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

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FORM 10-K

(Mark One)

|ý                                              |  | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934    
|---------------------------------------------- |  | ----------------------------------------------------------------------------------------
|For the fiscal year ended December 31, 2002
or
|o                                              |  | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from  to

Commission
file number: 1-03562

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AQUILA, INC.(Exact name of registrant as specified in its charter)

|Delaware(State or other jurisdiction of
incorporation or organization) |  | 44-0541877(I.R.S. Employer
Identification No.)
|---------------------------------------------------------------------- |  | ----------------------------------------------

20 West Ninth Street, Kansas City, Missouri 64105(Address of principal executive offices)

Registrant's telephone number, including area code (816) 421-6600

Securities registered pursuant to Section 12(b) of the Act:

|Title of each class                                                                                                                                    |  | Name of each exchange on which registered                              
|------------------------------------------------------------------------------------------------------------------------------------------------------ |  | -----------------------------------------------------------------------
|Common Stock, par value $1.00 per share
Convertible Subordinated Debentures,
65/8% due July 1, 2011
7.875% Quarterly Interest Bonds,
due March 1, 2032 |  | New York Stock Exchange
New York Stock Exchange
New York Stock Exchange

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

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

Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part 3 of this Form 10-K or any amendment to this
Form 10-K.    o

Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes
ý    No o

The
aggregate market value of the voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on June 30, 2002 as
reported on the New York Stock Exchange, was approximately $1,020,976,000. Shares of Common Stock held by each officer and director and by each person who owns 5% or more of the outstanding Common
Stock have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

|Title                                                |  | Outstanding (at March 14, 2003)
|---------------------------------------------------- |  | -------------------------------
|Common Stock, par value $1.00 per share              |  | 194,201,666                    
|Documents Incorporated by Reference:                 |  | Where Incorporated:            
|Proxy Statement for 2003
Annual Shareholders Meeting |  | Part 3                         

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INDEX

|                                                                      |         |     |                                                                                                | Page
|--------------------------------------------------------------------- | ------- | --- | ---------------------------------------------------------------------------------------------- | ----
|Part 1                                                                |         |     |                                                                                                |     
|                                                                      | Item 1  |     | Business                                                                                       |     
|                                                                      | Item 2  |     | Properties                                                                                     |     
|                                                                      | Item 3  |     | Legal Proceedings                                                                              |     
|                                                                      | Item 4  |     | Submission of Matters to a Vote of Security Holders                                            |     
|Part 2                                                                |         |     |                                                                                                |     
|                                                                      | Item 5  |     | Market for Registrant's Common Equity and Related Shareholder Matters                          |     
|                                                                      | Item 6  |     | Selected Financial Data                                                                        |     
|                                                                      | Item 7  |     | Management's Discussion and Analysis of Financial Condition and Results of Operations          |     
|                                                                      | Item 7a |     | Quantitative and Qualitative Disclosures About Market Risk                                     |     
|                                                                      | Item 8  |     | Financial Statements and Supplementary Data                                                    |     
|                                                                      | Item 9  |     | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure           |     
|Part 3                                                                |         |     |                                                                                                |     
|                                                                      | Item 10 |     | Directors and Executive Officers of the Company                                                |     
|                                                                      | Item 11 |     | Executive Compensation                                                                         |     
|                                                                      | Item 12 |     | Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters |     
|                                                                      | Item 13 |     | Certain Relationships and Related Transactions                                                 |     
|                                                                      | Item 14 |     | Controls and Procedures                                                                        |     
|Part 4                                                                |         |     |                                                                                                |     
|                                                                      | Item 15 |     | Exhibits, Reports on Form 8-K, and Financial Statement Schedules                               |     
|Index to Exhibits                                                     |         | 152
|Signatures                                                            |         | 154
|Certifications Pursuant to Item 302 of the Sarbanes-Oxley Act of 2002 |         | 155

2

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Part 1

Item 1. Business

History and Organization

Aquila, Inc. (the Company, which may be referred to as "we", "us" or "our") is a multinational energy provider headquartered in Kansas City, Missouri. We began as
Missouri Public Service Company in 1917 and reincorporated in Delaware as UtiliCorp United Inc. in 1985. In March 2002, we changed our name to Aquila, Inc. We operate regulated
and non-regulated businesses in four countries. As of December 31, 2002, we had 4,710 employees, with 3,496 of them in the United States and the remaining 1,214 in Canada. Our
business is organized into two groups: Global Networks Group, which consists of Domestic Networks and International Networks, and Merchant Services, which consists of Capacity Services and Wholesale
Services:



The
reports we file with the Securities and Exchange Commission are made available free of charge at our websitewww.aquila.comas soon as
reasonably practicable after these reports are filed.

Strategic and Financial Repositioning

There have been significant changes in the energy industry during the two years ending December 31, 2002. These changes were primarily a result of lower prices in the
power markets as new generation capacity continues to come online, the stabilization of commodity prices in California, the bankruptcy and near bankruptcy of several energy merchants, the tightening
of the credit markets (for energy merchant companies in particular), and the lack of liquidity in forward energy markets as companies continue to exit and/or scale back their energy trading
activities. In response to this escalating set of circumstances, we exited from our wholesale energy trading business and divested ourselves from the majority of our related activities and assets
during 2002. Separately, we restructured our Domestic Networks Group to more closely align it with its regulatory service areas. Staff reductions due to the restructuring, including employees
transferred with the sale of various businesses, consisted of approximately 1,205 Merchant Services employees, 75 Corporate employees and 550 Domestic Networks employees. With our exit from wholesale
trading, we began to transition to a business comprised primarily of

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our regulated utility business and our non-regulated power plants. As part of this transition, we took the following actions:



Proceeds
from these asset sales were used to pay down debt, fund restructuring charges and support our continuing operations. As part of our ongoing transition plan, our Board of
Directors has suspended the payment of dividends on our common stock indefinitely. We now plan to operate primarily as a regulated utility with various investments in non-regulated power
generation facilities.

We
have experienced significant net losses and negative cash flows from operations in 2002. We have also experienced a number of credit downgrades and are currently rated as
non-investment grade. This has caused us to post a substantial amount of cash or letters of credit as collateral on a number of our contractual agreements. As shown in our Consolidated Financial
Statements, we had a retained deficit of $1.7 billion as of December 31, 2002. In addition, as discussed in Notes 12 and 13 to the Consolidated Financial Statements, as a result of these
losses, we were in violation of an interest coverage ratio covenant and a covenant that requires us to maintain a maximum debt to capitalization ratio.

On
April 11, 2003, we closed on a three-year senior secured financing of $430.0 million and a 364-day senior secured financing of $100.0 million. The 364-day
financing also includes an option under which we can during a 30-day period following closing, at our discretion, increase the size of the financing by up to $100.0 million. Proceeds from the
financings will be used to retire debt and support existing and future letters of credit. The secured financings will eliminate the covenant violations stated above. With the above financings, we
believe we will have sufficient liquidity to cover our operational needs through June 2004. Our next significant need for outside capital relates to our need to retire senior notes maturing in
2004. We anticipate retiring these notes with proceeds from additional asset sales. In the event we are not successful in closing the asset sales, we would need to obtain a bridge loan to meet these
obligations. Although no assurance can be given on the above actions, we expect to be successful in their execution.

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Business Group Summary

Segment information for the three years ended December 31, 2002 is included in Note 22 to the Consolidated Financial Statements.

I. Global Networks Group

Our Global Networks Group is divided into two business segments: Domestic Networks and International Networks.

Domestic Networks

Our Domestic Networks businesses are engaged in the generation, transmission, distribution and sale of electricity to approximately 438,000 customers in Missouri, Kansas, and
Colorado. Our electric generation facilities supply electricity to our own distribution systems. We also sell excess power to other utilities and marketing companies. We also distribute natural gas to
approximately 891,000 customers in Missouri, Kansas, Colorado, Nebraska, Iowa, Minnesota, and Michigan. Domestic Networks also includes (a) our equity interest in Quanta Services, Inc.,
and (b) Everest Connections, our 96% owned domestic communications business which provides local and long-distance telephone, cable television, high-speed internet and
data services to areas of greater Kansas City.

