<PAGE>


                                   ST. JOSEPH

                                 LIGHT & POWER

                                    COMPANY


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As an investor-owned utility, St. Joseph Light & Power Company serves more than
3,300 square miles in all or part of 10 northwest Missouri counties.

Light & Power provides electric energy to nearly 63,000 customers in 74 cities,
towns and villages, and in a large rural area. The home office is in St. Joseph,
a city of about 73,000, which represents about one-half the population of the
service territory. Electric retail revenues represented about 72 percent of the
company's 1999 revenues.

The company supplies natural gas to almost 6,400 natural gas customers in
Maryville, a state university town of about 10,000 and 14 other communities.
Light & Power does not provide natural gas to St. Joseph. The company also
supplies industrial steam to six customers in St. Joseph.

Light & Power also owns SJLP Inc., a non-regulated investment subsidiary.

St. Joseph Light & Power Company has been in the public utility business since
1883. It became an independent, investor-owned business in 1950. St. Joseph
Light & Power has more than 4,700 shareholders, representing all 50 states. The
company's stock is traded on the New York Stock Exchange under the symbol SAJ.

                                          PROCEDURE FOR EXCHANGE OF COMMON STOCK

--------------------------------------------------------------------------------
   As soon as practicable after the closing of the merger, an Exchange Agent
   will mail a letter of transmittal to each holder of record of shares of Light
   & Power common stock. That letter will contain instructions to be followed by
   the shareowner in surrendering his/her Light & Power certificates in exchange
   for certificates of UtiliCorp common stock.

   Once the Exchange Agent has received the Light & Power certificates and the
   transmittal letter, signed by the shareowner, the Exchange Agent will forward
   the certificates representing the whole number of shares of UtiliCorp stock
   to which the former Light & Power shareowner is entitled. The certificates
   will be registered in such names as the owner may request. The Light & Power
   shareowner will also receive a check representing the cash value of
   fractional shares of UtiliCorp stock. That cash payment will be subject to
   income tax withholding, as appropriate.
--------------------------------------------------------------------------------

                                                                               1


<PAGE>


PRESIDENT'S MESSAGE


FELLOW SHAREOWNER:

1999 was a significant year in the long and successful history of St. Joseph
Light & Power Company. On March 5, the company announced the signing of a
definitive agreement to merge our company with UtiliCorp United Inc., of Kansas
City, Missouri.

Upon completion of the merger, you will receive $23 worth of UtiliCorp common
stock for each share of Light & Power Company stock, on a tax-free basis. In
addition, you will benefit from increased liquidity, enhanced opportunities for
long-term growth and, we expect, improvement in the dividend.

During this past year, your management team has focused on working to complete
the merger on a timely basis, as well as maintaining the record of excellent
service provided our customers and sustaining a competitive return to our
shareowners.

1999 Operating Results

A combination of factors adversely impacted the financial results of the company
during 1999. As a result, diluted earnings per share for the year were $.74,
compared with $1.31 per share reported in 1998. Net income in 1999 totaled $6.1
million, down from the $10.7 million reported in 1998.

The primary factors impacting the company's financial results were flat electric
retail revenues, increased per-unit costs for purchased power and merger-related
expenses. Excluding the merger-related expenses, 1999 earnings would have
totaled $1.07 per common share.

Please refer to Management's Discussion and Analysis, beginning on Page 5, for a
discussion of 1999 operating results.

RETURN TO SHAREOWNERS

Total return to shareowners (dividends plus stock price appreciation) in 1999
was 19.96 percent, placing the company eighth in the Edison Electric Institute
100 Index of Investor-Owned Electrics.

In January 2000, the board of directors approved a regular quarterly dividend of
25 cents per common share. This dividend continues Light & Power's record of
paying a dividend each quarter since the company became independent in 1950. The
effective annual rate is $1.00 per share.

RATE PROCEEDINGS

In July, the Missouri PSC concluded the rate proceedings begun in 1998. The
proceedings involved requests by Light & Power for increases in electric,
natural gas and industrial steam revenues and a commission staff complaint
alleging that electric revenues should be reduced. The electric filings by the
company and the PSC staff were consolidated.

The parties to the cases reached stipulated agreements, which the PSC approved,
that called for the company to implement certain accounting changes and to
reduce annual electric and industrial steam revenues by $2.5 million and
$25,000, respectively, for service provided after October 30, 1999. There were
no changes in natural gas prices. The accounting changes and revenue reductions
required by the agreements had a negligible effect on 1999 and are expected to
reduce net income about $300,000 annually.

RESTRUCTURING IN MISSOURI

While Missouri has yet to take any action on deregulating the electric industry,
activity has increased in the current session of the General Assembly. Industry
representatives have been meeting with various stakeholders since late summer
1999 on the issue. Consensus seems to be coalescing around a strategy that would
have the legislature first deal with the tax issues associated with
restructuring the industry and then pass a deregulation bill.

Failure to make changes in the way utilities are taxed could result in lower
taxes for competitors not currently regulated by the PSC. Both the tax bills and
some of the discussion

                                                                               2


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PRESIDENT'S MESSAGE

drafts of deregulation legislation currently being considered contain a
provision that deregulation cannot become effective until tax reforms have been
approved.

ENVIRONMENT

The quality of life in northwest Missouri is a special concern and the company
endeavors to serve as an example of environmental responsibility.

Our efforts to protect that quality of life were again recognized by the
National Arbor Day Foundation. For the third consecutive year, Light & Power was
named a Tree Line USA utility. The award acknowledges Light & Power's efforts to
promote and protect healthy trees while ensuring reliable service for customers.

In 1999, the company invested about $1.2 million for projects at the Lake Road
plant necessary to comply with the requirements of the Clean Air Act. Most of
those projects related to modifications to the plant's coal-handling facilities.
In total, about $18 million will be invested to achieve compliance.

YEAR 2000 ACTIVITIES

As expected, the midnight arrival of the Year 2000 was a non-event for our
customers from a service standpoint. While we were confident of the outcome,
many employees were on duty to handle any unforeseen emergency. When the hour
arrived, every system functioned as expected and no service interruptions or
other system failures occurred.

I am extremely proud of the employees in the Information Systems Department and
all the other employees involved in this complex endeavor. The years of
planning, implementing and testing paid off.

MERGER UPDATE

As you know, the merger was approved at the special shareowners' meeting in
June. Management and the Board of Directors are committed to securing regulatory
approval of the merger and implementing a smooth transition of Light & Power's
operations into UtiliCorp.

In October 1999, Light & Power and UtiliCorp filed a joint application with the
PSC for approval of the merger. As part of the application, the companies filed
a proposed procedural schedule outlining dates for significant events in the
approval process.

In late December, the PSC issued an order that essentially accepted the schedule
proposed by the companies, which calls for the hearing in mid-July. In addition,
in an order issued in January 2000, the PSC denied a motion by the PSC staff,
the Office of Public Counsel and intervenors to consolidate our merger
proceeding with that of UtiliCorp and The Empire District Electric Company of
Joplin, Missouri. Approval of that motion could have delayed the completion of
our merger.

All other required state regulatory commission approvals have been received.

In late November, an application was filed requesting the Federal Energy
Regulatory Commission's approval of UtiliCorp's mergers with Light & Power and
Empire District. The filing requested an expedited review of the application and
a decision is expected by mid-2000.

Although there are no statutory time limits for regulatory actions, we expect
the timing of the various regulatory decisions to allow for the closing of the
merger in the fall of 2000.

RECOGNITION OF EMPLOYEES

I want to conclude by recognizing the dedication of our employees, past and
present. It has been their hard work and commitment to customer service that has
made St. Joseph Light & Power Company a successful company.


/s/Terry F. Steinbecker
Terry F. Steinbecker
President and Chief Executive Officer
March 13, 2000

                                                                              3





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SELECTED FINANCIAL INFORMATION

The following table sets forth financial data regarding St. Joseph Light &Power
Company's financial position and operating results. This information should be
read in conjunction with Management's Discussion and Analysis and the
Consolidated Financial Statements and Notes thereto, appearing elsewhere in this
Annual Report.

<TABLE>
<CAPTION>

                                                              (In Thousands Except Per Share Data and Percentages)
                                              1999          1998           1997          1996          1995          1994
---------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>           <C>           <C>           <C>           <C>           <C>
STATEMENTS OF INCOME:
   Operating revenues                       $ 120,949     $ 124,374     $ 116,165     $  95,869     $  93,521     $  90,782
   Operating expenses                         104,391       102,187        93,177        74,941        73,249        70,033
                                            ---------     ---------     ---------     ---------     ---------     ---------
      Operating income                         16,558        22,187        22,988        20,928        20,272        20,749
   Interest charges, net                        7,312         6,787         6,480         5,807         5,555         4,460
   Other income                                  (507)         (847)         (440)         (504)       (1,470)          (32)
   Income taxes                                 3,705         5,512         6,214         5,268         5,147         5,255
   Minority interest                              (79)           71          (106)           --            --            --
                                            ---------     ---------     ---------     ---------     ---------     ---------
   Net income                               $   6,127     $  10,664     $  10,840     $  10,357     $  11,040     $  11,066
                                            ---------     ---------     ---------     ---------     ---------     ---------
                                            ---------     ---------     ---------     ---------     ---------     ---------

COMMON STOCK DATA:
(adjusted to reflect two-for-one stock split in July 1996)

   For the year ended December 31--
      Weighted average shares outstanding       8,212         8,100         7,989         7,868         7,813         7,884
      Basic earnings per share              $     .75     $    1.32     $    1.36     $    1.32     $    1.41     $    1.40
      Diluted earnings per share            $     .74     $    1.31     $    1.36     $    1.32     $    1.41     $    1.40
      Dividends per common share            $    1.00     $     .98     $     .96     $     .94     $     .92     $     .90
      Return on average common equity             6.4%         11.4%         12.2%         12.4%         13.9%         14.4%

   As of December 31--
      Market price per common share         $   20.50     $   17.94     $   17.75     $   15.38     $   17.75     $   14.25
      Book value per common share           $   11.63     $   11.76     $   11.34     $   10.87     $   10.42     $    9.93

Liquidity and capital resources data:
   Capital --
      Expenditures, excluding AFUDC         $  12,953     $  16,442     $  14,346     $  14,318     $  21,781     $  12,224
      Percent of expenditures financed
         internally from operations                22%           79%           79%           92%           58%           77%
      AFUDC as a percent of net income              3%            4%            2%            5%            4%            2%
   Capitalization ratios
      Common equity                                58%           57%           57%           54%           53%           59%
      Long-term debt (excluding                    42%           43%           43%           46%           47%           41%
         current maturities)
   Ratio of earnings to fixed charges            2.27          3.23          3.47          3.44          3.63          4.39

   Total assets                             $ 261,326     $ 251,255     $ 243,769     $ 227,250     $ 219,330     $ 199,699

   Long-term obligations                    $  71,294     $  76,417     $  71,837     $  76,371     $  75,612     $  55,627

</TABLE>


                                                                               4

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                                            MANAGEMENT'S DISCUSSION AND ANALYSIS

GENERAL

In Management's Discussion and Analysis, we explain the general financial
condition and operating results of St. Joseph Light & Power Company, a public
utility, its wholly owned subsidiary, SJLP Inc. and its subsidiary, Percy Kent
Bag Co., Inc. (Percy Kent). As you read Management's Discussion and Analysis, it
may be helpful to refer to our Consolidated Statements of Income, which present
the results of operations for 1999, 1998 and 1997.

We are engaged primarily in the generation and distribution of electric energy,
serving approximately 63,000 customers in northwest Missouri. We also sell
natural gas in 15 communities in the northern part of our service area and
industrial steam to six customers in St. Joseph. SJLP Inc. was formed in
September 1996 to pursue investments in non-utility areas. Effective May 31,
1997, SJLP Inc. acquired a controlling interest in Percy Kent, a manufacturer of
multiwall and small paper bags, primarily for food products, agricultural
products, specialty chemicals, pet foods and other consumer packaging companies
throughout the United States. Neither SJLP Inc.'s nor Percy Kent's operations
were material to St. Joseph Light & Power Company's consolidated financial
position or results of operations in any of the periods presented.

