<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, 1996
                                     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>
 
                   20 West Ninth, 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
          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 non-affiliates of the
Registrant, based upon the closing sale price of the Common Stock on March 4,
1997 as reported on the New York Stock Exchange, was approximately
$1,442,132,964. Shares of Common Stock held by each officer and director and by
each person who owns 5% or more of the outstanding Common Stock have been
excluded in that such persons may be deemed to be affiliates. This determination
of affiliate status is not necessarily a conclusive determination for other
purposes.
 
<TABLE>
<CAPTION>
                       TITLE                                   OUTSTANDING (AT MARCH 4, 1997)
---------------------------------------------------  ---------------------------------------------------
<S>                                                  <C>
Common Stock, par value $1.00 per share                                  53,412,332
--------------------------------------------------------------------------------------------------------
 
Documents Incorporated by Reference                                  Where Incorporated
 
1997 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......................................................................           15
  Item 3               Legal Proceedings...............................................................           19
  Item 4               Submission of Matters to a Vote of Security Holders.............................           19
 
PART 2
  Item 5               Market for Registrant's Common Equity and Related Stockholder Matters...........           19
  Item 6               Selected Financial Data.........................................................           20
  Item 7               Management's Discussion and Analysis of Financial Condition and Results of
                         Operation.....................................................................           21
  Item 8               Financial Statements and Supplementary Data.....................................           36
  Item 9               Changes in and Disagreements With Accountants on Accounting and Financial
                         Disclosure....................................................................           68
 
PART 3
  Item 10              Directors and Executive Officers of the Registrant..............................           68
  Item 11              Executive Compensation..........................................................           68
  Item 12              Security Ownership of Certain Beneficial Owners and Management..................           68
  Item 13              Certain Relationships and Related Transactions..................................           68
 
PART 4
  Item 14              Exhibits, Financial Statement Schedules, and Reports on Form 8-K................           68
 
INDEX TO EXHIBITS......................................................................................           71
 
SIGNATURES.............................................................................................           74
</TABLE>
 
                                       2
<PAGE>
                                     PART 1
 
ITEM 1.  BUSINESS.
 
ORGANIZATION AND HISTORY
 
    UtiliCorp United Inc. (the company) is an international energy company which
consists of electric and natural gas utility operations, natural gas gathering,
marketing and processing energy services and independent power projects managed
through the following businesses: UtiliCorp Energy Delivery (UED), consisting
primarily of domestic transmission and distribution utility operations; Aquila
Energy Corporation (Aquila), consisting of wholesale energy marketing, gas
processing, gathering and pipelines, and electricity marketing, and UtiliCorp
Energy Solutions (UES), consisting of retail gas marketing, appliance repair and
service contracts and other energy related products and services. The Generation
segment consists of domestic electric generation and independent power projects.
The company also has various operations that include generation, gas marketing,
electricity distribution and various equity investments that are discussed in
the international section of this report. The company's businesses are organized
as shown graphically below.
 
                                [GRAPHIC]
 
    The company was formed in 1985 and is incorporated under the laws of the
State of Delaware. Since then, the company has grown principally through utility
mergers, acquisitions and investments as shown below.
 
                                       3
<PAGE>
                MERGERS, ACQUISITIONS AND INVESTMENTS SINCE 1984
 
<TABLE>
<CAPTION>
                                                                                                 CUSTOMERS                COST
                                                                                                   AS OF                  (IN
                                                            SERVICE          OWNERSHIP            12/31/96             MILLIONS)
                                                    -----------------------  ---------       ------------------       ------------
ORIGINAL UTILITY OPERATIONS(a):
<S>                                                 <C>                      <C>             <C>                      <C>
Missouri Public Service...........................         Electric              100%              191,000              $ --
Missouri Public Service...........................            Gas                100                45,000                --
                                                                                                ----------            ------------
  Total Original Utility
    Operations....................................                                                 236,000                --
                                                                                                ----------            ------------
DOMESTIC UTILITY MERGERS AND ACQUISITIONS:
Kansas Public Service.............................            Gas                100%               27,000                   4.8
Peoples Natural Gas...............................            Gas                100               544,000                 246.0(b)
Northern Minnesota Utilities......................            Gas                100                32,000                  22.0
West Virginia Power...............................         Electric              100                26,000                  21.0
Michigan Gas Utilities............................            Gas                100               141,000                  62.0
West Virginia gas system..........................            Gas                100                24,000                   3.0
WestPlains Energy.................................         Electric              100               142,000                 209.2(c)
Missouri intrastate pipeline......................         Pipeline              100              --                        78.0
Kansas gas system.................................            Gas                100                    (d)                 23.0
Nebraska gas system...............................            Gas                100                    (d)                 78.0(e)
                                                                                                ----------            ------------
  Total Domestic Utility Mergers and
    Acquisitions..................................                                                 936,000                 747.0
                                                                                                ----------            ------------
INTERNATIONAL INVESTMENTS:
West Kootenay Power...............................         Electric              100%               83,000                  62.0
WEL Energy Group Ltd..............................         Electric             39.5(f)             60,000                  46.1
Power New Zealand Ltd.............................         Electric             30.3(f)            216,000                 134.2
United Energy Ltd.................................         Electric             49.9               533,000                 257.9
                                                                                                ----------            ------------
  Total...........................................                                                 892,000                 500.2
                                                                                                ----------            ------------
NON-REGULATED ACQUISITIONS AND INVESTMENTS:
Independent Power Projects........................         Electric            22-50%             --                       209.5
Oasis Pipe Line Company...........................         Pipeline               40              --                       132.0
Other.............................................  Gas Marketing and other      100              --                       123.0
                                                                                                ----------            ------------
                                                                                                  --                       464.5
                                                                                                ----------            ------------
  Total...........................................                                               2,064,000              $1,711.7
                                                                                                ----------            ------------
                                                                                                ----------            ------------
</TABLE>
 
------------------------
 
a)  UtiliCorp was formed in 1985 from Missouri Public Service Company, which was
    founded in 1917.
 
b)  Not including the Nebraska gas system acquired in February 1993 or the
    Kansas gas system acquired in September 1994. Both now operate as part of
    Peoples Natural Gas.
 
c)  The total value of the WestPlains Energy acquisition was $349.8 million,
    including the $209.2 million cash purchase price, assumption of $26.0
    million in debt, and the purchase by a third party of the ownership interest
    in a generating facility for $114.6 million. WestPlains Energy has use of
    that generating capacity through a 27-year operating lease.
 
d)  Customers are included in Peoples Natural Gas above.
 
e)  Excluding $21.0 million in working capital and liabilities assumed.
 
 f)  Interests are held through a 79%-owned subsidiary of the Company.
 
                                       4
<PAGE>
    The company had approximately 1.3 million utility customers and 4,700
employees at December 31, 1996. The company's electric utility operations are in
the states of Missouri, Kansas, Colorado and 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 markets natural gas throughout the United States and in
four provinces of Canada. The company also has several business ventures that
market natural gas in the United Kingdom. Aquila's 82% owned subsidiary, Aquila
Gas Pipeline Corporation (AGP), owns or has interests in 13 natural gas
gathering systems and four natural gas processing plants in Texas and Oklahoma.
The company has its ownership interests in power projects primarily through
Generation in which it has invested in 17 independent power projects located in
seven states and Jamaica. In addition, the company has made equity investments
in three electric distribution companies, two of them in New Zealand and one in
Australia.
 
BUSINESS GROUP SUMMARY
 
    Segment information for the three years ended December 31, 1996 appears on
pages 62 through 64.
 
I.  ENERGY DELIVERY
 
ELECTRIC OPERATING STATISTICS
 
    The following table summarizes the sales, volumes and customers of UED's
electric transmission and distribution businesses.
 
<TABLE>
<CAPTION>
                                                     1996         1995         1994         1993         1992
                                                  -----------  -----------  -----------  -----------  -----------
<S>                                               <C>          <C>          <C>          <C>          <C>
Sales (in millions)
  Residential...................................  $     227.3  $     219.5  $     211.4  $     204.0  $     182.4
  Commercial....................................        147.3        142.0        140.7        138.1        131.1
  Industrial....................................         70.4         67.9         66.4         63.2         62.4
  Other.........................................         74.3         60.7         57.6         54.1         50.4
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................        519.3        490.1        476.1        459.4        426.3
    Purchases from Generation...................        285.2        262.9        258.7        248.1*       230.4*
                                                  -----------  -----------  -----------  -----------  -----------
    Total UED...................................  $     234.1  $     227.2  $     217.4  $     211.3  $     195.9
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Volumes (MWH 000's)
  Residential...................................        2,897        2,758        2,639        2,597        2,329
  Commercial....................................        2,308        2,236        2,190        2,128        1,986
  Industrial....................................        1,660        1,608        1,535        1,430        1,374
  Other.........................................        1,939        1,372        1,230        1,090          923
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................        8,804        7,974        7,594        7,245        6,612
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Customers
  Residential...................................      308,271      302,857      297,801      292,546      288,878
  Commercial....................................       46,651       47,378       46,470       45,709       45,184
  Industrial....................................          286          288          285          266          266
  Other.........................................        3,606        3,556        3,545        3,513        3,572
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................      358,814      354,079      348,101      342,034      337,900
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
</TABLE>
 
------------------------
 
* Amount estimated.
 
    UED obtains all of its power supply from Generation with the exception of
its business in West Virginia, which purchases its power supply from an
unrelated party.
 
                                       5
<PAGE>
GAS OPERATING STATISTICS
 
    The following table summarizes the sales, volumes and customers of UED's gas
distribution businesses.
 
<TABLE>
<CAPTION>
                                                     1996         1995         1994         1993         1992
                                                  -----------  -----------  -----------  -----------  -----------
<S>                                               <C>          <C>          <C>          <C>          <C>
Sales (in millions)
  Residential...................................  $     429.1  $     362.2  $     356.4  $     380.2  $     276.0
  Commercial....................................        192.6        153.9        156.9        177.5        130.0
  Industrial....................................         45.8         45.8         66.7         89.8         76.4
  Other.........................................         60.4         54.9         38.6         38.6         33.3
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................  $     727.9  $     616.8  $     618.6  $     686.1  $     515.7
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Volumes (MCF)
  Residential...................................       81,698       76,461       71,208       74,421       58,095
  Commercial....................................       40,698       37,282       35,952       40,232       32,239
  Industrial....................................       10,944       12,901       18,439       26,868       23,841
  Transportation................................      166,562      178,114      135,924      115,877      112,831
  Other.........................................        1,611        1,827        2,420        3,672        2,683
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................      301,513      306,585      263,943      261,070      229,689
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
Customers
  Residential...................................      728,867      713,586      698,156      661,930      535,058
  Commercial....................................       77,742       76,430       76,015       73,365       60,054
  Industrial....................................        3,725        3,790        3,878        3,874        3,622
  Other.........................................        2,573        2,815        1,581        1,185          582
                                                  -----------  -----------  -----------  -----------  -----------
    Total.......................................      812,907      796,621      779,630      740,354      599,316
                                                  -----------  -----------  -----------  -----------  -----------
                                                  -----------  -----------  -----------  -----------  -----------
</TABLE>
 
    Except for its West Virginia operations, UED procures natural gas through a
central gas supply department. For West Virginia, UED procures its gas from
local suppliers and the spot market.
 
REGULATION
 
    The utility businesses of UED and Generation are regulated on a combined
basis and are impacted similarly by competition and seasonality. The
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
</TABLE>
 
    There is no state regulatory agency in Nebraska. Each municipality served by
the company regulates local rates and services.
 
                                       6
<PAGE>
    The following is a summary of the recent rate case activity of the company:
 
<TABLE>
<CAPTION>
                                       TYPE OF       DATE         DATE         AMOUNT        AMOUNT
RATE CASE DESIGNATION                  SERVICE     REQUESTED    APPROVED      REQUESTED      GRANTED
-----------------------------------  -----------  -----------  -----------  -------------  -----------
                                                                                  (IN MILLIONS)
<S>                                  <C>          <C>          <C>          <C>            <C>
Michigan
U-10960                                     Gas     10/31/95       (a)        $    10.5        (a)
 
Nebraska
Rate Areas 1&3                              Gas       8/1/95       2/1/96            5.2   $     2.78
 
Nebraska
Rate Area 2                                 Gas      5/31/96      10/1/96           5.45         3.35
 
Kansas
193,787U                                    Gas     12/31/95      12/1/96            5.1          3.5
</TABLE>
 
------------------------
 
(a) Pending
 
    In March 1997, the staff of the Missouri Public Service Commission filed a
complaint against the company seeking to reduce annual Missouri electric
revenues by $23 million. This review by the staff is a continuation of the
review that began as part of the UtiliCorp-KCPL merger application that was
terminated in September 1996. The investigation is in the discovery stage, and
as a result, management cannot predict the outcome of this investigation. The
company expects to file for a full rate proceeding to introduce certain
competitive initiatives, some of which were part of the merger application. No
resolution to these rate matters are anticipated before March 1998.
 
COMPETITION
 
ELECTRIC
 
    The electric industry has increasingly become more competitive as federal
and state regulators and legislators move to an unregulated environment. The
anticipation of reduced regulation triggered some dramatic events in recent
years. Several major utility mergers were announced, including those 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 with respect to
future increased competition three years ago. 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
(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. As competing electric utilities reduce
costs, it becomes more difficult to obtain new
 
                                       7
<PAGE>
customers through fuel switching opportunities and in certain cases the
increased competition may result in loss of customers. The Federal Energy
Regulatory Commission (FERC) Order 636 shifted gas supply responsibilities from
traditional pipeline company sources to distribution utilities, allowing
customers to bypass the company's system by connecting directly to a
transportation pipeline. The company has addressed increased competition and
industry changes in several ways. First, its natural gas is priced competitively
in its respective service territories relative to alternative energy sources.
Second, in 1993 the company established 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 a wide range of energy
solutions to meet its customers' needs.
 
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 the
compliance with laws and regulations related to hazardous materials and
hazardous waste compliance and remediation activities. 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 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.
 
    The company currently estimates that it will spend a minimum of
approximately $5.6 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 $5.6
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 exist for the recovery of these costs. The
company is also pursuing recovery from insurance carriers and other potentially
responsible parties.
 
OTHER
 
    In December 1996, the EPA promulgated its final rule for nitrous oxide (NOx)
emissions pursuant to the requirements of the Clean Air Act Amendments of 1980.
The new NOx regulations could impact one of the company's power plants by
necessitating the installation of additional emissions control equipment by
January 1, 2000. The company is currently evaluating the requirements of the
rule. Using EPA's default numbers contained in the cost-benefit analysis in its
final rule-making to estimate the cost of the additional equipment, the company
may be required to spend approximately $3.1 million to comply with these rules.
This estimate could be affected by the rule's applicability as determined by the
D.C. Court of Appeals in a lawsuit now pending, or by the engineering design
developed by the company for implementation of the new standards.
 
    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.
 
                                       8
<PAGE>
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, Kansas and Colorado electric         July and August
West Virginia electric                         November through March
</TABLE>
 
II.  AQUILA ENERGY
 
WHOLESALE ENERGY MARKETING
 
    Aquila's wholesale energy marketing business is conducted through various
operating units, 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 Canada.
Through more than 350 transportation agreements, it has over 15,000 gas
receiving and delivery points available on a network of 40 pipelines. Energy
Marketing adds value for customers by leveraging its national position in
financial deal structuring and gas and power marketing. It provides services
such as complex fuel supply arrangements, energy management services and project
development consulting. For the five years in the period ended December 31,
1996, Energy Marketing had marketing volumes of 2.1, 1.4, 1.0, 1.4 and 1.6
BCF/d, respectively.
 
    In 1995, Energy Marketing began selling electricity to wholesale customers,
much as it markets natural gas. Aquila expects that the electricity marketing
industry will expand rapidly as electricity futures trading is developed and the
infrastructure of this industry segment is established. Aquila's wholesale power
sales have grown from 129,000 megawatt hours in 1995 to 6,495,000 megawatt hours
in 1996, ranking it among the nation's 10-largest volume power marketers.
 
    Energy Marketing utilizes certain types of fixed-price contracts in
connection with its natural gas, natural gas liquids, and power marketing
businesses. These 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 contractual commitments, to reduce its exposure relative to
the volatility of cash market prices, take advantage of carefully selected
arbitrage opportunities via open positions, protect its investment in natural
gas storage inventories and provide price risk management services to its
customers. The company is also able to secure additional sources of energy or
create additional markets for existing supply through the use of exchange for
physical transactions allowed by NYMEX. The company's domestic and Canadian
natural gas and electricity 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
non-Canadian foreign gas marketing, domestic non-trading gas and natural gas
liquids 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. The company will at
times create a net open position or allow a net open position to continue when
it believes, based upon
 
                                       9
<PAGE>
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, the 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 non-performance 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 counter party.
 
GAS GATHERING AND PROCESSING
 
    Aquila through AGP gathers and processes natural gas and natural gas
liquids. AGP owns and operates a 3,416-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>
                                                                         1996       1995       1994       1993       1992
                                                                       ---------  ---------  ---------  ---------  ---------
<S>                                                                    <C>        <C>        <C>        <C>        <C>
Natural gas throughput (million cubic feet per day)..................        493        506        371        325        286
Natural gas liquids produced (thousand barrels per day)..............         41         32         31         31         24
Pipeline miles owned.................................................      3,416      3,311      2,718      2,531      2,014
</TABLE>
 
    Through two transactions in July and November 1996, Aquila Energy and its 82
percent-owned AGP acquired a combined 40% of the outstanding capital stock of
Oasis Pipe Line Company (Oasis) and related transportation rights for
approximately $132 million. The 600-mile Oasis pipeline system spans the state
of Texas and links Aquila's gathering systems to the Waha, Texas hub and the
Katy, Texas hub. As part of the purchase, another owner has the option to buy
one-fifth of Oasis, including 5% now owned by Aquila, on or before April 1,
1997. Aquila was notified by the other partner that it intends to exercise this
option.
 
III.  GENERATION
 
ELECTRIC UTILITY GENERATION
 
    Generation manages the company's domestic regulated electric generation and
supply businesses in Colorado, Kansas and Missouri. Collectively, the generating
plants located in these three states had the capacity to generate 1,669
megawatts (MW) of electricity during the year ended December 31, 1996. The
following table shows the overall fuel mix, and the generation capability for
the past five years.
 
<TABLE>
<CAPTION>
SOURCE                                               1996       1995       1994       1993       1992
-------------------------------------------------  ---------  ---------  ---------  ---------  ---------
                                                                           (MW)
<S>                                                <C>        <C>        <C>        <C>        <C>
Coal.............................................        885        875        868        864        863
Gas and oil......................................        784        705        705        700        716
                                                   ---------  ---------  ---------  ---------  ---------
    Total generation capability..................      1,669      1,580      1,573      1,564      1,579
                                                   ---------  ---------  ---------  ---------  ---------
                                                   ---------  ---------  ---------  ---------  ---------
</TABLE>
 
    A listing of Generation's generating plants is provided in the "Properties"
section of this Form 10-K. Generation also sells electricity to the wholesale
market. For the year ended December 31, 1996, Generation sold 998 megawatt hours
to non-affiliated parties.
 
                                       10
<PAGE>
INDEPENDENT POWER PROJECTS
 
    UtilCo Group Inc. (UtilCo) participates in the ownership and operation of
facilities in the independent and wholesale power generation market. Consistent
with the company's overall strategy to minimize risk through diversification,
UtilCo has invested in generation facilities which are geographically diverse
and use a variety of fuels and proven technologies. Additionally, each project
is a producer of competitively priced wholesale power in its geographic region
and has a long-term market for its output. To date, UtilCo has made investments
in 17 projects located in seven states and Jamaica, with a total net ownership
of approximately 320 MW of generating capacity. All of the projects are in
commercial operation. A description and listing of the power projects appears on
page 18 of this Form 10-K.
 
    The company does not anticipate further expansion or investment in
independent power projects. Due to increasing deregulation, the power generation
market does not offer the same high yield returns as the company's prior
investments.
 
IV.  ENERGY SOLUTIONS
 
    UES consists of retail gas marketing, appliance repair and service contracts
and energy related products and services. UES was formed to advance the
company's effort to become a leading retailer of energy and energy related
products and services.
 
