.........................................................         --           --          2.3
  Difference in tax rate of foreign subsidiaries....................................        1.3          1.9           .8
  Other.............................................................................         .4         (2.2)         1.6
                                                                                            ---          ---        -----
Effective Income Tax Rate...........................................................       39.5%        35.6%        25.8%
                                                                                            ---          ---        -----
                                                                                            ---          ---        -----
</TABLE>

                           NOTE 13: EMPLOYEE BENEFITS

    PENSIONS.   The following table represents  the funded status of the pension
plans and the amounts included in the Consolidated Balance Sheets and Statements
of Income:

<TABLE>
<CAPTION>
                                                                                YEAR ENDED DECEMBER 31,
                                                                      -------------------------------------------
                                                                          1995           1994           1993
                                                                      -------------  -------------  -------------
                                                                                  DOLLARS IN MILLIONS
<S>                                                                   <C>            <C>            <C>
Actuarial present value of benefit obligations:
  Vested benefit obligation.........................................  $     143.0    $     119.4    $     113.5
  Accumulated benefit obligation....................................        146.9          122.6          116.5
                                                                      -------------  -------------  -------------
                                                                      -------------  -------------  -------------
Projected benefit obligation........................................  $     183.9    $     152.1    $     144.6
Plan assets at fair value (primarily publicly traded common stocks
 and bonds)*........................................................        191.7          161.4          168.3
                                                                      -------------  -------------  -------------
                                                                      -------------  -------------  -------------
Excess of plan assets over the projected benefit obligation.........          7.8            9.3           23.7
Unrecognized net loss from past experience different from that
 assumed............................................................         24.1           22.0            7.2
Unrecognized net asset being recognized over 16 years...............        (12.5)         (13.7)         (15.6)
Unrecognized prior service cost.....................................          (.3)           (.7)            .1
                                                                      -------------  -------------  -------------
Pension asset included in prepayments...............................  $      19.1    $      16.9    $      15.4
                                                                      -------------  -------------  -------------
                                                                      -------------  -------------  -------------
Net pension expense included the following components:
  Service cost......................................................  $       5.8    $       5.6    $       5.3
  Interest cost on projected benefit obligation.....................         12.0           11.0           10.4
  Actual return on plan assets......................................        (37.6)            .6          (16.9)
  Regulatory adjustment.............................................           .6             .5             .3
  Net amortization and deferral.....................................         20.5          (16.7)           2.2
                                                                      -------------  -------------  -------------
Net pension expense.................................................  $       1.3    $       1.0    $       1.3
                                                                      -------------  -------------  -------------
                                                                      -------------  -------------  -------------
Discount rate assumed...............................................         7.17%          7.89%          7.89%
Assumed rate of return on future compensation levels................      5.0-5.5%       5.0-5.5%       5.0-5.5%
Assumed long-term rate of return on assets..........................     8.5-10.0%       8.5-9.0%       8.5-9.0%
</TABLE>

------------------------
*Includes $1.1 million of the company's convertible preference stock at December
 31, 1993. No  convertible preference stock  was held at  December 31, 1995  and
 1994.

                                       52
<PAGE>
    The company has pension plans covering substantially all qualified union and
non-union  employees. The benefit formulas vary and are based either on years of
service multiplied by a percentage of salary, or a flat benefit based upon years
of service.

    The company's policy is to fund, at a minimum, an amount sufficient to  meet
all ERISA funding requirements. In certain of its jurisdictions, the company has
recorded  pension expense equal to its funding contribution, consistent with the
rate treatment allowed for this cost.

    In 1995 the company changed its long-term view on pension fund asset returns
and increased its estimated return on domestic plan assets to 10%.

    OTHER POST-RETIREMENT BENEFITS.  The company provides post-retirement health
care and  life insurance  benefits  to certain  employees.  A majority  of  such
retirees pay a portion of the cost of the benefits.

    The  following table summarizes the  status of the company's post-retirement
plans for financial statement  purposes and the related  amount included in  the
Consolidated Balance Sheets at December 31, 1995, 1994 and 1993:

<TABLE>
<CAPTION>
                                                                                               DECEMBER 31,
                                                                                      -------------------------------
                                                                                        1995       1994       1993
                                                                                      ---------  ---------  ---------
                                                                                            DOLLARS IN MILLIONS
<S>                                                                                   <C>        <C>        <C>
Actuarial present value of post-retirement benefit obligations:
  Retirees..........................................................................  $    23.1  $    24.1  $    29.5
  Other fully eligible participants.................................................        6.0        7.6        9.0
  Other active participants.........................................................       11.1        8.3        6.8
  Plan assets at fair value.........................................................        (.9)       (.3)        --
  Unrecognized transition obligation................................................      (34.4)     (36.4)     (41.0)
  Unrecognized net gain (loss)......................................................        5.2        3.3       (1.8)
                                                                                      ---------  ---------  ---------
Accrued liability...................................................................  $    10.1  $     6.6  $     2.5
                                                                                      ---------  ---------  ---------
                                                                                      ---------  ---------  ---------
</TABLE>