Divestitures

See Notes 5 and 20 to the Consolidated Financial Statements for a more detailed discussion of our divestitures described below.

Pipeline Operations

In January 2002, we completed the sale of an intrastate pipeline system in Missouri.

Quanta Services

During 2002, we sold approximately 17.6 million shares of Quanta Services, reducing our ownership percentage from 38% to approximately 10%. We sold our remaining
11.6 million shares during the first quarter of 2003.

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Properties

As of December 31, 2002, our domestic electric generation plants included the following:

|Unit      |                      | Location |               | Year Installed |                  | Unit Capability
(MW) |     | Fuel  |          | 2002 Net
Generation
(MW Hours) |          
|--------- | -------------------- | -------- | ------------- | -------------- | ---------------- | -------------------- | --- | ----- | -------- | ------------------------------ | ---------
|          |                     
|Missouri: |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | Sibley #1-3          |          | Sibley        |                | 1960, 1962, 1969 |                      | 512 |       | Coal     |                                | 3,061,409
|          | Ralph Green #3       |          | Pleasant Hill |                | 1981             |                      | 71  |       | Gas      |                                | 14,673   
|          | Nevada               |          | Nevada        |                | 1974             |                      | 20  |       | Oil      |                                | (157     
|          | Greenwood #1-4       |          | Greenwood     |                | 1975-1979        |                      | 251 |       | Gas/Oil  |                                | 105,988  
|          | KCI #1-2             |          | Kansas City   |                | 1970             |                      | 31  |       | Gas      |                                | 554      
|          | Lake Road #1, 3      |          | St. Joseph    |                | 1951, 1962       |                      | 30  |       | Gas/Oil  |                                | 45,423   
|          | Lake Road #2, 4      |          | St. Joseph    |                | 1957, 1967       |                      | 122 |       | Coal/Gas |                                | 637,963  
|          | Lake Road #5         |          | St. Joseph    |                | 1974             |                      | 63  |       | Gas/Oil  |                                | (558     
|          | Lake Road #6-7       |          | St. Joseph    |                | 1989, 1990       |                      | 42  |       | Oil      |                                | 118      
|          | Iatan                |          | Iatan         |                | 1980             |                      | 121 |       | Coal     |                                | 729,187  
|Kansas:   |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | Judson Large #4      |          | Dodge City    |                | 1969             |                      | 145 |       | Gas      |                                | 304,339  
|          | Arthur Mullergren #3 |          | Great Bend    |                | 1963             |                      | 96  |       | Gas      |                                | 98,816   
|          | Cimarron River #1-2  |          | Liberal       |                | 1963, 1967       |                      | 72  |       | Gas      |                                | 109,059  
|          | Clifton #1-2         |          | Clifton       |                | 1974             |                      | 70  |       | Gas/Oil  |                                | 18,721   
|          | Jeffrey #1-3         |          | St. Mary's    |                | 1978, 1980, 1983 |                      | 344 |       | Coal     |                                | 2,499,635
|Colorado: |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | W.N. Clark #1-2      |          | Canon City    |                | 1955, 1959       |                      | 43  |       | Coal     |                                | 262,531  
|          | Pueblo #6            |          | Pueblo        |                | 1949             |                      | 20  |       | Gas      |                                | 43,575   
|          | Pueblo #5            |          | Pueblo        |                | 1941, 2001       |                      | 9   |       | Gas      |                                | 19,305   
|          | AIP Diesel           |          | Pueblo        |                | 2001             |                      | 10  |       | Oil      |                                | 364      
|          | Diesel #1-5          |          | Pueblo        |                | 1964             |                      | 10  |       | Oil      |                                | 1,801    
|          | Diesel #1-5          |          | Rocky Ford    |                | 1964             |                      | 10  |       | Oil      |                                | 837      
|          |                     
|          |                      | Total    |               |                |                  |                      |     | 2,092 |          |                                |          
|          |                     

The
following table shows the overall fuel mix and generation capability for the past three years:

|Fuel SourceIn Megawatts (MW) |                             | 2002  |       | 2001  |       | 2000 
|----------------------------- | --------------------------- | ----- | ----- | ----- | ----- | -----
|                             
|Coal                          |                             | 1,137 |       | 1,184 |       | 1,174
|Gas and oil                   |                             | 955   |       | 931   |       | 912  
|                             
|                              | Total generation capability |       | 2,092 |       | 2,115 |      
|                             

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At
December 31, 2002, we had electric transmission and distribution lines as follows:

|Description        |  | Length(Miles)
|------------------ |  | -------------
|                  
|Transmission lines |  | 4,665        
|Distribution lines |  | 15,448       
|                  
|Total              |  | 20,113       
|                  

At
December 31, 2002, our gas utility operations had 1,518 miles of gas gathering and transmission pipelines and 18,867 miles of distribution mains and service lines located
throughout our service territories.

The
following table summarizes sales, volumes and customers for our domestic electric network business:

|                                                        |             | 2002 |         | 2001    |   | 2000   
|------------------------------------------------------- | ----------- | ---- | ------- | ------- | - | -------
|                                                       
|Sales (in millions)                                     |             |      |         |         |   |        
|                                                        | Residential |      | $       | 283.2   |   | $      
|                                                        | Commercial  |      |         | 190.2   |   |        
|                                                        | Industrial  |      |         | 100.5   |   |        
|                                                        | Other       |      |         | 100.7   |   |        
|                                                       
|Total                                                   |             | $    | 674.6   |         | $ | 675.7  
|                                                       
|Volumes [Gigawatt Hours (one billion watt hours) (GWh)] |             |      |         |         |   |        
|                                                        | Residential |      |         | 4,075   |   |        
|                                                        | Commercial  |      |         | 3,343   |   |        
|                                                        | Industrial  |      |         | 2,459   |   |        
|                                                        | Other       |      |         | 2,496   |   |        
|                                                       
|Total                                                   |             |      | 12,373  |         |   | 12,286 
|                                                       
|Customers at Year End                                   |             |      |         |         |   |        
|                                                        | Residential |      |         | 374,697 |   |        
|                                                        | Commercial  |      |         | 59,087  |   |        
|                                                        | Industrial  |      |         | 467     |   |        
|                                                        | Other       |      |         | 3,714   |   |        
|                                                       
|Total                                                   |             |      | 437,965 |         |   | 430,926
|                                                       

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The
following table summarizes sales, volumes and customers for our domestic gas network business:

|                                    |                | 2002 |         | 2001    |   | 2000   
|----------------------------------- | -------------- | ---- | ------- | ------- | - | -------
|                                   
|Sales (in millions)                 |                |      |         |         |   |        
|                                    | Residential    |      | $       | 487.4   |   | $      
|                                    | Commercial     |      |         | 195.2   |   |        
|                                    | Industrial     |      |         | 34.8    |   |        
|                                    | Other          |      |         | 44.8    |   |        
|                                   
|Total                               |                | $    | 762.2   |         | $ | 964.3  
|                                   
|Volumes [Thousand Cubic Feet (Mcf)] |                |      |         |         |   |        
|                                    | Residential    |      |         | 72,454  |   |        
|                                    | Commercial     |      |         | 33,322  |   |        
|                                    | Industrial     |      |         | 7,974   |   |        
|                                    | Transportation |      |         | 120,974 |   |        
|                                    | Other          |      |         | 403     |   |        
|                                   
|Total                               |                |      | 235,127 |         |   | 216,559
|                                   
|Customers at Year End               |                |      |         |         |   |        
|                                    | Residential    |      |         | 796,207 |   |        
|                                    | Commercial     |      |         | 81,180  |   |        
|                                    | Industrial     |      |         | 2,300   |   |        
|                                    | Other          |      |         | 10,840  |   |        
|                                   
|Total                               |                |      | 890,527 |         |   | 874,038
|                                   

We
also had non-regulated commercial and industrial gas, appliance services and other sales (in millions) of $378.9, $570.0 and $514.0 in the years ended December 31,
2002, 2001 and 2000, respectively.