PROPOSED MERGER -- On March 4, 1999, we entered into an Agreement and Plan of
Merger to form a strategic business combination with UtiliCorp United Inc. Under
terms of the Agreement, each share of our common stock, valued at $23.00 per
share, will be exchanged for UtiliCorp United Inc. common stock. The Agreement
was approved by a vote of our shareholders at a special meeting in 1999, and by
the Public Utility Commissions of Colorado, West Virginia, Iowa, and Minnesota.
The transaction is subject to several additional closing conditions, including
approval by the Federal Energy Regulatory Commission (FERC), the Department of
Justice, the Federal Communications Commission, and the Missouri Public Service
Commission (PSC). The PSC has scheduled hearings for mid-July 2000. We expect
the merger to be completed in the fall of 2000.

After tax merger expenses of $2.7 million were incurred during 1999. Additional
merger-related expenses are expected to be incurred in 2000, resulting in an
after tax impact to earnings of approximately $4.5 million.




RESULTS OF OPERATIONS

1999 VS. 1998

EARNINGS -- Diluted earnings per share totaled $.74 in 1999, compared with 1998
earnings of $1.31 per share. The earnings decrease was primarily the result of
flat electric retail revenues, increases in per unit purchased power costs, and
expenses relating to the proposed merger.

ELECTRIC REVENUES -- 1999 electric operating revenues were $90.5 million, an
increase of 1% from 1998. The slight growth in 1999 revenues was primarily due
to increased sales for resale. Participation in an exchange agreement with
another utility, which began in 1998 (see 1998 vs. 1997 "Electric Revenues"),
increased the amount of energy available for resale in 1999, resulting in a 111%
increase in sales for resale volumes.

Retail sales totaled 1.67 million megawatt hours (mwh) in 1999, a 2% increase
from the 1.64 million mwh reported in 1998. The continued strong economy boosted
retail sales to the commercial (1.4%) and industrial (6.2%) customer classes.
Milder than normal temperatures resulted in a decline of 1.7% in sales to
residential customers. Although retail sales increased, this change in sales mix
resulted in flat retail revenue.

Electric retail revenues were also reduced by approximately $350,000 due to the
rate reductions implemented October 31, 1999 (see "Effects of Regulation").


                                                                               5


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MANAGEMENT'S DISCUSSION AND ANALYSIS

OTHER UTILITY -- Industrial steam revenues increased 5% from 1998's level. Sales
in 1999 increased 7% as a result of increased sales to a major customer.

Gas revenues declined 7% from 1998 as the result of lower per unit gas prices,
which are passed on to retail customers, and changes in the mix of sales to the
various customer classes due to milder weather.

MANUFACTURING REVENUES -- The operations of Percy Kent are reflected in
manufacturing revenues and cost of goods sold, which both decreased 18%. The
decreases are primarily due to reduced demand and the loss of two major
customers.

FUEL AND PURCHASED POWER -- Total energy costs (fuel and purchased power for
system energy and resale) were $34 million for 1999, $4 million more than the
1998 expense. This increase was the result of higher per unit costs for
purchased power and increased system requirements.

Per unit fuel costs were slightly higher in 1999 at $1.114 per million British
thermal units (Btu), up from $1.099 per million Btu in 1998, due to changes in
the mix of fuels and generating units utilized. Similar to the pattern of recent
years, coal made up 90% of the total fuel burned in 1999. The cost of coal
burned decreased from $.979 per million Btu in 1998 to $.928 per million Btu in
1999.

The coal-fired Iatan plant provided approximately 48% of our overall energy
needs in 1999, a decrease from 50% in 1998, due to unscheduled outages. A
Wyoming mine supplies low-sulfur coal to the plant under a 20-year contract,
which expires in 2003. The contract was renegotiated in 1999. In return for
lower unit prices through the remaining contract term, we made a prepayment of
$3.4 million. This prepayment is being amortized over the coal deliveries under
the contract and is included in Regulatory Assets on our balance sheet. The coal
is delivered by rail under an agreement that extends through 2000.

The Lake Road units supplied 26% of our energy needs, up slightly from 25% in
1998. Per unit fuel costs at Lake Road were up 3% in 1999.

We met the remaining 26% of our energy needs in 1999 through purchased power
arrangements compared to 25% in 1998. Both years reflect the purchase of
replacement power for Iatan outages. Purchased power fixed charges for firm and
peaking capacity were $3.3 million for 1999 and $2.7 million for 1998. We expect
our use of purchased power to increase in 2000 due to a planned maintenance
outage for the Iatan plant. We have contracted to purchase 171,600 mwh of energy
during a period beginning in March and extending through May of 2000.


Per unit costs of purchased power increased almost 6% in 1999. Along with many
other utilities, we saw a significant increase in these costs during the summer
months due to high summer demands and constraints on the regional transmission
system. We expect this trend of higher prices for purchased energy to continue.

OTHER OPERATIONS -- Other operations expenses for 1999 decreased $1.6 million in
comparison to 1998. The decrease is primarily the result of decreased payroll
and benefit costs for the year in addition to lower Year 2000 expenses. The
pension credit was $3.0 million and $2.2 million in 1999 and 1998, respectively.
See Note 2, Benefit Plans, in the footnotes.

MAINTENANCE -- Consistent with prior years, maintenance expenses remained
relatively stable in 1999, decreasing by $160,000 from 1998 levels, due to lower
maintenance costs at the Lake Road facility. The balanced expenses continue to
reflect our efforts to schedule maintenance outages in a way which minimizes
both maintenance and generation replacement costs.

INTEREST CHARGES -- The increase in interest charges is primarily due to an
increase in short-term notes payable throughout the year, partially offset by
reduced interest charges related to long-term debt. The increase in short-


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MANAGEMENT'S DISCUSSION AND ANALYSIS


term debt is a result of lower cash flows from operating activities, caused
primarily by merger-related expenses, and investments in our non-utility
businesses.

1998 VS. 1997

EARNINGS -- Diluted earnings per share totaled $1.31 in 1998, compared with 1997
earnings of $1.36 per share. The earnings decrease was primarily the result of
increases in per unit purchased power costs.

ELECTRIC REVENUES -- 1998 electric operating revenues were $89.7 million, an
increase of 3% from 1997. The growth in 1998 revenues was primarily due to
increased retail sales.

Retail sales totaled 1.64 million mwh in 1998, a 4% increase from the 1.58
million mwh reported in 1997. Warmer summer weather and the continued strong
economy boosted retail sales to all three customer classes -- residential, 2.1%;
commercial, 4.7%; and industrial, 5.8%.

We entered into an agreement with another utility in which we agreed to transfer
energy to them in 1998 in exchange for receiving approximately the same amount
of energy from them in 1999. Participation in this agreement reduced the amount
of energy available for resale in 1998, resulting in a 42% decrease in sales for
resale volumes.

OTHER UTILITY -- Industrial steam revenues increased 1.5% from 1997's level.
Sales in 1998 increased 3% as a result of increased sales to a major customer.

Gas revenues declined 20% from 1997, as the result of a 14% decrease in retail
sales and transportation services due to reduced heating requirements and lower
per unit gas prices which are passed on to customers.

MANUFACTURING REVENUES -- Manufacturing revenues and cost of goods sold
increased 38% and 34%, respectively. The increases are due to the inclusion of a
full year of operating results of Percy Kent in 1998 as compared to only seven
months in 1997, partially offset by the elimination of lower margin contracts.

FUEL AND PURCHASED POWER -- Total energy costs were $30 million for 1998, $2
million more than the 1997 expense. This increase was the result of higher per
unit costs for purchased power, increased system requirements, and more
expensive replacement energy required by outages at the Iatan generating
station, partially offset by lower resale requirements.

Per unit fuel costs were slightly higher in 1998 at $1.099 per million Btu, up
from $1.097 per million Btu in 1997, due to changes in the mix of fuels and
generating units utilized. Of the total fuel burned in 1998, 92% was coal,
similar to the pattern of recent years. The cost of coal burned decreased from
$1.002 per million Btu in 1997 to $.979 per million Btu in 1998.

The coal-fired Iatan plant provided approximately 50% of our overall energy
needs in 1998, a decrease from 52% in 1997, due to unscheduled outages. The Lake
Road units supplied 25% of our energy needs, down slightly from 26% in 1997. Per
unit fuel costs at Lake Road were up less than 1% in 1998 from 1997.

We met 25% of our energy needs through purchased power arrangements in 1998
compared to 22% in 1997, reflecting the purchase of replacement power for Iatan
outages. Purchased power fixed charges for firm and peaking capacity were $2.7
million for 1998 and $2.4 million for 1997.

Per unit costs of purchased power increased almost 18% in 1998. Along with many
utilities in the midwest, we saw the per unit costs for purchased power reach
unprecedented levels during one week in June 1998. The situation was a result of
hot, humid weather and reduced availability of transmission and generation
facilities, placing the region's electric supply under stress.

OTHER OPERATIONS -- Other operations expenses for 1998 increased $1.3 million in
comparison to 1997. The increase is primarily the result of the inclusion of a
full year of Percy Kent's expenses and increased Year 2000 expenses, partially
offset by lower benefits costs for the year.


                                                                               7


<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

MAINTENANCE -- Consistent with prior years, maintenance expenses remained
relatively stable in 1998, increasing only $.5 million over 1997, due to
increased Lake Road maintenance costs.

INTEREST CHARGES -- The increase in interest charges is primarily due to the
inclusion of a full year of Percy Kent's expenses.

FUTURE OUTLOOK

LIQUIDITY AND CAPITAL RESOURCES -- Our total authorized capital stock includes
25 million shares of common stock, four million shares of cumulative preferred
stock, and two million shares of preference stock. Common equity was 58% of
total capitalization in 1999 and 57% in 1998 and 1997.

Financial coverages are at levels in excess of those required for the issuance
of debt and preferred stock. St. Joseph Light & Power Company currently holds a
secured debt rating of A and an unsecured debt rating of A- from Standard &
Poors; we were placed on "Credit Watch-Negative" as a result of the proposed
merger. At year-end, we had $354,000 in cash and temporary investments.

Our short-term financing requirements are satisfied through borrowings under
unsecured lines of credit maintained with banks. At December 31, 1999, we had
available committed lines of credit of $3.0 million and an additional $6.7
million of uncommitted lines.

Percy Kent also has a revolving loan agreement through a finance company which
provides them with up to $4.5 million of available credit. At December 31, 1999,
the outstanding borrowings under this loan agreement, in the amount of $2.9
million, were classified as current maturities of long-term debt in our balance
sheet.

Cash generated from operations was lower in 1999, but remains strong. Over the
last three years, operating cash flows have been $10.2 million, $20.6 million,
and $18.6 million, respectively. Our ratio of earnings to fixed charges was 2.27
for 1999.

We project capital expenditures (excluding allowance for funds used during
construction (AFUDC) and including non-utility investments) for the five-year
period ending in 2004 to be approximately $62.1 million. We expect to finance
these expenditures primarily through internally generated funds supplemented by
external financing as necessary.

The combined aggregate amount of maturities and payments for long-term
obligations and for operating leases for the next five years is $10.9 million.
See Note (b), Long-Term Debt, in our statements of capitalization and Note 7,
Commitments and Contingencies, in the footnotes.

IMPACT OF ACCOUNTING STANDARDS CHANGES -- There were no accounting changes in
1999, 1998 or 1997 that had a material impact on the financial statements. See
"Effects of Regulation" for a discussion regarding the accounting changes
implemented pursuant to the PSC Order issued in 1999.