    The components of health care and life insurance costs are:

<TABLE>
<CAPTION>
                                                                                                      DECEMBER 31,
                                                                                             -------------------------------
                                                                                               1995       1994       1993
                                                                                             ---------  ---------  ---------
                                                                                                   DOLLARS IN MILLIONS
<S>                                                                                          <C>        <C>        <C>
Service cost...............................................................................  $      .8  $      .6  $      .6
Interest cost..............................................................................        2.7        2.9        3.4
Return on plan assets......................................................................         --         --         --
Amortization of transition obligation......................................................        2.0        2.0        2.0
Net amortization and deferral..............................................................        (.2)        --         --
                                                                                                   ---        ---        ---
Net health care and life insurance costs...................................................  $     5.3  $     5.5  $     6.0
                                                                                                   ---        ---        ---
                                                                                                   ---        ---        ---
</TABLE>

    The  following  actuarial assumptions  were used  in calculating  the plan's
year-end funded status:

<TABLE>
<CAPTION>
                                                                                 1995         1994         1993
                                                                              ----------  ------------  ----------
<S>                                                                           <C>         <C>           <C>
Discount rate...............................................................        7.0%         7.75%       7.75%
Health care cost trend rate.................................................    10%-6%      12.5%-6%      14%-6%
</TABLE>

    The rate  of change  in health  care cost  has an  effect on  the  projected
benefit obligation. Increasing the rate by 1% each year would have increased the
present  value of the  accumulated projected benefit  obligation by $2.4 million
and the aggregate of the service and interest cost components by $.3 million  in
1995.

    Pursuant  to regulatory orders or precedents, certain regulated divisions of
the company have deferred as a regulatory asset the incremental costs associated
with SFAS No. 106. At December 31, 1995, the amount deferred was $8.5 million.

                                       53
<PAGE>
                     NOTE 14: COMMITMENTS AND CONTINGENCIES

    COMMITMENTS.  The company has various commitments for the years 1996 through
2000 relating primarily to power and  gas supply commitments, fixed price  sales
obligations and lease and rental commitments. A table of the company's estimated
capital expenditures and more significant estimated commitments follows.

<TABLE>
<CAPTION>
                                                                  1996       1997       1998       1999       2000
                                                                ---------  ---------  ---------  ---------  ---------
                                                                        DOLLARS IN MILLIONS, EXCEPT PER UNIT
<S>                                                             <C>        <C>        <C>        <C>        <C>
Capital expenditures..........................................  $   271.9  $   254.3  $   186.8  $   166.8  $   158.3
Future minimum lease payments.................................       21.4       19.7       20.1       18.8       17.2
Purchased power obligations...................................       44.1       44.3       41.5       37.6       33.3
Coal contracts................................................       43.1       43.3       45.0       46.8       34.3
  Price ranges................................................  $12.92 to $28.84 per ton
Fixed price sales obligations (BCF)...........................       17.6       17.6       17.6       17.6       17.0
  Price ranges................................................  $1.71 to $4.06 per MCF
Fixed price purchase obligations (BCF)........................        9.2        9.1        7.3        7.3        7.3
  Price ranges................................................  $2.70 to $3.20 per MCF
</TABLE>

    Future  minimum lease payments primarily relate to the JEC interest, peaking
turbines, coal cars, and office space. Rent expense for the years 1995, 1994 and
1993 was (in millions) $25.9, $26.4 and $25.7, respectively.

    Purchased power obligations for 1996  through 2000 are estimated to  provide
916; 921; 896; 856; and 628 MW, respectively.

    FINANCIAL  GUARANTEES AND CAPITAL COMMITMENTS.  At December 31, 1995, UtilCo
Group had unconditional capital commitments to fund partnership capital in  1996
aggregating $11.6 million.

    UtiliCorp  U.K. Limited  (a subsidiary of  UtiliCorp U.K., Inc.,  which is a
75%-owned subsidiary of  the company) is  a 25% equity  partner in Midlands  Gas
Limited  (MGL), a gas  marketing joint venture with  Midlands Electricity Plc (a
United Kingdom electric  utility). On  behalf of MGL,  Midlands Electricity  Plc
provided  three financial performance guarantees to producers, each supported by
financial guarantees by the company for its 25% share of the contracts.

    UtiliCorp U.K.  Limited is  also  a 25%  equity  partner in  Caledonian  Gas
Limited  (CGL), a gas  marketing company, with Scottish  Power, a United Kingdom
electric utility. As part of the  agreement with Scottish Power, UtiliCorp  U.K.
Limited  is  required to  provide  funds to  CGL  proportional to  its ownership
interest, up  to 2.5  million British  pounds (approximately  $3.9 million).  No
capital calls have been made pursuant to this agreement.