Seasonal Variations of Business

Our domestic electric and gas utility businesses are weather-sensitive. We have both summer- and winter-peaking network assets to reduce dependence on a single peak season. The
table below shows peak seasons for our Domestic Networks businesses.

Operations

PeakGas network operations

November through MarchElectric network operations

July and August


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Competition

We currently have limited competition for the retail distribution of electricity and natural gas in our service areas. While various restructuring and competitive initiatives
have been discussed in the states in which our utilities operate, only Michigan has adopted rules for retail competition for residential customers. Residential retail gas customers in Michigan were
able to choose their service provider beginning in June 2002, however, no competitors have emerged. As a result of several factors including the energy crisis in California, many states have
either discontinued or delayed implementation of retail deregulation initiatives. However, we do face competition from independent marketers for the sale of natural gas to our industrial and
commercial customers.

Regulation

Our domestic utility operations are subject to the jurisdiction of the public service commissions in the states in which they operate with respect to services and facilities,
rates and charges, accounting, valuation of property, depreciation and various other matters. Certain commissions have jurisdiction over the creation of liens on property located in its state to
secure bonds or other securities. Under the Federal Power Act (FPA), our wholesale transmission and sale of electric energy in interstate commerce and our generation facilities are subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC). FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale, the issuance of
stock, long and short-term debt, the sale, lease or other disposition of such facilities, and accounting matters. The FPA and activities of the FERC are described more fully under the
regulation discussion of our Merchant Services group.

The
following summarizes our recent rate case activity:

|(In millions) |  | Type of Service |  | Date Requested |  | Amount Requested |      | Amount Approved
|------------- |  | --------------- |  | -------------- |  | ---------------- | ---- | ---------------
|             
|              |  |                 |  |                |  |                  |      |                
|Minnesota     |  | Gas             |  | 8/2000         |  | $                | 9.8  |                
|Missouri      |  | Electric        |  | 6/2001         |  |                  | 49.4 |                
|Iowa          |  | Gas             |  | 6/2002         |  |                  | 9.3  |                
|Michigan      |  | Gas             |  | 8/2002         |  |                  | 14.3 |                
|Colorado      |  | Electric        |  | 10/2002        |  |                  | 23.4 |                

We
filed a Minnesota gas rate case in August 2000 for an increase of $9.8 million. The case is pending before the Minnesota Utilities Commission with an interim rate
increase of approximately $5.2 million granted in October 2000. We expect a final settlement to be approved by the Commission in early summer 2003.

In
June 2001, we filed for a $49.4 million increase in our Missouri electric rates. Approximately $39.0 million of the request related to anticipated increased fuel
and purchased power costs that did not materialize. In February 2002, we reached a negotiated settlement with the Commission staff and all intervenors that resulted in a $4.3 million
annual rate reduction. The rate reduction
was driven primarily by a $16.0 million reduction in depreciation which reduced our cash flow but had little impact on earnings.

In
June 2002, we filed for a $9.3 million general rate increase in Iowa. We received approval to place an interim increase of $5.6 million into effect, subject to
refund. In February 2003, we reached a settlement with the Commission for an increase of $4.3 million.

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In
August 2002, we filed for a $14.3 million general rate increase in Michigan. We received approval to place an interim increase of $8.2 million into effect as of
December 2002. We reached a settlement with the Commission staff and other intervening parties for an increase of $9.1 million. This settlement was approved by the Commission in
March 2003 and the new rates have gone into effect. This increase was partially offset within a separate depreciation case docket whereby our annual rates were reduced by $.7 million.
This decrease relates to our depreciation rates, which reduced cash flow but had little impact on earnings.

In
October 2002, we filed for a $23.4 million increase in our Colorado electric rates. A hearing will be held in April 2003 and new rates are expected to become
effective in June.

Our
domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute gas in seven states. All of our gas distribution utilities have
Purchased Gas Cost Adjustment (PGA) provisions that allow them to pass the cost of the commodity to the customer. To the extent that gas prices are higher or lower than amounts in our current billing
rates, adjustments are made on a periodic basis to "true-up" billed amounts to actual cost incurred.

In
our regulated electric business, we generate approximately 56% of the power that we sell and purchase the remaining 44% through long-term contracts or in the open market.
The regulatory provisions for recovering power costs vary by state. In Kansas, we have an Energy Cost Adjustment (ECA) that serves a similar purpose as the PGAs in place for the gas utility. To the
extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. For Colorado, we have an Incentive Clause
Adjustment (ICA) that provides for an equal sharing of the variability of energy costs between us and the customer. In Missouri, we do not have the ability to adjust the rates we charge for electric
service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our
electric earnings can fluctuate more in Missouri than in our other electric rate jurisdictions. In January 2003, legislation to provide a fuel adjustment clause was introduced in both the
Missouri House and Senate. This legislation has now passed both the House and Senate Committees and has been submitted to the respective legislative chambers for
passage. If passed and signed by the Governor, we will be able to file periodic fuel and purchase power adjustments.

Environmental Matters

General.We are subject to a number of federal, state and local requirements relating to:



These
requirements relate to a broad range of our activities, including:



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Water Issues.The Federal Clean Water Act controls effluent and intake requirements and generally prohibits the discharge of
any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency
or the Environmental Protection Agency (EPA). All of our facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are lawfully
operating under the prior permit.

In
April 2002, the EPA proposed new rules for cooling water intake structures. The final action, expected by August 2003, may require environmental impact studies as a
condition of permit renewals. At this time it is not known what impact, if any, this may have on operations.

In
July 2000, the EPA issued final rules for the implementation of the Total Maximum Daily Load (TMDL) program of the Clean Water Act. While the EPA issued a proposed rule to
withdraw the TMDL rules, their goal was to establish over the next 15 years, the maximum amounts of various pollutants that can be discharged into waterways while keeping those waterways in
compliance with water quality standards. The establishment of TMDL values may eventually result in more stringent discharge limits in each facility's wastewater discharge permit. We will not know the
future impact of the rule until the change is finalized.

Air Emissions.Our facilities are subject to the Federal Clean Air Act and many state laws and regulations relating to air
pollution. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxides (NOx) and particulate
matter. Our facilities generally emit these pollutants at levels within regulatory requirements. Fossil-fuel power generating facilities typically are major sources of air pollutants and
are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies. The Bush administration has introduced a Clear Skies Initiative that would require
further reductions in sulfur dioxide, nitrogen oxides and mercury emissions from power plants. Until the legislation is developed and passed, we cannot determine the impact this action will have on
our power plants. In 2003, several of our power plants will come under a NOx budget requirement. However, this will not significantly impact the business.

Carbon Dioxide.In November 1998, the United States became a signatory to the Kyoto Protocol to the United Nations
Framework Convention on Climate Change. The Kyoto Protocol calls for developed nations to reduce their emissions of greenhouse gases, which are believed to contribute to global climate change. Carbon
dioxide, a major byproduct of the combustion of fossil fuel, is considered to be a greenhouse gas. The Kyoto Protocol, however, will not become law in the United States until the U.S. Senate ratifies
it. Aside from the Kyoto Protocol, the current administration has indicated it will not pursue limitations on carbon dioxide emissions. Nevertheless, bills continue to be introduced in Congress that
include carbon dioxide emission limitations. Similarly, a number of states, primarily in the Northeast, are poised to include carbon dioxide limitations in state law. At this time there is no
enforceable standard for carbon dioxide emissions, and it is unclear what effect, if any, current federal and state efforts to impose such a standard will have on our facilities.