GAS MARKETING
 
    UES's gas marketing businesses are its largest segment. Although some of
UES's gas marketing operations have long been part of the company, the
underlying operating plans for these businesses have changed. UES ultimately
intends to market gas to residential customers in addition to its expanding
small commercial and industrial customer base. UES expects to participate in
various residential customer choice trials as competitive experiments occur. UES
has grown its gas marketing business over the last two years by acquiring gas
marketing companies in states with more favorable regulation and sufficient
customer density.
 
PRODUCTS AND SERVICES
 
    Consistent with UES's overall plan to expand its efforts in serving the
retail sector, UES formed four teams to develop and bring to market new products
and services. These new products and services are expected to build on existing
competencies within the company. Management expects to introduce new products
and services in mid-1997. Management is hopeful, although no assurance can be
made given the competitive influences involved, that the products and services
brought to market will be profitable. The company expects to spend approximately
$8.0 million on product development in 1997.
 
V.  INTERNATIONAL
 
    The company's international operations are managed separately from the four
business groups previously discussed. The international businesses have local
management and report separately to the company. The contribution to earnings
from international businesses was 25%, 12% and 9% for the years ended December
31, 1996, 1995 and 1994, respectively. As of December 31, 1996, the company had
$860.5 million invested internationally. The following discussion briefly
describes the operations of these businesses.
 
AUSTRALIA
 
    In September 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
 
                                       11
<PAGE>
manages the operation of UE on behalf of PPL and receives a management fee
consisting of a base amount indexed to the consumer price index and a variable
amount based on UE's financial performance.
 
    Summarized UE financial information as of and for the year ended December
31, 1996 is as follows:
 
<TABLE>
<CAPTION>
                                                                                  (IN
                                                                               MILLIONS)
                                                                              ------------
<S>                                                                           <C>
Sales.......................................................................   $    546.8
Gross profit................................................................        216.7
Operating expenses..........................................................         93.7
                                                                              ------------
Earnings before interest and taxes..........................................   $    123.0
                                                                              ------------
                                                                              ------------
 
Total assets................................................................   $  1,399.0
                                                                              ------------
                                                                              ------------
Liabilities.................................................................   $  1,357.0
Equity......................................................................         42.0
                                                                              ------------
Total liabilities and equity................................................   $  1,399.0
                                                                              ------------
                                                                              ------------
</TABLE>
 
NEW ZEALAND
 
    The New Zealand operations mainly consist of UtiliCorp N.Z., Inc. (UNZ), a
79%-owned subsidiary, which purchased a 29.4% ownership interest in Power New
Zealand Limited (PNZ), primarily in November 1995. As additional shares were
purchased throughout 1996, the ownership interest in PNZ increased to 30.3%. In
addition, UNZ has a 39.5% ownership position in WEL Energy Group Limited (WEL).
Both PNZ and WEL are New Zealand electric distribution utilities serving 216,000
and 60,000 customers, respectively.
 
    Summarized PNZ and WEL financial information as of and for the years ended
September 30, 1996 and June 30, 1996, respectively, are as follows:
 
<TABLE>
<CAPTION>
                                                                     PNZ        WEL
                                                                  ---------  ---------
                                                                     (IN MILLIONS)
<S>                                                               <C>        <C>
Sales...........................................................  $   226.0  $    71.5
Earnings before taxes...........................................       64.2       18.2
 
Total assets....................................................  $   427.5  $   138.7
                                                                  ---------  ---------
                                                                  ---------  ---------
Liabilities.....................................................  $    87.9  $    20.2
Equity..........................................................      339.6      118.5
                                                                  ---------  ---------
Total liabilities and equity....................................  $   427.5  $   138.7
                                                                  ---------  ---------
                                                                  ---------  ---------
</TABLE>
 
UNITED KINGDOM
 
    The company has several business ventures in the United Kingdom (UK) that
market natural gas to wholesale, commercial, residential and industrial
customers. United Gas Limited (UGL) is the company's primary UK subsidiary. UGL
markets gas to approximately 48,000 customers and had sales volumes of 56 BCF
for the year ended December 31, 1996. In addition to UGL, the company has two
gas marketing joint ventures in which it is a 25% equity partner.
 
    In 1996, the company realigned certain of its business relationships in the
United Kingdom (UK). The equity relationships with Caledonian Gas Limited, Egas
Limited and Midlands Gas Limited (Midlands) were terminated. As part of the
termination of the equity relationship in Midlands, the company
 
                                       12
<PAGE>
assumed an interest in two long-term gas supply contracts (for deliveries
through 2005) that is assimilated into its existing portfolio of sales and
supply contracts
 
    On April 15, 1996, the company acquired the 25% interest in UtiliCorp U.K.,
Inc., it did not already own for approximately $12 million. This transaction was
accounted for as a purchase.
 
    The utility industry in the United Kingdom has seen dramatic changes in
recent years. Ten of the UK's thirteen electric companies were sold to other
companies, six being purchased by U.S. utilities. One natural gas marketing
segment which the company competes in is dominated by British Gas which
currently serves almost all of the 18 million potential gas customers. Through
various deregulation stages, the entire gas market will become open within the
next two years with customers able to freely choose their gas supplier. Through
its established wholesale marketing businesses and associations with two
regional electric companies, the company is positioning itself to take advantage
of this competitive market. In addition, the company's UK businesses are
upgrading their gas management systems. In an effort to increase market
liquidity, the International Petroleum Exchange began trading a new natural gas
futures contract in January 1997 that closely resembles the NYMEX contract sold
in the U.S.
 
CANADA
 
    In Canada, the company owns West Kootenay Power Ltd. (WKP), a hydro-electric
utility in British Columbia. WKP has four hydro-electric generation facilities
with a capacity of 205 megawatts and 915 miles of transmission lines that serve
approximately 82,536 customers in south central British Columbia. WKP generates
about half of its power requirements and purchases the remaining requirements
through power contracts.
 
    The following table summarizes the sales, volumes and customers of WKP.
 
<TABLE>
<CAPTION>
                                                                  1996       1995       1994       1993       1992
                                                                ---------  ---------  ---------  ---------  ---------
<S>                                                             <C>        <C>        <C>        <C>        <C>
Sales (in millions)
  Residential.................................................  $    37.0  $    32.9  $    34.4  $    32.8  $    30.1
  Commercial..................................................       19.7       19.1       16.6       18.1       17.2
  Industrial..................................................        9.4        9.4        8.7       12.8       10.9
  Other.......................................................       26.8       26.2       21.2       23.8       23.3
                                                                ---------  ---------  ---------  ---------  ---------
    Total.....................................................  $    92.9  $    87.6  $    80.9  $    87.5  $    81.5
                                                                ---------  ---------  ---------  ---------  ---------
                                                                ---------  ---------  ---------  ---------  ---------
Volumes (MWH 000s)
  Residential.................................................        990        920        873        939        847
  Commercial..................................................        467        440        421        400        381
  Industrial..................................................        313        319        362        491        426
  Other.......................................................        909        892        869        849        825
                                                                ---------  ---------  ---------  ---------  ---------
    Total.....................................................      2,679      2,571      2,525      2,679      2,479
                                                                ---------  ---------  ---------  ---------  ---------
                                                                ---------  ---------  ---------  ---------  ---------
Customers
  Residential.................................................     73,413     71,844     70,142     67,883     65,208
  Commercial..................................................      8,041      7,888      7,974      7,766      7,564
  Industrial..................................................         37         36         36         36         35
  Other.......................................................      1,045      1,019        161        165        119
                                                                ---------  ---------  ---------  ---------  ---------
    Total.....................................................     82,536     80,787     78,313     75,850     72,926
                                                                ---------  ---------  ---------  ---------  ---------
                                                                ---------  ---------  ---------  ---------  ---------
</TABLE>
 
    WKP is regulated by the British Columbia Utilities Commission. WKP is in the
second year of a three year incentive based rate setting mechanism. This
mechanism is the first of its kind for electric utilities in Canada and was the
result of a negotiated settlement with customers and regulators. The mechanism
 
                                       13
<PAGE>
calls for equal sharing of savings between the customer and WKP in situations
where WKP performs over and above negotiated performance expectations.
 
    British Columbia is the first province in Canada to allow wholesale
transmission access for large wholesale customers. WKP has recently filed an
application to allow retail transmission access on its transmission system, the
first application of its kind in Canada. A hearing is scheduled to commence
April 1, 1997 before the British Columbia Utilities Commission to deal with the
issue of retail transmission access in the entire province of British Columbia.
Management anticipates the province being opened up for large customer
competition over the next few years.
 
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: 42
                          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. Mr. Green is a director of BHA Group, Inc., and CAT, Ltd.
 
Robert K. Green           TITLES: President of the company, and Chairman of the Board of Directors of United
                          Energy Limited
                          AGE: 35
                          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. Mr. Green is also a
                          director of UMB Bank, n.a.
 
Terry G. Westbrook        TITLE: Senior Vice President and Chief Financial Officer
                          AGE: 50
                          5-YEAR HISTORY: In present position since March 1996. Prior to being employed by the
                          company, Mr. Westbrook was employed by The Quaker Oats Company where he was Senior Vice
                          President-Finance and Chief Financial Officer since 1991. He joined Quaker Oats in 1983
                          and subsequently had a number of key officer positions in corporate development,
                          strategic planning, finance, and the company's Asian food and beverage operations.
 
James G. Miller           TITLE: Senior Vice President, Energy Delivery
                          AGE: 48
                          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 Group and President of Aquila Energy Corporation.
                          AGE: 49
                          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.
</TABLE>
 
                                       14
<PAGE>
    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.
 
UTILITY FACILITIES
 
    The company's electric generation facilities, as of December 31, 1996, are
as follows:
 
<TABLE>
<CAPTION>
                                                                             UNIT CAPABILITY                 NET
                                                                              (KW NET, PER                GENERATION
           UNIT                      LOCATION             YEAR INSTALLED          HOUR)         FUEL      (MW HOURS)
--------------------------  --------------------------  -------------------  ---------------  ---------  ------------
<S>                         <C>                         <C>                  <C>              <C>        <C>
MISSOURI:
Sibley #1 - #3              Sibley                        1960, 1962,1969           496,000     Coal       2,792,773
Ralph Green #3              Pleasant Hill                      1981                  75,000      Gas          21,617
Nevada                      Nevada                             1974                  20,000      Oil              --
Greenwood #1 - #4           Greenwood                       1975 - 1979             241,000    Gas/Oil        34,647
KCI #1 and #2               Kansas City                        1970                  30,000      Gas           1,191
-----------------------------------------------------------------------------------------------------
KANSAS:
Judson Large #4             Dodge City                         1969                 137,000    Gas/Oil       383,340
Arthur Mullergren #3        Great Bend                         1963                  92,000    Gas/Oil        91,349
Cimarron River #1 - #2      Liberal                         1963, 1967               72,000      Gas          95,248
Clifton #1 - #2             Clifton                            1974                  73,500    Gas/Oil         4,682
Jeffrey #1 - #3             St. Mary's                   1978, 1980, 1983           347,400     Coal       2,248,656
-----------------------------------------------------------------------------------------------------
COLORADO:
W.N. Clark #1 - #2          Canon City                      1955, 1959               39,690     Coal         226,792
Pueblo #6                   Pueblo                             1949                  19,000    Gas/Oil        52,960
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           1,735
-----------------------------------------------------------------------------------------------------
CANADA:
No. 1                       Lower Bonnington, BC               1925                  52,500     Hydro        331,084
No. 2                       Upper Bonnington, BC         1907, 1916, 1940            61,520     Hydro        413,827
No. 3                       South Slocan, BC                   1928                  52,500     Hydro        423,633
No. 4                       Corra Linn, BC                     1932                  45,000     Hydro        339,679
-----------------------------------------------------------------------------------------------------
TOTAL                                                                             1,874,110                7,463,213
-----------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------
</TABLE>
 
    At December 31, 1996, the company had transmission and distribution lines as
follows:
 
<TABLE>
<CAPTION>
                                                                                     LENGTH
DESCRIPTION                                                                       (POLE MILES)
--------------------------------------------------------------------------------  ------------
<S>                                                                               <C>
Transmission lines..............................................................        5,204
Overhead distribution lines.....................................................       16,570
Underground distribution lines..................................................        1,560
                                                                                  ------------
    Total.......................................................................       23,334
                                                                                  ------------
                                                                                  ------------
</TABLE>
 
    At December 31, 1996, the company owned substations aggregating 9,171,395
KVA.
 
                                       15
<PAGE>
    At December 31, 1996, the company's gas utility operations had 2,917 miles
of gas gathering and transmission pipelines and 22,244 miles of distribution
mains and service lines located throughout its service territories.
 
GAS PROCESSING AND GATHERING ASSETS
 
    AGP owned and/or operated 13 natural gas pipeline systems with an aggregate
length of approximately 3,416 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, 1996:
 
<TABLE>
<CAPTION>
                                                                                              GAS         Avg. Daily
                                                                                          THROUGHPUT          Gas
                                                                                           CAPACITY       Throughput
                                                                            MILES OF       (MMcf/d)        (MMcf/d)
GATHERING SYSTEMS                                          LOCATION        PIPELINE(1)      (1),(3)       (1),(2),(3)
-----------------------------------------------------  -----------------  -------------  -------------  ---------------
<S>                                                    <C>                <C>            <C>            <C>
Southeast Texas Pipeline System (SETPS)..............  SE Texas                 2,222            710             437
Mentone..............................................  W. Texas                    13             60          --
Gomez................................................  W. Texas                    11             40               1
Menard County........................................  C. Texas                   120             30               4
Maverick County......................................  W. Texas                   118             20               2
Rhoda Walker.........................................  W. Texas                    21             20               8
Panola County........................................  E. Texas                    24              8               1
Elk City.............................................  SW Oklahoma                160            115              82
Mooreland............................................  NW Oklahoma                325             40              14
Dorado--40%..........................................  S. Texas                    57             40              19
Warwink--35%.........................................  W. Texas                    44            100              17
Benedum/Wilshire--5%.................................  W. Texas                   204            125               4
Brooks-Hidalgo (4)...................................  S. Texas                    97             75               7
                                                                                -----          -----             ---
                                                                                3,416          1,383             596
Fuel and Shrinkage...................................                          --             --                (103)
                                                                                -----          -----             ---
    Total............................................                           3,416          1,383             493
                                                                                -----          -----             ---
                                                                                -----          -----             ---
</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 marketing sales with average daily volumes of 482 MMcf/d
    sold from other companies' facilities.
 
(3) Gross gas throughput capacity is included at 100% while net average
    throughput is presented at AGP's joint venture ownership interest.
 
(4) In 1996, Aquila ownership percentage decreased from 50% to 22%.
 
    At December 31, 1996, Aquila owned 40% of the capital stock of Oasis Pipe
Line Company (Oasis) and the right to transport 320 MMcf/d of natural gas on
Oasis' pipeline, plus the opportunity to utilize excess capacity on an
interruptible basis. The Oasis pipeline is a 600-mile, 36-inch diameter natural
gas pipeline which connects the Waha, Texas hub and the Katy, Texas hub. The
Oasis pipeline has one Bcf/d of throughput capacity. The volumes transported on
the Oasis pipeline are reflected in the off-system marketing activities of the
company. Aquila utilizes the equity method of accounting for its investment in
the capital stock of Oasis.
 
                                       16
<PAGE>
    At December 31, 1996, AGP owned and/or operated an interest in four natural
gas processing plants. Set forth below is information with respect to AGP's
processing plants as of December 31, 1996:
 
<TABLE>
<CAPTION>
                                                                               GAS              Gas             NGLs
                                                                           THROUGHPUT       Throughput       Production
                                                                           CAPACITY(1)       (1), (2)         (1), (2)
PROCESSING PLANTS                                                           (MMcf/d)         (MMcf/d)       (MBbls/d)(4)
-----------------------------------------------------------------------  ---------------  ---------------  ---------------
<S>                                                                      <C>              <C>              <C>
La Grange, Texas.......................................................           230              191             24.6
Somerville, Texas......................................................            28               15              2.0
Benedum, Texas--5%.....................................................           125                4           --
Elk City, Oklahoma.....................................................           115               82              4.0
                                                                                  ---              ---              ---
Total--owned plants....................................................           498              292             30.6
Katy, Texas (3)........................................................        --                  222             10.5
                                                                                  ---              ---              ---
    Total..............................................................           498              514             41.1
                                                                                  ---              ---              ---
                                                                                  ---              ---              ---
</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 present AGP ownership
    interest.
 
(3) This plant is owned and operated by a third party from which AGP receives a
    portion of the NGLs produced from gas AGP delivers to the plant. The plant
    is included in this section for informational purposes to show the gas
    throughput and NGLs production that AGP received utilizing the access to
    this plant.
 
(4) Thousands of barrels per day (MBbls/d).
 
    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.
 
                                       17
<PAGE>
INDEPENDENT POWER PROJECTS
 
    Information regarding the company's generating projects is set forth below.
 
<TABLE>
<CAPTION>
                                    TYPE OF         PERCENT     CAPACITY
     PROJECT & LOCATION           INVESTMENT         OWNED       (MW)(A)            FUEL            DATE IN SERVICE
-----------------------------  -----------------  -----------  -----------  --------------------  -------------------
<S>                            <C>                <C>          <C>          <C>                   <C>
Mega Renewables G.P., 4        General                 49.75         12.2   Hydro                 Spring 1987(b)
  projects in California       partnership
-------------------------------------------------------------------------------------------
Topsham Hydro Partners, Maine  Leveraged lease            50         13.9   Hydro                 October 1987
-------------------------------------------------------------------------------------------
Stockton CoGen Company,        General                    50         49.9   Coal                  March 1988(c)
  California                   partnership
-------------------------------------------------------------------------------------------
Westwood Energy Properties,    Limited                    38        29.25   Waste coal            July 1988
  Pennsylvania                 partnership
-------------------------------------------------------------------------------------------
BAF Energy L.P., California    Limited                  23.1          111   Natural Gas           May 1989
                               partnership
-------------------------------------------------------------------------------------------
Rumford Cogeneration Company   Limited                  24.3           75   Coal and waste wood   May 1990
  L.P., Maine                  partnership
-------------------------------------------------------------------------------------------
Koma Kulshan Associates,       Limited                 49.75         13.7   Hydro                 October 1990
  Washington                   partnership
-------------------------------------------------------------------------------------------
Badger Creek Limited,          Limited                 49.75         46.6   Natural gas           April 1991
  California                   partnership
-------------------------------------------------------------------------------------------
McKittrick Limited,            Limited                 49.75         45.4   Natural gas           October 1991
  California                   partnership
-------------------------------------------------------------------------------------------
Live Oak Limited, California   Limited                    50         45.8   Natural gas           April 1992
                               partnership
-------------------------------------------------------------------------------------------
Lockport Energy Associates,    Limited                 22.56        168.8   Natural gas           December 1992
  L.P., New York               partnership
-------------------------------------------------------------------------------------------
Orlando Cogen Limited, L.P.,   Limited                    50          120   Natural gas           September 1993
  Florida                      partnership
-------------------------------------------------------------------------------------------
Naheola Cogeneration LP,       Limited                    50         81.2   Black liquor solids,  March 1993(d)
  Alabama                      partnership                                  coal, gas, wood
-------------------------------------------------------------------------------------------
Jamaica Private Power          Limited liability          22           60   Diesel                January 1997
  Company, Jamaica             Company
-------------------------------------------------------------------------------------------
</TABLE>
 
(a) Total capacity, net of power consumed in generation.
 
(b) Interest acquired by the company in June 1989.
 
(c) Interest acquired by the company in December 1988.
 
(d) Interest acquired by the company in May 1995.
 
                                       18
<PAGE>
ITEM 3. LEGAL PROCEEDINGS.
 
    William Alpern vs. UtiliCorp United Inc. On June 17, 1992, a class action
suit was filed by a stockholder against the company in the United States
District Court for the Western District of Missouri. Plaintiff alleges that the
company violated 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. Plaintiff seeks unspecified compensatory
damages. The District Court dismissed the case by granting summary judgment to
UtiliCorp. Plaintiff appealed that decision to the United States Court of
Appeals for the Eighth Circuit. On May 17, 1996, the Court of Appeals reversed
the decision of the District Court, reinstated plaintiff's claims and remanded
the case back to the District Court. A trial is anticipated in 1997.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
 
    None.
 