    Both  of these joint ventures are  anticipated to require additional funding
due to commitments to purchase gas under long-term contracts at prices which are
currently above market. The company is in discussion with its partners in  these
two  joint ventures regarding  these matters. Although the  company has not paid
any amounts to date, the company accrued a reserve of $11.0 million in  December
1995.  Based on current views of the market and the plans of the joint ventures,
the company believes that  the resolution of these  matters will not  materially
effect the financial position or results of operations of the company.

    The  company or its subsidiaries have  other financial guarantees related to
business activities in  the United Kingdom,  but management believes  it is  not
probable that such guarantees will be called.

    ENVIRONMENTAL.    The  company  is subject  to  various  environmental laws,
including regulations  governing  air and  water  quality and  the  storage  and
disposal  of  hazardous or  toxic wastes.  The company  assesses, on  an ongoing
basis, measures  to  ensure compliance  with  laws and  regulations  related  to
hazardous materials and hazardous waste compliance and remediation activities.

                                       54
<PAGE>
    The  company owns or  previously operated 29  former manufactured gas plants
(MGPs) which may, or  may not, require some  form of environmental  remediation.
The  company has contacted appropriate federal and  state agencies and is in the
process of determining what, if any,  specific cleanup activities may be  needed
at these sites.

    As  of December 31,  1995, the company has  spent approximately $7.0 million
for investigating and remediating its MGP sites. The company currently estimates
that it will spend a minimum of approximately $6.2 million over the next several
years on  the  company's  identified  MGP  sites.  These  amounts  could  change
materially  based  upon  further investigations,  the  actions  of environmental
agencies and the financial viability of other responsible parties. Additionally,
the ultimate liability  may be  significantly affected  if the  company is  held
responsible for parties not financially able to contribute to these costs. Based
on  prior experience, available facts and existing law, the company has recorded
a liability  of  $6.2  million  representing  its  estimate  of  the  amount  of
environmental costs currently expected to be incurred.

    The  company  has  received  favorable  rate  orders  for  recovery  of  its
environmental cleanup costs  in certain jurisdictions.  In other  jurisdictions,
favorable  regulatory  precedent exists  for the  recovery  of these  costs. The
company is also pursuing recovery from insurance carriers and other  potentially
responsible parties.

    It   is  management's  opinion   that  the  ultimate   resolution  of  these
environmental matters will not have a material adverse impact upon the financial
position or results of operations of the company.

    OTHER.  The company is subject to various legal proceedings and claims which
arise in  the  ordinary  course  of  business  operations.  In  the  opinion  of
management, the amount of liability, if any, with respect to these actions would
not  materially affect the consolidated financial position of the company or its
results of operations.

              NOTE 15: FAIR VALUE OF CERTAIN FINANCIAL INSTRUMENTS

    Cash and cash  equivalents and  short-term debt  are carried  at cost  which
approximates  fair  value.  The  fair value  of  long-term  debt  and redeemable
preference stock 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.

    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 preference stock would not have a material effect on the company's
financial position or results of operations.

<TABLE>
<CAPTION>
                                                  CARRYING AMOUNT                        FAIR VALUE
                                         ----------------------------------  ----------------------------------
                                            1995        1994        1993        1995        1994        1993
                                         ----------  ----------  ----------  ----------  ----------  ----------
                                                                  DOLLARS IN MILLIONS
<S>                                      <C>         <C>         <C>         <C>         <C>         <C>
Long-term debt, including current
 maturities............................  $  1,370.5  $  1,115.7  $  1,011.5  $  1,473.6  $  1,094.4  $  1,127.9
Redeemable preference stock............          --          --        58.5          --          --        88.7
Note receivable........................        21.4        22.9        24.3        21.4        22.9        24.3
Interest rate swap.....................          --          --          --         (.6)         --          --
Investment in convertible subordinated
 notes.................................       129.7          --          --       129.7          --          --
Investment in floating rate
 subordinated debt.....................        92.7          --          --        92.7          --          --
</TABLE>

    The company enters into forwards, futures and other contracts related to its
commodity businesses. At December 31, 1995 and 1994, the company had natural gas
financial   instruments  with  a  contractual  volume  of  1,327  and  310  BCF,
respectively, expiring in 2008. As of December 31, 1995 and 1994 the future cash
flow  requirements,  net  of  margin   deposits,  related  to  these   financial
instruments  was $44.2 and $9.9 million, respectively. Financial instruments are
used to manage fluctuations in

                                       55
<PAGE>
price on the portfolio of natural gas transactions. The estimated fair value and
cash flow requirements for these financial  instruments are based on the  market
prices  in effect at the financial statement date and do not necessarily reflect
the company's entire trading portfolio.