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Mercury.In December 2000, the EPA announced that it would regulate mercury emissions from coal- and
oil-fired power plants. The EPA is expected to propose regulations by December 2003 and issue final regulations by December 2004. The impact of this action on our power
plants cannot be determined until final regulations are issued.

Past Operations.Some federal and state laws authorize the EPA and other agencies to issue orders and compel responsible
parties to clean up sites that are determined to present actual or potential threat to human health or the environment. We are named as a potentially responsible party at two disposal sites for
Polychlorinated Biphenyls (PCBs). In addition, we have retained some environmental liability for several operations and investments we no longer own. We also own or have acquired liabilities from
companies that once owned or operated 29 former manufactured gas plant sites. We estimate our ongoing program to remediate these sites will cost $8.7 million.

In
EPA Region VII, we and several other gas utilities were requested to provide information on past use of mercury regulators. We responded to the EPA's request and do not expect this
inquiry to result in a material cost to us.

International Networks

The following discussion describes our International Networks businesses.

Australia

We have a 33.8% ownership interest in United Energy Limited (UEL), an electricity distribution utility serving 578,000 customers in Melbourne, Victoria. Under an operating
services agreement with UEL, we manage the utility for a fee. UEL distributes and sells electricity, with the majority of its sales originating from the regulated distribution network business. We
also have a 25.5% equity interest in Multinet Gas, a gas distribution business in Melbourne that serves approximately 630,000 accounts. In addition, we own a 50% interest in WA Gas Holdings
Pty Ltd (WA Gas), which in turn owns 45% of AlintaGas Limited, the principal gas distribution and retail business in Western Australia. UEL owns the other 50% interest in WA Gas. AlintaGas
serves approximately 463,000 customers. WA Gas has an operating services agreement with AlintaGas and receives a fee for management services provided under the agreement.

We
are exploring the sale of our interest in the above properties and anticipate a sale being completed in 2003, however, there can be no assurance that this will occur.

New Zealand

In October 2002, through a public tender offer in New Zealand, VECTOR Limited acquired all of the outstanding shares of UnitedNetworks Limited (UNL), in which we had a
70.2% indirect interest. This tender resulted in an after tax gain of $28.0 million. See Note 10 to the Consolidated Financial Statements for a more detailed discussion of this
divestiture.

Canada

We own Aquila Networks Canada (British Columbia) Ltd. (ANCBC), a hydroelectric utility in British Columbia, Canada. ANCBC has four hydroelectric generation facilities
with a capacity of 212 megawatts and approximately 4,243 miles of distribution and transmission lines that serve approximately 93,000 customers in south central British Columbia. ANCBC generates about
half

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of its power needs and acquires the rest through power purchase contracts. We also own Aquila Networks Canada (Alberta) Ltd. (ANCA). ANCA serves approximately 390,000 electric customers
through 58,894 miles of low-voltage distribution lines representing 50% of Alberta's distribution network. As part of our restructuring initiatives, we plan to explore the possible sale of
our Canadian operations.

As
of December 31, 2002, our hydroelectric generation plants in British Columbia included the following:

|Unit  |  | Location         |  | Year Installed |  | Unit Capability
(MW) |  | 2002 Net
Generation
(MW Hours)(a)
|----- |  | ---------------- |  | -------------- |  | -------------------- |  | ---------------------------------
|     
|      |  |                  |  |                |  |                      |  |                                  
|No. 1 |  | Lower Bonnington |  | 1924           |  | 44.4                 |  | 239,857                          
|No. 2 |  | Upper Bonnington |  | 1907           |  | 60.0                 |  | 214,662                          
|No. 3 |  | South Slocan     |  | 1928           |  | 56.4                 |  | 252,522                          
|No. 4 |  | Corra Linn       |  | 1932           |  | 51.3                 |  | 201,848                          
|     
|Total |  | 212.1            |  | 908,889       
|     



The following table summarizes sales, volumes and customers for our Canadian electric network transmission and distribution businesses:

|                      |  | 2002 |         | 2001(a) |   | 2000(b)
|--------------------- |  | ---- | ------- | ------- | - | -------
|                     
|                      |  |      |         |         |   |        
|Sales (in millions)   |  | $    | 258.7   |         | $ | 241.4  
|Volumes (GWh)         |  |      | 16,003  |         |   | 15,373 
|Customers at Year End |  |      | 482,553 |         |   | 468,515
|                     



United Kingdom

In May 2002, we purchased from FirstEnergy Corporation a 79.9% equity interest in Avon Energy Partners Holding Company, the holding company for Midlands Electricity, a
United Kingdom electric distribution network. FirstEnergy retained the remaining 20.1% of Avon. Although we have since written off substantially all of our investment, at the time of the

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acquisition, the gross purchase price of the acquisition was valued at approximately $262 million and was comprised of the following:

|In millions                                                                                                |                               |  
|---------------------------------------------------------------------------------------------------------- | ----------------------------- | -
|                                                                                                          
|                                                                                                           |                               |  
|Initial payment                                                                                            |                               | $
|Transaction costs                                                                                          |                               |  
|Present value of promissory note to be paid in six annual payments of $19
million beginning on May 8, 2003 |                               |  
|                                                                                                          
|                                                                                                           | Total value of purchase price |  
|                                                                                                          

Midlands
is the fourth-largest regional electricity company in the United Kingdom, serving approximately 2.4 million network customers through a 38,000-mile
distribution network. Midlands also owns a combined 884 megawatts of net generation capacity in the United Kingdom, Turkey and Pakistan.

In
connection with the acquisition, FirstEnergy retained substantive participating and protective rights as the minority partner. We and FirstEnergy each have 50% voting power and an
equal number of representatives on the Avon board of directors. Although we have the majority economic interest, FirstEnergy's participation in day-to-day business decisions is
significant, including approval of executive compensation, additional capital contributions, budgets, and the dissolution of the company.

Recent
downgrades in credit ratings assigned to the public debt in the Midlands ownership chain have called into question the ability of Midlands to pay us management fees and dividends.
Additionally, the local regulatory body, the Office of Gas and Electricity Markets (Ofgem), now requires pre-approval of cash payments to the owners in the form of management fees or
dividends. Accordingly, in 2003 and beyond, we intend to record equity earnings and management fees only to the extent of cash received.

In
August 2002, Aquila and FirstEnergy initiated a process for the sale of Midlands with final binding bids due in December 2002. We received offers in early December and
are currently in negotiations with the prospective buyer.

Seasonal Variations of Business

Our International Networks businesses are weather-sensitive. We have both summer- and winter-peaking assets. The table below shows the peak seasons for these businesses.

Location

PeakCanadaElectric

November through MarchAustraliaElectric

December through MarchAustraliaGas

June through SeptemberUnited KingdomElectric

No peak season


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Regulation

Our investments in electric and gas distribution businesses in foreign countries are subject to regulation by government-appointed agencies. In general, formal approvals are
required to amend customer rate tariffs, issue long-term debt, undertake major capital construction or asset dispositions, establish property valuations, or change accounting policies.

Electric
distribution businesses in British Columbia and Alberta, Canada, are regulated by the British Columbia Utilities Commission (BCUC) and by the Alberta Energy Utilities Board
(AEUB), respectively. Customer rates are generally set for one- or two-year periods based on a forecasted cost of service. The BCUC has approved the use of an incentive-based
ratemaking mechanism for the past several years. In British Columbia, only wholesale customers have the right of open access to transmission and alternate suppliers. Since January 2001, all
customers in Alberta have access to alternate suppliers. We sold our Alberta retail supply business to an unaffiliated company in December 2000.

The
electric and gas distribution businesses in Victoria, Australia, are regulated by that state's Essential Services Commission. Customer rates for use of the distribution systems are
reset at five year intervals following an examination of the companies' historical and projected costs, return on invested capital, and other aspects of customer service. Those rates are adjusted
annually after each reset interval, primarily by the rate of inflation minus a predetermined productivity factor. An efficiency carry-over mechanism provides for a five-year
rolling adjustment for actual changes in operating and maintenance cost efficiencies. Gas rates were reset in January 2003 with a reduction of 2%. The next reset for electric rates will occur
in January 2006. The final stage of full retail competition for electric customers was implemented in January 2002, and for gas customers in October 2002.