                                     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, 1996, the company
had 41,796 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>
1996 QUARTERS
  First.................................................  $   30.25  $   28.25       $     .44
  Second................................................      29.13      25.75             .44
  Third.................................................      29.13      26.50             .44
  Fourth................................................      27.25      26.38             .44
 
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
</TABLE>
 
    Cash dividends on the common stock of the company and its predecessor have
been paid each year since 1939.
 
                                       19
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
 
<TABLE>
<CAPTION>
                                                        1996        1995        1994        1993        1992
                                                     ----------  ----------  ----------  ----------  ----------
<S>                                                  <C>         <C>         <C>         <C>         <C>
                                                                    IN MILLIONS EXCEPT PER SHARE
Sales..............................................  $  4,332.3  $  2,798.5  $  2,398.1  $  2,746.1  $  2,339.0
Income from operations.............................       223.4       225.1       228.0       144.0       165.4
Net income.........................................       105.8        79.8        94.4        86.4        52.9
Earnings available for common shares...............       103.7        77.7        91.4        79.5        46.0
Primary earnings per common share..................        2.20        1.72        2.08        1.95        1.32
Fully diluted earnings per common share............        2.19        1.71        2.06        1.92        1.31
Cash dividends per common share....................        1.76        1.72        1.70        1.62        1.60
Total assets.......................................     4,704.9     3,885.9     3,111.1     2,850.5     2,552.8
Short-term debt (including current maturities).....       277.7       303.7       321.2        71.8       236.8
Long-term debt.....................................     1,470.7     1,355.4       976.9     1,009.7       890.8
Company-obligated mandatorily redeemable preferred
  securities of a partnership......................       100.0       100.0      --          --          --
Preference and preferred stock.....................        25.0        25.4        25.4        83.9        95.1
Common shareholders' equity........................     1,158.0       946.3       906.8       851.7       661.1
Book value per common share........................       21.73       20.59       20.24       20.27       18.66
</TABLE>
 
------------------------
 
(1) In 1996, the company wrote off $11.0 million of pretax deferred merger
    costs, net of a termination fee payment.
 
(2) In 1996, the company recorded an $11.8 million after-tax gain from a sales
    lease transaction at a power project, which was partially offset by certain
    restructuring reserves.
 
(3) In 1996, the company issued 6 million shares of its common stock in a stock
    offering that netted $160.8 million in proceeds.
 
(4) In 1995, the company recorded a $34.6 million pretax charge related to
    impaired assets.
 
(5) 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.
 
(6) In 1993, Aquila, a subsidiary of the company, recorded a $69.8 million
    restructuring charge against pretax earnings related to a change in
    strategic direction.
 
(7) In 1993, Aquila sold 18% of AGP in an initial public offering resulting in a
    non-taxable gain of $47.8 million.
 
(8) In 1992, Aquila recorded a $17.7 million charge against pretax earnings
    related to improper payments by former employees.
 
                                       20
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATION.
 
KEY EVENTS OF 1996
 
    - UtiliCorp's sales, earnings before interest and taxes (EBIT), and earnings
      available for common shares all set records in 1996 at $4,332.3 million,
      $322.1 million and $103.7 million, respectively.
 
    - UtiliCorp's first full year of 49.9 percent ownership of United Energy in
      Australia brought earnings of $14.1 million. In the last four months of
      1995, results were $2.9 million.
 
    - Aquila Energy's normalized EBIT was $60.2 million, or 42% higher than in
      1995.
 
    - Rate increases for gas operations in Nebraska and Kansas added $4.4
      million to EBIT in 1996.
 
    - In April, a sales lease arrangement at a project in which a UtiliCorp
      subsidiary holds a 23 percent interest resulted in a significant one-time
      gain, of which the company's share was $11.8 million after taxes.
 
    - Through two transactions in July and November, Aquila Energy acquired a
      combined 40% of Oasis Pipe Line Company and related transportation rights
      for approximately $132 million. The Oasis pipeline system spans the state
      of Texas.
 
    - In September, Kansas City Power & Light Company (KCPL) terminated its
      merger agreement with UtiliCorp and paid the company a $5 million
      termination fee. UtiliCorp expensed approximately $11.0 million of
      deferred merger costs, net of the $5 million received. In February 1997,
      KCPL paid UtiliCorp a $53 million breakup fee, recorded in the 1997 first
      quarter, following KCPL's signing of a definitive agreement to merge with
      Western Resources Inc.
 
    - In October, the company issued $100 million of 6.7% Senior Notes due in
      2006, and in November it issued 6 million new shares of common stock. Net
      proceeds totaling $260.3 million were used to reduce short-term debt.
 
    - In January 1997, the company announced its intention to redeem its $2.05
      Series preference stock on March 1, 1997 at $25.00 per share. Funded by
      short-term debt, this redemption is expected to increase annual earnings
      available by approximately $1.1 million after tax, based on current
      short-term interest rates.
 
CONSOLIDATED OPERATIONS
 
    Except where noted, the following discussion refers to the consolidated
entity, UtiliCorp United Inc., including the following businesses: UtiliCorp
Energy Delivery (UED), consisting primarily of transmission and distribution
utility operations; Aquila Energy Corporation (Aquila), consisting primarily of
wholesale energy marketing, gas processing and gathering, gas pipelines and
electricity marketing; and UtiliCorp Energy Solutions (UES), consisting of
retail gas marketing, appliance repair and service contracts, and other energy
related products and services. The Generation segment consists of domestic
electric generation and independent power projects. The company also has various
operations that include generation, gas marketing, electric distribution and
various equity investments that are discussed in the International section of
this report.
 
    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, 1996.
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.
 
                                       21
<PAGE>
    The results of operations for the years ended December 31, 1996, 1995 and
1994 have been affected by several items that do not have a continuing impact on
the company's financial position or results from operations.
 
    The table below summarizes the after-tax impact of the non-recurring items
on earnings available for common shares.
 
<TABLE>
<CAPTION>
                                                                                            YEAR ENDED DECEMBER 31,
                                                                                        -------------------------------
                                                                                          1996       1995       1994
                                                                                        ---------  ---------  ---------
                                                                                                  IN MILLIONS
<S>                                                                                     <C>        <C>        <C>
Earnings available, as reported.......................................................  $   103.7  $    77.7  $    91.4
Non-recurring items:
  Merger termination, net of termination fee received (a).............................        6.8     --         --
  Gain on sales lease of a power project (b)..........................................      (11.8)    --         --
  Provision for asset impairments (c).................................................     --           19.6     --
  Change to mark-to-market method of accounting (d)...................................     --          (18.3)    --
  Reserve for United Kingdom gas contracts (e)........................................     --            6.8     --
  Net loss from oil and gas production business and other (f).........................     --            5.0        3.9
                                                                                        ---------  ---------  ---------
Normalized earnings...................................................................  $    98.7  $    90.8  $    95.3
                                                                                        ---------  ---------  ---------
                                                                                        ---------  ---------  ---------
</TABLE>
 
------------------------
 
(a) In 1996, the company expensed deferred merger costs, net of a termination
    fee received, resulting in a $6.8 million after-tax charge against earnings.
 
(b) In 1996, the company recorded a gain from a sales lease on a power project,
    which was partially offset by certain restructuring reserves in connection
    with changes in power project agreements. The result of these items
    increased earnings $11.8 million after tax.
 
(c) In 1995, the company recorded a provision for impaired assets of $19.6
    million after tax.
 
(d) In 1995, the company changed its method of accounting for domestic natural
    gas trading operations to the mark-to-market method. This increased after
    tax earnings by $18.3 million.
 
(e) In 1995, the company recorded a $6.8 million after-tax reserve against
    earnings for unfavorable gas supply contracts in the United Kingdom.
 
(f)  In 1995, the company sold substantially all of its oil and gas production
    assets at book value for $204.5 million. This normalizing adjustment
    represents the net loss from this business in 1995 and 1994. In 1994, the
    company settled with certain defendants in lawsuits filed as a result of
    improper payments. The settlements and insurance recoveries, net of legal
    and related costs, resulted in a favorable adjustment of $1.5 million after
    tax.
 
    Normalized earnings or normalized income are terms used by management to
describe the recurring earnings or income of the company. These terms are not
meant to replace net income or other measures under generally accepted
accounting principles.
 
                                       22
<PAGE>
ENERGY DELIVERY
 
    The following table summarizes the operations of UtiliCorp Energy Delivery
for the three years ended December 31, 1996.
 
<TABLE>
<CAPTION>
                                                                                  YEAR ENDED DECEMBER 31,
                                                                           -------------------------------------
THREE-YEAR REVIEW--ENERGY DELIVERY                                            1996         1995         1994
-------------------------------------------------------------------------  -----------  -----------  -----------
                                                                                    DOLLARS IN MILLIONS
<S>                                                                        <C>          <C>          <C>
Sales:
  Electric...............................................................  $     519.3  $     490.1  $     476.1
  Gas....................................................................        727.9        616.8        618.6
  Other..................................................................         51.9         45.9         41.0
  Purchases from Generation..............................................       (285.2)      (262.9)      (258.7)
                                                                           -----------  -----------  -----------
Total net sales..........................................................      1,013.9        889.9        877.0
                                                                           -----------  -----------  -----------
Cost of sales:
  Electric...............................................................         14.9         14.2         13.9
  Gas....................................................................        453.9        348.9        381.1
  Other..................................................................         32.1         30.7         23.6
                                                                           -----------  -----------  -----------
Total cost of sales......................................................        500.9        393.8        418.6
                                                                           -----------  -----------  -----------
Gross profit.............................................................        513.0        496.1        458.4
                                                                           -----------  -----------  -----------
Operating expenses:
  Other operating........................................................        213.3        216.7        196.0
  Maintenance............................................................         26.0         22.7         25.4
  Taxes, other than income taxes.........................................         50.6         48.0         45.5
  Depreciation and amortization..........................................         66.1         67.9         60.4
                                                                           -----------  -----------  -----------
Total operating expenses.................................................        356.0        355.3        327.3
                                                                           -----------  -----------  -----------
Income from operations...................................................        157.0        140.8        131.1
Other income.............................................................         11.0          7.4          5.6
                                                                           -----------  -----------  -----------
Earnings before interest expense and income taxes (EBIT).................  $     168.0  $     148.2  $     136.7
                                                                           -----------  -----------  -----------
                                                                           -----------  -----------  -----------
Identifiable assets......................................................  $   1,762.4  $   1,646.4  $   1,556.0
Electric sales (MWH 000's)...............................................        9,607        8,351        8,300
Gas sales and transportation (MCF 000's).................................      301,513      306,585      263,943
Number of customers......................................................    1,172,000    1,151,000    1,128,000
                                                                           -------------------------------------
</TABLE>
 
SALES
 
    Energy Delivery sales increased $124.0 million in 1996 compared to 1995,
which increased gross profit by $16.9 million. Sales were affected favorably by
colder temperatures and higher gas prices which increased sales by $119.6
million and gross profit by $11.9 million. In addition, increased gas rates in
Nebraska and Kansas contributed approximately $4.4 million in gross profit in
1996.
 
    In 1995 compared to 1994, Energy Delivery sales increased $12.9 million due
to more favorable weather and continued growth in the number of customers.
 
    Energy Delivery obtains all of its electricity requirements from Generation
except for its West Virginia operations. The cost of electricity from Generation
is reflected as "Purchases from Generation" in the sales section of the
three-year table above.
 
                                       23
<PAGE>
COST OF SALES
 
    The $105.0 million increase in 1996 cost of gas over 1995 is due primarily
to higher natural gas prices stemming from cold winter temperatures which
increased demand for gas supplies.
 
    Cost of sales decreased by $24.8 million in 1995 compared to 1994, primarily
due to a $32.2 million decrease in gas cost of sales. On January 1, 1995, Energy
Delivery spent $78.0 million to acquire a Missouri gas pipeline company which
transports gas impacting sales, but not cost of sales. This caused gas gross
profit margins to vary between periods.
 
OPERATING EXPENSES
 
    Operating expenses in 1996 were about the same as in 1995. Energy Delivery
reduced employment by 280 in 1995, which decreased salary and benefit costs.
These savings were offset by increased property taxes and increased
uncollectible customer accounts triggered by escalating gas prices.
 
    Operating expenses increased $28.0 million or 8.6% in 1995 compared to 1994
mainly due to the costs of repositioning and reshaping the businesses. In 1995,
the company began integrating business support functions such as human
resources, accounting and information technology, among others, which previously
were located in the company's business units. The increase in depreciation and
amortization expense was due to additional capital improvements made to utility
assets.
 
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 also 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
 
    The electric industry has increasingly become more competitive as federal
and state regulators move to an unregulated environment. The anticipation of
reduced regulation triggered some dramatic events. Several major utility mergers
were announced, including those 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.
 
    UtiliCorp began looking at its strengths and opportunities with respect to
future increased competition three years ago. Approximately 100 employees from
around the company were brought together to work on a strategic plan that would
be the foundation from which to reposition and reshape the business. In 1995,
the company began integrating 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 competitive forces affecting the company's electric operations are also
affecting the company's gas operations. As competing electric utilities reduce
costs, it becomes more difficult to obtain new customers through fuel switching
opportunities and in certain cases the result may be a loss of customers.
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
 
                                       24
<PAGE>
in its respective service territories compared to alternate 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 customers' needs.
 
    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.
 
REGULATORY MATTERS
 
    Energy Delivery has pending a gas rate case for its Michigan operations.
Energy Delivery requested a $9.1 million rate increase in late 1995. The
Michigan Commission has no time limit to make a final decision. UED does not
expect a final ruling on this case before spring 1997. See Missouri earnings
investigation discussion in the Generation section for a pending electric rate
matter.
 
GENERATION
 
    The following table summarizes the operations of Generation for the three
years ended December 31, 1996.
 
<TABLE>
<CAPTION>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                                     -------------------------------
THREE-YEAR REVIEW--GENERATION                                                          1996       1995       1994
-----------------------------------------------------------------------------------  ---------  ---------  ---------
                                                                                           DOLLARS IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Sales to affiliate and other.......................................................  $   285.2  $   262.9  $   258.7
Cost of sales--fuel used for generation and purchased power........................      166.5      152.3      150.7
                                                                                     ---------  ---------  ---------
Gross profit.......................................................................      118.7      110.6      108.0
                                                                                     ---------  ---------  ---------
Operating expenses:
  Other operating..................................................................       50.1       41.2       36.1
  Maintenance......................................................................       14.6       12.8       15.0
  Taxes, other than income taxes...................................................        6.6        6.8        6.7
  Depreciation and amortization....................................................       18.8       19.4       17.8
  Provision for asset impairment...................................................     --           15.4     --
                                                                                     ---------  ---------  ---------
Total operating expenses...........................................................       90.1       95.6       75.6
                                                                                     ---------  ---------  ---------
Income from operations.............................................................       28.6       15.0       32.4
Equity in earnings of investments and partnerships.................................       50.9       21.9       19.2
Other expense......................................................................        (.2)       (.5)      (1.0)
                                                                                     ---------  ---------  ---------
Earnings before interest expense and income taxes (EBIT)...........................       79.3       36.4       50.6
                                                                                     ---------  ---------  ---------
Non-recurring items:
  Provision for asset impairments..................................................     --           15.4     --
  Gain on sales lease of power project.............................................      (20.9)    --         --
                                                                                     ---------  ---------  ---------
Normalized EBIT....................................................................  $    58.4  $    51.8  $    50.6
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
Identifiable assets................................................................  $   482.1  $   460.8  $   397.2
Affiliate wholesale sales (MWH 000's)..............................................      7,411      6,998      6,767
Non-affiliate wholesale sales (MWH 000's)..........................................        998        589        459
                                                                                     -------------------------------
</TABLE>
 
                                       25
<PAGE>
SALES
 
    Generation provides firm wholesale electricity to UED. Sales to UED are
based on an internal transfer pricing model which represents a full requirements
capacity and energy contract. The opening of the wholesale market increased the
regulated trading opportunities resulting in increased sales in 1996 compared to
1995. Also included in sales to affiliates are sales to other wholesalers of
$23.3 million, $12.2 million and $10.9 million, respectively, for 1996, 1995 and
1994.
 
COST OF SALES
 
    The increase in fuel and purchased power of approximately $14.2 million in
1996 compared to 1995 is primarily due to an increase of 409,000 MWH in
wholesale transactions combined with increased firm sales to UED resulting from
favorable weather and customer growth. The reduced cost of sales on a per unit
sold basis reflects savings from new coal supply and transportation contracts
signed in January 1996 combined with increased blending of low sulfur western
coal at the Sibley generating station. On August 1, 1996, the company amended an
electric supply contract with another utility, which is expected to reduce
future energy costs by $1 million and capacity costs by $2.9 million on an
annual basis. The company's customers will share in the fuel cost savings
through a fuel adjustment mechanism. As a result of this amended supply
contract, the company secured 168 megawatts of supply through 2001 at lower
prices and postponed its planned construction of a generating plant.
 
OPERATING EXPENSES
 
    Operating expenses increased $9.9 million in 1996 compared to 1995 after
adjusting for the provisions for asset impairment recorded in 1995 relating to a
power project. The 1996 normalized increase is due to additional support costs,
such as information technology, human resources, legal, and other activities.
Additional increases primarily related to the establishment of an energy trading
group to sell available generation capacity during off-peak periods.
 
    The provision for asset impairments was the result of a review of the
carrying value of Generation assets and the adoption of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets to be Disposed Of" (SFAS 121), which resulted in a non-cash, pretax
charge of $15.4 million.
 
EQUITY IN EARNINGS
 
    Equity earnings in 1996 increased $8.1 million after adjusting for the net
gain on a sales lease transaction and other restructuring charges. The equity
earnings increase is due to higher steam output, new rates at two projects and a
full year of performance at another.
 
    The company does not anticipate further expansion or investment in
independent power projects. Due to increasing deregulation, the power generation
market does not offer the same high yield returns as prior investments.
 
PENDING EARNINGS INVESTIGATION
 
    In March 1997, the staff of the Missouri Public Service Commission filed a
complaint against the company seeking to reduce annual Missouri electric
revenues by $23 million. This review by the staff is a continuation of the
review that began as part of the UtiliCorp-KCPL merger application that was
terminated in September 1996. The investigation is in the discovery stage and as
a result, management cannot predict the outcome of this investigation. The
company expects to file for a full rate proceeding to introduce certain
competitive initiatives, some of which were part of the merger application. No
resolution to these rate matters is anticipated before March 1998.
 
                                       26
<PAGE>
ENVIRONMENTAL MATTERS
 
    In December 1996, the EPA promulgated its final rule for nitrous oxide (NOx)
emissions pursuant to the requirements of the Clean Air Act Amendments of 1990.
The new NOx regulations could impact one of the company's power plants by
necessitating the installation of additional emissions control equipment by
January 1, 2000, as more fully discussed in Note 14.
 
COMPETITION
 
    See discussion of electric utility competition in the Energy Delivery
section.
 
AQUILA ENERGY
 
    The following table summarizes the operations of Aquila Energy for the three
years ended December 31, 1996.
 