                          NOTE 16: SEGMENT INFORMATION

<TABLE>
<CAPTION>
                                                                                         DECEMBER 31,
                                                                             ------------------------------------
                                                                                1995         1994         1993
                                                                             ----------  ------------  ----------
                                                                                     DOLLARS IN MILLIONS
<S>                                                                          <C>         <C>           <C>
Sales:
  Electric.................................................................  $    577.7   $    557.0   $    546.9
  Gas......................................................................       616.8        618.6        686.1
  Energy related businesses................................................     1,171.0        935.8      1,292.0
  Other....................................................................       433.0        286.7        221.1
                                                                             ----------  ------------  ----------
  Total Sales..............................................................  $  2,798.5   $  2,398.1   $  2,746.1
                                                                             ----------  ------------  ----------
                                                                             ----------  ------------  ----------
Depreciation, Depletion and Amortization:
  Electric.................................................................  $     53.7   $     49.9   $     45.9
  Gas......................................................................        34.3         30.1         28.6
  Energy related businesses................................................        49.6         59.6         60.8
  Other....................................................................         7.8          5.9          5.5
                                                                             ----------  ------------  ----------
  Total Depreciation, Depletion and Amortization...........................  $    145.4   $    145.5   $    140.8
                                                                             ----------  ------------  ----------
                                                                             ----------  ------------  ----------
Income (Loss) From Operations:
  Electric.................................................................  $    127.4   $    125.3   $    119.4
  Gas......................................................................        68.3         61.8         65.7
  Energy related businesses................................................        68.4         43.4        (32.9)
  Other....................................................................       (39.0)        (2.5)        (8.2)
                                                                             ----------  ------------  ----------
  Total Income From Operations.............................................  $    225.1   $    228.0   $    144.0
                                                                             ----------  ------------  ----------
                                                                             ----------  ------------  ----------
Identifiable Assets:
  Electric.................................................................  $  1,200.2   $  1,164.6   $  1,162.0
  Gas......................................................................       900.0        819.9        716.9
  Energy related businesses................................................       873.1        717.1        604.2
  Other....................................................................       912.6        409.5        367.4
                                                                             ----------  ------------  ----------
  Total Assets.............................................................  $  3,885.9   $  3,111.1   $  2,850.5
                                                                             ----------  ------------  ----------
                                                                             ----------  ------------  ----------
Capital Expenditures:
  Electric.................................................................  $     69.5   $     81.3   $     87.4
  Gas......................................................................        39.9         50.7         53.1
  Energy related businesses................................................       144.0        113.6         94.5
                                                                             ----------  ------------  ----------
  Total Capital Expenditures...............................................  $    253.4   $    245.6   $    235.0
                                                                             ----------  ------------  ----------
                                                                             ----------  ------------  ----------
</TABLE>

                                       56
<PAGE>
     NOTE 17: SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

    The table  below  presents  the  results of  operations  from  oil  and  gas
producing  activities. Substantially all  related assets were  sold in the third
quarter of 1995, as discussed in Note 4. Accordingly, all disclosures on oil and
gas activities required by  Statement of Financial  Accounting Standards No.  69
have been eliminated.

<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,
                                                                               -------------------------------
                                                                                 1995       1994       1993
                                                                               ---------  ---------  ---------
                                                                                     DOLLARS IN MILLIONS
<S>                                                                            <C>        <C>        <C>
Oil and gas sales............................................................  $    57.5  $    73.3  $    78.2
                                                                               ---------  ---------  ---------
Expenses:
  Production costs...........................................................       15.9       17.5       18.9
  Depreciation, depletion and amortization...................................       29.4       41.1       39.6
                                                                               ---------  ---------  ---------
Total Expenses...............................................................       45.3       58.6       58.5
                                                                               ---------  ---------  ---------
Results before income taxes..................................................       12.2       14.7       19.7
Income taxes.................................................................        4.3        5.1        6.9
                                                                               ---------  ---------  ---------
Results of Operations........................................................  $     7.9  $     9.6  $    12.8
                                                                               ---------  ---------  ---------
                                                                               ---------  ---------  ---------
</TABLE>

                 NOTE 18: QUARTERLY FINANCIAL DATA (UNAUDITED)

    Due to the timing of acquisitions, the effect of weather on sales, and other
factors  characteristic  of utility  operations  and energy  related businesses,
financial results for interim periods  are not necessarily indicative of  trends
for any 12-month period.