MARKET RISK -- We are exposed to various market risks in our business
operations. Commodity market prices are one such risk as Missouri does not have
an energy cost adjustment provision to allow for current recovery of changes in
the cost of fuel or purchased power.

We have entered into a long-term, fixed-price contract to meet our fuel needs at
the coal-fired Iatan generating plant to mitigate our exposure to market price
fluctuations. Coal for the Lake Road plant, approximately $8.3 million in 1999,
is mainly purchased on the spot market. The availability and cost of rail
transportation used to deliver coal to our generating facilities are additional
market risks we face. Again, we have rail service contracts for both Iatan and
Lake Road to help reduce our risk.

We are also exposed to price risk when we purchase energy to meet our system
requirements throughout the year. We have been able to partially reduce our
exposure to that risk for approximately 75 percent of our anticipated 2000
energy purchases by entering into cost-based contracts.


                                                                               8

<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

Changes in spot market prices for energy, similar to those experienced the last
two summers, can have a significant negative impact on our results (see "Fuel
and Purchased Power"). We also have the ability to reduce our need for spot
market purchases by placing into service higher cost generating units when
market prices exceed the cost of the units' operation. We are required to
maintain certain levels of capacity for which long-term, fixed price contracts
are in place (see "Capacity").

Commodity market prices for natural gas also represent a risk. However, changes
in the price of natural gas purchased for resale are passed on to our customers.

Interest and inflation rates also pose risks to our financial position. We have
limited our exposure to interest rate risk by maintaining the majority of our
debt capitalization in long-term, fixed-rate instruments. During the year, we
had weighted average short-term debt outstanding, subject to variable market
rates, of $15,531,000.

Under the ratemaking practices followed by the PSC, only historical costs are
recoverable in revenues. Assuming adequate and timely rate relief, we will
recover the increases in cost of service caused by inflation.

About two-thirds of our approximately 320 employees are covered under physical
and clerical bargaining agreements that expire July 31, 2001. Substantially all
of Percy Kent's manufacturing labor force is covered by a collective bargaining
agreement, which expires in March 2003.

COMPETITION/DEREGULATION -- While state law currently prohibits competing with
rural electric cooperatives for existing customers, competition remains for new
customers, especially industrial, in the rural areas of our service territory.
In order to compete for new, large customers and encourage businesses to locate
in our service territory, we offer an economic development incentive rate for
customers meeting certain criteria.

The 1992 Energy Policy Act (the Act) promotes competition in the way electricity
is transmitted and marketed. The Act provides for increased competition in the
wholesale electric market by permitting the FERC to order third party access to
utilities' transmission systems and by liberalizing the rules of generating
facility ownership. The FERC's Order 888 requires all transmission owning public
utilities in the country to provide non-discriminatory transmission service to
all eligible customers using FERC's standard ProForma Open Access Transmission
Tariff. As an eligible customer under FERC's tariff, we are able to access
utilities, marketers, and wholesale generators throughout the country for the
purchase and sale of wholesale electric energy. We also use the regional
transmission tariffs of the MidContinent Area Power Pool (MAPP) and Southwest
Power Pool which are rates less than those available under FERC's ProForma
tariff.

The opening of the nation's transmission system has increased the size of the
market from which we buy and sell wholesale energy. We believe that increased
transmission access will continue to increase the demand for available wholesale
energy supply and result in higher purchased energy costs.

In December 1999, the FERC issued Order No. 2000 which calls for all
transmission owners to join regional transmission organizations (RTOs). The
formation of these umbrella organizations will put all public utility
transmission facilities within a region under common control. The FERC believes
RTOs will increase competition between electric service providers.

The rule requires all public utilities that own, operate, or control interstate
transmission to file, by October 15, 2000, proposals to participate in an RTO,
or an explanation of why they have not acted, or reasons why they cannot join an
RTO. The FERC expects all utilities to be members of operating RTOs by December
15, 2001. We are currently reviewing our options for participation in an RTO
that would meet the FERC's requirements.

In March 1997, the PSC opened a docket to investigate restructuring in the
electric utility industry in the state. The Retail Electric Competition Task
Force, comprised of representatives from various groups, was charged with
preparing comprehensive reports for the PSC. The reports were prepared in 1998
based upon a thorough investigation of retail wheeling of electricity and
related issues. Included were recommendations outlining how Missouri should


                                                                               9


<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

implement retail electric competition should enabling legislation be enacted.

At the present time, a general consensus exists that the legislature should
first deal with the tax issues associated with restructuring the industry and
then pass a deregulation bill. Since a provision in the Missouri constitution
requires voter approval of new taxes, the various tax issues cannot be addressed
in a deregulation law as has been done in many other states. Failure to make
changes in the way utilities are taxed could result in lower taxes for
competitors not currently regulated by the PSC. We expect that a proposal to
reform utility taxes will be submitted to voters as a constitutional amendment
in November 2000. If voters approve the proposal, a deregulation law could be
passed in the 2001 session. Based on current legislative activity, we believe
that retail competition might begin in Missouri sometime during 2004.

Based on the PSC docket and deregulation plans implemented or considered by
other states, we believe it is most likely that the generation portion of the
business could become unregulated while the transmission and distribution
functions will continue to be regulated.

If retail wheeling were to be implemented, we believe that our current low
prices and the excellent power supply options available to us to meet future
requirements will permit us to remain competitive in comparison with other
regional suppliers.

EFFECTS OF REGULATION -- We are subject to rate regulation by the PSC. Rates are
established to allow us an opportunity to recover our costs and earn a return on
our investment. We currently apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," which
recognizes the economic effects of rate regulation. In the event we determine
that we no longer meet the criteria for following SFAS 71, the accounting impact
would be a non-cash charge to operations of an amount that could be material.
Criteria that give rise to the discontinuance of SFAS 71 include (1) increasing
competition that restricts our ability to establish prices to recover specific
costs, and (2) a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. We
continually review the applicability of SFAS 71 considering the current
regulatory environment.

Based on our current evaluation of the various factors and conditions that are
expected to impact future cost recovery (see "Competition/Deregulation"), we
believe that our regulatory assets, including those related to generation, are
probable of future recovery and that the utilization of SFAS 71 continues to be
appropriate.

If the generation portion of the business is deregulated, all or a portion of
its net regulatory assets, which are approximately $4.6 million at December 31,
1999, are expected to be recovered from ratepayers through a charge collected by
the regulated businesses.

                                                                         10

<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

On December 1, 1998, we filed rate cases before the PSC asking for price
increases of approximately $6,100,000, $500,000, and $275,000 for electric,
natural gas, and industrial steam, respectively. An earlier electric earnings
complaint filed by the PSC staff, requesting a reduction of $6.4 million, was
consolidated with our electric case.

Stipulated agreements were reached between the parties to the cases and were
approved by the PSC. Under the agreements, we reduced annual electric revenues
by $2.5 million and annual steam revenues by $25,000 effective for service
rendered after October 30, 1999. There were no changes in natural gas prices.
Included in the PSC Order were regulatory accounting policies which were
different from our current accounting policies. These differences primarily
related to the recognition of pension expense, other post-employment benefits
expense, and deferred income tax expense. As a result, the recognition of these
expenses in November and December followed the accounting treatment mandated by
the PSC Order. The revenue reductions and accounting changes required by the
agreements had a negligible effect on 1999 results and are expected to reduce
net income approximately $300,000 annually.

ENVIRONMENTAL ISSUES -- We are subject to various environmental regulations,
including those related to air and water quality, polychlorinated biphenyl, ash
removal, and asbestos. Routine testing and maintenance programs have been put in
place to comply with these regulations.

We continue to plan and implement projects to meet the Phase II acid deposition
control provisions of the Clean Air Act Amendments of 1990, which establish
standards for electric utilities to reduce certain emissions from coal-fired
generating stations. Final compliance with this legislation becomes effective in
2000. Missouri's air quality law is in compliance with, and does not contain
requirements that are more stringent than, the federal legislation.

While the Iatan plant meets the Phase II requirements, the Lake Road plant is
completing modifications to meet the stricter standards. Alterations to the
plant's main generating units have been made, an electrostatic precipitator was
modified, and a continuous emissions monitoring system and flue gas conditioning
system were installed to allow for the use of low-sulfur coal. Modifications to
the ash handling system and rail modifications that allow coal deliveries by
unit train have also been made.

The Missouri Department of Natural Resources (MDNR) has found that the
ground-level concentration of sulfur dioxide (SO2) near the Lake Road plant
exceeded the limit set by the National Ambient Air Quality Standards (NAAQS)
twice in 1997 and once in 1998. The maximum allowed is once per year. We have
conducted dispersion air modeling to identify appropriate SO2 emission control
measures. Based on the modeling, we have provided the MDNR with a plan to
achieve NAAQS compliance. We have commenced implementation of the plan to assure
that no further violations occur while we negotiate a consent agreement with the
MDNR and the United States Environmental Protection Agency (EPA). We experienced
no additional violations in 1999.

We expect total future capital expenditures of about $800,000 in 2000 to meet
the above Clean Air Act requirements.

In 1998, the EPA issued a nitrogen oxide (NOx) State Implementation Plan (SIP)
call under which Missouri, twenty-one other eastern and midwestern states, and
the District of Columbia are required to revise their SIPs to establish more
stringent emission standards for NOx. This was being done primarily to help the
northeastern states meet the NAAQS for ozone. The EPA determined that the
transport of NOx (a precursor of ozone) from neighboring states is the major
cause of ozone non-compliance in the northeastern states. In March 2000, the
D.C. Circuit Court of Appeals ruled on a case challenging the EPA's SIP call.
Although the D.C. Circuit Court decided for the EPA with regard to the issues
involving other states, the Court decided in favor of the western Missouri
utilities, including St. Joseph Light & Power Company, and vacated the NOxSIP
call for Missouri. The EPA can appeal or request a rehearing on the Missouri
issues.

A regional NOx issue emerged in 1999 due to the inability of the St. Louis area
to comply with the NAAQS for ozone. To address this problem, the MDNR has issued
a proposed NOx reduction regulation for Missouri somewhat similar in nature to
the EPA's NOx SIP call. The reduction levels in


                                                                              11

<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS

the proposed regulation are less stringent than the NOx SIPcall and allow for
smaller reductions in the western part of the state than the eastern part of the
state. If approved, the regulation would require compliance by 2003. The full
extent of how we will be affected and the related cost of implementation are not
yet known.

The Kyoto Protocol to the United Nations global warming treaty mandates that the
U.S. reduce its overall greenhouse gas emissions 7% below 1990 levels over the
period 2008-2012. Most observers believe the Protocol will not be ratified by
the U.S. Congress in its present form. A study by Energy Security Analysis Inc.
indicates that the treaty could cost the utility industry $10 billion annually
by 2010, primarily in higher fuel costs. We cannot currently estimate the
treaty's impact on us; however, it could have a significant continuing impact on
our results of operations and financial position.

CAPACITY -- In 1996, we signed a long-term contract to purchase both capacity
and energy beginning in mid-2000 and running through mid-2011. In the first year
of the contract, we will receive 60 megawatts (mw) of electricity. This will
increase by 10 mw each year until it reaches 100 mw in 2004 and remains at that
level for the remainder of the contract. Fixed charges under this contract total
$40 million for the five years ending in 2004. We believe that this contract
will enable us to economically provide for the growing demand in our service
territory.

In addition, we are a member of the MAPP Reliability Council and reserve sharing
pool (MRC). The 34 utility members of the MRC combine their generating resources
to provide emergency replacement energy to each other in the event of an
unscheduled generator outage.

Impact of the Year 2000 Issue -- The Year 2000 issue was the result of computer
programs written using two digits rather than four to define a year. Computer
programs that have date-sensitive software might have recognized a date using
"00" as 1900 rather than 2000. Additionally, other equipment with microchips
with embedded logic, may have failed to function correctly after December 31,
1999, resulting in system failure or miscalculations causing disruptions of
operations.