<TABLE>
<CAPTION>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                                 ---------------------------------
THREE-YEAR REVIEW--AQUILA ENERGY                                                    1996        1995       1994
-------------------------------------------------------------------------------  ----------  ----------  ---------
                                                                                        DOLLARS IN MILLIONS
<S>                                                                              <C>         <C>         <C>
Sales:
  Wholesale energy marketing...................................................  $  2,051.1  $    835.7  $   613.2
  Gas sales, transmission and processing.......................................       376.0       284.7      245.7
  Oil and gas production.......................................................      --            50.6       76.9
                                                                                 ----------  ----------  ---------
Total sales....................................................................     2,427.1     1,171.0      935.8
                                                                                 ----------  ----------  ---------
Cost of sales:
  Cost of wholesale energy marketing...........................................     1,982.1       774.8      596.8
  Cost of gas gathering and processing.........................................       267.7       193.8      166.6
                                                                                 ----------  ----------  ---------
Total cost of sales............................................................     2,249.8       968.6      763.4
                                                                                 ----------  ----------  ---------
Gross profit...................................................................       177.3       202.4      172.4
                                                                                 ----------  ----------  ---------
Operating expenses:
  Operating and maintenance....................................................        81.4        71.2       69.4
  Depreciation, depletion and amortization.....................................        25.7        49.6       59.6
  Provision for asset impairments..............................................      --            13.2     --
                                                                                 ----------  ----------  ---------
Total operating expenses.......................................................       107.1       134.0      129.0
                                                                                 ----------  ----------  ---------
Income from operations.........................................................        70.2        68.4       43.4
Minority interest expense and other............................................        10.0         2.1        3.8
                                                                                 ----------  ----------  ---------
Earnings before interest expense and income taxes (EBIT).......................        60.2        66.3       39.6
                                                                                 ----------  ----------  ---------
Non-recurring items:
  Change to mark-to-market method of accounting................................      --           (29.8)    --
  Provision for asset impairments ($13.2 million less minority interest).......      --            10.8     --
  Oil and gas operating income and other.......................................      --            (5.0)      (7.8)
                                                                                 ----------  ----------  ---------
Normalized EBIT................................................................  $     60.2  $     42.3  $    31.8
                                                                                 ----------  ----------  ---------
                                                                                 ----------  ----------  ---------
Identifiable assets............................................................  $  1,416.9  $    873.1  $   717.1
Physical gas sales and throughput (billion cubic feet per day).................         2.6         1.9        1.4
Electricity marketing volumes (MWH 000's)......................................       6,495         129     --
Natural gas liquids produced (thousand barrels per day)........................          41          32         31
                                                                                 ---------------------------------
</TABLE>
 
                                       27
<PAGE>
REVIEW OF OPERATIONS
 
    Sales increased in 1996 by $1.3 billion or 107% compared to 1995, primarily
due to a 54% increase in gas marketing volumes and a 48% increase in natural gas
prices. Natural gas marketing volumes reached 2.1 BCF per day as Aquila Energy
expanded market share of its gas wholesale business. For 1996 Aquila Energy
ranked among the 10 largest gas marketers in the United States. Aquila has
implemented an aggressive strategy to further grow this business so that it may
become one of the largest companies in the U.S. in terms of marketed volumes.
Sales were also positively affected by a 28% increase in production of natural
gas liquids (NGLs) and a 20% increase in NGL prices. The significant increase in
sales contributed to a normalized $56.9 million increase in gross profit.
Operating and maintenance expenses increased $10.2 million due to additional
employees and higher incentive payouts due to improved performance from the
wholesale energy marketing business.
 
    Sales increased $235.2 million in 1995 due to a 42% increase in marketing
volumes and a 36% increase in gas pipeline throughput. Gas marketing volumes
increased mainly due to the January 1995 acquisition of Tristar Gas Company,
which had volumes of approximately 185 million cubic feet per day in 1995. Gas
throughput volumes increased due mainly to expanded drilling in Aquila Gas
Pipeline's gathering region. In addition, the company changed its method of
accounting for energy trading operations, which increased sales and EBIT by
$29.8 million.
 
    Sales from oil and gas production activities decreased due to the sale of
all production assets for approximately $205 million in September 1995, which
also lowered depreciation, depletion and amortization expense in 1996 and 1995.
 
COMPETITION
 
    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 market share on a volumetric basis. The company expects the gas
marketing industry to consolidate into a few megamarketing companies. Electric
power marketing will be affected 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 gathering and processing business will be influenced by natural gas
and oil commodity prices and the drilling activity surrounding its major
pipeline asset in Southeast Texas. Aquila expects new well connections to
maintain or increase throughput as horizontal drilling technology increases
economically recoverable reserves in this area. Many pipeline acquisition
opportunities also exist for this business.
 
                                       28
<PAGE>
ENERGY SOLUTIONS
 
    The following table summarizes the operations of Energy Solutions for the
three years ended December 31, 1996.
 
<TABLE>
<CAPTION>
                                                                                          YEAR ENDED DECEMBER 31,
                                                                                      -------------------------------
THREE-YEAR REVIEW--ENERGY SOLUTIONS                                                     1996       1995       1994
------------------------------------------------------------------------------------  ---------  ---------  ---------
                                                                                                IN MILLIONS
<S>                                                                                   <C>        <C>        <C>
Sales...............................................................................  $   313.9  $   178.5  $    77.6
Cost of sales.......................................................................      285.1      152.7       56.5
                                                                                      ---------  ---------  ---------
Gross profit........................................................................       28.8       25.8       21.1
                                                                                      ---------  ---------  ---------
Operating expenses:
  Operating and maintenance.........................................................       44.7       26.0       13.5
  Depreciation, depletion and amortization..........................................        4.2     --             .3
                                                                                      ---------  ---------  ---------
Total operating expenses............................................................       48.9       26.0       13.8
                                                                                      ---------  ---------  ---------
Income (loss) from operations.......................................................      (20.1)       (.2)       7.3
                                                                                      ---------  ---------  ---------
Other expense.......................................................................         .2     --         --
                                                                                      ---------  ---------  ---------
Earnings before interest expense and income taxes (EBIT)............................  $   (20.3) $     (.2) $     7.3
                                                                                      ---------  ---------  ---------
                                                                                      ---------  ---------  ---------
Identifiable assets.................................................................  $   112.6  $   118.6  $    66.1
                                                                                      -------------------------------
</TABLE>
 
REVIEW OF OPERATIONS
 
    Energy Solutions sales increased 76% in 1996 compared to 1995, and more than
300% since 1994. UES has expanded its retail presence since 1994 by acquiring
gas marketing companies serving small commercial and industrial customers in
strategic locations. UES also has a multi-state appliance repair and servicing
business as well as a start-up home security business. Energy Solutions
operations, although expanding toward the goal of developing and selling
consumer-oriented products and services, are best described as start-up
operations as EBIT decreased to a $20.3 million loss in 1996. Energy Solutions'
gas marketing businesses, its primary operation, suffered from the effects of
severe winter weather which caused gas supply prices to increase rapidly
compared to its fixed price sales contracts, primarily in the first quarter of
1996.
 
    In addition, when the colder weather increased customer demand for gas, UES
incurred pipeline penalties that compressed margins. The surge in price could
not be passed on to customers and in some cases resulted in losing customers to
other gas marketing companies.
 
OPERATING EXPENSES
 
    Operating expenses increased $22.9 million or 88% in 1996 over 1995, and
more than 250% since 1994. The increase was the result of additional operating
expenses of $10.5 million incurred by Energy Solutions in its sales and
marketing organization relating to the acquisition of two gas marketing
companies, research and development costs for new consumer products and brand
support activities. The remaining 1996 increase in expenses related to
additional back office support activities, bad debt expenses and severance
costs. The 1995 operating expense increase of $12.2 million was primarily
related to the $9.9 million spent to launch the EnergyOne-SM- brand and hire
sales and marketing staffs.
 
                                       29
<PAGE>
COMPETITION AND OUTLOOK
 
    Management believes 1996 was a year of competitive positioning, which
focused UES to take advantage of the retail segment opportunities. UES's gas
marketing business competes with many regional and local companies for small
commercial and industrial customers. Although the gas marketing business is
highly competitive with small margins, management believes it has several
advantages over its competitors relating to gas procurement and marketing and
sales processes.
 
    For products and services, UES staffed four research and development teams
late in 1996 to speed up the rollout of consumer-oriented products. UES's
long-term success depends on successful new product development and rollout to
the marketplace.
 
    The company expects UES to improve its results in 1997, but still show a
loss for the year.
 
INTERNATIONAL
 
    The following table summarizes the company's International operations for
the three years ended December 31, 1996.
 
<TABLE>
<CAPTION>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                                     -------------------------------
THREE-YEAR REVIEW--INTERNATIONAL                                                       1996       1995       1994
-----------------------------------------------------------------------------------  ---------  ---------  ---------
                                                                                               IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Sales:
  Electric (Canada)................................................................  $    92.9  $    87.6  $    80.9
  Gas marketing (primarily United Kingdom).........................................      199.2      199.9      163.8
                                                                                     ---------  ---------  ---------
Total sales........................................................................      292.1      287.5      244.7
                                                                                     ---------  ---------  ---------
Cost of Sales:
  Cost of fuel and purchased power (Canada)........................................       29.8       27.4       27.3
  Cost of gas marketing (United Kingdom)...........................................      187.5      184.2      155.5
                                                                                     ---------  ---------  ---------
Total cost of sales................................................................      217.3      211.6      182.8
                                                                                     ---------  ---------  ---------
Gross profit.......................................................................       74.8       75.9       61.9
                                                                                     ---------  ---------  ---------
Operating expenses:
  Other operating..................................................................       26.6       28.4       13.1
  Maintenance......................................................................        9.0        8.9        7.4
  Taxes, other than income taxes...................................................       12.1       13.0       12.3
  Depreciation and amortization....................................................       12.5        7.1        6.4
                                                                                     ---------  ---------  ---------
Total expense......................................................................       60.2       57.4       39.2
                                                                                     ---------  ---------  ---------
Income from operations.............................................................       14.6       18.5       22.7
Equity earnings (loss) in subsidiaries and partnerships
 (after foreign taxes).............................................................       60.1        9.8        (.9)
Other income (expense).............................................................        3.4        3.4        (.3)
                                                                                     ---------  ---------  ---------
Earnings before interest expense and income taxes (EBIT)...........................       78.1       31.7       21.5
                                                                                     ---------  ---------  ---------
Non-recurring item:
  Reserve for United Kingdom gas contracts.........................................     --           11.0     --
                                                                                     ---------  ---------  ---------
Normalized EBIT....................................................................  $    78.1  $    42.7  $    21.5
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
Identifiable assets................................................................  $   860.5  $   712.1  $   295.4
                                                                                     -------------------------------
</TABLE>
 
                                       30
<PAGE>
OPERATING PERFORMANCE
 
    International EBIT and earnings available for common shares were $78.1
million and $26.4 million, respectively, in 1996, up well over 100% compared to
1995 levels. Over the last three years, the international operations have
continued to become a larger part of the consolidated operations. For the three
years ended December 31, 1996, 1995 and 1994, international earnings contributed
25%, 12% and 9%, respectively, of total earnings available for common shares.
 
AUSTRALIA
 
    In 1996 and 1995, the company's Australian investments contributed $14.1
million and $2.9 million, respectively, to the company's consolidated earnings
available for common shares. The increase in earnings is a result of having
equity earnings relating to a full year of operations and from transforming
United Energy Limited (UE) to a competitive and customer-focused operation at a
much faster pace than anticipated. UtiliCorp Australia Holdings Limited, a
wholly-owned subsidiary of the company, manages UE and receives an annual
management fee consisting of a fixed fee and a variable fee dependent on UE's
financial performance. The company earned management fees of $6.9 million during
the year ended December 31, 1996.
 
    UE was the first electric distribution business to be privatized in
Australia, and has become a benchmark for other privatized Australian
distribution businesses. Major achievements during 1996 include the
reengineering of business processes and replacement of core business support
systems. A key focus has been on efficiency improvements including staff
reductions. Productivity improvements have been made possible by improved
business processes, work practices and better use of resources.
 
    Retail competition in the state of Victoria, where United Energy is located,
is being introduced in phases. Currently, customers using more than 750 MWH per
year (generally large commercial and industrial customers) are able to choose
their electricity supplier. Smaller commercial and residential customers will
have that choice by the year 2001.
 
CANADA
 
    The company's Canadian operations consist primarily of its wholly-owned
Canadian electric distribution company, West Kootenay Power. This utility has
four hydro-electric generation facilities with a capacity of 205 megawatts and
915 miles of transmission lines that serve approximately 83,000 customers in the
south-central interior of British Columbia. The company achieved two historic
firsts in 1996. It became the first electric utility in Canada to be granted
performance-based regulation, and it filed a groundbreaking transmission access
application, opening the door to competition.
 
    Canadian operations provided earnings available for common shares of $9.5
million, $8.2 million and $6.2 million for the periods ending December 31, 1996,
1995 and 1994, respectively. Increased earnings in 1996 resulted from the sale
of one of WKP's investments and favorable negotiations of purchased power
arrangements. Increased earnings in 1995 over 1994 were primarily due to a 4.7%
increase in rates reflecting an increase in the allowed return on equity.
 
NEW ZEALAND
 
    The company's New Zealand investments (Power New Zealand and WEL Energy
Group) together contributed $2.4 million and $.7 million to earnings available
for common shares in 1996 and 1995, respectively. Earnings improved in 1996
compared to 1995 as a result of having a full year of equity earnings from Power
New Zealand shares purchased late in 1995, the additional earnings attached to
shares purchased throughout 1996 from both investments, and improved operations
at the underlying electric distribution companies.
 
                                       31
<PAGE>
UNITED KINGDOM
 
    The company has several business ventures in the United Kingdom (U.K.) that
market natural gas to wholesale and industrial customers. United Gas Limited
(UGL) is the company's primary U.K. subsidiary. UGL markets gas to approximately
48,000 customers and had sales volumes of 56 BCF for the year ended December 31,
1996. In addition to UGL, the company has two gas marketing joint ventures
(collectively referred to as Regional Gas Companies or RGCs) in which it is a
25% equity partner. In 1996, the company realigned certain of its business
relationships in the United Kingdom. The equity relationships with Caledonian
Gas Limited, Egas Limited and Midlands Gas Limited (Midlands) were terminated.
As part of the termination of the equity relationship in Midlands, the company
assumed an interest in two long-term gas supply contracts (for deliveries
through 2005) that it assimilated into its existing portfolio of sales and
supply contracts.
 
    At December 31, 1996, the company's portfolio of U.K. contracts was in a net
long position, as it included volumetric supply commitments of 72 BCF expiring
through 2005 and volumetric sales commitments of 62 BCF expiring through 1999.
Estimated losses on the above portfolio ranged from $14 million to $23 million
depending on the estimated future spot price of natural gas. Since the United
Kingdom natural gas market does not have liquid long-term pricing, it is
difficult to estimate future profitability of the portfolio. Based on
management's estimates and available market data at December 31, 1996, the
company is carrying a $14 million pretax reserve relating to future losses that
may exist within the portfolio of contracts. Management believes that this
reserve is adequate and that any additional losses would not be material. In
April 1996, the company acquired the 25% interest in UtiliCorp U.K., Inc. it did
not already own for approximately $12 million. This transaction was accounted
for as a purchase.
 
    Earnings available for common shares from the United Kingdom businesses for
the three-year period ended December 31, 1996, 1995 and 1994 were $.7 million,
$(2.5) million and $2.4 million, respectively. The increase in 1996 earnings
over 1995 was mainly due to the establishment of a $11.0 million pretax reserve
in 1995 for unfavorable long-term gas supply contracts, offset by the adverse
effect on trading profits due to the unexpected rise in natural gas prices
beginning in August 1996.
 
    The lower 1995 results compared to 1994 were primarily due to the decline in
spot market prices and its effects on margins, equity investment values and
certain financial guarantees the company or subsidiaries had with its partners.
In the 1995 fourth quarter, the company reserved $11.0 million (pretax) for
probable funding requirements it expected to make to support its investments in
one of the RGCs and recognized an additional $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.
 
LIQUIDITY AND CAPITAL RESOURCES
 
    The company's cash requirements arise primarily from its continued growth,
electric and gas utility construction programs, non-regulated investment
opportunities and information technology investments. The company's ability to
attract the necessary financial capital at reasonable terms is critical to the
company's overall plan. Historically, acquisitions and investments have been
initially financed with short-term debt and subsequently funded with an
appropriate mix of common equity and long-term debt securities, depending on
prevailing market conditions.
 
    A primary source of short-term cash has been bank borrowings from
uncommitted bank lines which aggregated $202.0 million, $153.1 million and
$155.4 million at December 31, 1996, 1995 and 1994, respectively. The company
can also issue up to $150 million of commercial paper which is supported by a
$250 million committed revolving credit agreement. The credit agreement expires
in December 2000 and allows for the issuance of notes at interest rates based on
various money market rates. Commercial paper borrowings at December 31, 1996,
1995 and 1994 were $50.0 million, $135.5 million and $27.0 million,
respectively.
 
                                       32
<PAGE>
    To maintain flexibility in its capital structure and to take advantage of
favorable short-term rates, the company also uses proceeds from its two accounts
receivable sale programs to fund a portion of its short-term cash requirements.
The level of funding available from these programs varies depending on the level
of eligible accounts receivable, which fluctuates seasonally. These programs
were fully utilized at December 31, 1996.
 
    At December 31, 1996, the company had approximately $86.7 million in cash in
its international businesses. The company does not provide for U.S. tax on its
international operations.
 
    Total capitalization at December 31, 1996 was $2.8 billion. Common equity as
a percentage of total capitalization increased to 42% at December 31, 1996, up
from 39% at December 31, 1995. The increase relates primarily to increased
earnings, the issuance of 6 million shares of common stock, and the issuance of
1.3 million shares through customer stock purchase plans.
 
OPERATING CASH FLOWS
 
    Cash flows provided from operations were $262.8, $261.2 and $229.3 million
for the three years ended December 31, 1996, 1995 and 1994, respectively. Cash
flows from operating activities increased slightly between 1996 and 1995. The
increase is primarily due to the timing of cash receipts and cash payments from
the prior year.
 
    Cash flows 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 $73.4 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 were
increased net borrowings from the company's accounts receivable financing
program which provided $50.8 million of additional operating cash flow.
 
INVESTING CASH FLOWS
 
    Net cash used in investing activities totaled $411.6 million, $634.9 million
and $346.3 million for the three years ended December 31, 1996, 1995 and 1994,
respectively. Net cash flows used in investing activities decreased $223.3
million in 1996 compared to 1995 due to fewer acquisition opportunities than in
the prior year.
 
    In July and November 1996, Aquila acquired 40% of the outstanding capital
stock of Oasis Pipe Line Company (Oasis) and related transportation rights for
approximately $132 million. The 600-mile Oasis pipeline system spans the state
of Texas and links Aquila's gathering systems to key gas market hubs. Oasis has
1 billion cubic feet per day of throughput capacity. In April 1997, Aquila
expects to receive $17 million for the sale of 5% of the outstanding stock in
Oasis.
 
    Net cash used in investing activities increased $288.6 million between 1995
and 1994. The majority of the increase related to an increase in acquired
businesses of $452.0 million partially offset by $204.5 million of cash proceeds
received from the sale of the company's oil and gas properties.
 
                                       33
<PAGE>
    Investing activities by the company over the last three years are as
follows:
 
<TABLE>
<CAPTION>
                                                                                      1996       1995       1994
                                                                                    ---------  ---------  ---------
                                                                                              IN MILLIONS
<S>                                                                                 <C>        <C>        <C>
Electric capital expenditures.....................................................  $    85.8  $    69.5  $    81.3
Gas capital expenditures..........................................................       48.5       39.9       50.7
Acquired businesses--domestic.....................................................      138.1      100.9       28.2
Acquired businesses--international................................................       42.3      379.3     --
Gas pipeline, gathering and processing............................................       26.4      104.7       33.2
Independent power projects........................................................     --           59.0       22.2
Oil and gas reserve development and purchases.....................................     --           39.3       80.4
Sale of oil and gas properties....................................................     --         (204.5)    --
Other.............................................................................       70.5       46.8       50.3
                                                                                    ---------  ---------  ---------
Total investing activities........................................................  $   411.6  $   634.9  $   346.3
                                                                                    ---------  ---------  ---------
                                                                                    ---------  ---------  ---------
</TABLE>
 
    The company's operating cash flow provided approximately 64%, 41% and 66% of
the investing activities for the three years ended December 31, 1996, 1995 and
1994, respectively, assuming all operating cash flows were applied to the
investment needs first. The remaining cash flows were provided from financing
activities as discussed below.
 
FINANCING CASH FLOWS
 
    Net cash provided from financing activities totaled $175.2 million, $417.2
million and $128.3 million for the three years ended December 31, 1996, 1995 and
1994, respectively. Net cash flows provided from financing activities decreased
$242.0 million primarily due to the lower level of acquisition related activity
in 1996 compared to 1995.
 
    Net cash provided by financing activities increased $288.9 million between
1995 and 1994. The majority of the increase related to additional borrowings
needed to acquire the company's equity investments in Australia and New Zealand.
 