<TABLE>
<CAPTION>
                                                     1995 QUARTERS (A)                             1994 QUARTERS
                                         ------------------------------------------  ------------------------------------------
                                           FIRST     SECOND      THIRD     FOURTH      FIRST     SECOND      THIRD     FOURTH
                                         ---------  ---------  ---------  ---------  ---------  ---------  ---------  ---------
                                                                      IN MILLIONS EXCEPT PER SHARE
<S>                                      <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Sales..................................  $   726.3  $   600.8  $   607.5  $   863.9  $   773.5  $   516.3  $   491.5  $   616.8
Income from operations.................       81.5       34.9       81.8       26.9       82.4       31.5       43.3       70.8
Net income.............................       32.2        7.2       32.9        7.5       39.0        7.4       14.5       33.6
                                         --------------------------------------------------------------------------------------
Earnings per common share:
  Primary (b)..........................  $     .71  $     .15  $     .72  $     .15  $     .88  $     .15  $     .31  $     .76
  Fully diluted (c)....................        .70        .15        .71        .15        .85        .15        .31        .74
                                         ---------  ---------  ---------  ---------  ---------  ---------  ---------  ---------
                                         ---------  ---------  ---------  ---------  ---------  ---------  ---------  ---------
Cash dividend per common share.........  $     .43  $     .43  $     .43  $     .43  $     .42  $     .42  $     .43  $     .43
Market price per common share:
  High.................................  $   29.50  $   29.00  $   28.50  $   29.63  $   31.63  $   31.38  $   29.75  $   27.75
  Low..................................      26.25      27.25      26.63      27.50      29.00      28.00      26.25      25.38
</TABLE>

------------------------------
(a) Restated for accounting change. See Note 1.

(b)  The sum of  the quarterly primary  earnings per share  amounts differs from
    that reflected in the Consolidated Statements of Income due to the weighting
    of common shares outstanding during each of the respective periods.

(c) The sum of  the quarterly fully diluted  earnings per share amounts  differs
    from  that reflected  in the Consolidated  Statements of  Income because the
    company's convertible  securities were  anti-dilutive in  certain  quarterly
    calculations.

                                       57
<PAGE>
                              REPORT OF MANAGEMENT

    The  management of UtiliCorp United Inc.  is responsible for the information
that appears in  this annual  report, including its  accuracy. The  accompanying
Consolidated  Financial Statements  were prepared  in accordance  with generally
accepted accounting principles. In addition to selecting appropriate  accounting
principles, management is responsible for the manner of presentation and for the
reliability  of  the  information.  In  fulfilling  this  responsibility,  it is
necessary  for  management  to  make  estimates  based  on  currently  available
information and judgments of current conditions and circumstances.

    Through  well-developed  systems of  internal  control, management  seeks to
assure the integrity and objectivity  of the consolidated financial  information
contained  herein. These  systems of  internal control  are designed  to provide
reasonable assurance that the assets of the company are safeguarded and that the
transactions are executed  to management's authorizations,  and are recorded  in
accordance with the appropriate accounting principles.

    The  Board of Directors participates  in the financial information reporting
process through its Audit Committee,  which selects the independent  accountants
and  reviews,  along  with  management, the  company's  financial  reporting and
internal accounting controls, policies, and practices.

                                          Richard C. Green, Jr.
                                          Chairman of the Board and
                                          Chief Executive Officer

                                       58
<PAGE>
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
      TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF UTILICORP UNITED INC.:

    We have audited the accompanying consolidated balance sheets and  statements
of  preferred and preference stock of  UtiliCorp United Inc. and subsidiaries at
December 31, 1995,  1994 and  1993 and  the related  consolidated statements  of
income,  common shareowners'  equity, and  cash flows  for the  three years then
ended. These  financial  statements  are the  responsibility  of  the  company's
management.  Our  responsibility is  to express  an  opinion on  these financial
statements based on our audits.

    We conducted  our  audits in  accordance  with generally  accepted  auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence  supporting
the  amounts and disclosures in the financial statements. An audit also included
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 UtiliCorp
United Inc.  and subsidiaries  at December  31,  1995, 1994  and 1993,  and  the
consolidated results of their operations and their cash flows for the years then
ended in conformity with generally accepted accounting principles.

    As  explained in Note 3 to  the consolidated financial statements, effective
January 1, 1995,  the company changed  its method of  accounting for price  risk
management  activities. As  explained in  Note 7  to the  consolidated financial
statements, in 1995 the company changed  its method of assessing the  impairment
of long-lived assets.

                                          ARTHUR ANDERSEN LLP

Kansas City, Missouri
February 6, 1996

                                       59
<PAGE>
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

    None.

PART 3
ITEMS 10, 11, 12 AND 13. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY,
EXECUTIVE COMPENSATION, SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT, AND CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

    Information  regarding  these items  appears  in the  company's  joint proxy
statement and prospectus for its annual  meeting of shareholders to be held  May
15,  1996 and is hereby incorporated by  reference in this Annual Report on Form
10-K, pursuant to General  Instruction G(3) of Form  10-K. For information  with
respect  to  the executive  officers of  the  company, see  "Executive Officers"
following Item 1 in Part 1.

                                       60
<PAGE>
ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT.