We believe that the Year 2000 issue has been mitigated with no significant
adverse effect on customers or disruption to business operations. We have not
encountered any significant system problems, nor have we experienced any
interruptions of service to our customers, associated with the year 2000 issue.

Expenses incurred through December 31, 1999 for the efforts related to Year 2000
issues were about $600,000, excluding the costs of redeployment of existing
resources. No significant additional costs are expected to be incurred.

Because of the unprecedented nature of the Year 2000 issue, associated risks may
still exist. All business units have contingency plans to cover essential
business functions for possible Year 2000 related failures.

FORWARD-LOOKING INFORMATION -- This report contains information based on
projections and estimates made by management, which involve risks and
uncertainties. 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 conditions, inflation rates, regulatory changes
(including, but not limited to, ongoing state and federal activities with
respect to electric utility deregulation, competition, and restructuring),
weather conditions, financial market conditions, interest rates, Year 2000
issues, future business decisions, and other uncertainties, all of which are
difficult to predict and many of which are beyond our control.


                                                                              12

<PAGE>


CONSOLIDATED STATEMENTS OF INCOME


<TABLE>
<CAPTION>


YEARS ENDED DECEMBER 31                                          1999              1998             1997
------------------------------------------------------------------------------------------------------------
<S>                                                          <C>              <C>              <C>
OPERATING REVENUES:
     Electric utility                                        $  90,499,000    $  89,678,000    $  86,910,000
     Other utility                                              10,898,000       10,876,000       11,948,000
     Manufacturing                                              19,552,000       23,820,000       17,307,000
                                                             -------------    -------------    -------------
                                                               120,949,000      124,374,000      116,165,000
                                                             -------------    -------------    -------------
OPERATING EXPENSES:
     Production fuel                                            21,200,000       19,964,000       19,166,000
     Purchased power                                            12,708,000        9,896,000        8,307,000
     Gas purchased for resale                                    2,278,000        2,481,000        3,456,000
     Manufacturing cost of goods sold                           16,300,000       19,868,000       14,864,000
     Other operations                                           21,144,000       22,749,000       21,596,000
     Merger-related expenses                                     3,141,000          105,000             --
     Maintenance                                                 8,312,000        8,472,000        7,976,000
     Depreciation                                               12,084,000       11,535,000       11,045,000
     Taxes other than income taxes                               7,224,000        7,117,000        6,767,000
                                                             -------------    -------------    -------------
                                                               104,391,000      102,187,000       93,177,000
                                                             -------------    -------------    -------------
OPERATING INCOME                                                16,558,000       22,187,000       22,988,000
INTEREST CHARGES, NET:
     Long-term debt                                              5,652,000        6,057,000        6,182,000
     Notes payable                                               1,453,000          562,000          181,000
     Other                                                         267,000          320,000          192,000
     Allowance for borrowed funds used during construction         (60,000)        (152,000)         (75,000)
                                                             -------------    -------------    -------------
                                                                 7,312,000        6,787,000        6,480,000
                                                             -------------    -------------    -------------
OTHER INCOME                                                       507,000          847,000          440,000
                                                             -------------    -------------    -------------
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST                 9,753,000       16,247,000       16,948,000
INCOME TAXES                                                     3,705,000        5,512,000        6,214,000
                                                             -------------    -------------    -------------
INCOME BEFORE MINORITY INTEREST                                  6,048,000       10,735,000       10,734,000
MINORITY INTEREST IN INCOME (LOSS) OF SUBSIDIARY                   (79,000)          71,000         (106,000)
                                                             -------------    -------------    -------------
NET INCOME                                                   $   6,127,000    $  10,664,000    $  10,840,000
                                                             -------------    -------------    -------------
                                                             -------------    -------------    -------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING                       8,212,108        8,099,928        7,988,714

BASIC EARNINGS PER SHARE                                     $         .75    $        1.32    $        1.36
                                                             -------------    -------------    -------------

DILUTED EARNINGS PER SHARE                                   $         .74    $        1.31    $        1.36
                                                             -------------    -------------    -------------
                                                             -------------    -------------    -------------

</TABLE>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                                                              13

<PAGE>


CONSOLIDATED BALANCE SHEETS


<TABLE>
<CAPTION>

DECEMBER 31                                                              1999             1998
---------------------------------------------------------------------------------------------------
<S>                                                                  <C>              <C>
--ASSETS--

PROPERTY, PLANT AND EQUIPMENT:
     Electric utility plant                                          $ 333,513,000    $ 324,621,000
     Other                                                              20,912,000       20,377,000
                                                                     -------------    -------------
                                                                       354,425,000      344,998,000
     Less - Reserves for depreciation                                 (178,057,000)    (167,112,000)
                                                                     -------------    -------------
                                                                       176,368,000      177,886,000
     Construction work in progress                                       5,661,000        3,669,000
                                                                     -------------    -------------
                                                                       182,029,000      181,555,000
OTHER INVESTMENTS                                                        6,741,000        4,922,000

CURRENT ASSETS:
     Cash and cash equivalents                                             354,000          371,000
     Accounts receivable, net of reserves of $310,000 and $282,000      10,014,000       10,160,000
     Accrued utility revenue                                             3,306,000        3,674,000
     Manufacturing inventories, at first-in first-out cost               3,187,000        2,911,000
     Fuel, at average cost                                               4,641,000        3,366,000
     Materials and supplies, at average cost                             5,626,000        5,674,000
     Prepayments and other                                               3,100,000        1,902,000
                                                                     -------------    -------------
                                                                        30,228,000       28,058,000
DEFERRED CHARGES:
     Debt expense, being amortized over term of debt                     1,249,000        1,349,000
     Lease payments receivable                                           3,042,000        3,166,000
     Prepaid pension expense                                            20,001,000       16,389,000
     Regulatory assets                                                  16,446,000       13,843,000
     Other                                                               1,590,000        1,973,000
                                                                     -------------    -------------
                                                                        42,328,000       36,720,000
                                                                     -------------    -------------
                                                                     $ 261,326,000    $ 251,255,000
                                                                     -------------    -------------
                                                                     -------------    -------------

--CAPITALIZATION AND LIABILITIES--

CAPITALIZATION:
     Common stock                                                    $  33,816,000    $  33,816,000
     Retained earnings                                                  71,376,000       73,450,000
     Other paid-in capital                                               2,879,000        1,877,000
     Less - Treasury stock                                             (11,883,000)     (13,338,000)
                                                                     -------------    -------------
                                                                        96,188,000       95,805,000
     Long-term debt                                                     68,597,000       73,515,000
                                                                     -------------    -------------
                                                                       164,785,000      169,320,000

MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY                             1,313,000        1,369,000

CURRENT LIABILITIES:
     Outstanding checks in excess of cash balances                       3,611,000        3,512,000
     Current maturities of long-term obligations                         5,685,000        1,213,000
     Accounts payable                                                    9,395,000        9,988,000
     Notes payable                                                      17,762,000        7,290,000
     Accrued income and general taxes                                      398,000          823,000
     Accrued interest                                                    1,983,000        1,923,000
     Accrued vacation                                                    1,247,000        1,233,000
     Other                                                                 686,000          679,000
                                                                     -------------    -------------
                                                                        40,767,000       26,661,000

NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
     Capital lease obligations                                           2,697,000        2,902,000
     Deferred income taxes                                              32,610,000       31,822,000
     Investment tax credit                                               3,280,000        3,689,000
     Accrued claims and benefits                                         1,586,000        1,833,000
     Deferred interest                                                   2,021,000        2,138,000
     Regulatory liabilities                                              8,812,000        8,440,000
     Other                                                               3,455,000        3,081,000
                                                                     -------------    -------------
                                                                        54,461,000       53,905,000
                                                                     -------------    -------------

COMMITMENTS AND CONTINGENCIES (NOTE 7)                               $ 261,326,000    $ 251,255,000
                                                                     -------------    -------------
                                                                     -------------    -------------

</TABLE>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                                                              14

<PAGE>


CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>

YEARS ENDED DECEMBER 31                                         1999                  1998               1997
------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>                 <C>                 <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income                                               $ 6,127,000         $ 10,664,000        $ 10,840,000
     Adjustments to reconcile net income to net
       cash provided by operating activities:
         Depreciation                                          12,611,000           12,346,000          11,440,000
         Pension expense                                       (3,024,000)          (2,228,000)         (1,961,000)
         Deferred taxes and investment tax credit                 740,000              812,000             402,000
         Allowance for equity funds used during construction     (111,000)            (249,000)           (129,000)
         Net changes in working capital items
           not considered elsewhere:
              Accounts receivable and accrued utility revenue     514,000             (727,000)            591,000
              Inventories                                      (1,503,000)             405,000            (255,000)
              Accounts payable and outstanding checks            (494,000)          (1,188,000)         (2,804,000)
              Accrued income and general taxes                 (1,202,000)              88,000             234,000
              Other, net                                         (342,000)            (118,000)           (147,000)
     Net changes in regulatory assets and liabilities          (2,593,000)             535,000             464,000
     Net changes in other assets and liabilities                   12,000              266,000             (98,000)
                                                              -----------          -----------         -----------
       Net cash provided by operating activities               10,735,000           20,606,000          18,577,000
                                                              -----------          -----------         -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
     Additions to plant                                       (13,124,000)         (16,843,000)        (14,128,000)
     Allowance for borrowed funds used during construction         60,000              152,000              75,000
     Investments                                               (1,818,000)             202,000           2,996,000
     Other                                                         52,000               97,000             (18,000)
                                                              -----------          -----------         -----------
       Net cash used in investing activities                  (14,830,000)         (16,392,000)        (11,075,000)
                                                              -----------          -----------         -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
     Lines of credit increase (decrease)                       10,472,000            6,811,000            (462,000)
     Principal payments under capital lease obligations          (205,000)            (191,000)           (178,000)
     Long-term debt retired                                    (2,416,000)          (7,873,000)         (1,358,000)
     Long-term debt issued                                      1,971,000            3,087,000                  --
     Common stock purchased                                            --                   --              (4,000)
     Common stock issued                                        2,457,000            1,901,000           1,821,000
     Dividends paid                                            (8,201,000)          (7,928,000)         (7,659,000)
                                                              -----------          -----------         -----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES             4,078,000           (4,193,000)         (7,840,000)
                                                              -----------          -----------         -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS              (17,000)              21,000            (338,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                    371,000              350,000             688,000
                                                              -----------          -----------         -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR                      $   354,000         $    371,000        $    350,000
                                                              -----------          -----------         -----------
                                                              -----------          -----------         -----------

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
CASH PAID DURING THE YEAR FOR:
       Interest                                               $ 7,195,000         $  6,677,000        $  7,444,000
       Income taxes, net of refunds                             4,385,000            4,588,000           5,609,000

</TABLE>


For purposes of the Consolidated Statements of Cash Flows, the Company considers
all highly liquid debt instruments purchased with an original maturity of three
months or less to be cash equivalents.