    Financing activities by the company over the last three years were as
follows:
 
<TABLE>
<CAPTION>
                                                                                      1996       1995       1994
                                                                                    ---------  ---------  ---------
                                                                                              IN MILLIONS
<S>                                                                                 <C>        <C>        <C>
Stock ownership and option plans..................................................  $    37.6  $    29.5  $     2.8
Issuance of stock.................................................................      160.8     --         --
Payment of dividends..............................................................      (86.7)     (80.0)     (77.6)
Treasury stock....................................................................       (6.4)       6.6       (6.6)
Issuance of senior notes..........................................................       99.5       99.3       99.5
Retirement of senior notes........................................................      (12.5)    (125.0)    --
Monthly income securities.........................................................     --          100.0     --
Foreign debt borrowings, net......................................................       29.7      286.4     --
Net change in short-term debt.....................................................      (37.6)     106.2      112.4
Other.............................................................................       (9.2)      (5.8)      (2.2)
                                                                                    ---------  ---------  ---------
Total net financing activities....................................................  $   175.2  $   417.2  $   128.3
                                                                                    ---------  ---------  ---------
                                                                                    ---------  ---------  ---------
</TABLE>
 
                                       34
<PAGE>
FUTURE CASH REQUIREMENTS
 
    Future cash requirements include utility plant additions, required
redemptions of long-term securities and acquisition opportunities. The company's
estimated expenditures over the next five years for these activities, excluding
acquisitions, are as follows:
 
<TABLE>
<CAPTION>
                                                                  1997       1998       1999       2000       2001
                                                                ---------  ---------  ---------  ---------  ---------
                                                                                     IN MILLIONS
<S>                                                             <C>        <C>        <C>        <C>        <C>
Energy Delivery...............................................  $   101.3  $    97.7  $    98.4  $   100.4  $   103.7
Generation....................................................       18.2       17.0       18.0       16.5       17.5
Aquila Energy.................................................       39.1       47.8       44.9       44.6       44.6
Energy Solutions..............................................        7.2     --         --         --         --
Maturing long-term debt.......................................       25.7      163.7      165.9      280.6       16.0
Other.........................................................       84.1       64.6       75.1       68.6       70.6
                                                                ---------  ---------  ---------  ---------  ---------
Total.........................................................  $   275.6  $   390.8  $   402.3  $   510.7  $   252.4
                                                                ---------  ---------  ---------  ---------  ---------
                                                                ---------  ---------  ---------  ---------  ---------
</TABLE>
 
    Amounts included in Other primarily relate to the company's continuing
information system reengineering efforts and other technology capital
expenditures to enable the company to implement its operating strategy.
 
    On January 21, 1997, the company announced its intention to redeem all 1
million outstanding shares of its $2.05 Series preference stock on March 1,
1997. Shares will be redeemed at $25.00 a share and will be funded with
short-term debt. This redemption will increase earnings available by an
estimated $1.1 million after tax based on current short-term interest rates.
 
    The company believes that its available cash resources from both operating
cash flows and borrowing capacity will be adequate to meet its anticipated
future cash requirements.
 
MERGER TERMINATION
 
    On September 17, 1996, KCPL terminated the Amended and Restated Agreement
and Plan of Merger (the Agreement) among KCPL, KC Merger Sub, Inc., the company,
and KC United Corp. Pursuant to the termination provision in the Agreement, KCPL
paid the company $5 million in 1996 and upon KCPL's definitive agreement to
merge with another company KCPL paid the company a $53 million breakup fee in
the first quarter of 1997. The company used the $53 million to reduce short-term
debt. In 1996 the company expensed $11.0 million of its deferred merger cost,
net of the $5 million termination fee received in 1996, against income.
 
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 competitive 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.
 
                                       35
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
                       CONSOLIDATED STATEMENTS OF INCOME
 
<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1996        1995        1994
                                                                               ----------  ----------  ----------
                                                                                  IN MILLIONS EXCEPT PER SHARE
<S>                                                                            <C>         <C>         <C>
Sales........................................................................  $  4,332.3  $  2,798.5  $  2,398.1
Cost of sales................................................................     3,422.5     1,881.8     1,575.8
                                                                               ----------  ----------  ----------
Gross profit.................................................................       909.8       916.7       822.3
                                                                               ----------  ----------  ----------
Operating, administrative and maintenance expense............................       547.6       508.2       448.8
Depreciation, depletion and amortization.....................................       127.8       148.8       145.5
Provision for asset impairments..............................................      --            34.6      --
Write-off of deferred merger costs, net of termination fee received..........        11.0      --          --
                                                                               ----------  ----------  ----------
Income from operations.......................................................       223.4       225.1       228.0
                                                                               ----------  ----------  ----------
Other income (expense):
  Equity in earnings of investments and partnerships (Received dividends of
    $42.7, $18.6 and $13.7 million, respectively for the years ended 1996,
    1995 and 1994)...........................................................       111.1        31.8        18.3
  Minority interests and other expense.......................................       (27.2)      (16.7)      (12.4)
  Other income...............................................................        14.8        12.3         6.1
                                                                               ----------  ----------  ----------
Total other income...........................................................        98.7        27.4        12.0
                                                                               ----------  ----------  ----------
Earnings before interest and taxes...........................................       322.1       252.5       240.0
                                                                               ----------  ----------  ----------
Interest expense:
  Interest expense--long-term debt...........................................       118.0       105.5        89.5
  Interest expense--short-term debt..........................................         8.7        10.5         4.0
  Minority interest in income of partnership.................................         8.9         4.7      --
                                                                               ----------  ----------  ----------
Total interest expense.......................................................       135.6       120.7        93.5
                                                                               ----------  ----------  ----------
Earnings before income taxes.................................................       186.5       131.8       146.5
                                                                               ----------  ----------  ----------
Income taxes.................................................................        80.7        52.0        52.1
                                                                               ----------  ----------  ----------
Net income...................................................................       105.8        79.8        94.4
                                                                               ----------  ----------  ----------
Preference dividends.........................................................         2.1         2.1         3.0
                                                                               ----------  ----------  ----------
Earnings Available for Common Shares.........................................  $    103.7  $     77.7  $     91.4
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
Weighted Average Common Shares Outstanding:
  Primary....................................................................       47.21       45.08       43.97
  Fully diluted..............................................................       47.53       45.47       45.18
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
Earnings Per Common Share:
  Primary....................................................................  $     2.20  $     1.72  $     2.08
  Fully diluted..............................................................        2.19        1.71        2.06
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>
 
See accompanying notes to consolidated financial statements.
 
                                       36
<PAGE>
                          CONSOLIDATED BALANCE SHEETS
 
<TABLE>
<CAPTION>
                                                                                          DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1996        1995        1994
                                                                               ----------  ----------  ----------
                                                                                          IN MILLIONS
<S>                                                                            <C>         <C>         <C>
ASSETS
Current Assets:
  Cash and cash equivalents..................................................  $    137.1  $    110.7  $     67.2
  Funds on deposit...........................................................        56.8        41.2        44.8
  Accounts receivable, net...................................................       811.6       332.2       215.6
  Inventories and supplies...................................................       110.9       112.5       134.3
  Price risk management assets...............................................        55.2        26.4          --
  Prepayments and other......................................................        32.9        53.0        51.9
                                                                               ----------  ----------  ----------
Total current assets.........................................................     1,204.5       676.0       513.8
                                                                               ----------  ----------  ----------
Property, plant and equipment, net...........................................     2,406.7     2,279.6     2,266.4
Investments in subsidiaries and partnerships.................................       761.0       574.4       148.5
Price risk management assets.................................................       154.1       175.5          --
Deferred charges.............................................................       178.6       180.4       182.4
                                                                               ----------  ----------  ----------
Total Assets.................................................................  $  4,704.9  $  3,885.9  $  3,111.1
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
 
LIABILITIES AND SHAREOWNERS' EQUITY
 
Current Liabilities:
  Current maturities of long-term debt.......................................  $     25.7  $     15.1  $    138.8
  Short-term debt............................................................       252.0       288.6       182.4
  Accounts payable...........................................................       912.9       434.3       340.3
  Accrued liabilities........................................................        50.0        34.8        43.1
  Price risk management liabilities..........................................        71.7        67.9          --
  Other......................................................................       107.3       107.1        89.0
                                                                               ----------  ----------  ----------
Total current liabilities....................................................     1,419.6       947.8       793.6
                                                                               ----------  ----------  ----------
Long-term liabilities:
  Long-term debt, net........................................................     1,470.7     1,355.4       976.9
  Deferred income taxes and credits..........................................       313.7       279.2       300.4
  Price risk management liabilities..........................................        64.5        94.6          --
  Minority interests.........................................................        56.9        45.9        28.4
  Other deferred credits.....................................................        96.5        91.3        79.6
                                                                               ----------  ----------  ----------
Total long-term liabilities..................................................     2,002.3     1,866.4     1,385.3
                                                                               ----------  ----------  ----------
Company-obligated mandatorily redeemable
  preferred securities of partnership........................................       100.0       100.0          --
Preferred and preference stock...............................................        25.0        25.4        25.4
Common shareowners' equity...................................................     1,158.0       946.3       906.8
Commitments and contingencies................................................
                                                                               ----------  ----------  ----------
Total Liabilities and Shareowners' Equity....................................  $  4,704.9  $  3,885.9  $  3,111.1
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>
 
See accompanying notes to consolidated financial statements.
 
                                       37
<PAGE>
           CONSOLIDATED STATEMENTS OF PREFERRED AND PREFERENCE STOCK
 
<TABLE>
<CAPTION>
                                                                                             DECEMBER 31,
                                                                                   --------------------------------
                                                                                      1996       1995       1994
                                                                                   ----------  ---------  ---------
                                                                                         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
Preferred Stock of Subsidiary, retractable.......................................          --         .4         .4
                                                                                   ----------  ---------  ---------
Total Preferred and Preference Stock.............................................  $     25.0  $    25.4  $    25.4
                                                                                   ----------  ---------  ---------
                                                                                   ----------  ---------  ---------
</TABLE>
 
------------------------
 
*The company intends to redeem all outstanding shares of its $2.05 Series
 preference stock on March 1, 1997.
 
             CONSOLIDATED STATEMENTS OF COMMON SHAREOWNERS' EQUITY
 
<TABLE>
<CAPTION>
                                                                                       YEAR ENDED DECEMBER 31,
                                                                                   --------------------------------
                                                                                      1996       1995       1994
                                                                                   ----------  ---------  ---------
                                                                                         DOLLARS IN MILLIONS
                                                                                           EXCEPT PER SHARE
<S>                                                                                <C>         <C>        <C>
Common Stock: authorized 100,000,000 shares, par value $1 per share, 53,293,645
 shares outstanding (45,965,952 at December 31, 1995 and 44,827,135 at December
 31, 1994); authorized 20,000,000 shares of Class A common stock, par value $1
 per share, none issued
  Balance beginning of year......................................................  $     46.0  $    44.8  $    42.0
  Issuance of common stock.......................................................         7.3        1.2        2.8
                                                                                   ----------  ---------  ---------
Balance end of year..............................................................        53.3       46.0       44.8
                                                                                   ----------  ---------  ---------
Premium on Capital Stock:
  Balance beginning of year......................................................       800.6      774.2      722.4
  Issuance of common stock.......................................................       191.1       26.4       51.8
                                                                                   ----------  ---------  ---------
Balance end of year..............................................................       991.7      800.6      774.2
                                                                                   ----------  ---------  ---------
Retained Earnings:
  Balance beginning of year......................................................       106.2      107.0       93.4
  Net income.....................................................................       105.8       79.8       94.4
  Dividends on preference stock..................................................        (2.1)      (2.1)      (3.0)
  Dividends on common stock -- $1.76 per share in
    1996, $1.72 in 1995, and $1.70 in 1994.......................................       (84.6)     (77.9)     (74.6)
  Reissuance of common stock.....................................................      --            (.6)      (3.2)
                                                                                   ----------  ---------  ---------
Balance end of year..............................................................       125.3      106.2      107.0
                                                                                   ----------  ---------  ---------
Treasury stock, at cost (228,807 shares at December 31,
 1996 and 227,587 shares at December 31, 1994)...................................        (6.4)    --           (6.6)
Currency translation adjustment..................................................        (5.9)      (6.5)     (12.6)
                                                                                   ----------  ---------  ---------
Total Common Shareowners' Equity.................................................  $  1,158.0  $   946.3  $   906.8
                                                                                   ----------  ---------  ---------
                                                                                   ----------  ---------  ---------
</TABLE>
 
See accompanying notes to consolidated financial statements.
 
                                       38
<PAGE>
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                                       YEAR ENDED DECEMBER 31,
                                                                                   -------------------------------
                                                                                     1996       1995       1994
                                                                                   ---------  ---------  ---------
                                                                                             IN MILLIONS
<S>                                                                                <C>        <C>        <C>
Cash Flows From Operating Activities:
  Net income.....................................................................  $   105.8  $    79.8  $    94.4
  Adjustments to reconcile net income to net cash provided:
    Depreciation, depletion and amortization.....................................      127.8      155.6      147.1
    Provision for asset impairments..............................................         --       34.6         --
    Net changes in price risk management assets and liabilities..................      (33.7)     (39.4)        --
    Deferred taxes and investment tax credits....................................       34.5      (21.2)      66.5
    Equity in earnings from investments and partnerships.........................     (111.1)     (31.8)     (18.3)
    Dividends from investments and partnerships..................................       42.7       18.6       13.7
    Minority interests...........................................................        8.0        3.7        3.4
    Write-off of deferred merger costs, net of termination fee received..........       11.0         --         --
    Changes in certain assets and liabilities, net of effects of acquisitions and
      restructuring --
      Accounts receivable, net...................................................     (506.2)    (167.4)      40.5
      Accounts receivable sold...................................................       61.6       50.8      (21.5)
      Inventories and supplies...................................................        1.6       21.8      (32.5)
      Prepayments and other......................................................       20.1       (1.1)     (20.5)
      Accounts payable...........................................................      478.6       94.0      (52.2)
      Accrued liabilities........................................................       15.2       (8.3)      (5.3)
      Deferred charges, net......................................................       (1.0)       2.0      (31.8)
      Other......................................................................        7.9       69.5       45.8
                                                                                   ---------  ---------  ---------
Cash provided from operating activities..........................................      262.8      261.2      229.3
                                                                                   ---------  ---------  ---------
Cash Flows From Investing Activities:
  Additions to utility plant.....................................................     (134.3)    (109.4)    (132.0)
  Purchase of utility and other businesses.......................................     (138.1)    (100.9)     (28.2)
  Investments in international businesses........................................      (42.3)    (379.3)        --
  Investments in independent power projects......................................         --      (59.0)     (22.2)
  Proceeds on sale of oil and gas properties.....................................         --      204.5         --
  Investments in energy related properties.......................................      (26.4)    (144.0)    (113.6)
  Other..........................................................................      (70.5)     (46.8)     (50.3)
                                                                                   ---------  ---------  ---------
Cash used for investing activities...............................................     (411.6)    (634.9)    (346.3)
                                                                                   ---------  ---------  ---------
Cash Flows From Financing Activities:
  Issuance of common stock.......................................................      198.4       29.5        2.8
  Issuance of company-obligated mandatorily redeemable
    preferred securities of partnership..........................................         --      100.0         --
  Retirements of preference stock................................................         --         --       (6.8)
  Treasury stock sold (acquired).................................................       (6.4)       6.6       (6.6)
  Issuance of long-term debt.....................................................      129.7      415.2      104.1
  Retirement of long-term debt...................................................      (22.2)    (160.3)        --
  Short-term borrowings (repayments), net........................................      (37.6)     106.2      112.4
  Cash dividends paid............................................................      (86.7)     (80.0)     (77.6)
                                                                                   ---------  ---------  ---------
Cash provided from financing activities..........................................      175.2      417.2      128.3
                                                                                   ---------  ---------  ---------
Increase in cash and cash equivalents............................................       26.4       43.5       11.3
Cash and cash equivalents at beginning of year...................................      110.7       67.2       55.9
                                                                                   ---------  ---------  ---------
Cash and Cash Equivalents at End of Year.........................................  $   137.1  $   110.7  $    67.2
                                                                                   ---------  ---------  ---------
                                                                                   ---------  ---------  ---------
</TABLE>
 
See accompanying notes to consolidated financial statements.
 
                                       39
<PAGE>
               NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
NATURE OF OPERATIONS
 
    UtiliCorp United Inc. (the company, a Delaware corporation) is an
international energy and energy services company. The company's principal lines
of business are in the following segments: UtiliCorp Energy Delivery (UED),
Generation, Aquila Energy (Aquila) and UtiliCorp Energy Solutions (UES). The
company's international operations are managed as stand-alone companies or
investments through locally based management. UED's businesses consist of the
domestic utility distribution and transmission businesses and certain on-system
appliance repair and servicing businesses. Generation's businesses are domestic
electricity generation and independent power projects. Aquila's businesses are
the wholesale energy marketing, natural gas processing and gathering businesses.
UES's businesses are small commercial and industrial gas marketing, appliance
repair and servicing and other consumer products and services. The utility
businesses operate in eight states and one province of Canada. Natural gas is
marketed throughout the U.S. and in parts of Canada and the United Kingdom
(U.K.). The company's gas processing operations are in Texas and Oklahoma. In
addition to U.S., Canadian and U.K. businesses, the company has various
investments in Australia, New Zealand and Jamaica.
 
USE OF ESTIMATES
 
    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.
 
PRINCIPLES OF CONSOLIDATION
 
    The consolidated financial statements of the company include all operating
divisions and all majority-owned subsidiaries. Investments in which the company
has an ownership interest between 20% and 50% or otherwise exercises significant
influence are accounted for using the equity method. All significant
intercompany accounts and transactions have been eliminated.
 
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 company that
invests in New Zealand electric utilities.
 
PROPERTY, PLANT AND EQUIPMENT
 
    Property, plant and equipment are stated at original cost. Repair and
maintenance costs are expensed as incurred. Depreciation is provided on a
straight-line basis over the estimated lives for utility plant by applying
composite average annual rates, ranging from 3.1% to 4.3%, as approved by
regulatory authorities. When property is replaced, removed or abandoned, its
cost, together with the costs of removal less salvage, is charged to accumulated
depreciation. Non-regulated property, plant and equipment are depreciated on a
straight-line basis over their estimated lives ranging from three to 50 years.
Depreciation was determined for oil and gas properties using the units of
production method over the estimated lives of the producing properties based on
estimated quantities of proved reserves. Gathering, processing and other energy
related property is depreciated using a composite average annual rate of 5.0%.
 
                                       40
<PAGE>
    The excess of total acquisition costs over the aggregate regulated value of
net assets acquired to date is included in utility plant ($163.8 million at
December 31, 1996) and is being amortized on a straight-line basis over periods
ranging from 15 to 40 years.
 
SALES RECOGNITION
 
    Sales are generally recognized as products and services are delivered,
except for price risk management activities as discussed below.
 
    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 an adjustment to sales upon contract execution.
Changes in the market value of the 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 periods prior to 1995 and increased 1995 sales and income from operations by
$29.8 million ($18.3 million after tax). The impact primarily resulted 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.
 
FINANCIAL INSTRUMENTS
 
    As indicated above, the company accounts for financial instruments
associated with its natural gas and electricity 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 income tax expense or
benefit is based on the changes in the assets and liabilities from period to
period. Deferred investment tax credits are amortized over the lives of the
related properties.
 
CASH EQUIVALENTS AND CASH FLOW INFORMATION
 
    Cash equivalents are defined as temporary cash investments with an original
maturity of three months or less. As of December 31, 1996, 1995 and 1994, the
company had cash held in foreign countries of $86.7 million, $77.5 million and
$58.5 million, respectively.
 