The
gas distribution business in Western Australia is regulated by the Office of Gas Access Regulation. Refinement of the regulatory regime is in progress, following the privatization of
the formerly government-owned gas utility in November 2000. The regulatory process for review of customer rates will likely reflect a number of the features of the Victoria model. The
proportion of gas volumes used by industrial and large commercial customers compared to residential customers is very high. Because the company's franchise is not exclusive, other companies can
construct pipelines that by-pass the incumbent network. The implementation of full retail gas competition is expected during 2003.

Electric
distribution businesses in the United Kingdom are regulated by Ofgem. Full retail competition is in effect in the U.K. However, we do not participate in the retail supply
business. Customer rates for use of the distribution systems are reset at five year intervals following an examination of the companies' historical costs, industry benchmark costs, return on invested
capital, and customer service levels. Those rates are adjusted annually after each reset interval, primarily by the rate of inflation minus a predetermined productivity factor. The next reset for our
electricity rates will be in April 2005.

The
following highlights our recent rate case activity:

|(In millions)            |  | Type of
Service |  | Date
Requested |  | Amount Requested |      | Amount Approved |  
|------------------------ |  | --------------- |  | -------------- |  | ---------------- | ---- | --------------- | -
|                         | 
|                         |  |                 |  |                |  |                  |      |                 |  
|Alberta, Canada          |  | Electric        |  | 12/2001        |  | $                | 12.7 |                 | $
|British Columbia, Canada |  | Electric        |  | 11/2002        |  |                  | 4.9  |                 |  

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In
December 2001, we filed for an annual rate increase in Alberta of about $30 million along with an application for a performance-based rate-setting mechanism.
We subsequently modified that request and sought a $12.7 million increase for 2002 and a $6.0 million increase for 2003. In July 2002, an interim rate increase of approximately
$9.6 million was approved. Hearings were held in September and October 2002 and a final order was issued in February 2003, resulting in a decrease in rates of $21.0 million
for 2002, and no increase in rates in 2003 (2002 rates carried forward to 2003). Almost all of the reduction in rates related to depreciation on distribution assets (average asset lives were extended)
and the related income tax effect. The decision did not adjust the allowed rate of return earned by the company and therefore, net income is not expected to be materially impacted by this decision.
However, the decision is estimated to reduce annual cash flow from operations by approximately $17.0 million for 2004 and beyond. With regard to 2003, cash flow from operations will be reduced
by approximately $33.0 million, which includes the effect of both the 2002 and 2003 reduction.

In
November 2002, we filed a request for a $4.9 million interim rate increase effective in January 2003 in British Columbia. Following a review process, the BCUC
issued a final order in February 2003 approving a $4.2 million rate increase.

Environmental Matters

Canada.Our Canadian operations are governed by environmental laws and regulations similar to those in the United States. In addition, the
operation and maintenance of our hydroelectric generation facilities is governed by the Canadian Fisheries Act and provincial water permits and licenses. The Department of Fisheries and Oceans is
moving towards stricter enforcement of the Fisheries Act, which might lead to higher compliance costs in the future.

II.  Merchant Services

Merchant
Services businesses operate as two business segments: Capacity Services and Wholesale Services. These businesses are operated through our wholly-owned subsidiary, Aquila Merchant
Services, Inc. (Aquila Merchant).

Exchange Offer

In January 2002, we completed an exchange offer and merger in which we acquired all the outstanding publicly held shares of Aquila Merchant in exchange for shares of
Aquila common stock. The public shareholders of Aquila Merchant received .6896 shares of Aquila common stock in a tax-free exchange for each outstanding share of Aquila Merchant
Class A common stock. Aquila Merchant shareholders holding approximately 1.8 million shares of Aquila Merchant Class A shares exercised dissenters' rights with respect to the
merger.

Capacity Services

Our Capacity Services business owns, controls and operates energy-related assets. These assets historically complemented our Wholesale Services business by providing power,
natural gas and coal supplies and an enhanced ability to structure innovative new products and services for clients. Following the asset sales discussed below, our remaining Capacity Services assets
are comprised of non-regulated power generation assets.

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Acquisitions and Divestitures

See Notes 5, 6 and 13 to the Consolidated Financial Statements for a more detailed discussion of the following acquisitions and divestitures.

Power Plant Construction

Piatt County Power Plant.In February 2002, we agreed to lease from a special purpose entity (SPE), a 510-megawatt power
plant being constructed in Piatt County, Illinois. We expect construction to be completed in June 2003. In the fourth quarter of 2002, we repaid $30.0 million of debt related to this
project. Because of the debt repayment and the redemption of a portion of the SPE's equity, we consolidated the assets and related debt of the SPE onto our balance sheet, as it no longer qualified for
off-balance sheet treatment. Concurrent with our new financings described in Notes 12 and 13 to the Consolidated Financial Statements, this debt was repaid in full during the second
quarter of 2003.

Clay County Power Plant.In November 2000, we agreed to lease from an SPE a 340-megawatt power plant being constructed
in Clay County, Illinois. The plant became operational in November 2002. In the fourth quarter of 2002, we repaid $34.5 million of debt related to this project. Because of the debt
repayment and the redemption of a portion of the SPE's equity, we consolidated the assets and related debt of the SPE onto our balance sheet, as it no longer qualified for off-balance
sheet treatment. Concurrent with our new financings described in Notes 12 and 13 to the Consolidated Financial Statements, this debt was repaid in full during the second quarter of 2003.

Coahoma Power Plant.In September 2002, construction was completed on a 340-megawatt power plant that we own and operate
in Clarksdale, Mississippi.

Termination of Cogentrix Acquisition

In August 2002, we agreed to terminate the purchase agreement we signed in April 2002 to acquire Cogentrix Energy, Inc., an independent power producer. We
agreed with Cogentrix that due to the current uncertainty of the electric power market, the deterioration of the creditworthiness of some of Cogentrix's customers and our exit from the wholesale
energy trading business, proceeding with the transaction was impractical and not in either company's interest.

Sale of Lockport Energy

In September 2002, we sold our 16.58% interest in the Lockport Energy facility, a 180-megawatt gas-fired power plant located approximately 30
miles north of Buffalo, New York.

Sale of Gas Gathering and Pipeline Assets

In October 2002, we sold our Texas and Oklahoma natural gas pipeline systems, including our natural gas and natural gas liquids processing assets, and our 50% ownership
interest in the Oasis Pipe Line Company.

Sale of U.K. Gas Storage Assets

In October 2002, we sold our Hole House natural gas storage assets in the United Kingdom. The assets consisted principally of a natural gas storage facility in Cheshire,
England.

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Sale of Lodi Gas Storage

In October 2002, we sold our investment in the Lodi gas storage project in California. We owned 50% of WHP Acquisition Company LLC, a company jointly established in 2001
with an affiliate of ArcLight Energy Partners Fund I, L.P., to purchase Western Hub Properties LLC, the developer of the Lodi gas storage project.

Sale of Gas Storage Facility

In December 2002, we sold our Texas natural gas storage facility in Katy, Texas, one of the largest operating storage facilities in the Southwest.

Sale of Coal Terminal

In February 2003, we sold our coal terminal in West Virginia that provides blending and storage services, with annual capacity of approximately 5 million tons.

Properties

Contracted Power Plants

We own interests in a number of "qualifying facilities" (QFs) and "exempt wholesale generators" (EWGs) which have long-term contracts to sell power. QFs are small
power producers or cogenerators (power producers that produce steam as a byproduct of the electricity generating process, for use in a second industrial process) that meet certain operating,
efficiency and fuel-use standards set forth by the FERC. Electric utilities are required to purchase generating capacity and electric energy from QFs at a price approved by state
regulatory bodies. EWGs are independent power projects that are exempt from the Public Utility Holding Company Act (PUHCA), but must obtain FERC approval for wholesale rates. Our EWGs have been
granted market-based rate authority.