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                                                              15

<PAGE>


CONSOLIDATED STATEMENTS OF CAPITALIZATION


<TABLE>
<CAPTION>

DECEMBER 31                                                1999              1998
------------------------------------------------------------------------------------
<S>                                                   <C>              <C>
COMMON EQUITY:
     Common stock - authorized 25,000,000 shares,
         without par value; issued 9,252,748 shares   $  33,816,000    $  33,816,000
     Retained earnings                                   71,376,000       73,450,000
     Other paid-in capital (principally gain on
         issuance of treasury stock)                      2,879,000        1,877,000
     Less - Treasury stock, at cost, 985,200 and
            1,105,821 shares                            (11,883,000)     (13,338,000)
                                                      -------------    -------------
                                                         96,188,000       95,805,000

LONG-TERM DEBT:
     First mortgage bonds -
         9.44% series due February 1, 2021               22,500,000       22,500,000

     Unsecured pollution control revenue bonds -
         5.85% series due February 1, 2013                5,600,000        5,600,000
     Unsecured medium-term notes -
         7.13% due November 29, 2013                      1,000,000        1,000,000
         7.16% due November 29, 2013                      9,000,000        9,000,000
         7.17% due December 1, 2023                       7,000,000        7,000,000
         7.33% due November 30, 2023                      3,000,000        3,000,000
         8.36% due March 15, 2005                        20,000,000       20,000,000
                                                      -------------    -------------
                                                         40,000,000       40,000,000
     Other long-term debt                                 6,182,000        6,628,000
                                                      -------------    -------------
                                                         74,282,000       74,728,000
     Less - Current maturities                           (5,685,000)      (1,213,000)
                                                      -------------    -------------
                                                         68,597,000       73,515,000
                                                      -------------    -------------
         Total capitalization                         $ 164,785,000    $ 169,320,000
                                                      -------------    -------------
                                                      -------------    -------------

</TABLE>


Notes:

(a) Common Stock:

    At December 31, 1999, there were 8,267,548 shares of common stock
    outstanding.

    St. Joseph Light &Power Company (the Company) has an Automatic Dividend
    Reinvestment and Optional Cash Payment Plan. Under this Plan, common shares
    may be newly issued, reissued or purchased on the open market.

    At December 31, 1999, the Company had 246,550 shares of common stock
    reserved for this Plan. In addition, the Company has 371,524 shares of stock
    reserved for its stock-based compensation plans. Refer to Note 3 in the
    Notes to Consolidated Financial Statements.

    At December 31, 1999, there were 8,267,548 Rights outstanding. Each Right
    entitles the holder thereof to purchase one-half share of common stock at a
    price of $35 per one-half share.

    The Rights, which expire on December 4, 2006, have no voting rights. The
    Rights are exercisable in the event of certain attempted business
    acquisitions. Exercising the Rights will cause substantial dilution to a
    person or group attempting to acquire the Company on terms not approved by
    the Company's board of directors. The Rights Agreement is inoperable with
    respect to the proposed merger agreement. Refer to Note 1 in the Notes to
    Consolidated Financial Statements.


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                                                              16

<PAGE>


(b) Long-Term Debt:

    The first mortgage bonds are secured equally and ratably by a direct lien on
    substantially all fixed property and franchises now owned or hereafter
    acquired.

    Other long-term debt includes notes payable to banks and finance companies
    which are payable through 2003 and bear interest at rates ranging from
    9.635% to 9.75% and prime plus 1.5% to prime plus 2.75%. These notes are
    collateralized by substantially all of the assets of Percy Kent Bag Co.,
    Inc. (Percy Kent). Refer to Note 1 in the Notes to Consolidated Financial
    Statements.

    The combined aggregate amount of maturities and unfulfilled sinking fund
    requirements for the next five years are as follows:

<TABLE>
                   <S>                              <C>
                   2000                             $ 5,685,000
                   2001                                 404,000
                   2002                               1,152,000
                   2003                               1,192,000
                   2004                               1,125,000
                                                    -----------
                                                    $ 9,558,000
                                                    -----------
                                                    -----------

</TABLE>



(c) Cumulative Preferred Stock:

    Cumulative preferred stock of 4,000,000 shares, without par value, is
    authorized.

(d) Preference Stock:

    Preference stock of 2,000,000 shares, without par value, is authorized.


CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


<TABLE>
<CAPTION>

YEARS ENDED DECEMBER 31                               1999            1998            1997
----------------------------------------------------------------------------------------------
<S>                                               <C>             <C>             <C>
BALANCE AT BEGINNING OF YEAR                      $ 73,450,000    $ 70,714,000    $ 67,533,000
NET INCOME                                           6,127,000      10,664,000      10,840,000
                                                  ------------    ------------    ------------
                                                    79,577,000      81,378,000      78,373,000
LESS - Dividends on common stock of $1.00, $.98
         and $.96 per share                         (8,201,000)     (7,928,000)     (7,659,000)
                                                  ------------    ------------    ------------

BALANCE AT END OF YEAR                            $ 71,376,000    $ 73,450,000    $ 70,714,000
                                                  ------------    ------------    ------------
                                                  ------------    ------------    ------------

</TABLE>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

                                                                              17


<PAGE>


CONSOLIDATED STATEMENTS OF TAXES


<TABLE>
<CAPTION>

YEARS ENDED DECEMBER 31                                                1999             1998            1997
----------------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>             <C>
COMPONENTS OF INCOME TAX EXPENSE:
     Taxes payable currently --
       Federal                                                     $  2,570,000     $ 4,156,000     $  5,025,000
       State                                                            395,000         544,000          787,000
                                                                   ------------     -----------     ------------
                                                                      2,965,000       4,700,000        5,812,000
     Provisions for deferred taxes (a) --
       Depreciation and other plant-related differences (b)             (54,000)        648,000          255,000
       Pensions                                                       1,383,000       1,072,000          971,000
       Other                                                           (179,000)       (501,000)        (417,000)
                                                                   ------------     -----------     ------------
                                                                      1,150,000       1,219,000          809,000
     Amortization of investment tax credits                            (410,000)       (407,000)        (407,000)
                                                                   ------------     -----------     ------------
       Total income tax expense                                    $  3,705,000     $ 5,512,000     $  6,214,000
                                                                   ------------     -----------     ------------
                                                                   ------------     -----------     ------------

RECONCILIATION OF INCOME TAX RATES:
     Statutory federal income tax rate                                     35.0%         35.0%              35.0%
     State income tax benefit for deduction of
       federal income taxes                                                (1.8)         (1.8)              (1.8)
     Timing differences flowed through as required
       by regulators                                                        2.3           1.8                1.2
     Amortization of investment tax credits                                (4.2)         (2.5)              (2.4)
     Amortization of excess deferred taxes                                 (1.3)         (1.3)              (1.0)
     State income taxes, net of federal income tax benefit                  6.5           5.6                5.8
     Non-deductible merger expenses                                         7.3            --                 --
     Tax on contribution in aid of construction paid by customer           (2.2)           --                 --
     Other                                                                 (3.9)         (2.7)               (.4)
                                                                   ------------     -----------     ------------
       Effective income tax rate (c)                                       37.7%         34.1%              36.4%
                                                                   ------------     -----------     ------------
                                                                   ------------     -----------     ------------

</TABLE>


Notes:

(a) The Company has recorded regulatory assets and liabilities to account for
    the effect of expected future regulatory actions related to unamortized
    investment tax credits, income tax liabilities recorded at tax rates in
    excess of current rates, and other items for which deferred taxes have not
    previously been provided. The principal components of the Company's deferred
    income tax balances consist of the following:


<TABLE>
<CAPTION>


DECEMBER 31                                     1999             1998
-------------------------------------------------------------------------
<S>                                         <C>             <C>
Accelerated depreciation and other
    plant-related differences               $ 24,669,000    $ 24,934,000
Pensions                                       7,650,000       6,265,000
Unamortized investment tax credits            (2,299,000)     (2,552,000)
Regulatory assets                             12,811,000      12,802,000
Regulatory liabilities                        (6,513,000)     (5,888,000)
Net operating loss carryforwards of
    Percy Kent, which expire through 2019     (2,100,000)     (2,060,000)
Other, net                                    (1,608,000)     (1,679,000)
                                            ------------    ------------
Net deferred tax liabilities                $ 32,610,000    $ 31,822,000
                                            ------------    ------------
                                            ------------    ------------

</TABLE>


(b) The Company has elected, for tax purposes, to apply various accelerated
    depreciation methods allowed by the Internal Revenue Code.

(c) The effective income tax rate is computed by dividing total income tax
    expense by the sum of tax expense and net income.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                                                              18

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 STATEMENT OF ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements include the
accounts of St. Joseph Light & Power Company, a public utility, and its wholly
owned subsidiary, SJLP Inc. and its subsidiary, Percy Kent. Collectively, these
entities are referred to as the "Company." All significant intercompany
transactions have been eliminated in consolidation.

The Company is engaged principally in the generation, purchase, transmission,
distribution, and sale of electricity, the generation and distribution of
industrial steam, and the distribution of natural gas. SJLP Inc. was formed in
September 1996, to pursue investments in non-utility areas. Effective May 31,
1997, SJLPInc. acquired a controlling interest in Percy Kent, a manufacturer of
multiwall and small paper bags.

The acquisition was accounted for as a purchase. Acquired goodwill of
$1,211,000, net of amortization, is included in other deferred charges in the
Consolidated Balance Sheets and is being amortized on a straight-line basis over
15 years. The consolidated financial statements include the results of
operations since the date of acquisition. Pro forma financial data prior to the
date of acquisition do not materially differ from reported results.

On March 4, 1999, the Company and UtiliCorp United Inc. (UtiliCorp) entered into
an Agreement and Plan of merger to form a strategic business combination. Under
terms of the Agreement, each share of common stock of the Company, valued at $23
per share, will be exchanged for shares of UtiliCorp common stock. The Agreement
was approved by a vote of the Company's shareholders at a special meeting in
1999, and by the Public Utility Commissions of Colorado, West Virginia, Iowa,
and Minnesota. The transaction is subject to several additional closing
conditions, including approvals by the Federal Energy Regulatory Commission
(FERC), the Department of Justice, the Federal Communications Commission, and
the Missouri Public Service Commission (PSC). The PSC has scheduled hearings for
mid-July 2000. Management expects the merger to be completed in the fall of
2000. Additional merger-related expenses are expected to be incurred in 2000,
resulting in an after tax impact to earnings of approximately $4.5 million.

The Merger Agreement limits the Company's ability to do certain things prior to
closing, including issue or redeem securities, merge with any entity or make
acquisitions, incur material liens, and declare or pay dividends other than
regular cash dividends.

PROPERTY, PLANT AND EQUIPMENT -- Property, plant and equipment is stated at
original cost. These costs include payroll-related costs such as taxes, pensions
and other fringe benefits, and allowance for funds used during construction
(AFUDC).

Improvements to units of property are capitalized. Utility property units
retired are charged to accumulated depreciation together with any related
removal costs, net of salvage. Maintenance costs and replacements of assets
which do not constitute units of property are expensed as incurred.

DEPRECIATION -- Provisions for utility depreciation have been computed on a
straight-line basis by applying rates approved by the PSC to the classified
account balances. The Company's annual depreciation provisions (including
amounts classified elsewhere in the Consolidated Statements of Income), as a
percentage of the average balance of depreciable property, were 3.7% for 1999,
1998 and 1997.

Percy Kent management has reevaluated and extended the estimated useful lives of
its printing and production equipment to reflect reduced utilization of the
equipment. In conjunction with the decision to extend the lives, management
began depreciating the remaining book value over the anticipated remaining
machine hours which resulted in an increase to the Company's consolidated net
income of approximately $200,000 in 1999.

JOINTLY OWNED IATAN PLANT -- The Company has an agreement with Kansas City Power
and Light Company and The Empire District Electric Company for joint ownership
of a coal-burning generating plant in Iatan, Missouri. The Company's share of
operating expenses for Iatan is included in operating expenses in the
Consolidated Statements of Income. The amounts below represent the Company's 18%
interest in the 670-megawatt unit:

<TABLE>
<CAPTION>


         DECEMBER 31                       1999              1998
         -------------------------------------------------------------
         <S>                          <C>                <C>
         Electric utility plant       $  61,553,000      $ 61,541,000
         Reserves for depreciation       37,348,000        35,339,000

</TABLE>


REVENUE RECOGNITION -- Utility revenues relating to service rendered but
unbilled are recognized in the period the service is provided. Manufacturing
revenues are recognized at the time the finished bags are shipped to the
customer.