                                       41
<PAGE>
    Cash payments for interest, taxes and supplemental disclosures relating to
acquisition activities are presented below:
 
<TABLE>
<CAPTION>
                                                                                       1996       1995       1994
                                                                                     ---------  ---------  ---------
                                                                                               IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Cash paid during the year for--
  Interest, net of amount capitalized..............................................  $   132.1  $   135.4  $   100.3
  Income taxes.....................................................................       49.1       46.9       11.4
                                                                                     ---------  ---------  ---------
Liabilities assumed in acquisitions--
  Fair value of assets acquired....................................................  $     7.0  $   114.0  $    35.9
  Cash paid for acquisitions.......................................................     --          100.9       28.2
  Liabilities assumed..............................................................        7.0       13.1        7.7
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</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
 
CURRENCY TRANSLATION ADJUSTMENTS
 
    The financial statements of foreign operations have been translated into
U.S. dollars using the weighted average exchange rates during the period for
income statement items and year-end exchange rates for balance sheet items. The
resulting changes in the value of foreign currencies affect the asset and
liability value, and income and loss contributions. The cumulative translation
adjustments are reflected in the consolidated statements of common shareowners'
equity.
 
SOFTWARE DEVELOPMENT COSTS
 
    The company capitalizes the direct development costs of internal-use
software after technological feasibility has been achieved. All costs incurred
prior to reaching technical feasibility are expensed in the period incurred.
 
STOCK-BASED COMPENSATION
 
    In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-based
Compensation" (SFAS 123). 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
require either recording additional compensation expense or disclosing the
impact on net income and earnings per share as if the company elected to record
compensation expense. The company has elected to disclose pro forma information
required by SFAS 123 rather than record compensation expense. For the years
ended December 31, 1996, 1995, and 1994, compensation expense under SFAS 123,
relating to stock-based compensation plans would be $1.5 million, $3.6 million
and $1.5 million, respectively. If the company had recorded compensation expense
pursuant to the requirements of SFAS 123, earnings per share would have been
reduced by $.02, $.05, and $.02 for the years ended December 31, 1996, 1995, and
1994, respectively.
 
RECLASSIFICATIONS
 
    Certain prior year amounts in the consolidated financial statements have
been reclassified where necessary to conform to the 1996 presentation.
 
                                       42
<PAGE>
                         NOTE 2: PRICE RISK MANAGEMENT
 
A. TRADING ACTIVITIES
 
PRICE RISK MANAGEMENT ACTIVITIES
 
    The company offers price risk management services in connection with its
energy trading activities. These services are provided through a variety of
financial instruments, including forward contracts which commit the company to
purchase or sell energy in the future; swap agreements, which require payments
to (or receipt of payments from) counterparties based on the differential
between specified prices for the related commodity; futures and options
contracts traded on the New York Mercantile Exchange (NYMEX); and other
contractual arrangements.
 
    The availability 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, protect its investment in natural gas storage
inventories and provide price risk management services to its customers. The
company is also able to secure additional sources of energy or create additional
markets for existing supply through the use of exchange for physical
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. The contractual amounts and terms of these
financial instruments at December 31, 1996, are shown below:
 
<TABLE>
<CAPTION>
                                                                    FIXED PRICE    FIXED PRICE      MAXIMUM TERM IN
                                                                       PAYOR         RECEIVER            YEARS
                                                                    ------------  --------------  -------------------
<S>                                                                 <C>           <C>             <C>
Energy Commodities:
  Gas (trillion BTUs).............................................        506.4          341.0                11
  Electricity (megawatt-hours)....................................      134,400        492,000                 1
                                                                    -------------------------------------------------
Financial Products:
  Interest rate instruments (in millions).........................   $  1,570.0             --                 7
                                                                    -------------------------------------------------
</TABLE>
 
    Although the company 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. A
simultaneous price movement of $.10 per MMBtu along the entire forward price
curve for natural gas positions held at December 31, 1996 would have impacted
sales by approximately $.8 million.
 
    The company measures the risk in its trading portfolio using value-at-risk
methodologies, which simulate forward price curves in the energy markets to
estimate the size of future potential losses. The quantification of market risk
using value-at-risk methodologies provides a consistent measure of risk across
diverse energy markets and products. The use of this method requires a number of
key assumptions including the selection of a confidence level for losses, the
estimated holding period and the treatment of risks outside the value-at-risk
method.
 
                                       43
<PAGE>
    The company expresses value-at-risk as a percentage of earnings based on a
95% confidence level using three day holding periods. On a three day basis as of
December 31, 1996, the company's value-at-risk (unaudited) for its price risk
management activities was not material to consolidated net income. The company
employs additional risk control mechanisms such as stress testing, daily loss
limits and commodity position limits as well as daily monitoring of the trading
function by an independent function.
 
    Based upon the policies and controls discussed above, management does not
anticipate a materially adverse effect on financial position or results of
operations as a result of market fluctuations.
 
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 contractual commitments included in its energy 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 following table displays the mark-to-market values of the company's
energy transactions at December 31, 1996 and 1995 and the average value for the
year ended December 31, 1996 and 1995:
 
<TABLE>
<CAPTION>
                                            PRICE RISK MANAGEMENT ASSETS       PRICE RISK MANAGEMENT LIABILITIES
                                        ------------------------------------  ------------------------------------
                                         AVERAGE VALUE    DECEMBER 31, 1996    AVERAGE VALUE    DECEMBER 31, 1996
                                        ---------------  -------------------  ---------------  -------------------
                                                                       IN MILLIONS
<S>                                     <C>              <C>                  <C>              <C>
Independent power producers...........     $   172.2          $   158.3          $  --              $      .1
Financial institutions................          17.4               18.3               34.3               21.0
Oil and gas producers.................           2.8                9.1               24.4               19.9
Gas transmission......................           5.4               10.0               23.5               25.1
Energy marketers......................           4.5                9.7                2.7               10.5
Other.................................           2.9                3.8                2.6                2.3
                                             -------            -------            -------            -------
Gross value...........................         205.2              209.2               87.5               78.9
Reserves..............................                                                64.6               57.2
                                             -------            -------            -------            -------
Total.................................     $   205.2          $   209.2          $   152.1          $   136.1
                                             -------            -------            -------            -------
Net Value.............................                        $    73.1
                                                                -------
                                                                -------
</TABLE>
 
                                       44
<PAGE>
 
<TABLE>
<CAPTION>
                                            PRICE RISK MANAGEMENT ASSETS       PRICE RISK MANAGEMENT LIABILITIES
                                        ------------------------------------  ------------------------------------
                                         AVERAGE VALUE    DECEMBER 31, 1995    AVERAGE VALUE    DECEMBER 31, 1995
                                        ---------------  -------------------  ---------------  -------------------
                                                                       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                 .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>
 
    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 could impact its overall
exposure to credit risk, either positively or negatively. However, the company
maintains credit policies with regard to its counterparties that management
believes minimizes overall credit risk.
 
    Three independent power producers comprise the majority of the company's net
price risk management assets. This concentration of customers may impact the
company's overall exposure to credit risk, either positively or negatively, in
that the counterparties may be similarly affected by changes in economic,
regulatory or other conditions.
 
B. NON-TRADING ACTIVITIES--HEDGING INSTRUMENTS
 
    The company enters into forwards, futures and other contracts related to its
commodity businesses. Financial instruments are used to manage price
fluctuations in 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.
 
    At December 31, 1996, 1995 and 1994, the company had natural gas financial
instruments with a contractual volume of 1,701, 1,327 and 310 BCF, respectively,
expiring in 2007. As of December 31, 1996, 1995 and 1994 the future cash flow
requirements, net of margin deposits, related to these financial instruments was
$(33.1), $44.2 and $9.9 million, respectively. Margin deposits are required on
certain financial instruments to address significant fluctuations in market
prices.
 
                          NOTE 3: ACCOUNTS RECEIVABLE
 
    The components of accounts receivable on the Consolidated Balance Sheets are
as follows:
 
<TABLE>
<CAPTION>
                                                                                           DECEMBER 31,
                                                                                  -------------------------------
                                                                                    1996       1995       1994
                                                                                  ---------  ---------  ---------
                                                                                            IN MILLIONS
<S>                                                                               <C>        <C>        <C>
Accounts receivable, net........................................................  $   925.2  $   405.1  $   261.7
Unbilled revenue................................................................      116.4       95.5       71.5
Accounts receivable sale program................................................     (230.0)    (168.4)    (117.6)
                                                                                  ---------  ---------  ---------
Total...........................................................................  $   811.6  $   332.2  $   215.6
                                                                                  ---------  ---------  ---------
                                                                                  ---------  ---------  ---------
</TABLE>
 
                                       45
<PAGE>
    The company has agreements with financial institutions to sell, on a
continuing basis, up to $230 million of eligible accounts receivable on a
limited recourse basis. Fees associated with these sales were approximately (in
millions) $12.2 in 1996, $8.6 in 1995 and $6.9 in 1994 and are included in
minority interests and other expense in the accompanying Consolidated Statements
of Income. The agreements were recently modified to meet the new criteria for
sales accounting treatment under the Statement of Financial Accounting Standards
No. 125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liability" (SFAS 125). These modifications were minor and had
no impact on the underlying economics of these facilities.
 
                     NOTE 4: PROPERTY, PLANT AND EQUIPMENT
 
    The components of property, plant and equipment are as follows:
 
<TABLE>
<CAPTION>
                                                                                          DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1996        1995        1994
                                                                               ----------  ----------  ----------
                                                                                          IN MILLIONS
<S>                                                                            <C>         <C>         <C>
Electric utility.............................................................  $  1,703.8  $  1,645.0  $  1,578.7
Gas utility..................................................................     1,102.2     1,064.8       954.6
Gas gathering and pipeline systems...........................................       569.2       547.0       440.0
Oil and gas properties.......................................................      --          --           416.7
Other non-regulated plant....................................................       189.4       106.2        88.3
Construction in process (includes $34.1 of internal-use software costs at
 December 31, 1996)..........................................................        93.3        47.6        23.3
                                                                               ----------  ----------  ----------
                                                                                  3,657.9     3,410.6     3,501.6
Less--depreciation, depletion and amortization...............................     1,251.2     1,131.0     1,235.2
                                                                               ----------  ----------  ----------
Property, plant and equipment, net...........................................  $  2,406.7  $  2,279.6  $  2,266.4
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
</TABLE>
 
JOINTLY OWNED ELECTRIC UTILITY PLANT
 
    The company holds an 8% ownership interest and leases another 8% in three
coal-fired plants, approximately 600-megawatt generating units (Jeffrey Energy
Center or JEC). The JEC is operated by another utility. At December 31, 1996,
electric utility plant and accumulated depreciation included $101.5 million and
$46.9 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.
 
SALE OF OIL AND GAS ASSETS
 
    On September 27, 1995, the company sold the 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
properties.
 
                           NOTE 5: ASSET IMPAIRMENTS
 
    In 1995 the company reviewed its long-lived asset carrying values 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
 
                                       46
<PAGE>
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.......................................    $    15.4
Gas gathering systems............................................................         13.2
Gas processing plants............................................................          6.0
                                                                                         -----
Total............................................................................    $    34.6
                                                                                         -----
                                                                                         -----
</TABLE>
 
    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 6: 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), New Zealand, via UtiliCorp N.Z., Inc. (UNZ), two U.K. gas
marketing joint ventures, via UtiliCorp U.K., Limited and 17 power projects via
UtilCo Group which are accounted for under the equity method. For the company's
international businesses, adjustments for 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
 
                                       47
<PAGE>
statements. The following table summarizes the company's equity investment
balances and related equity earnings for 1996 through 1994.
 
<TABLE>
<CAPTION>
                                                                      INVESTMENT
                                                                   DECEMBER 31, (A)                  EQUITY EARNINGS
                           OWNERSHIP                        -------------------------------  -------------------------------
                          AT 12/31/96        COUNTRY          1996       1995       1994       1996       1995       1994
                          -----------  -------------------  ---------  ---------  ---------  ---------  ---------  ---------
                                                                                      IN MILLIONS
<S>                       <C>          <C>                  <C>        <C>        <C>        <C>        <C>        <C>
UAHL investment (b).....       49.9%        Australia       $   274.0  $   257.9  $  --      $    42.7  $     9.3  $  --
UNZ investments: (c)
  WEL Energy Group Ltd.
    (WEL)(d)............       39.5%       New Zealand           46.1       39.1       24.3        6.2        2.2         .2
  Power New Zealand Ltd.
    (PNZ)...............       30.3%       New Zealand          134.2      107.1     --           11.2     --         --
UtiliCorp U.K., Limited
 investments (e)........         25%     United Kingdom        --         --            1.4     --           (1.6)      (1.1)
UtilCo Group
 partnerships (e)(f)....     22%-50%     U.S. & Jamaica         195.9      170.3      122.8       50.9       21.9       19.2
Oasis Pipe Line Company
 (Oasis)................         40%      United States         110.8     --         --             .1     --         --
                                                            ---------  ---------  ---------  ---------  ---------  ---------
Total...................                                    $   761.0  $   574.4  $   148.5  $   111.1  $    31.8  $    18.3
                                                            ---------  ---------  ---------  ---------  ---------  ---------
                                                            ---------  ---------  ---------  ---------  ---------  ---------
</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. As of December 31, 1996, the UAHL, WEL, PNZ,
    UtilCo and Oasis investments had $8.0 million, $5.2 million, $39.9 million,
    $30.6 million and $96.8 million, respectively, of value in excess of the
    underlying pro rata equity amounts which are being amortized over periods
    ranging between 10 and 40 years on a straight-line basis.
 
(b) Equity earnings include interest income and management fees between the
    equity investee and UAHL.
 
(c) The company owns 79% of UNZ with the remaining 21% owned by an unrelated
    party.
 
(d) Prior to February 1995, the company's participation in WEL's earnings was
    limited to 5%.
 
(e) Investments are aggregated. Individual investments are not significant.
 
(f)  Investment and share of pretax earnings include the James River project,
    49% owned by the company and 1% owned by UtilCo Group.
 
                                       48
<PAGE>
    Summarized combined financial information of unconsolidated material equity
investments is presented below.
 
<TABLE>
<CAPTION>
                                                                                           DECEMBER 31,
                                                                                 ---------------------------------
                                                                                    1996        1995       1994
                                                                                 ----------  ----------  ---------
                                                                                            IN MILLIONS
<S>                                                                              <C>         <C>         <C>
Assets:
  Current assets...............................................................  $    328.5  $    336.5  $   115.7
  Non-current assets...........................................................     3,131.0     2,785.3      855.5
                                                                                 ----------  ----------  ---------
Total assets...................................................................  $  3,459.5  $  3,121.8  $   971.2
                                                                                 ----------  ----------  ---------
                                                                                 ----------  ----------  ---------
Liabilities and Equity:
  Current liabilities..........................................................  $    325.2  $    276.5  $    93.7
  Non-current liabilities......................................................     2,163.7     2,125.6      694.8
  Equity.......................................................................       970.6       719.7      182.7
                                                                                 ----------  ----------  ---------
Total liabilities and capital..................................................  $  3,459.5  $  3,121.8  $   971.2
                                                                                 ----------  ----------  ---------
                                                                                 ----------  ----------  ---------
</TABLE>
 
<TABLE>
<CAPTION>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                                 ---------------------------------
                                                                                    1996        1995       1994
                                                                                 ----------  ----------  ---------
                                                                                            IN MILLIONS
<S>                                                                              <C>         <C>         <C>
Operating Results:
  Revenues.....................................................................  $  1,277.8  $    729.6  $   352.8
  Costs and expenses...........................................................     1,109.1       657.3      299.7
                                                                                 ----------  ----------  ---------
Net income.....................................................................  $    168.7  $     72.3  $    53.1
                                                                                 ----------  ----------  ---------
                                                                                 ----------  ----------  ---------
</TABLE>
 
INTEREST IN AUSTRALIAN ELECTRIC UTILITY
 
    In September 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-denominated revolving credit facilities. See Note 9 for more
information regarding financing arrangements.
 
                                       49
<PAGE>
    The acquisition was recorded as a purchase and, accordingly, the assets and
liabilities were recorded at the estimated fair value at the date of
acquisition. The equity investment is included in Investments in Subsidiaries
and Partnerships on the Consolidated Balance Sheets. Pro forma unaudited results
of operations for the company, assuming the acquisition occurred at the
beginning of each period, are shown below. For the 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>
 
    The company's Australian investments are comprised of the following
components:
 
<TABLE>
<CAPTION>
                                                                             CARRYING VALUE          FAIR VALUE
                                                                          --------------------  --------------------
                                                                            1996       1995       1996       1995
                                                                          ---------  ---------  ---------  ---------
                                                                                         IN MILLIONS
<S>                                                                       <C>        <C>        <C>        <C>
Investment in convertible notes(a)(b)...................................  $   138.1  $   129.7  $   138.1  $   129.7
Investment in floating subordinated debt(a)(b)..........................       74.2       92.7       74.2       92.7
Investment in PPL common stock (not traded).............................       61.7       35.5
                                                                          ---------  ---------
Total...................................................................  $   274.0  $   257.9
                                                                          ---------  ---------
                                                                          ---------  ---------
</TABLE>
 
------------------------
 
(a) The company classifies these securities as held-to-maturity.
 
(b) These securities have floating interest rates at 2.75% above the Australian
    Bank Bill rate maturing in September 2015. The interest rate at December 31,
    1996, was 9.57%.
 
INTEREST IN NEW ZEALAND ELECTRIC UTILITIES
 
    In November 1995, UNZ acquired 20.0% of the common stock of PNZ, a New
Zealand electric distribution utility, for $69.4 million. This acquisition was
financed through a New Zealand-dollar-denominated credit facility. UNZ has
continued to acquire PNZ shares throughout 1996. PNZ is New Zealand's second
largest electric distribution utility, serving approximately 216,000 customers.
 
    In February 1995, UNZ paid $16.1 million to WEL to satisfy its capital
commitment. Since then, UNZ has participated 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%. UNZ has
continued to acquire WEL shares throughout 1996. WEL is an electric distribution
utility serving approximately 60,000 customers.
 
INTERESTS IN INDEPENDENT POWER PROJECTS
 
    In April 1996, one of UtilCo Group's power projects entered into a long-term
lease arrangement with a third party. This transaction was accounted for as a
sale by the partnership and resulted in the recognition of a gain. UtilCo Group
recorded its share of the gain through equity earnings during the
 
                                       50
<PAGE>
second quarter. In addition, UtilCo Group recorded certain restructuring
reserves primarily in connection with changes in power project agreements. The
net gain from these items was $11.8 million after tax.
 
    In May 1995, the company and UtilCo Group acquired a 50% interest in an
independent power project in Alabama for $59 million.
 
INVESTMENT IN PIPELINE SYSTEM
 
    In July 1996 and November 1996, the company acquired, in aggregate, 40% of
Oasis Pipe Line Company for approximately $132.0 million. Oasis consists of a
600-mile intrastate pipeline system in Texas near many of Aquila Energy's
existing gathering systems. As part of the purchase, another owner has the
option to buy one-fifth of Oasis, including 5% now held by Aquila, on or before
April 1, 1997. Aquila was notified by the other partner that it intends to
exercise this option.
 
                           NOTE 7: REGULATORY ASSETS
 
    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. If the company discontinued applying this accounting
standard, it would be required to make an adjustment to the carrying value of
certain assets.
 
    The following table presents the amount of regulatory assets recorded at
December 31, 1996, 1995 and 1994, respectively. These regulatory assets are
primarily reflected as deferred charges on the consolidated balance sheets.
 
<TABLE>
<CAPTION>
                                                                                       1996       1995       1994
                                                                                     ---------  ---------  ---------
                                                                                               IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Income taxes.......................................................................  $    53.6  $    53.7  $    72.3
Environmental liabilities..........................................................       11.3       10.4       10.9
Debt-related costs.................................................................       22.3       23.8       21.9
Regulatory accounting orders.......................................................        9.1        7.8        8.3
Demand-side management programs....................................................       10.8        8.6        5.0
Post-retirement benefits...........................................................       10.5        8.5        7.9
Purchased gas and related costs....................................................        5.6        3.3        4.2
Other (including FERC Order No. 636)...............................................       22.6       30.3       31.6
                                                                                     ---------  ---------  ---------
Total..............................................................................  $   145.8  $   146.4  $   162.1
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>
 
                            NOTE 8: SHORT-TERM DEBT
 
    Short-term debt is comprised of the following components:
 
<TABLE>
<CAPTION>
                                                                                              DECEMBER 31,
                                                                                     -------------------------------
                                                                                       1996       1995       1994
                                                                                     ---------  ---------  ---------
                                                                                               IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Bank borrowing (uncommitted).......................................................  $   202.0  $   153.1  $   155.4
Commercial paper...................................................................       50.0      135.5       27.0
                                                                                     ---------  ---------  ---------
Total..............................................................................  $   252.0  $   288.6  $   182.4
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
Weighted average interest rate at year end.........................................      5.78%      6.14%      6.20%
                                                                                     -------------------------------
</TABLE>
 
                                       51
<PAGE>
    The company has a commercial paper program of $150 million. To support the
program, 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 unused portion of the
revolving credit facility.
 