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The table below shows information about our contracted power plants:

|Plant and Location                                |                     | Type of
Investment        |       | Percent
Owned |     | Gross
Capacity
(MW) |  | Net
Capacity
(MW) |  | Fuel   |  | Date in
Service           
|------------------------------------------------- | ------------------- | ------------------------- | ----- | ------------- | --- | ------------------- |  | ----------------- |  | ------ |  | --------------------------
|                                                 
|                                                  |                     |                           |       |               |     |                     |  |                   |  |        |  |                           
|Topsham Hydro Partners, Maine (QF)                |                     | Leveraged lease           |       | 50.00         |     | 14                  |  | 7                 |  | Hydro  |  | October 1987              
|Stockton CoGen Company, California (QF)           |                     | General partnership       |       | 50.00         |     | 60                  |  | 30                |  | Coal   |  | March 1988                
|BAF Energy L.P., California (QF)                  |                     | Limited partnership       |       | 23.11         |     | 120                 |  | 28                |  | Gas    |  | May 1989                  
|Rumford Cogeneration Company L.P., Maine (QF)     |                     | Limited partnership       |       | 24.30         |     | 85                  |  | 21                |  | Coal   |  | May 1990                  
|Koma Kulshan Associates, Washington (QF)          |                     | Limited partnership       |       | 49.75         |     | 14                  |  | 7                 |  | Hydro  |  | October 1990              
|Badger Creek Limited, California (QF)             |                     | Limited partnership       |       | 48.75         |     | 50                  |  | 24                |  | Gas    |  | April 1991                
|Orlando Cogen Limited, L.P., Florida (QF)         |                     | Limited partnership       |       | 50.00         |     | 126                 |  | 63                |  | Gas    |  | September 1993            
|Jamaica Private Power Company, Jamaica (EWG)      |                     | Limited liability company |       | 24.09         |     | 58                  |  | 14                |  | Diesel |  | January 1998              
|Batesville Unit No. 3, Mississippi (EWG)          |                     | Toll Contract             |       |              |     | 279                 |  | 279               |  | Gas    |  | August 2000               
|Lake Cogen Ltd., Florida (QF)                     |                     | Limited partnership       |       | 99.90         |     | 110                 |  | 110               |  | Gas    |  | July 1993                 
|Mid-Georgia Cogen, L.P., Georgia (QF)             |                     | Limited partnership       |       | 50.00         |     | 296                 |  | 148               |  | Gas    |  | June 1998                 
|Pasco Cogen Ltd., Florida (QF)                    |                     | Limited partnership       |       | 49.90         |     | 109                 |  | 54                |  | Gas    |  | July 1993                 
|Prime Energy Limited Partnership, New Jersey (QF) |                     | Limited partnership       |       | 50.00         |     | 65                  |  | 33                |  | Gas    |  | July 1989                 
|Onondaga Cogen. Ltd. Partnership, New York (EWG)  |                     | Limited partnership       |       | 100.00        |     | 75                  |  | 75                |  | Gas    |  | December 1993             
|Selkirk Cogen. Partners, L.P., New York (QF)      |                     | Limited partnership       |       | 19.90         |     | 345                 |  | 69                |  | Gas    |  | March 1992/
September 1994
|                                                 
|                                                  | Total Capacity (MW) |                           | 1,806 |               | 962 |                     |  |                   | 
|                                                 

Merchant Power Plants

We own or control 2,664 MW of net power generation capacity from merchant facilities, including capacity under construction. Our merchant power plants generally do not have
dedicated customers, because they are designed to operate only during periods of peak demand in the geographic area in which the plant is located. Generally these plants provide power to utilities
when they experience unexpected outages or transmission difficulties or the demands of their customers exceed their regular power supply due to extreme weather.

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The
table below shows information about our merchant power plants:

|Plant & Location                         |                     | Type of
Investment |       | Percent
Owned |       | Gross
Capacity
(MW) |  | Net
Capacity
(MW) |  | Heat Rates(d) |  | Fuel |  | Date in
Service       
|---------------------------------------- | ------------------- | ------------------ | ----- | ------------- | ----- | ------------------- |  | ----------------- |  | ------------- |  | ---- |  | ----------------------
|                                        
|                                         |                     |                    |       |               |       |                     |  |                   |  |               |  |      |  |                       
|Aries L.L.C., Missouri (EWG)             |                     | Owned              |       | 50.00         |       | 580                 |  | 290               |  | 7.1           |  | Gas  |  | June 2001/(a)
May 2002
|Elwood Energy L.L.C., Illinois (EWG)     |                     | Toll Contract      |       |              |       | 604                 |  | 604               |  | 10.7          |  | Gas  |  | July 2001(b)          
|Acadia Power Plant, Louisiana (EWG)      |                     | Toll Contract      |       |              |       | 580                 |  | 580               |  | 7.5           |  | Gas  |  | July 2002(c)          
|Coahoma Power Plant, Mississippi (EWG)   |                     | Owned              |       | 100.00        |       | 340                 |  | 340               |  | 11.9          |  | Gas  |  | September 2002        
|Clay County Power Plant, Illinois (EWG)  |                     | Owned              |       | 97.2          |       | 340                 |  | 340               |  | 11.9          |  | Gas  |  | November 2002         
|Piatt County Power Plant, Illinois (EWG) |                     | Owned              |       | 94.9          |       | 510                 |  | 510               |  | 12.0          |  | Gas  |  | June 2003*            
|                                        
|                                         | Total Capacity (MW) |                    | 2,954 |               | 2,664 |                     |  |                   |  |               | 
|                                        



Natural Gas Assets

We owned significant natural gas gathering, transportation, processing and storage facilities located in Texas, Oklahoma and California. These assets were sold as part of our
restructuring in the second half of 2002.

Competition

Our contracted power plants have agreements to sell all their power under long-dated, fixed-price contracts and therefore generally do not face competition.
Generally, the purchasers of this power are regulated utilities with investment grade credit ratings. However, if the purchasers were to become bankrupt or default on the contracts, or if the purchase
contracts were to be otherwise terminated, we would need to find replacement purchasers of the power from these facilities. Because our facilities are generally less efficient than the most modern
power plants, we would have difficulty competing for new customers.

Our
merchant power plants compete with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies
in the development and operation of energy-producing projects. There is an oversupply of power in the geographic areas in which our merchant power generation plants are located, resulting in strong
price competition for electric power. Often our marginal cost of producing power exceeds the

20

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marginal costs of other generators or normal market prices. Our merchant power plants are therefore generally dependent on outages and transmission difficulties occurring at generation facilities and
distribution networks of others or short-term spikes in demand for power resulting from extreme weather. Those events, if they occur, can create short-term opportunities for
our merchant power plants to produce and sell power at very favorable prices. We continue to work in the market place to mitigate our costs, however, if significant events do not occur, we will incur
significant losses related to these plants.

Wholesale Services

Although we are winding down the activities related to Wholesale Services, this business historically has represented a substantial portion of our income, expense, assets and
liabilities. Because of the increased capital required to operate Wholesale Services, we began scaling back its activities during the second quarter of 2002. We stopped entering into new transactions
and began liquidating our assets and liabilities related to this business during the third quarter. Nevertheless, because of the significance of this business to our historical operations and the
continuing impact of the remaining obligations and risks associated with Wholesale Services, an understanding of these historical operations continues to be relevant.

Wholesale
Services was functionally aligned as follows:



Commodity Services

We stopped growing our wholesale trading portfolio during the third quarter of 2002. Subsequent activity has been focused on limiting our credit risk to counterparties and
liquidating our trading positions. However, we still have certain contracts that remain in the trading portfolio because we were unable to liquidate or terminate them. These positions have been hedged
to mitigate the exposure of price movements and will continue to be our assets and liabilities until the contracts are settled.