                                                                              19

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EARNINGS PER SHARE -- Basic and diluted earnings per average common share were
computed by dividing net income by the following:

<TABLE>
<CAPTION>

                                                             1999        1998        1997
--------------------------------------------------------------------------------------------
<S>                                                        <C>         <C>         <C>
Denominator for basic EPS - Weighted average number
   of shares of common stock outstanding during the year   8,212,108   8,099,928   7,988,714
Stock options (see Note 3)                                    16,535      13,578       7,550
Contingently issuable shares pursuant to long-term
   incentive plan (see Note 3)                                18,199      15,423        --
                                                           ---------   ---------   ---------
Denominator for diluted EPS                                8,246,842   8,128,929   7,996,264
                                                           ---------   ---------   ---------
                                                           ---------   ---------   ---------

</TABLE>


ACCOUNTING POLICIES -- 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.

In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities." In June 1999, the FASB issued Statement
137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral
of the Effective Date of SFAS 133." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting.

SFAS 133, as amended, is effective for fiscal years beginning after June 15,
2000. A company may also implement the Statement as of the beginning of any
fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998
and thereafter). SFAS 133 cannot be applied retroactively.

The Company believes its fixed-price contracts for future purchases of energy,
fossil fuels, and rail service are not derivatives as defined in SFAS 133
because there are no net settlement features. The Company's investments include
debt with detachable warrrants. SFAS 133 will require such securities to be
accounted for as two separate instruments: a warrant for the issuer's stock and
a plain interest-bearing security. SFAS 133 will require changes in the fair
value of the separated warrants to be reported currently in earnings. There is
no public market for such warrants or for the debt or common stock of the
investee, however, the excess of the fair value of the warrants over the
exercise price is currently estimated to be $4.1 million. Refer to Note 5, Fair
Value of Financial Instruments.

The Company is continuing to study the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of its adoption of SFAS
133. However, the Statement could increase volatility in earnings and other
comprehensive income.

RECLASSIFICATIONS -- Certain reclassifications have been made in the financial
statements to enhance comparability.

2 BENEFIT PLANS

RETIREMENT SAVINGS PLAN -- The Company has a Retirement Savings Plan under
Section 401(k) of the Internal Revenue Code. The plan covers all employees.
Under this plan, eligible employees may defer and contribute a portion of
current compensation in order to supplement retirement benefits. The Company
makes a matching contribution for employees with one year or more of service of
50 percent of employee contributions, up to 6 percent of compensation, on a
monthly basis. The Company made contributions of $425,000 for 1999, $359,000 for
1998, and $300,000 for 1997.

PENSION AND POSTRETIREMENT BENEFIT PLANS -- The Company has two non-contributory
defined benefit pension plans, one for bargaining and one for non-bargaining
employees, covering all employees with one year or more of continuous service.
Benefits for both plans are based on years of service and compensation,
utilizing the final average-pay benefit formula. The Company's funding policy is
to comply with the minimum funding requirements of the Employee Retirement
Income Security Act.


                                                                              20

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In addition to providing pension benefits, the Company provides certain
postretirement medical and life insurance benefits (OPEB). Employees hired after
December 31, 1992 are not eligible for postretirement life insurance benefits.
Employees covered under the plans become eligible for these benefits if they
reach retirement age while working for the Company and have 10 years of service.
The Company uses Voluntary Employees' Beneficiary Association trusts, which
cover substantially all active and retired employees.

The following table summarizes the net pension credits and postretirement
benefit costs, including amounts capitalized:

<TABLE>
<CAPTION>


                                                                 PENSION                                     OPEB
                                                      1999         1998         1997             1999        1998          1997
                                                   -------------------------------------     -------------------------------------
<S>                                                <C>          <C>          <C>               <C>         <C>          <C>
  Service cost--benefits earned during the period  $ 1,050,000  $   977,000  $   861,000       $  257,000  $  216,000   $ 149,000
  Interest cost on benefit obligation                2,559,000    2,433,000    2,280,000          855,000     733,000     672,000
  Expected return on plan assets                    (5,976,000)  (5,392,000)  (4,755,000)        (332,000)   (229,000    (169,000)
  Amortization of transition (asset) obligation       (431,000)    (431,000)    (431,000)         388,000     388,000     388,000
  Amortization of prior service cost                   249,000      223,000      175,000               --          --          --
  Recognized net actuarial (gain) loss              (1,063,000)    (627,000)    (551,000)          21,000          --          --
                                                   -----------  -----------  -----------      -----------  ---------   ---------
                                                    (3,612,000)  (2,817,000)  (2,421,000)       1,189,000   1,108,000    1,040,000

Amounts credited (charged) to construction             588,000      589,000      460,000         (194,000)   (232,000)    (198,000)
                                                   -----------  -----------  -----------       ----------  ----------   ----------
  Net benefit costs (credits) included
     in operating expenses                         $(3,024,000) $(2,228,000) $(1,961,000)      $  995,000  $  876,000   $  842,000
                                                   -----------  -----------  -----------       ----------  ----------   ----------
                                                   -----------  -----------  -----------       ----------  ----------   ----------

</TABLE>


The following table reconciles the beginning and ending balances of the plans'
benefit obligations and fair value of plan assets and reconciles the funded
status of the plans to the related amounts recognized in the Consolidated
Balance Sheets:

<TABLE>
<CAPTION>

                                                                      PENSION                              OPEB
                                                                1999            1998               1999             1998
                                                            -----------------------------     -----------------------------
<S>                                                         <C>              <C>              <C>              <C>
Change in benefit obligation:
 Benefit obligation at beginning of year                    $ 34,860,000     $ 32,643,000     $ 10,593,000     $ 10,140,000
      Service cost--benefits earned during period              1,050,000          977,000          257,000          216,000
      Interest cost on benefit obligation                      2,559,000        2,433,000          855,000          733,000
      Actuarial (gains) losses                                (3,124,000)         350,000          365,000          (55,000)
      Plan amendments                                            337,000          633,000             --               --
      Participant contributions                                     --               --            216,000          222,000
      Benefits paid and other expenses                        (2,238,000)      (2,176,000)      (1,041,000)        (663,000)
                                                            ------------     ------------     ------------     ------------
      Benefit obligation at end of year                     $ 33,444,000     $ 34,860,000     $ 11,245,000     $ 10,593,000

  Change in plan assets:
      Fair value of plan assets at beginning of year        $ 67,456,000     $ 60,971,000     $  4,064,000     $  2,783,000
      Actual return on plan assets                             9,356,000        8,661,000          430,000          588,000
      Employer contribution                                         --               --          1,237,000        1,134,000
      Participant contributions                                     --               --            216,000          222,000
      Benefits paid and other expenses                        (2,238,000)      (2,176,000)      (1,041,000)        (663,000)
                                                            ------------     ------------     ------------     ------------
      Fair value of plan assets at end of year              $ 74,574,000     $ 67,456,000     $  4,906,000     $  4,064,000

   Funded status:
      Plan assets in excess of (less than) benefit
       obligation                                           $ 41,130,000     $ 32,596,000     $ (6,339,000)    $ (6,529,000)
      Unrecognized net actuarial (gain) loss                 (22,309,000)    (16,868,000)         222,000          (23,000)
      Unrecognized transition (asset) obligation                (863,000)      (1,294,000)       5,019,000        5,407,000
      Unrecognized prior service cost                          2,043,000        1,955,000             --               --
                                                            ------------     ------------     ------------     ------------
      Prepaid (accrued) benefit cost                        $ 20,001,000     $ 16,389,000     $ (1,098,000)    $ (1,145,000)

   Assumptions as of December 31:
      Discount rate                                                 8.00%            7.25%            8.00%            7.25%
      Expected return on plan assets                                9.00%            9.00%            9.00%            9.00%
      Rate of compensation increase                                 4.30%            4.30%             N/A              N/A

</TABLE>


For measurement purposes, a 7.5 percent annual rate of increase in the
per-capita health care benefits was assumed for 2000; the rate was assumed to
decrease gradually to 6 percent by 2020 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects:

<TABLE>
<CAPTION>


                                                                      1-PERCENTAGE-          1-PERCENTAGE-
                                                                     POINT INCREASE         POINT DECREASE

            <S>                                                        <C>                    <C>
            Effect on total of service and interest cost components    $  248,000             $  195,000
            Effect on postretirement benefit obligation                $1,994,000             $1,617,000

</TABLE>
                                                                            21
<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3 STOCK-BASED COMPENSATION PLANS

The Company has a long-term stock incentive plan (the Plan). Under the Plan,
non-employee directors are automatically granted restricted stock and
non-qualified options to purchase shares of common stock. All options are
exercisable in full from the date of grant and have exercise prices equal to the
stock's market price on the date of the grant. The options will expire at the
end of six months after the close of the merger with UtiliCorp.

The following table is a summary of data regarding stock options and restricted
stock for non-employee directors:

<TABLE>
<CAPTION>


                                                             1999                 1998                1997
                                                       ---------------------------------------------------------
                                                        SHARES   PRICE1      SHARES  PRICE1      SHARES   PRICE1
<S>                                                    <C>      <C>        <C>      <C>         <C>      <C>
      Options outstanding at January 1                 121,000  $15.660    123,000  $15.250     106,000  $15.125
      Options granted                                   16,000   20.875     16,000   18.313      17,000   16.030
      Options exercised                                     --      N/A     18,000   15.222          --      N/A
                                                       -------  -------    -------  -------     -------  -------
      Options outstanding at December 31               137,000  $16.269    121,000  $15.660     123,000  $15.250
                                                       -------  -------    -------  -------     -------  -------
                                                       -------  -------    -------  -------     -------  -------

      Restricted shares granted and compensation         3,000  $63,000      3,000  $55,000       2,500  $40,000
         expense, respectively

</TABLE>


----------
1weighted average exercise price

The Company accounts for the option feature of the Plan under Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees," under
which no compensation cost has been recognized. The following table shows the
assumptions made for grants in each year, as well as the amounts the Company's
net income and earnings per share would have been had compensation cost for this
plan been recorded consistent with SFAS 123, "Accounting for Stock-Based
Compensation," using the Black-Scholes pricing model:

<TABLE>
<CAPTION>


                                                              1999                1998                1997
                                                          ---------------------------------------------------
<S>                                                       <C>                 <C>                 <C>
      Net income:    As reported                          $6,127,000          $10,664,000         $10,840,000
                     Pro forma                             6,096,000           10,640,000          10,815,000
      Basic EPS:     As reported                                $.75               $1.32                $1.36
                     Pro forma                                   .74                1.31                 1.35
      Diluted EPS:   As reported                                 .74                1.31                 1.36
                     Pro forma                                   .74                1.31                 1.35
      Risk-free interest rate                                   5.94%               5.81%                6.89%
      Expected dividend yield                                   5.50%               5.83%                5.79%
      Expected life                                         10 years            10 years             10 years
      Expected volatility                                         20%                 19%                  18%
      Weighted average fair value of options granted           $3.14               $2.42                $2.37

</TABLE>


The Plan also covers long-term incentives for officers and certain other key
employees. It provides for overlapping three-year performance cycles with stock
awards established on the first day and earned on the last day of each
performance cycle. Compensation of $721,000, $132,000, and $(9,000) was expensed
for this portion of the Plan in 1999, 1998, and 1997, respectively.

At December 31,1999, there were 371,524 shares available for grant for
non-employee directors options and restricted stock and for officers and key
employees restricted stock.

All shares of restricted stock will be converted into unrestricted shares of
UtiliCorp common stock as of the closing of the merger.

4 SHORT-TERM BORROWINGS

The Company has arrangements with certain banks to provide unsecured short-term
lines of credit on a committed basis with available amounts at December 31,
1999, totaling $3,000,000. In addition, the Company has agreements with several
banks to borrow, as available, on an uncommitted basis at market-based rates
quoted by the banks. Outstanding notes bear interest at rates based on the prime
rate or money market rates.