                             NOTE 9: LONG-TERM DEBT
 
    The company's long-term debt is summarized below:
 
<TABLE>
<CAPTION>
                                                                                          DECEMBER 31,
                                                                               ----------------------------------
                                                                                  1996        1995        1994
                                                                               ----------  ----------  ----------
                                                                                          IN MILLIONS
<S>                                                                            <C>         <C>         <C>
First Mortgage Bonds:
  Various, 9.93%*, due 1997-2008.............................................  $     23.0  $     23.0  $     23.0
Senior Notes:
  9.30% Series, retired......................................................      --          --           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       100.0
  Aquila Southwest Energy 8.29% Series, due September 15, 2002...............        75.0        87.5       100.0
  6.375% Series, due June 1, 2005............................................       100.0       100.0      --
  6.70% Series, due October 15, 2006.........................................       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:
  9.43%*, due 1997-2023......................................................        68.2        50.3        54.0
Convertible Subordinated Debentures:
  6.625%, due July 1, 2011...................................................         7.2         8.0        20.7
New Zealand Denominated Credit Facility, due February 28, 1998...............        78.9        63.6      --
Australian Denominated Credit Facility, due July 20, 2000....................       237.3       222.8      --
Other Notes and Obligations..................................................        56.8        65.3        43.0
                                                                               ----------  ----------  ----------
Total Long-Term Debt.........................................................     1,496.4     1,370.5     1,115.7
Less current maturities......................................................        25.7        15.1       138.8
                                                                               ----------  ----------  ----------
Long-term debt, net..........................................................  $  1,470.7  $  1,355.4  $    976.9
                                                                               ----------  ----------  ----------
                                                                               ----------  ----------  ----------
Fair value of long-term debt, including current maturities(a)................  $  1,559.3  $  1,473.6  $  1,094.4
Interest rate swap(a)........................................................        (1.8)        (.6)     --
                                                                               ----------------------------------
</TABLE>
 
------------------------
 
*   Weighted average interest rate.
 
(a) The fair value of long-term debt is based on current rates at which the
    company could borrow funds with similar remaining maturities. The interest
    rate swap agreements are used to reduce the effect of changing interest
    rates on the company's Australian Dollar Denominated Credit Facility.
 
    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
 
                                       52
<PAGE>
indentures without directly securing the 6.0%, 8.45%, 8.2%, 9.0%, 8.0%, 6.375%
and 6.70% Senior Notes equally as any mortgage bond issue. Currently the company
has no plans to issue mortgage bonds.
 
    The amounts of long-term debt maturing in each of the next five years and
thereafter are shown at right:
 
<TABLE>
<CAPTION>
                                                                             MATURING AMOUNTS
                                                                            ------------------
                                                                               IN MILLIONS
<S>                                                                         <C>
1997......................................................................     $       25.7
1998......................................................................            163.7
1999......................................................................            165.9
2000......................................................................            280.6
2001......................................................................             16.0
Thereafter................................................................            844.5
                                                                                   --------
Total.....................................................................     $    1,496.4
                                                                                   --------
                                                                                   --------
</TABLE>
 
    For the three years ended December 31, 1996, the company issued the
following series of Senior Notes which were used to reduce short-term debt.
 
<TABLE>
<CAPTION>
                                                         DATE ISSUED       MATURITY     FACE AMOUNT    NET PROCEEDS
                                                     -------------------  -----------  -------------  ---------------
                                                                           DOLLARS IN MILLIONS
<S>                                                  <C>                  <C>          <C>            <C>
6.7% series........................................         October 1996        2006*    $   100.0       $    99.5
6.375% series......................................            June 1995        2005*        100.0            99.3
8.45% series.......................................        November 1994        1999         100.0            99.5
</TABLE>
 
------------------------
 
*   The holder of each 6.7% and 6.375% senior note may elect to redeem any
    portion in multiples of $1,000 on October 15, 2001, and June 1, 2000,
    respectively, at face value plus accrued interest.
 
NEW ZEALAND DENOMINATED CREDIT FACILITY
 
    UtiliCorp South Pacific, Inc. (USP) has a $NZ135 million credit facility
with a consortium of banks that was used to finance a portion of the investments
made by UNZ. The interest rate floats (9.7% at December 31, 1996) with changes
in the New Zealand bank bill rate. The credit facility matures on February 28,
1998. A commitment fee of .20% applies to the unused portion of the credit
facility.
 
AUSTRALIAN DENOMINATED CREDIT FACILITIES
 
    UAHL has two five-year credit facilities ($A225 million and $A75 million)
with a consortium of banks that mature on July 20, 2000, which 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, 1996 was 6.79%. A commitment fee of .20% applies to the unused portion of
the credit facility.
 
    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.
 
CONVERTIBLE SUBORDINATED DEBENTURES
 
    At December 31, 1996, 6.625% convertible subordinated debentures totaling
$7.2 million remained outstanding. The debentures can be converted into
approximately 300,000 shares of common stock,
 
                                       53
<PAGE>
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 10: COMPANY-OBLIGATED PREFERRED SECURITIES
 
    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 Partnership on the Consolidated Balance
Sheets. The dividends are shown as minority interest in income of partnership.
The net proceeds were used to reduce short-term debt.
 
                             NOTE 11: CAPITAL STOCK
 
COMMON STOCK OFFERING
 
    In November 1996, the company issued 6 million shares of common stock at
$27.625. The net proceeds of $160.8 were used to reduce short-term debt.
 
DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
 
    In February 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. For the year ended December 31, 1996, 1.3
million shares were issued under this plan. As of December 31, 1996, 900,000
shares were available to issue under this 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 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
 
                                       54
<PAGE>
Savings Plan also includes a stock contribution fund whereby the company can
contribute an additional amount of company common stock to participants.
 
STOCK INCENTIVE PLAN
 
    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.
 
EMPLOYEE STOCK OPTION PLAN
 
    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.
 
    Stock options as of December 31, 1996, 1995 and 1994 are summarized below:
 
<TABLE>
<CAPTION>
                                                                              1996         1995         1994
                                                                           -----------  -----------  -----------
                                                                                          SHARES
<S>                                                                        <C>          <C>          <C>
Beginning balance........................................................    2,015,500    1,273,797    1,188,007
Granted..................................................................      303,850      812,403      203,650
Exercised................................................................      (18,410)     (11,900)     (98,910)
Cancelled................................................................     (100,490)     (58,800)     (18,950)
                                                                           -----------  -----------  -----------
Ending balance...........................................................    2,200,450    2,015,500    1,273,797
                                                                           -----------  -----------  -----------
                                                                           -----------  -----------  -----------
Weighted average prices:
Beginning balance........................................................  $     27.83  $     28.13  $     31.63
Granted price............................................................        28.55        27.36        31.63
Exercised price..........................................................        23.96        25.07        23.93
Cancelled price..........................................................        28.40        28.36        27.90
Ending balance...........................................................        27.94        27.83        28.13
</TABLE>
 
    At December 31, 1996, restricted stock awards and stock options which were
exercisable totaled 1,755,017 shares (at prices ranging between $17.40 and
$31.63).
 
                                       55
<PAGE>
                             NOTE 12: INCOME TAXES
 
    Income tax expense consists of the following components:
 
<TABLE>
<CAPTION>
                                                                                           YEAR ENDED DECEMBER 31,
                                                                                       -------------------------------
                                                                                         1996       1995       1994
                                                                                       ---------  ---------  ---------
                                                                                                 IN MILLIONS
<S>                                                                                    <C>        <C>        <C>
Currently Payable:
  Federal............................................................................  $    34.0  $    35.4  $    15.3
  Foreign............................................................................       14.2       10.6        5.2
  State..............................................................................        5.5       11.3       (1.5)
Deferred:
  Federal............................................................................       23.0       (3.6)      26.2
  State..............................................................................        4.3        (.4)       8.2
Investment tax credit amortization...................................................        (.3)      (1.3)      (1.3)
                                                                                       ---------  ---------  ---------
Total Income Tax Expense.............................................................  $    80.7  $    52.0  $    52.1
                                                                                       ---------  ---------  ---------
                                                                                       ---------  ---------  ---------
</TABLE>
 
    The principal components of the company's deferred income taxes consist of
the following:
 
<TABLE>
<CAPTION>
                                                                                              DECEMBER 31,
                                                                                     -------------------------------
                                                                                       1996       1995       1994
                                                                                     ---------  ---------  ---------
                                                                                               IN MILLIONS
<S>                                                                                  <C>        <C>        <C>
Deferred Tax Assets:
  Alternative minimum tax credit carryforward......................................  $    95.1  $    88.2  $    83.5
  Net operating loss carryforward..................................................     --         --           26.3
  Restructuring charges............................................................     --         --           16.0
                                                                                     ---------  ---------  ---------
Total deferred tax assets..........................................................       95.1       88.2      125.8
                                                                                     ---------  ---------  ---------
Deferred Tax Liabilities:
  Accelerated depreciation and other plant differences
    Regulated......................................................................      146.4      160.9      176.5
    Non-regulated..................................................................      158.3      140.2      168.7
  Regulatory asset--SFAS 109.......................................................       37.1       33.8       32.8
  Other, net.......................................................................       67.0       32.5       48.2
                                                                                     ---------  ---------  ---------
Total deferred tax liabilities.....................................................      408.8      367.4      426.2
                                                                                     ---------  ---------  ---------
Deferred income taxes, net.........................................................  $   313.7  $   279.2  $   300.4
                                                                                     ---------  ---------  ---------
                                                                                     ---------  ---------  ---------
</TABLE>
 
                                       56
<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,
                                                                                       -------------------------------------
                                                                                          1996         1995         1994
                                                                                       -----------  -----------  -----------
<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......................         .2          (.5)        (1.3)
  Investment tax credit amortization.................................................        (.2)        (1.0)         (.9)
  State income taxes, net of federal benefit.........................................        5.8          4.3          3.1
  Difference in tax rate of foreign subsidiaries.....................................         .9          1.3          1.9
  Other..............................................................................        1.6           .4         (2.2)
                                                                                             ---          ---          ---
Effective Income Tax Rate............................................................       43.3%        39.5%        35.6%
                                                                                             ---          ---          ---
                                                                                             ---          ---          ---
</TABLE>
 
    The company has an alternative minimum tax credit carryforward of
approximately $95.1 million at December 31, 1996. Alternative minimum tax
credits can be carried forward indefinitely and the company has not recorded a
valuation allowance against its tax credit carryforwards.
 
    No provision is made for U.S. income taxes on undistributed earnings of the
company's international businesses ($85.9 million at December 31, 1996) because
it is management's intention to reinvest such earnings in those international
operations. In the event of a distribution of these earnings in the form of
dividends, the company may be subject to both foreign withholding taxes and U.S.
income taxes net of allowable foreign tax credits. Consolidated income before
income taxes for the years ended December 31, 1996, 1995 and 1994 included
$39.2, $16.6 and $14.2 million, respectively, from international operations.
 
                                       57
<PAGE>
                           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,
                                                                           ---------------------------------------
                                                                               1996          1995         1994
                                                                           ------------  ------------  -----------
                                                                                     DOLLARS IN MILLIONS
<S>                                                                        <C>           <C>           <C>
Actuarial present value of benefit obligations:
  Vested benefit obligation..............................................      $153.9        $143.0       $119.4
  Accumulated benefit obligation.........................................       158.1         146.9        122.6
                                                                           ------------  ------------  -----------
Projected benefit obligation.............................................      $185.9        $183.9       $152.1
Plan assets at fair value (primarily publicly traded common stocks and
  bonds).................................................................       208.7         191.7        161.4
                                                                           ------------  ------------  -----------
Excess of plan assets over the projected benefit obligation..............        22.8           7.8          9.3
Unrecognized net loss from past experience different from that assumed...         8.2          24.1         22.0
Unrecognized net asset being recognized over 16 years....................       (11.3)        (12.5)       (13.7)
Unrecognized prior service cost..........................................          .9           (.3)         (.7)
                                                                           ------------  ------------  -----------
Pension assets included in prepayments and other.........................      $ 20.6        $ 19.1       $ 16.9
                                                                           ------------  ------------  -----------
                                                                           ------------  ------------  -----------
Net pension expense included the following components:
  Service cost...........................................................      $  6.5        $  5.8       $  5.6
  Interest cost on projected benefit obligation..........................        13.0          12.0         11.0
  Actual return on plan assets...........................................       (25.7)        (37.6)          .6
  Regulatory adjustment..................................................          .9            .6           .5
  Net amortization and deferral..........................................         6.5          20.5        (16.7)
                                                                           ------------  ------------  -----------
Net pension expense......................................................      $  1.2        $  1.3       $  1.0
                                                                           ------------  ------------  -----------
                                                                           ------------  ------------  -----------
Discount rate assumed....................................................        7.60%         7.17%        7.89%
Assumed rate of return on future compensation levels.....................     5.0-5.4%      5.0-5.5%     5.0-5.5%
Assumed long-term rate of return on assets...............................    8.0-10.0%     8.5-10.0%     8.5-9.0%
                                                                           ---------------------------------------
</TABLE>
 
    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, which is
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 substantially all employees. The majority of the plan's funding is provided
by the company on a pay-as-you-go basis with most retirees paying a portion of
the cost.
 
                                       58
<PAGE>
    The following table summarizes the status of the company's post-retirement
plans for financial statement purposes and the related amounts included in the
Consolidated Balance Sheets at December 31, 1996, 1995 and 1994:
 
<TABLE>
<CAPTION>
                                                                                               DECEMBER 31,
                                                                                      -------------------------------
                                                                                        1996       1995       1994
                                                                                      ---------  ---------  ---------
                                                                                                IN MILLIONS
<S>                                                                                   <C>        <C>        <C>
Actuarial present value of post-retirement benefit obligations:
  Retirees..........................................................................  $    27.8  $    23.1  $    24.1
  Other fully eligible participants.................................................        4.2        6.0        7.6
  Other active participants.........................................................        7.0       11.1        8.3
  Plan assets at fair value.........................................................        (.5)       (.9)       (.3)
  Unrecognized transition obligation................................................      (32.4)     (34.4)     (36.4)
  Unrecognized net gain.............................................................        8.5        5.2        3.3
                                                                                      ---------  ---------  ---------
Accrued liability...................................................................  $    14.6  $    10.1  $     6.6
                                                                                      ---------  ---------  ---------
                                                                                      ---------  ---------  ---------
</TABLE>
 
    The components of health care and life insurance costs are:
 
<TABLE>
<CAPTION>
                                                                                        1996       1995       1994
                                                                                      ---------  ---------  ---------
                                                                                                IN MILLIONS
<S>                                                                                   <C>        <C>        <C>
Service cost........................................................................  $     1.0  $      .8  $      .6
Interest cost.......................................................................        2.9        2.7        2.9
Amortization of transition obligation...............................................        2.0        2.0        2.0
Net amortization and deferral.......................................................         --        (.2)
                                                                                      ---------  ---------  ---------
Net health care and life insurance costs............................................  $     5.9  $     5.3  $     5.5
                                                                                      ---------  ---------  ---------
                                                                                      ---------  ---------  ---------
</TABLE>
 
    The following actuarial assumptions were used in calculating the plan's
year-end funded status:
 
<TABLE>
<CAPTION>
                                                                             1996          1995          1994
                                                                         ------------  ------------  ------------
<S>                                                                      <C>           <C>           <C>
Discount rate..........................................................           7.5%          7.0%         7.75%
Assumed rate of return on future compensation levels...................      5.0--5.4%     5.0--5.5%     5.0--5.5%
Health care cost trend rate............................................       8.25--6%        10--6%      12.5--6%
                                                                         ----------------------------------------
</TABLE>
 
                                       59
<PAGE>
    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 $2.8 million
and the aggregate of the service and interest cost components by $.4 million in
1996.
 
    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
 
                     NOTE 14: COMMITMENTS AND CONTINGENCIES
 
COMMITMENTS
 
    The company has various commitments for the years 1997 through 2001 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>
                                                                  1997       1998       1999       2000       2001
                                                                ---------  ---------  ---------  ---------  ---------
                                                                         DOLLARS IN MILLIONS EXCEPT PER UNIT
<S>                                                             <C>        <C>        <C>        <C>        <C>
Capital expenditures..........................................  $   249.9  $   227.1  $   236.4  $   230.1  $   236.4
Future minimum lease payments.................................       21.5       22.3       20.9       19.3       17.6
Purchased power obligations...................................       65.3       69.4       71.8       67.8       60.5
                                                                -----------------------------------------------------
Coal contracts................................................       37.3       39.9       41.5       41.7       28.8
  Price ranges................................................
                                                                      ------  $21.61 to $27.74 per ton  ------
                                                                -----------------------------------------------------
Fixed price sales obligations (trillion BTUs).................      192.8       61.0       22.8       13.9       13.9
  Price ranges................................................
                                                                      ------   $1.75 to $3.20 per MCF   ------
                                                                -----------------------------------------------------
Fixed price purchase obligations (trillion BTUs)..............      199.0       39.2       12.0       11.2        2.2
  Price ranges................................................
                                                                      ------   $1.75 to $4.30 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 1996, 1995 and
1994 was (in millions) $29.4, $25.9 and $26.4, respectively.
 
    Purchased power obligations for 1997 through 2001 are estimated to provide
1,026; 1,064; 1,108; 937; and 960 MW, respectively.
 
LONG-TERM GAS SUPPLY CONTRACT
 
    In 1996, the company realigned certain of its business relationships in the
United Kingdom (U.K.). Its equity relationships in the Caledonian Gas Limited,
Midlands Gas Limited (Midlands), and Egas Limited joint ventures were
terminated. As part of the termination of the equity relationship in Midlands,
the company assumed an interest in two long-term gas supply contracts (for
deliveries through 2005) that it assimilated into its existing portfolios of
sales and supply contracts.
 
    At December 31, 1996, the portfolio of U.K. contracts was in a net long
position. It has 72 BCF of supply commitments through 2005, and 62 BCF of sales
commitments through 1999. Pretax losses on the above portfolio range from $14
million to $23 million depending on the estimated future spot price of natural
gas. Since the U.K. natural gas market does not have liquid long-term pricing,
it is difficult to calculate future profitability of the portfolio. Based on
management's estimates and available market data at December 31, 1996, the
company is carrying a $14 million pretax reserve relating to future losses that
may exist within the portfolio of contracts. Management believes that this
reserve is adequate and that any additional increases in the reserve would not
be material.
 
                                       60
<PAGE>
BUYOUT PROVISION
 
    Upon the occurrence of certain events, the company may be required to buy
out its minority partner in UNZ. The buyout price would be based on the fair
market value of UNZ as agreed to by both parties.
 
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. 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, 1996, the company estimates that it will spend a minimum
of approximately $5.6 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 $5.6
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.
 
    In December 1996, the EPA promulgated its final rule for nitrous oxide (NOx)
emissions pursuant to the requirements of the Clean Air Act Amendments of 1990.
The new NOx regulations could impact one of the company's power plants by
necessitating the installation of additional emissions control equipment by
January 1, 2000. The company is currently evaluating the requirements of the
rule. Using EPA's default numbers contained in the cost-benefit analysis in its
final rule-making to estimate the cost of the additional equipment, the company
may be required to spend approximately $3.1 million to comply with these rules.
These estimates could be affected by the rule's applicability as determined by
the D.C. Court of Appeals in a lawsuit now pending, or by the engineering design
developed by the company for implementation of the new standards.
 
    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.
 