(1) FINANCIAL STATEMENTS:

<TABLE>
<CAPTION>
                                                                                                 PAGE NO.
                                                                                                -----------
<S>                                                                                             <C>
Consolidated Statements of Income for the three years ended December 31, 1995.................          34
Consolidated Balance Sheets at December 31, 1995, 1994, and 1993..............................          35
Consolidated Statements of Preferred and Preference Stock at December 31, 1995, 1994 and
 1993.........................................................................................          36
Consolidated Statements of Common Shareowners' Equity for the three years ended December 31,
 1995.........................................................................................          36
Consolidated Statements of Cash Flows for the three years ended December 31, 1995.............          37
Notes to Consolidated Financial Statements....................................................       38-57
Report of Arthur Andersen LLP.................................................................          59
</TABLE>

(2) FINANCIAL STATEMENT SCHEDULE

<TABLE>
<S>                                                                          <C>
Report of Independent Accountant on Financial Statement Schedule II                  62
Valuation and Qualifying Accounts for the years 1995, 1994 and 1993                  63
</TABLE>

    All  other  schedules are  omitted because  they are  not applicable  or the
required information is shown in the financial statements or notes thereto.

(3) LIST OF EXHIBITS *
The following exhibits relate to a  management contract or compensatory plan  or
    arrangement:

<TABLE>
<S>        <C>
10(a)(2)   UtiliCorp United Inc. Deferred Income Plan.
10(a)(3)   UtiliCorp United Inc. Amended and Restated 1986 Stock Incentive Plan.
10(a)(4)   UtiliCorp United Inc. Annual and Long-Term Incentive Plan.
10(a)(5)   UtiliCorp United Inc. 1990 Non-Employee Director Stock Plan.
10(a)(6)   Supplemental Executive Retirement Agreement dated October 13, 1988,
           between the company and Dale J. Wolf.
10(a)(7)   Severance Compensation Agreement.
10(a)(8)   Executive Severance Payment Agreement.
10(a)(9)   Temporary Contract Employee Agreement.
10(a)(10)  Split Dollar Agreement.
10(a)(11)  Supplemental Retirement Agreement.
10(a)(13)  UtiliCorp United Inc. Life Insurance Program for Officers.
</TABLE>

------------------------
* Incorporated by reference to the Index to Exhibits.

(b) Reports on Form 8-K

    A current report on Form 8-K dated October 25, 1995, with respect to
     Item 5.
    A current report on Form 8-K/A dated November 14, 1995, with respect to
     Items 2 and 7.

                                       61
<PAGE>
                      REPORT OF INDEPENDENT ACCOUNTANTS ON
                          FINANCIAL STATEMENT SCHEDULE

    We  have audited in  accordance with generally  accepted auditing standards,
the consolidated financial statements for 1995, 1994 and 1993 described on  page
59  of UtiliCorp United Inc.'s  Annual Report on Form  10-K, and have issued our
report thereon dated February 6, 1996. Our  audits were made for the purpose  of
forming  an  opinion  on  those  statements  taken  as  a  whole.  The Financial
Statements Schedule  listed in  Item 14(a)2  is presented  for the  purposes  of
complying with the Securities and Exchange Commission's rules and is not part of
the  basic  financial  statements and,  in  our  opinion, fairly  states  in all
material respects  the  financial data  required  to  be set  forth  therein  in
relation to the basic financial statements taken as a whole.

                                          ARTHUR ANDERSEN LLP
Kansas City, Missouri
February 6, 1996

                                       62
<PAGE>
                             UTILICORP UNITED INC.
                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                                 (IN MILLIONS)

    Allowance for doubtful accounts:

<TABLE>
<CAPTION>
   COLUMN A        COLUMN B        COLUMN C        COLUMN D        COLUMN E        COLUMN F
--------------  --------------  --------------  --------------  --------------  --------------
                                                                  DEDUCTIONS
                                                                FROM RESERVES
                  BEGINNING                       ADDITIONS      FOR PURPOSES
                  BALANCE AT    PURCHASE OF A     CHARGED TO      FOR WHICH     ENDING BALANCE
 DESCRIPTION     DECEMBER 31       BUSINESS        EXPENSE         CREATED      AT DECEMBER 31
--------------  --------------  --------------  --------------  --------------  --------------
<S>             <C>             <C>             <C>             <C>             <C>
Allowance for doubtful accounts:
1995..........       $1.8             --             2.4             2.7             $1.5
1994..........       $4.2             --             4.6             7.0             $1.8
1993..........       $2.6             .3             5.4             4.1             $4.2

Price Risk Management--credit and service reserves:
1995..........       $--              --           70.6(1)            --            $70.6
1994..........       $--              --              --              --             $ --
1993..........       $--              --              --              --             $ --
</TABLE>

------------------------

(1)  Amount established in connection with change in accounting principle to the
    mark-to-market  method  of  accounting  for  domestic  natural  gas  trading
    activities in 1995.