At December 31, 1999 and 1998, respectively, outstanding borrowings consisted of
$17,762,000 and $7,290,000 of notes payable to banks with weighted average
interest rates of 6.4% and 6.1%. During 1999 and 1998, weighted average
short-term debt outstanding was $15,531,000 and $1,169,000, with weighted
average interest rates of 5.9% and 6.7%, respectively.


                                                                              22

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5 FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:

Cash and Temporary Investments -- The fair value of these investments is
estimated based on quoted market prices for the same or similar issues and
approximates the carrying amount.

OTHER INVESTMENTS -- The balance includes investments in convertible securities
of two non-publicly traded companies, a business park joint venture, community
betterment projects, and retirement trusts. A recent sale of stock of one of the
two non-public companies indicates the fair value of the Company's investment in
that entity is $6,400,000. The fair value of the investments in the remaining
convertible securities, the joint venture and the community betterment projects
are stated at the original cost of $1,028,000, $500,000 and $350,000,
respectively, due to the impracticability of estimating the market value. The
fair value of the underlying instruments of the retirement trusts of $3,019,000
is estimated based on quoted market prices for the same or similar issues. The
investment in the trusts is offset by a corresponding liability for future
obligations in other non-current liabilities.

LONG-TERM DEBT -- Most of the Company's long-term debt is not publicly traded;
therefore, a market price does not exist for these instruments. The fair value
of long-term debt is estimated based upon market prices for comparable
securities with similar maturities.

<TABLE>
<CAPTION>


                                                         1999                                    1998
                                           ---------------------------------------------------------------------
                                           Carrying Amounts  Fair Values          Carrying Amounts   Fair Values
<S>                                          <C>             <C>                    <C>             <C>
     Cash and temporary investments          $   354,000     $   354,000            $   373,000     $   373,000
     Other investments                         6,741,000      11,297,000              4,922,000       5,215,000
     Long-term debt                           74,282,000      76,046,000             74,728,000      85,739,000

</TABLE>


The difference in carrying amounts and fair values of financial instruments is
not expected to result in a material impact on the Company's financial position
or results of operations. Under the ratemaking principles followed by the PSC,
any gain or loss on early refinancing of the Company's long-term debt would be
used to reduce or increase the Company's rates over a prescribed amortization
period.

6 EFFECTS OF REGULATION

The Company is subject to rate regulation by the PSC. Rates are established to
allow the Company an opportunity to recover its costs and earn a return on its
investment. The Company currently applies SFAS 71, "Accounting for the Effects
of Certain Types of Regulation," which recognizes the economic effects of rate
regulation. In the event the Company determines that it no longer meets the
criteria for following SFAS 71, the accounting impact would be a non-cash charge
to operations of an amount that could be material. Criteria that give rise to
the discontinuance of SFAS 71 include (1) increasing competition that restricts
the Company's ability to establish prices to recover specific costs, and (2) a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The continued applicability
of SFAS 71 is regularly reviewed based on the current regulatory environment.

In March 1997, the PSC opened a docket to investigate restructuring in the
electric utility industry. The Retail Electric Competition Task Force, comprised
of representatives from various groups, was charged with preparing comprehensive
reports to the PSC. The reports were prepared in 1998 based upon a thorough
investigation and study of retail wheeling of electricity and related issues.
Included were recommendations outlining how Missouri should implement retail
electric competition should enabling legislation be enacted.

At the present time, a general consensus exists that the legislature should
first deal with the tax issues associated with restructuring the industry and
then pass a deregulation bill. Since a provision in the Missouri constitution
requires voter approval of new taxes, the various tax issues cannot be addressed
in a deregulation law as has been done in many other states. Failure to make
changes in the way utilities are taxed could result in lower taxes for
competitors not currently regulated by the PSC. We expect that a proposal to
reform utility taxes will be submitted to voters as a constitutional amendment
in November 2000. If voters approve the proposal, a deregulation law could be
passed in the 2001 session. Based on current legislative activity, we believe
that retail competition might begin in Missouri sometime during 2004.


                                                                              23

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Based on the PSC docket and deregulation plans implemented or considered by
other states, management believes it is most likely that the generation portion
of the business could become unregulated and the transmission and distribution
functions will continue to be regulated.

Based on a current evaluation of the various factors and conditions that are
expected to impact future cost recovery, the Company believes that its
regulatory assets, including those related to generation, are probable of future
recovery and that the utilization of SFAS 71 continues to be appropriate.
Accordingly, the Company has recorded regulatory assets and liabilities on the
Consolidated Balance Sheets, consisting primarily of deferred taxes as noted in
Note(a) to Consolidated Statements of Taxes.

On December 1, 1998, the Company filed separate rate cases before the PSC asking
for price increases of approximately $6,100,000, $500,000, and $275,000 for
electric, natural gas, and industrial steam, respectively. An earlier electric
earnings complaint filed by the PSC staff, requesting a reduction of $6.4
million, was consolidated with the Company's electric case.

Stipulated agreements were reached between the Company and other parties to the
cases and were approved by the PSC. Under the agreements, the Company reduced
annual electric revenues by $2.5 million and annual steam revenues by $25,000
effective for service rendered after October 30, 1999. There were no changes in
natural gas prices. Included in the PSC Order were regulatory accounting
policies which were different from the Company's current accounting policies.
These differences primarily related to the recognition of pension expense, OPEB
expense, and deferred income tax expense. As a result, the recognition of these
expenses in November and December followed the accounting treatment mandated by
the PSC Order. The revenue reductions and accounting changes required by the
agreements had a negligible effect on 1999 results and are expected to reduce
net income approximately $300,000 annually.

7 COMMITMENTS AND CONTINGENCIES

LEASES -- The Company has a 50-year capital lease agreement with six other
regional utilities for a transmission line and related facilities. Electric
utility plant, as of December 31, 1999, includes $2,697,000 for the leased joint
facilities and other property acquired under capital leases. The Company is also
the lessor under 50-year direct financing lease agreements for terminal and
associated joint facilities. The future minimum lease payments and receivables
under these agreements are:

<TABLE>
<CAPTION>

                                                                          PAYMENTS               RECEIVABLES
                                                                        -----------            -------------
     <S>                                                                 <C>                    <C>
     2000                                                                $  426,000             $   123,000
     2001                                                                   267,000                 123,000
     2002                                                                   216,000                 123,000
     2003                                                                   216,000                 123,000
     2004                                                                   216,000                 123,000
     Later years                                                          5,102,000               2,427,000
                                                                         ----------             -----------
     Total minimum lease payments/receivables                             6,443,000               3,042,000
     Less - Amounts representing interest                                 3,746,000               2,021,000
                                                                         ----------             -----------
     Present value of obligations under capital leases/net receivables   $2,697,000             $ 1,021,000
                                                                         ----------             -----------
                                                                         ----------             -----------

</TABLE>


OTHER COMMITMENTS -- The Company's capital budget, excluding AFUDC and including
non-utility investments, for 2000 is approximately $10,944,000. The five-year
capital budget is estimated to be $62,094,000.

The Company has entered into long-term contracts to purchase generating
capacity, fossil fuels, and rail transportation. Minimum annual amounts to be
purchased under these contracts approximate $13,918,000, $13,470,000,
$11,424,000, $12,708,000, and $10,708,000 for each of the next five years,
respectively.

ENVIRONMENTAL CONTINGENCIES -- The Company is required to meet various
environmental regulations governing air and water standards. The Company expects
future capital expenditures of about $800,000 related to compliance with the
Clean Air Act.

The United States Environmental Protection Agency (EPA) has issued a nitrogen
oxide (NOx) State Implementation Plan (SIP) call under which Missouri,
twenty-one other states, and the District of Columbia were required to revise
their SIPs to establish more stringent emission standards for NOx. The Company
joined with five other western Missouri utilities, other states, and private
organizations in a lawsuit challenging the EPA's SIP call. In March 2000, the
D.C. Circuit Court decided for the EPA with regard to the issues involving other
states; however, the Court decided in favor of the western Missouri utilities
and vacated the NOx SIP call for Missouri.

The EPA can appeal or request a rehearing on the Missouri issues.

A regional NOx issue emerged in 1999 due to the inability of the St. Louis area
to comply with the NAAQS for ozone. To address this problem, the Missouri
Department of Natural Resources has issued a proposed NOx reduction regulation
for Missouri somewhat similar


                                                                              24


<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

in nature to the EPA's NOx SIP call. The reduction levels in the proposed
regulation are less stringent than the NOx SIP call and allow for smaller
reductions in the western part of the state than the eastern part of the state.
If approved, the regulation would require compliance by 2003. The full extent of
how we will be affcted and the related cost of implementation are not yet known.

TRANSMISSION REVENUE -- In April 1999, the FERC issued an order directing the
MidContinent Area Power Pool (MAPP), of which the Company is a member, to refund
payments for transmission charges assessed from March 1997 through March 1999.
The FERC disagrees with the method MAPP was using to assess transmission charges
for transactions with non-member entities. Fifteen MAPP transmission providers,
including the Company, filed a petition for rehearing on the FERC's order, which
was denied by the FERC. The Company, therefore, made the required payment and
expensed $597,000 in October 1999. The Company is participating in a joint
appeal of the FERC's order.

OTHER CONTINGENCIES -- Certain legal actions are pending which may impact the
Company. In management's opinion, the ultimate resolution of these matters is
not expected to materially affect the Company's financial position or operating
results.

8 SEGMENTS OF BUSINESS

The Company has two reportable segments: electric utility and manufacturing. The
Company is a public utility engaged primarily in the business of generating and
distributing electric energy in a 10-county area in northwest Missouri. The
Company's 63,000 regulated customers include residential, commercial, and
industrial classes. The Company's manufacturing segment represents a controlling
interest in a company which manufactures multiwall and small paper bags
primarily for food products, agricultural products, specialty chemicals, pet
foods and other consumer packaging. Other operations of the Company include the
limited sale of natural gas and industrial steam, as well as investment in
non-utility businesses.

The accounting policies of the segments are the same as those described in the
summary of significant accounting policies in Note 1. The Company evaluates
performance and allocates resources to its regulated business units based on
profit or loss from operations, not including interest charges or nonrecurring
gains and losses, and on the rate of return achieved. The performance of the
Company's manufacturing segment is evaluated based on net income after taxes and
minority interest.