                                       61
<PAGE>
                          NOTE 15: SEGMENT INFORMATION
 
A. BUSINESS LINES
 
<TABLE>
<CAPTION>
                                                                              YEAR ENDED DECEMBER 31,
                                                                   ---------------------------------------------
                                                                      1996                   1995        1994
                                                                   ----------             ----------  ----------
                                                                                DOLLARS IN MILLIONS
<S>                                                                <C>         <C>        <C>         <C>
SALES:
Energy Delivery--
  Electric:
    Unaffiliated.................................................  $    519.3             $    490.1  $    476.1
    Affiliated...................................................      (285.2)                (262.9)     (258.7)
                                                                   ----------             ----------  ----------
  Total electric.................................................       234.1        5.4%      227.2       217.4
                                                                   ----------             ----------  ----------
  Gas............................................................       727.9       16.8       616.8       618.6
  Other..........................................................        51.9        1.2        45.9        41.0
                                                                   ----------             ----------  ----------
Total Energy Delivery............................................     1,013.9                  889.9       877.0
                                                                   ----------             ----------  ----------
Generation--Affiliated...........................................       285.2        6.6       262.9       258.7
Aquila Energy....................................................     2,427.1       56.0     1,171.0       935.8
Energy Solutions.................................................       313.9        7.2       178.5        77.6
International and other..........................................       292.2        6.8       296.2       249.0
                                                                   ----------  ---------  ----------  ----------
Total............................................................  $  4,332.3      100.0% $  2,798.5  $  2,398.1
                                                                   ----------  ---------  ----------  ----------
                                                                   ----------  ---------  ----------  ----------
</TABLE>
 
<TABLE>
<S>                                                     <C>        <C>        <C>        <C>
INCOME (LOSS) FROM OPERATIONS:
Energy Delivery--
  Electric............................................  $    78.1       35.0% $    71.9  $    70.2
  Gas.................................................       81.0       36.3       65.2       59.7
  Other...............................................       (2.1)      (.9)        3.7        1.2
                                                        ---------             ---------  ---------
      Total Energy Delivery...........................      157.0                 140.8      131.1
                                                        ---------             ---------  ---------
Generation (a)........................................       28.6       12.8       15.0       32.4
Aquila Energy.........................................       70.2       31.4       68.4       43.4
Energy Solutions......................................      (20.1)     (9.0)        (.2)       7.3
International (b).....................................       14.6        6.5       18.5       22.7
Corporate and other...................................      (26.9)     (12.1)     (17.4)      (8.9)
                                                        ---------  ---------  ---------  ---------
Total.................................................  $   223.4      100.0% $   225.1  $   228.0
                                                        ---------  ---------  ---------  ---------
                                                        ---------  ---------  ---------  ---------
</TABLE>
 
------------------------
 
(a) The Generation segment includes the UtilCo Group partnership equity
    investments that had equity earnings of $50.9 million, $21.9 million and
    $19.2 million not included in operating income.
 
(b) The International segment includes operating activities in Australia, New
    Zealand and the United Kingdom which had equity earnings of $60.1 million,
    $9.9 million and $(.9) million.
 
                                       62
<PAGE>
 
<TABLE>
<CAPTION>
                                                                                 YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1996                   1995        1994
                                                                      ----------             ----------  ----------
                                                                                   DOLLARS IN MILLIONS
<S>                                                                   <C>         <C>        <C>         <C>
DEPRECIATION, DEPLETION AND AMORTIZATION:
Energy Delivery--
  Electric..........................................................  $     30.8       23.9% $     34.7  $     27.6
  Gas...............................................................        35.8       28.0        34.3        30.1
  Other.............................................................         (.5)      (.4)        (1.1)        2.7
                                                                      ----------             ----------  ----------
Total Energy Delivery...............................................        66.1                   67.9        60.4
                                                                      ----------             ----------  ----------
Generation..........................................................        18.8       14.7        19.4        17.8
Aquila Energy.......................................................        25.7       20.1        49.6        59.6
Energy Solutions....................................................         4.2        3.4          --          .3
International.......................................................        12.5        9.9         7.1         6.4
Corporate and other.................................................          .5         .4         4.8         1.0
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $    127.8      100.0% $    148.8  $    145.5
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
</TABLE>
 
<TABLE>
<CAPTION>
                                                                                      DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1996                   1995        1994
                                                                      ----------             ----------  ----------
                                                                                   DOLLARS IN MILLIONS
<S>                                                                   <C>         <C>        <C>         <C>
IDENTIFIABLE ASSETS:
Energy Delivery--
  Electric..........................................................  $    718.7       15.3% $    695.9  $    690.6
  Gas...............................................................       958.9       20.4       900.0       819.9
  Other.............................................................        84.8        1.8        50.5        45.5
                                                                      ----------             ----------  ----------
Total Energy Delivery...............................................     1,762.4                1,646.4     1,556.0
                                                                      ----------             ----------  ----------
Generation--
  Electric generation...............................................       281.0        6.0       279.0       259.7
  Independent power projects........................................       201.1        4.3       181.8       137.5
                                                                      ----------             ----------  ----------
Total Generation....................................................       482.1                  460.8       397.2
                                                                      ----------             ----------  ----------
Aquila Energy.......................................................     1,416.9       30.1       873.1       717.1
Energy Solutions....................................................       112.6        2.4       118.6        66.1
International.......................................................       860.5       18.3       712.1       295.4
Corporate and other.................................................        70.4        1.4        74.9        79.3
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $  4,704.9      100.0% $  3,885.9  $  3,111.1
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
</TABLE>
 
<TABLE>
<CAPTION>
                                                                                 YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1996                   1995        1994
                                                                      ----------             ----------  ----------
                                                                                   DOLLARS IN MILLIONS
<S>                                                                   <C>         <C>        <C>         <C>
CAPITAL EXPENDITURES:
Energy Delivery--
  Electric..........................................................  $     47.7       29.7% $     39.1  $     43.6
  Gas...............................................................        48.5       30.2        39.9        50.7
                                                                      ----------             ----------  ----------
Total Energy Delivery...............................................        96.2                   79.0        94.3
                                                                      ----------             ----------  ----------
Generation..........................................................        16.6       10.3        11.2        17.9
Aquila Energy.......................................................        26.4       16.4       144.0       113.6
International.......................................................        21.5       13.4        19.2        19.8
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $    160.7      100.0% $    253.4  $    245.6
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
</TABLE>
 
                                       63
<PAGE>
B.  GEOGRAPHICAL INFORMATION
 
<TABLE>
<CAPTION>
                                                                                 YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1996                   1995        1994
                                                                      ----------             ----------  ----------
                                                                                   DOLLARS IN MILLIONS
<S>                                                                   <C>         <C>        <C>         <C>
SALES:
United States.......................................................  $  3,962.5       91.5% $  2,510.9  $  2,153.4
Canada (a)..........................................................       180.9        4.2        89.2        80.9
United Kingdom......................................................       188.9        4.3       198.4       163.8
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $  4,332.3      100.0% $  2,798.5  $  2,398.1
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
EARNINGS AVAILABLE FOR COMMON SHARES:
United States.......................................................  $     77.0       74.3% $     68.4  $     82.9
Canada (a)..........................................................         9.5        9.2         8.2         6.2
Australia (b).......................................................        14.1       13.6         2.9      --
New Zealand (b).....................................................         2.4        2.3          .7         (.1)
United Kingdom......................................................          .7         .6        (2.5)        2.4
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $    103.7      100.0% $     77.7  $     91.4
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
</TABLE>
 
<TABLE>
<CAPTION>
                                                                                      DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1996                   1995        1994
                                                                      ----------             ----------  ----------
                                                                                   DOLLARS IN MILLIONS
<S>                                                                   <C>         <C>        <C>         <C>
IDENTIFIABLE ASSETS:
United States.......................................................  $  3,764.0       80.0% $  3,173.8  $  2,815.7
Canada (a)..........................................................       351.5        7.5       225.3       214.3
Australia (b).......................................................       306.3        6.5       252.5      --
New Zealand (b).....................................................       185.1        3.9       150.6        26.1
United Kingdom......................................................        98.0        2.1        83.7        55.0
                                                                      ----------  ---------  ----------  ----------
Total...............................................................  $  4,704.9      100.0% $  3,885.9  $  3,111.1
                                                                      ----------  ---------  ----------  ----------
                                                                      ----------  ---------  ----------  ----------
</TABLE>
 
------------------------
 
(a) Canadian sales, earnings available for common shares and identifiable assets
    include Aquila Energy's Canadian operations and various small Canadian gas
    marketing companies.
 
(b) Earnings available and a majority of the identifiable assets relate to
    equity investments.
 
                                       64
<PAGE>
      NOTE 16: TERMINATED MERGER--KANSAS CITY POWER & LIGHT COMPANY (KCPL)
 
    On September 17, 1996, KCPL terminated the Amended and Restated Agreement
and Plan of Merger (the Agreement) among KCPL, KC Merger Sub, Inc., the company,
and KC United Corp., which would have provided for the merger of the company and
KCPL.
 
    Since KCPL's shareholders did not approve the merger under the terms of the
Agreement, KCPL was required to pay the company $5 million. The company received
this termination payment on September 19, 1996. In connection with the Agreement
termination, the company expensed deferred merger costs of approximately $11.0
million (pretax), net of the termination fee payment.
 
    In February 1997, Western Resources Inc. and KCPL signed a definitive
agreement to merge. As a result, KCPL paid the company a $53 million breakup fee
which was recorded in the first quarter of 1997.
 
                 NOTE 17: 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>
                                                   1996 QUARTERS                               1995 QUARTERS (A)
                                    --------------------------------------------  --------------------------------------------
                                      FIRST      SECOND       THIRD     FOURTH      FIRST      SECOND       THIRD     FOURTH
                                    ---------  -----------  ---------  ---------  ---------  -----------  ---------  ---------
                                                                   IN MILLIONS EXCEPT PER SHARE
<S>                                 <C>        <C>          <C>        <C>        <C>        <C>          <C>        <C>
Sales.............................  $ 1,084.4   $   765.0   $   892.6  $ 1,590.3  $   726.3   $   600.8   $   607.5  $   863.9
Gross profit......................      249.7       202.4       204.4      253.3      236.2       196.6       250.0      233.9
Income from operations............       88.0        35.1        32.7       67.6       81.5        34.9        81.8       26.9
Net income........................       37.3        26.3        14.1       28.1       32.2         7.2        32.9        7.5
                                    ------------------------------------------------------------------------------------------
Earnings per common share:
  Primary (b).....................  $     .80   $     .55   $     .29  $     .56  $     .71   $     .15   $     .72  $     .15
  Fully diluted (c)...............        .79         .55         .29        .56        .70         .15         .71        .15
                                    ------------------------------------------------------------------------------------------
Cash dividend per common share....  $     .44   $     .44   $     .44  $     .44  $     .43   $     .43   $     .43  $     .43
Market price per common share:
  High............................  $   30.25   $   29.13   $   29.13  $   27.25  $   29.50   $   29.00   $   28.50  $   29.63
  Low.............................      28.25       25.75       26.50      26.38      26.25       27.25       26.63      27.50
                                    ------------------------------------------------------------------------------------------
</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.
 
                                       65
<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.
 
<TABLE>
<S>                        <C>
                           Terry G. Westbrook
Richard C. Green, Jr.      Senior Vice President
Chairman of the Board and  and
Chief Executive Officer    Chief Financial Officer
</TABLE>
 
                                       66
<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, 1996, 1995 and 1994 and the related consolidated statements of
income, common shareowners' equity, and cash flows for the years then ended.
These financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
 
    We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits 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, 1996, 1995 and 1994, 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 1 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 5 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 11, 1997
 
                                       67
<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 proxy statement
and prospectus for its annual meeting of shareholders to be held May 7, 1997 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 of this Form 10-K.
 
                                     PART 4
 
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, 1996......      36
Consolidated Balance Sheets at December 31, 1996, 1995, and 1994...................      37
Consolidated Statements of Preferred and Preference Stock at December 31, 1996,
  1995 and 1994....................................................................      38
Consolidated Statements of Common Shareowners' Equity for the three years ended
  December 31, 1996................................................................      38
Consolidated Statements of Cash Flows for the three years ended December 31,
  1996.............................................................................      39
Notes to Consolidated Financial Statements.........................................     40-65
Report of Independent Public Accountants...........................................      67
</TABLE>
 
(2) FINANCIAL STATEMENT SCHEDULE
 
<TABLE>
<S>                                                                 <C>
Report of Independent Accountants on Financial Statement Schedule
II................................................................      69
Valuation and Qualifying Accounts for the years 1996, 1995 and
  1994............................................................      70
</TABLE>
 
    All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
 
                                       68
<PAGE>
(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)   Severance Compensation Agreement.
10(a)(7)   Executive Severance Payment Agreement.
10(a)(8)   Split Dollar Agreement.
10(a)(9)   Supplemental Retirement Agreement.
10(a)(11)  UtiliCorp United Inc. Life Insurance Program for Officers.
10(a)(12)  Summary of Terms and Conditions of Employment of Charles K.
             Dempster.
10(a)(13)  Summary of Terms and Conditions of Employment of Terry G.
             Westbrook.
10(a)(14)  Employment Agreement for Richard C. Green, Jr.
10(a)(15)  Employment Agreement for Robert K. Green.
</TABLE>
 
------------------------
 
* Incorporated by reference to the Index to Exhibits.
 
(b) Reports on Form 8-K
 
    A current report on Form 8-K dated September 30, 1996, filed on October 1,
1996, with respect to Item 5 was filed with the Securities and Exchange
Commission by the Registrant.
 
                      REPORT OF INDEPENDENT ACCOUNTANTS ON
                          FINANCIAL STATEMENT SCHEDULE
 
To the Board of Directors and Shareholders of UtiliCorp United Inc.:
 
    We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements for 1996, 1995 and 1994 described on page
67 of UtiliCorp United Inc.'s Annual Report on Form 10-K, and have issued our
report thereon dated February 11, 1997. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The Financial Statement
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
consolidated financial statements taken as a whole.
 
ARTHUR ANDERSEN LLP
 
Kansas City, Missouri
February 11, 1997
 
                                       69
<PAGE>
                             UTILICORP UNITED INC.
                 SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1996
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                                                                            COLUMN E
                                    COLUMN B                              COLUMN D     -------------------
                                 ---------------       COLUMN C        --------------    DEDUCTIONS FROM        COLUMN F
           COLUMN A                 BEGINNING     -------------------    ADDITIONS        RESERVES FOR      -----------------
-------------------------------    BALANCE AT        PURCHASE OF A       CHARGED TO       PURPOSES FOR       ENDING BALANCE
          DESCRIPTION              DECEMBER 31         BUSINESS           EXPENSE         WHICH CREATED      AT DECEMBER 31
-------------------------------  ---------------  -------------------  --------------  -------------------  -----------------
<S>                              <C>              <C>                  <C>             <C>                  <C>
Price Risk Management-- credit
  and service reserves:
  1996.........................     $    70.6             --                 --                  13.4           $    57.2
  1995.........................     $  --                 --                 70.6(1)           --               $    70.6
  1994.........................     $  --                 --                 --                --               $  --
Reserve for United Kingdom gas
  contracts
  1996.........................     $    11.0             --                  3.0              --               $    14.0
  1995.........................     $  --                 --                 11.0              --               $    11.0
  1994.........................     $  --                 --                 --                --               $  --
</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.
 
                                       70
<PAGE>
                             UTILICORP UNITED INC.
                               INDEX TO EXHIBITS
 
<TABLE>
<CAPTION>
  EXHIBIT
   NUMBER                                                 DESCRIPTION
------------  ----------------------------------------------------------------------------------------------------
<C>           <S>
    *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) and  By-laws of the Company as amended.
     4(a)(1)
 
    *4(a)(2)  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)(3)  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)(4)  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(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.
 
    *4(b)(8)  Seventh Supplemental Indenture, dated as of June 1, 1995. (Exhibit 4 to the Company's Form 10-Q for
                the period ended June 30, 1995.)
 
     4(b)(9)  Eighth Supplemental Indenture, dated as of October 1, 1996.
</TABLE>
 
                                       71
<PAGE>
<TABLE>
<CAPTION>
  EXHIBIT
   NUMBER                                                 DESCRIPTION
------------  ----------------------------------------------------------------------------------------------------
<C>           <S>
 
       *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.)
                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. (Exhibit 4(d)(1) to the
                company's Annual Report on Form 10-K for the year ended December 31, 1995.)
 
    *4(d)(2)  First Supplemental Indenture, dated as of June 1, 1995, Supplement to Indenture dated June 1, 1995.
                (Exhibit 4(d)(2) to the company's Annual Report on Form 10-K for the year ended December 31,
                1995.)
 
       *4(e)  Form of Rights Agreement between UtiliCorp United Inc. and First Chicago Trust Company of New York,
                as Rights Agent. (Exhibit 4 to the company's Form 10-Q for the period ended September 30, 1996.)
 
   *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. (Exhibit 10 (a)(3) to the
                company's Annual Report on Form 10-K for the year ended December 31, 1995.)
 
   *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)  Form of Severance Compensation Agreement between UtiliCorp United Inc., and certain Executives of
                the Company. (Exhibit 10 (a)(7) to the company's Annual Report on Form 10-K for the year ended
                December 31, 1995.)
 
   *10(a)(7)  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)(8)  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)(9)  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)(10)  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.)
</TABLE>
 
                                       72
<PAGE>
<TABLE>
<CAPTION>
  EXHIBIT
   NUMBER                                                 DESCRIPTION
------------  ----------------------------------------------------------------------------------------------------
<C>           <S>
  *10(a)(11)  UtiliCorp United Inc. Life Insurance Program for Officers. (Exhibit 10 (a)(13) to the company's
                Annual Report on Form 10-K for the year ended December 31, 1995.)
 
  *10(a)(12)  Summary of Terms and Conditions of Employment of Charles K. Dempster. (Exhibit 10 to the company's
                quarterly report on Form 10-Q for the period ended March 31, 1996.)
 
   10(a)(13)  Summary of Terms and Conditions of Employment of Terry G. Westbrook.
 
   10(a)(14)  Employment Agreement for Richard C. Green, Jr.
 
   10(a)(15)  Employment Agreement for Robert K. Green.
 
          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.
 
                                       73
<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.
 
<TABLE>
<S>   <C>                           <C>
By:    /s/ RICHARD C. GREEN, JR.
      ----------------------------
         Richard C. Green, Jr.      Chairman of the Board of
                                      Directors, Chief Executive
                                      Officer (Principal Executive
                                      Officer)
 
Date: March 14, 1997
</TABLE>
 
    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>
<S>   <C>                           <C>
By:    /s/ RICHARD C. GREEN, JR.
      ----------------------------
         Richard C. Green, Jr.      Chairman of the Board of
                                      Directors, Chief Executive
                                      Officer (Principal Executive
                                      Officer)
 
Date: March 14, 1997
 
By:       /s/ ROBERT K. GREEN
      ----------------------------
            Robert K. Green
                                    President and Director
 
Date: March 14, 1997
 
By:      /s/ TERRY G. WESTBROOK
      ----------------------------
           Terry G. Westbrook
                                    Senior Vice President and Chief
                                      Financial Officer
 
Date: March 14, 1997
 
By:        /s/ JOHN R. BAKER
      ----------------------------
             John R. Baker
                                    Director
 
Date: March 14, 1997
 
By:        /s/ AVIS G. TUCKER
      ----------------------------
             Avis G. Tucker
                                    Director
 
Date: March 14, 1997
</TABLE>
 
                                       74
<PAGE>
<TABLE>
<S>   <C>                           <C>
By:      /s/ ROBERT F. JACKSON
      ----------------------------
           Robert F. Jackson
                                    Director
 
Date: March 14, 1997
 
By:       /s/ L. PATTON KLINE
      ----------------------------
            L. Patton Kline
                                    Director
 
Date: March 14, 1997
 
By:         /s/ HERMAN CAIN
      ----------------------------
              Herman Cain
                                    Director
 
Date: March 14, 1997
 
By:     /s/ IRVINE O. HOCKADAY,
                  JR.
      ----------------------------
        Irvine O. Hockaday, Jr.
                                    Director
 
Date: March 14, 1997
 
By:        /s/ DR. STANLEY O.
               IKENBERRY
      ----------------------------
        Dr. Stanley O. Ikenberry
                                    Director
 
Date: March 14, 1997
</TABLE>
 
                                       75