Power.We purchased electric power from generation facilities and sold it primarily to utilities, municipalities,
cooperatives and other marketing companies.

Our
power marketing and trading activities included trading electricity at various points of receipt, aggregating power supplies and arranging for transmission and delivery. We made
transmission arrangements with non-affiliated interstate and intrastate transmission companies through a variety of means, including short-term and long-term firm
and interruptible transmission agreements.

Natural Gas.We purchased natural gas from a variety of suppliers under daily, monthly, variable load, base load and term
contracts that included either market-sensitive or fixed-price terms. We sold natural gas under sales agreements that had varying terms and conditions, most of which were intended to match seasonal
and other changes in demand.

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Our
natural gas marketing activities included contracting to buy natural gas from suppliers at various points of receipt, aggregating natural gas supplies, arranging for their
transportation, negotiating the sale of natural gas and matching natural gas receipts and deliveries based on volumes required by clients. We made transportation arrangements with affiliated and
non-affiliated interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. We also
utilized our natural gas storage facilities and entered into various short-term and long-term firm and interruptible agreements for
natural gas storage in order to offer peak delivery services to satisfy winter heating and summer electric generating demands.

We
also entered into long-term gas transactions with municipalities, agreeing to deliver natural gas to them for an extended period of time (generally 10 to 12 years)
at a fixed cost. The municipalities paid us in advance for the commodity. Between 1997 and 2000, we closed five of these transactions with an aggregate payment amount of approximately
$1 billion. Our obligation to deliver gas under these contracts has not changed, and we are committed to meeting those obligations. As of December 31, 2002, we had obligations of
$752.7 million on the balance sheet related to these contracts. We have substantially hedged our risk of changes in the price of natural gas to be delivered under these contracts.

Client Services

We offered products to help our clients manage multiple risks, including price, liquidity, credit, performance, volatility and weather risks. We used our access to current
market information, trends, opportunities and threats, as well as the quantitative analytical and practical skills we developed in our marketing and trading business, to develop innovative products
and services in order to better manage the risks of our clients.

Capital Services

Our Capital Services group provided capital structuring services to our clients by bundling structured financing with our commodity and capacity capabilities. Our structuring
alternatives typically included traditional asset-based lending, revolving facilities, convertible preferred stock and volumetric production payments.

Our
Capital Services earnings were derived from the spread between the price we charged our clients for funding and our cost for these funds. In addition, incremental value was created
when we completed transactions that we otherwise might not have captured without our commodity capabilities. In December 2002, we sold substantially all our notes receivable in the loan
portfolio as we exited from this business. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of this divestiture.

Regulation

Natural Gas Marketing.The FERC has implemented regulations on the transportation and marketing of natural gas that are intended to induce
interstate pipeline companies to provide non-discriminatory transportation services to producers, distributors and other shippers. The effect of the regulations has been the creation of an
open access market for natural gas purchases and sales and the creation of a business environment that has fostered the evolution of various privately negotiated natural gas sales, purchase and
transportation arrangements. Regulations in Canada have created a similar business environment in that country. The sale for resale of natural gas in North America has substantially completed its
evolution to an open access market.

22

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In
Canada, certain federal and provincial regulatory authorities require parties to hold export or removal permits for transactions by which natural gas is to be exported from the
jurisdiction in which it is produced. These requirements apply whether the natural gas is moved from one province to another or from a province to the United States. We hold permits for such purposes
from the provinces of Alberta, British Columbia, Manitoba, Saskatchewan, Ontario and Quebec, and from the Canadian National Energy Board and the United States Department of Energy.

Other Natural Gas Regulatory Issues.Our natural gas purchases and sales are generally not regulated by the FERC or other regulatory
authorities. However, we depend on the natural gas transportation and storage services offered by various pipeline companies that are regulated by the FERC and state regulatory authorities to enable
the sale and delivery of our natural gas supplies.

Power Marketing Regulation.The Federal Power Act (FPA) and rules put out by the FERC regulate the transmission of electricity in
interstate commerce and sales for resale of electric power. As a result, portions of our operations are under the jurisdiction of the FPA and the FERC. In April 1996, the FERC adopted Order 888
to expand transmission service and access and to provide alternative methods of pricing for transmission services. Order 888 was intended to open the FERC regulated interstate transmission grid in the
continental United States to all qualified persons seeking transmission services. Owners of FERC regulated transmission facilities are required to provide non-discriminatory open access to
those facilities with rates, terms and conditions that are materially comparable to those that the owner imposes on itself. Second generation implementation issues arising out of Order 888 abound.
These include issues relating to power pool structures and transmission pricing.

In
December 1999, the FERC issued Order 2000 addressing some of the significant regional transmission issues. Among other things, Order 2000 required transmission-owning utilities
that do not already participate in an independent system operator (ISO) to file plans by October 2000, detailing their participation in an organization that will control the transmission
facilities within a region. Utilities that already participated in an ISO had to submit filings in January 2001. Filings by many utilities and regional transmission entities are now on file and
pending FERC review. Our electric marketing transactions may be impacted by the functioning of these new
regional transmission organizations. Order 2000 allows significant flexibility in the structure and operation of these new organizations. We therefore cannot predict their impact on our power
marketing business.

Power Generation Regulation.Historically in the United States, regulated and government-owned utilities have been the only significant
producers of electricity for sale to third parties. The enactment of the Public Utility Regulatory Policies Act (PURPA) in 1978 encouraged non-utility companies to enter the electric power
business by reducing their regulatory burdens. In addition, PURPA and its implementing regulations created unique opportunities for the development of cogeneration and small power production
facilities by requiring utilities to purchase electricity generated by such facilities that meet certain requirements, referred to as "qualifying facilities." As a result of PURPA, a significant
market for electricity produced by independent power producers developed in the United States. The benefits and exemptions afforded by PURPA to qualifying facilities are important to us and our
competitors.

The
enactment in 1978 of PURPA and the adoption of regulations by the FERC and individual states provide incentives for the development of small power production and cogeneration
facilities meeting FERC criteria concerning the facility's size, fuel use, ownership and operating standards. In order to be a qualifying facility, a cogeneration facility must

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(i) produce not only electricity but also a FERC-mandated quantity of useful thermal output, (ii) meet FERC-mandated operating and efficiency standards when
using oil or natural gas as a fuel source and (iii) be not more than 50% owned by an electric utility or electric utility holding company, or any combination thereof. In order to be a
qualifying facility, a small power production facility must meet the same ownership criteria as qualifying cogeneration facilities and must have as its primary energy source biomass, waste, renewable
resources, geothermal resources or some combination thereof. Small power production facilities must have a capacity of no more than 80 MW, unless the primary energy source of the facility is solar,
wind or waste, or the facility qualifies under FPA Section 3(17)(E), in which case there is no maximum plant size. Hydroelectric small power production facilities also may be PURPA qualifying
facilities if, among other things, they impound or direct water by means of a new dam or diversion and meet FERC-specified environmental regulations.

PURPA
provides two primary benefits to qualifying facilities. First, qualifying facilities are exempt from otherwise applicable requirements of PUHCA, the FPA and state laws respecting
rate and financial regulation, except for state laws pertaining to sales of energy to a qualifying facility for the setting of avoided cost rates for purchases from the qualifying facility and
establishing reliability procedures and standards. Second, PURPA requires that electric utilities purchase electricity generated by qualifying facilities at a price equal to the incremental cost the
utility would have incurred to generate or purchase the power from another source (i.e., the utility's "avoided cost"). PURPA also requires the utility to sell back-up power to the
qualifying facility on a non-discriminatory basis. The FERC regulations permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at rates other
than the purchasing utility's avoided cost. If Congress amends PURPA, the statutory requirement that an electric utility purchase electricity from a qualifying facility could be eliminated and even
the validity and effect of existing contracts could be adversely affected. Moreover, although current legislative
proposals specify the honoring of existing contracts, a repeal of the statutory purchase requirements of PURPA going forward could increase pressure to renegotiate existing contracts. Any changes that
result in lower contract prices for qualifying facilities could have an adverse effect on our results of operations and financial position.