The following table sets forth certain information regarding the Company's
segments of business:

<TABLE>
<CAPTION>


   (IN THOUSANDS)                                            ELECTRIC UTILITY  MANUFACTURING     ALL OTHER      TOTALS
                                                        ---------------------------------------------------------------
<S>                                                               <C>          <C>               <C>          <C>
  YEAR ENDED DECEMBER 31, 1999
   Revenues from external customers                               $  90,499    $  19,552         $  10,898    $ 120,949
   Depreciation                                                      11,432          618               561       12,611
   Income taxes                                                       3,625           --               (25)       3,600
   Segment profit (loss)                                             12,633         (180)              258       12,711
   Segment assets                                                   224,359       13,553            17,357      255,269
   Expenditures for segment assets, including AFUDC                  12,574          180               370       13,124
   Net regulatory assets                                              7,478           --               156        7,634
   Accumulated deferred income taxes and investment tax credits      33,477           --             2,413       35,890
   Other non-cash items--pension expense                             (2,637)          --              (387)      (3,024)

YEAR ENDED DECEMBER 31, 1998
   Revenues from external customers                               $  89,678    $  23,820         $  10,876    $ 124,374
   Depreciation                                                      10,813          995               538       12,346
   Income taxes                                                       5,307           --               (48)       5,259
   Segment profit (loss)                                             15,617          (24)              396       15,989
   Segment assets                                                   217,947       13,906            14,804      246,657
   Expenditures for segment assets, including AFUDC                  15,659          768               416       16,843
   Net regulatory assets                                              5,191           --               212        5,403
   Accumulated deferred income taxes and investment tax credits      33,252           --             2,259       35,511
   Other non-cash items--pension expense                             (1,941)          --              (287)      (2,228)

YEAR ENDED DECEMBER 31, 1997
   Revenues from external customers                               $  86,910    $  17,307         $  11,948    $ 116,165
   Depreciation                                                      10,409          526               505       11,440
   Income taxes                                                       5,881           --                75        5,956
   Segment profit (loss)                                             16,476         (168)              381       16,689
   Segment assets                                                   209,505       15,671            12,848      238,024
   Expenditures for segment assets, including AFUDC                  13,520          143               465       14,128
   Net regulatory assets                                              4,805           --               164        4,969
   Accumulated deferred income taxes and investment tax credits      31,745           --             1,986       33,731
   Other non-cash items--pension expense                             (1,716)          --              (245)      (1,961)


</TABLE>


                                                                              25

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table reconciles reportable segment profit, assets, depreciation,
and income taxes, disclosed above, to the Company's Consolidated Financial
Statements:

<TABLE>
<CAPTION>

   YEARS ENDED DECEMBER 31 (IN THOUSANDS)                     1999             1998            1997
----------------------------------------------------------------------------------------------------
<S>                                                        <C>              <C>             <C>
   Profit
      Reportable segment profit                            $ 12,453         $ 15,593        $ 16,308
      Other profit                                              258              396             381
      Interest charges (net)1                                (6,650)          (5,909)         (5,931)
      Other income                                              171              837             340
      Income taxes on other income                             (105)            (253)           (258)
                                                           --------         --------        --------
      Consolidated net income                              $  6,127         $ 10,664        $ 10,840
                                                           --------         --------        --------
                                                           --------         --------        --------
   Assets
      Reportable segment assets                            $237,912         $231,853        $225,176
      Other assets                                           17,357           14,804          12,848
      Temporary and other investments                         3,216            2,810           3,923
      Debt expense                                            1,238            1,324           1,437
      Other assets not allocated                              1,603              464             385
                                                           --------         --------        --------
      Consolidated assets                                  $261,326         $251,255        $243,769
                                                           --------         --------        --------
                                                           --------         --------        --------
   Depreciation
      Reportable segment depreciation                      $ 12,050         $ 11,808        $ 10,935
      Other depreciation                                        561              538             505
      Less--Manufacturing depreciation included in
       cost of goods sold                                      (470)            (811)           (395)
      Less--Electric depreciation included in other
       operations and maintenance                               (57)              --              --
                                                           --------         --------        --------
      Consolidated depreciation                            $ 12,084         $ 11,535        $ 11,045
                                                           --------         --------        --------
                                                           --------         --------        --------
   Income Taxes
      Reportable segment income taxes                      $  3,625         $  5,307        $  5,881
      Other income taxes                                        (25)             (48)             75
      Income taxes on other income                              105              253             258
                                                           --------         --------        --------
      Consolidated income taxes                            $  3,705         $  5,512        $  6,214
                                                           --------         --------        --------
                                                           --------         --------        --------

</TABLE>


1 Excludes manufacturing segment interest expense of $662,000, $878,000, and
549,000 for 1999, 1998, and 1997, respectively, as interest expense is included
in manufacturing net income which is the measure of profit or loss used to
evaluate the performance of that segment.

9 QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>


                                               First            Second            Third            Fourth
                                              Quarter           Quarter          Quarter           Quarter
------------------------------------------------------------------------------------------------------------
<S>                                        <C>               <C>              <C>               <C>
1999

Operating revenues                         $ 28,686,000      $ 28,306,000     $ 36,348,000      $ 27,609,000
Operating income                              2,588,000         1,796,000        9,998,000         2,176,000
Net income (loss)                               414,000          (182,000)       5,404,000           491,000
Weighted average common shares outstanding    8,158,109         8,187,817        8,241,328         8,259,740
Basic earnings per average common share            $.05             $(.02)            $.66              $.06
Diluted earnings per average common share           .05              (.02)             .65               .06

1998

Operating revenues                         $ 29,717,000      $ 30,056,000     $ 37,366,000      $ 27,235,000
Operating income                              4,999,000         4,842,000       10,122,000         2,224,000
Net income                                    2,401,000         1,990,000        5,214,000         1,059,000
Weighted average common shares outstanding    8,056,020         8,092,173        8,114,921         8,135,561
Basic and diluted earnings per average
     common share                                  $.30              $.25             $.64              $.13

</TABLE>


The quarterly data reflect seasonal variations common to the utility industry.
Quarterly net income was reduced by after tax merger-related expenses of
$994,000, $1,579,000, $0, and $144,000.


                                                                              26

<PAGE>


FINANCIAL RESPONSIBILITY / INDEPENDENT AUDIT

RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of St. Joseph Light & Power Company is responsible for the
preparation and presentation of the financial information in this Annual Report.
The preceding financial statements have been prepared in accordance with
generally accepted accounting principles consistently applied, and reflect
management's best estimates and informed judgments as required.

To fulfill these responsibilities, management has developed and maintains a
comprehensive system of internal operating, accounting, and financial controls.
These controls provide reasonable assurance that the Company's assets are
safeguarded, transactions are properly recorded, and resulting financial
statements are reliable. An internal audit function assists management in
monitoring the effectiveness of the controls.

The Report of Independent Public Accountants on the financial statements appears
on this page. The responsibility of the independent auditors is limited to the
audit of financial statements presented and the expression of an opinion as to
their fairness.

The Board of Directors maintains oversight of the Company's financial situation
through its monthly review of operations and financial condition and its
selection of the independent auditors. The Audit Committee, comprised of board
members who are not employees or officers of the Company, also meets
periodically with the independent auditors and the Company's internal audit
staff. The auditors have complete access to and meet with the Audit Committee,
without management representatives present, to review accounting, auditing, and
financial matters. Pertinent items discussed at the meetings are reviewed
with the full Board of Directors.


/s/Terry F. Steinbecker
Terry F. Steinbecker
President and Chief Executive Officer

/s/Larry J. Stoll
Larry J. Stoll
Vice President-Finance,Treasurer and Assistant Secretary

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of St. Joseph Light & Power Company:

We have audited the accompanying consolidated balance sheets and statements of
capitalization of St. Joseph Light & Power Company (a Missouri corporation) and
subsidiaries as of December 31, 1999 and 1998, and the related consolidated
statements of income, retained earnings, cash flows, and taxes for each of the
three years in the period ended December 31, 1999. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion of 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 financial position of St. Joseph Light & Power
Company and subsidiaries as of December 31, 1999 and 1998, and the results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.



ARTHUR ANDERSEN LLP
Kansas City, Missouri
January 21, 2000


                                                                              27

<PAGE>


DIRECTORS AND OFFICERS

BOARD OF DIRECTORS

-   JOHN P. BARCLAY, JR., 70
    Chairman, President and Chief Executive Officer - Wire Rope Corporation of
    America, Inc. (Manufacturer and distributor of wire rope and wire rope
    products)
    St. Joseph, Missouri - Director since 1974.

    DEBORAH A. BECK, 52
    Senior Vice President - Insurance Operations - Northwestern Mutual Life
    Insurance Company (Insurance company)
    Milwaukee, Wisconsin -  Director since 1997.

-   DANIEL A. BURKHARDT, 52
    Principal - The Jones Financial Companies (Investment banking and retail
    securities firm)
    St. Louis, Missouri - Director since 1988.

    JAMES P. CAROLUS, 49
    President - Hillyard Industries, Inc. (Manufacturer of maintenance cleaning
    products)
    St. Joseph, Missouri - Director since 1989.

-   WILLIAM J. GREMP, 57
    Investments  -  Merrill Lynch & Company
    Greenwich, Connecticut  -  Director since 1995.

    DAVID W. SHINNEMAN, 61
    President, - Shinneman Management Company (Operator of McDonald's
    restaurants)
    St. Joseph, Missouri - Director since 1994.

-   ROBERT L. SIMPSON, 66
    General Partner  -  St. Joseph Riverboat Partners
    (Riverboat casino)
    St. Joseph, Missouri  -  Director since 1983.

    GERALD R. SPRONG, 66
    President and Chief Executive Officer - The Morris Plan Company of St.
    Joseph (Financial management and lending)
    St. Joseph, Missouri

    Director, Chairman and Chief Executive Officer - First Savings Bank, F.S.B.
    (Banking)
    Manhattan, Kansas

    President and Chief Executive Officer - Noble Properties of Iowa, L.L.C.
    (Ownership and management of hotels)
    Des Moines, Iowa - Director since 1976.

    Terry F. Steinbecker, 54
    President and Chief Executive Officer  -  St. Joseph Light & Power Company
    St. Joseph, Missouri  -  Director since 1985.

-   Member of Audit Committee

    OFFICERS

    TERRY F. STEINBECKER, 54  -  President and Chief Executive Officer
    GARY L. MYERS, 46  -  Vice President, General Counsel and Secretary
    LARRY J. STOLL, 47  -  Vice President - Finance, Treasurer and Assistant
     Secretary
    JOHN A. STUART, 46  -  Vice President - Customer Services & Energy Delivery
    DWIGHT V. SVUBA, 57  -  Vice President - Energy Supply


                                                                              28

CORPORATE INFORMATION                               ANNUAL SHAREHOLDERS MEETING
Corporate Offices                       The annual meeting of shareholders will
520 Francis Street                       be at 9 a.m., Wednesday, May 17, 2000,
Post Office Box 998                       at the Albrecht-Kemper Museum of Art,
St. Joseph, Missouri            2818 Frederick Boulevard, St. Joseph, Missouri.
64502-0998

(816) 387-6434
fax (816) 387-6332                                                    Form 10-k
1-800-367-4562                A copy of the Annual Report to the Securities and
http://www.sjlp.com           Exchange Commission, Form 10-K, will be furnished
email: invrel@sjlp.com        without charge to any shareholder upon contacting:

INDEPENDENT PUBLIC ACCOUNTANTS                   St. Joseph Light &Power Company
Arthur Andersen LLP                                Investor Relations Department
2301 McGee, Suite 400                                         520 Francis Street
Kansas City, Missouri 64108                                  Post Office Box 998
                                                 St. Joseph, Missouri 64502-0998

STOCK LISTING AND PRINCIPAL MARKET            Access to the Form 10-K is also
New York Stock Exchange                       available via the internet through
Eleven Wall Street                            the EDGAR database on the SEC
New York, New York 10005                      website at www.sec.gov or on the
Symbol: SAJ                                   Company's website listed at the
                                              left.


COMMON STOCK TRANSFER AGENT AND REGISTRAR*    This report and financial
Harris Trust and Savings Bank                 statements contained herein are
311 West Monroe Street                        submitted for the general
Chicago, Illinois 60690                       information of the security
                                              holders of St. Joseph Light &
                                              Power Company, and are not in
                                              connection with, or to induce, any
                                              sale or offer to sell or to buy
                                              any securities of the Company, or
                                              in connection with preliminary
                                              negotiations for such sale or
                                              purchase.


* On Feb. 1, 2000, Harris Bank announced the sale of its shareholder services
business to Computershare Limited, an Australian company that operates in seven
countries. The transaction is subject to regulatory approval and was expected to
close 45 days from the Feb. 1 announcement.


COMMON STOCK PRICES

<TABLE>
<CAPTION>

                               High           Low
<S>                          <C>           <C>
1999     First quarter       $ 21.000      $ 15.500
         Second quarter        21.000        20.188
         Third quarter         21.188        20.500
         Fourth quarter        21.063        20.063


1998     First quarter       $ 18.625      $ 17.250
         Second quarter        19.000        18.000
         Third quarter         19.375        17.813
         Fourth quarter        19.125        17.563

DIVIDENDS PER COMMON SHARE

1999     First quarter         $ .25
         Second quarter          .25
         Third quarter           .25
         Fourth quarter          .25
                               -----
                               $1.00

1998     First quarter         $.245
         Second quarter         .245
         Third quarter          .245
         Fourth quarter         .245
                               -----
                               $.980

</TABLE>


                                                                              29

<PAGE>