                                       63
<PAGE>
                             UTILICORP UNITED INC.

                               INDEX TO EXHIBITS

<TABLE>
<CAPTION>
 EXHIBIT NUMBER                                               DESCRIPTION
----------------  ----------------------------------------------------------------------------------------------------
<C>               <S>
       *2(a)      Asset Purchase Agreement between Power Partnership PTY LTD and United Energy Limited. (Exhibit 2.1
                   to the Company's Current Report on Form 8-K dated September 13, 1995.)
       *2(b)      Asset Sale Agreement between United Energy Limited and Power Partnership PTY LTD. (Exhibit 2.2 to
                   the Company's Current Report on Form 8-K dated September 13, 1995.)
       *2(c)      Share Sales Agreement Between the State of Victoria, Power Partnership PTY LTD. and the
                   Convenantors. (Exhibit 2.3 to the Company's Current Report on Form 8-K dated September 13, 1995.)
       *3(a)(1)   Certificate of Incorporation of the Company. (Exhibit 3(a)(1) to the Company's Annual Report on Form
                   10-K for the year ended December 31, 1991.)
       *3(a)(2)   Certificate of Amendment to Certificate of Incorporation of the Company. (Exhibit 4(a)(1) to
                   Registration Statement No. 33-16990 filed September 3, 1987.)
       *3(a)(3)   Certificate of Designation of the Preference Stock (Cumulative), $2.05 Series. (Exhibit 3(a)(4) to
                   the Company's Annual Report on Form 10-K for the year ended December 31, 1991.)
       *3(a)(4)   By-laws of the Company as amended. (Exhibit 3 to the Company's Quarterly Report on Form 10-Q for the
                   quarter ended June 30, 1993.)
       *4(a)(1)   Certificate of Incorporation of the Company. (Exhibit 4(a)(1) to the Company's Annual Report on Form
                   10-K for the year ended December 31, 1991.)
       *4(a)(2)   Certificate of Amendment to Certificate of Incorporation of the Company. (Exhibit 4(a)(1) to
                   Registration Statement No. 33-16990 filed September 3, 1987.)
       *4(a)(3)   Certificate of Designation of the Preference Stock (Cumulative), $2.05 Series. (Exhibit 4(a)(4) to
                   the Company's Annual Report on Form 10-K for the year ended December 31, 1991.)
       *4(a)(4)   By-laws of the Company as amended. (Exhibit 3 to the Company's Quarterly Report on Form 10-Q for the
                   quarter ended June 30, 1993.)
       *4(b)(1)   Indenture, dated as of November 1, 1990, between the Company and The First National Bank of Chicago,
                   Trustee. (Exhibit 4(a) to the Company's Current Report on Form 8-K, dated November 30, 1990.)
       *4(b)(2)   First Supplemental Indenture, dated as of November 27, 1990. (Exhibit 4(b) to the Company's Current
                   Report on Form 8-K, dated November 30, 1990.)
       *4(b)(3)   Second Supplemental Indenture, dated as of November 15, 1991. (Exhibit 4(a) to UtiliCorp United
                   Inc.'s Current Report on Form 8-K dated December 19, 1991.)
       *4(b)(4)   Third Supplemental Indenture, dated as of January 15, 1992. (Exhibit 4(c)(4) to the Company's Annual
                   Report on Form 10-K for the year ended December 31, 1991.)
       *4(b)(5)   Fourth Supplemental Indenture, dated as of February 24, 1993. (Exhibit 4(c)(5) to the Company's
                   Annual Report on Form 10-K for the year ended December 31, 1992.)
       *4(b)(6)   Fifth Supplemental Indenture, dated as of April 1, 1993. (Exhibit 4(c)(6) to the Company's Annual
                   Report on Form 10-K for the year ended December 31, 1993.)
       *4(b)(7)   Sixth Supplemental Indenture, dated as of November 1, 1994. (Exhibit 4(d)(7) to the Company's
                   Registration Statement on Form S-3 No. 33-57167, filed January 4, 1995.
</TABLE>

                                       64
<PAGE>
<TABLE>
<CAPTION>
 EXHIBIT NUMBER                                               DESCRIPTION
----------------  ----------------------------------------------------------------------------------------------------
       *4(c)      Twentieth Supplemental Indenture, dated as of May 26, 1989, Supplement to Indenture of Mortgage and
                   Deed of Trust, dated July 1, 1951. (Exhibit 4(d) to Registration Statement No. 33-45382, filed
                   January 30, 1992.)
<C>               <S>
                  Long-Term debt instruments of the Company in amounts not exceeding 10 percent of the total assets of
                   the Company and its subsidiaries on a consolidated basis will be furnished to the Commission upon
                   request.
        4(d)(1)   Indenture, dated as of June 1, 1995, Junior Subordinated Debentures.
        4(d)(2)   First Supplemental Indenture, dated as of June 1, 1995, Supplement to Indenture dated June 1, 1995.
      *10(a)(1)   Agreement for the Construction and Ownership of Jeffrey Energy Center, dated as of January 13, 1975,
                   among Missouri Public Service Company, The Kansas Power & Light Company, Kansas Gas and Electric
                   Company and Central Telephone & Utilities Corporation. (Exhibit 5(e)(1) to Registration Statement
                   No. 2-54964, filed November 7, 1975.)
      *10(a)(2)   UtiliCorp United Inc. Deferred Income Plan. (Exhibit 10(a)(2) to the Company's Annual Report on Form
                   10-K for the year ended December 31, 1991.)
       10(a)(3)   UtiliCorp United Inc. Amended and Restated 1986 Stock Incentive Plan
      *10(a)(4)   UtiliCorp United Inc. Annual and Long-Term Incentive Plan. (Exhibit 10(a)(4) to the Company's Annual
                   Report on Form 10-K for the year ended December 31, 1994)
      *10(a)(5)   UtiliCorp United Inc. 1990 Non-Employee Director Stock Plan. (Exhibit 10(a)(5) to the Company's
                   Annual Report on Form 10-K for the year ended December 31, 1991.)
       10(a)(6)   Supplemental Executive Retirement Agreement dated October 13, 1988, between the Company and Dale J.
                   Wolf.
       10(a)(7)   Form of Severance Compensation Agreement between UtiliCorp United Inc., and certain Executives of
                   the Company.
      *10(a)(8)   Executive Severance Payment Agreement (Exhibit 10 to the Company's Quarterly Report on Form 10-Q
                   filed for the quarter ended September 30, 1993.)
      *10(a)(9)   Temporary Contract Employee Agreement. (Exhibit 10(a)(10) to the Company's Annual Report on Form
                   10-K for the year ended December 31, 1993.)
      *10(a)(10)  Split Dollar Agreement dated as of June 12, 1985, between the Company and James G. Miller. (Exhibit
                   10(a)(10) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994.)
      *10(a)(11)  Supplemental Retirement Agreement dated as of January 27, 1983, between the Company and James G.
                   Miller. (Exhibit 10(a)(11) to the Company's Annual Report on Form 10-K for the year ended December
                   31, 1994.)
      *10(a)(12)  Lease Agreement dated as of August 15, 1991, between Wilmington Trust Company, as Lessor, and the
                   Company, as Lessee. (Exhibit 10(a)(13) to the Company's Annual Report on Form 10-K for the year
                   ended December 31, 1991.)
       10(a)(13)  UtiliCorp United Inc. Life Insurance Program for Officers.
       11         Statement regarding Computation of Per Share Earnings.
       21         Subsidiaries of the Company.
       23         Consent of Arthur Andersen LLP.
       27         Financial Data Schedule.
</TABLE>

------------------------
* Exhibits  marked with an  asterisk are incorporated  by reference as indicated
  pursuant to Rule 12(b)-23.

                                       65
<PAGE>
                                   SIGNATURES

    Pursuant to  the requirements  of  Section 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.

UTILICORP UNITED INC.

By: /s/Richard
C. Green, Jr.
Richard      Chairman of the Board of
C.   Directors, Chief Executive Officer
Green,   (Principal Executive Officer)
Jr.

Date: February 21, 1996

    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.

<TABLE>
<C>                                            <S>
                                               Chairman of the Board of Directors, Chief
        By: /s/Richard C. Green, Jr.            Executive Officer (Principal Executive
            Richard C. Green, Jr.               Officer)

Date: February 21, 1996

           By: /s/Robert K. Green
               Robert K. Green                 President and Director

Date: February 21, 1996

                                               Vice President Finance, Treasurer and
             By: /s/Dale J. Wolf                Corporate Secretary
                Dale J. Wolf                    (Principal Financial Officer)

Date: February 21, 1996

            By: /s/James S. Brook
               James S. Brook                  Vice President (Principal Accounting Officer)

Date: February 21, 1996

            By: /s/John R. Baker
                John R. Baker                  Director

Date: February 21, 1996
</TABLE>

                                       66
<PAGE>
<TABLE>
<C>                                            <S>
            By: /s/Avis G. Tucker
               Avis G. Tucker                  Director

Date: February 21, 1996

          By: /s/Robert F. Jackson
              Robert F. Jackson                Director

Date: February 21, 1996

           By: /s/L. Patton Kline
               L. Patton Kline                 Director

Date: February 21, 1996

             By: /s/Herman Cain
                 Herman Cain                   Director

Date: February 21, 1996

       By: /s/Irvine O. Hockaday, Jr.
           Irvine O. Hockaday, Jr.             Director

Date: February 21, 1996

       By: /s/Dr. Stanley O. Ikenberry
          Dr. Stanley O. Ikenberry             Director

Date: February 21, 1996
</TABLE>

                                       67