Congress
passed the Energy Act to promote further competition in the development of new wholesale power generation sources by encouraging the development of independent power projects
that are certified by the FERC as exempt wholesale generators (EWGs). The owners or operators of EWGs are exempt from the provisions of PUHCA, but not from the FPA. The Energy Act also provided the
FERC with extensive new authority to order electric utilities to provide other electric utilities, qualifying facilities and independent power projects with access to their transmission systems.
However, the Energy Act does preclude the FERC from ordering transmission services to retail customers and prohibits "sham" wholesale energy transactions which appear to provide wholesale service, but
actually are providing service to retail customers.

The
FPA grants the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce. The FPA provides the FERC with ongoing as well as initial
jurisdiction, enabling the FERC to modify previously approved rates. Such rates may be based on a cost-of-service approach or through competitive bidding or negotiation on a
market basis. Although qualifying facilities under PURPA are exempt from the FPA's rate-making and rate approval requirements, independent power projects (including EWGs) must obtain FERC
acceptance of their rates under FPA Section 205. Wholesale electricity sales related to power marketing activities are also subject to FERC acceptance on the basis that the rates either are
cost-justified or are market-based. Independent power projects in which we have an interest and that are not qualifying facilities have been granted market-based rate authority and comply
with the FPA requirements governing approval of wholesale rates.

24

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Our Executive Team

|Name                          |  | Age |  | Position                                                      
|----------------------------- |  | --- |  | --------------------------------------------------------------
|                              |  |     |  |                                                               
|Richard C. Green, Jr. (Rick)  |  | 48  |  | President, Chief Executive Officer and Chairman               
|Keith G. Stamm                |  | 42  |  | Senior Vice President and Chief Operating Officer             
|Rick J. Dobson                |  | 44  |  | Interim Chief Financial Officer                               
|Leo E. Morton                 |  | 57  |  | Senior Vice President and Chief Administrative Officer        
|Leslie J. Parrette, Jr. (Les) |  | 41  |  | Senior Vice President, General Counsel and Corporate Secretary
|C. E. Payne, Jr. (Cal)        |  | 52  |  | Senior Vice President and Chief Risk Officer                  
|Michael G. Jonagan (Mike)     |  | 41  |  | Senior Vice President, Capacity Services                      

Richard C. Green, Jr. (B.S., Business, Southern Methodist University)

Rick
joined our company in 1976 and held various financial and operating positions between 1976 and 1982. In 1982, he was appointed Executive Vice President at Missouri Public Service,
the predecessor to Aquila. Rick served as President and Chief Executive Officer from 1985 to 1996 and has been Chairman of the Board of the Company since 1989. He was also Chief Executive Officer from
1996 through 2001. In October 2002, Rick resumed the roles of President and Chief Executive Officer.

Keith G. Stamm (B.S., Mechanical Engineering, University of Missouri at Columbia; M.B.A., Rockhurst College)

Keith
joined our company in 1983 as a staff engineer at our Sibley Generating Station. Between 1985 and 1995, he held various operating positions. In 1995, Keith was promoted to Vice
President, Energy Trading and in 1996, to Vice President and General Manager, Regulated Power. In 1997, he became the Chief Executive Officer of United Energy Limited, a 33.8% owned foreign traded
Australian company and currently serves as its Chairman. From January 2000 to November 2001, he served as Chief Executive Officer of Aquila Merchant Services, Inc. In
November 2001, he was appointed President and Chief Operating Officer of our Global Networks Group. He also serves on the board of AlintaGas Limited, a 22.5% owned foreign traded Australian
company. In October 2002, Keith became Chief Operating Officer of Aquila.

Rick J. Dobson (B.B.A. Accounting, University of Wisconsin at Madison, M.B.A., University of Nebraska at Omaha)

Rick
joined Aquila Merchant Services in 1989 as Vice President and Controller. In 1995, he left Aquila to serve as Vice President and Controller for ProEnergy in Houston, Texas. He
rejoined Aquila Merchant Services in 1997 and served as Vice President Financial Management until November 2002 when he was appointed Interim Chief Financial Officer of Aquila. Prior to joining
our company, Rick served in a management position with Arthur Andersen LLP.

Leo E. Morton (B.S., Mechanical Engineering, Tuskegee University; M.S., Management, Massachusetts Institute of Technology)

Leo
joined our company in 1994 as Vice President, Performance Management. He was appointed Senior Vice President in 1995 and Senior Vice President, Human Resources and Operations Support
in 1997. In 2000, he was named Senior Vice President and Chief

25

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Administrative Officer. Prior to working for us, Leo held executive and management positions in manufacturing and engineering for AT&T beginning in 1973.

Leslie J. Parrette, Jr. (A.B., Harvard College; J.D., Harvard Law School)

Les
joined our company in July 2000 as Senior Vice President and General Counsel. In September 2001, he was also appointed Corporate Secretary of Aquila. Prior to joining
our company, Les was a partner in the law firm of Blackwell Sanders Peper Martin LLP from 1992 through June 2000.

C. E. Payne Jr. (B.S., Portland State University)

Cal
joined our company in December 1995 as our first Trading Control Officer. In 2000, he was appointed Vice President and Chief Risk Officer, and in March 2001 he became
Senior Vice President and Chief Risk Officer. Prior to joining our company, Cal held executive and management positions for 11 years at Transco Energy Company in Houston, Texas.

Michael G. Jonagan (B.S. Mechanical Engineering and B.S. Petroleum Engineering, University of MissouriRolla; M.S. Engineering Management, University of Kansas)

Mike
joined our company in 1986 as a staff engineer at our Sibley Generating Station. Between 1986 and 1999 he held various operating positions. In 1999, he was named Vice President,
Origination at Aquila Merchant Services and in 2000 he became Vice President, Regulated Power Generation. In October 2000, Mike became Chief Operating Officer of UEL and he presently serves on
its board of directors. From July 2002 until October 2002, Mike was the Chief Executive Officer of our domestic regulated utility business and in October 2002 he became Senior
Vice President, Capacity Services.

Item 2. Properties

Our corporate offices are located in 225,000 square feet of owned office space in Kansas City, Missouri. We also occupy other owned and leased office space for various
operating offices.

In
addition, we lease or own various real property and facilities relating to our regulated and non-regulated electricity generation assets. Our principal assets are
generally described under "Capacity Services," "International NetworksCanada" and "Domestic Networks." Certain of these properties are encumbered by liens securing loans made to us. See
Notes 12 and 13 to our Consolidated Financial Statements for a description of the liens.

Item 3. Legal Proceedings

On February 19, 2002, we filed a suit against Chubb Insurance Group, the issuer of surety bonds in support of certain of our long-term gas supply contracts.
Previously, Chubb had demanded that it be released from its surety obligation of up to $540 million or, alternatively, that we post collateral to secure its obligation. We do not believe that
Chubb is entitled to be released from its surety obligations or that we are obligated to post collateral to secure its obligations unless it is likely we will default on the contracts. Chubb has not
alleged that we are likely to default on the contracts. If Chubb were to prevail, it would have a material adverse impact on our liquidity and financial position. We rely on other sureties in support
of long-term gas supply contracts similar to those described above. There can be no assurance that these sureties will not make claims

26

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similar to those raised by Chubb. We have performed under these contracts since their inception and intend to continue to fully perform under these contracts.

A
consolidated lawsuit was filed against us in Delaware Chancery Court in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange
offer completed in January 2002. The suit raises allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange offer
on behalf of the public shareholders of Aquila Merchant. The plaintiffs' claims for equitable
relief were denied by the Delaware Chancery Court in January 2002, and there has been no further activity with the lawsuit. Securities fraud complaints seeking damages based on the same conduct
were also filed against us in federal court in Missouri. Persons holding certificates formerly representing approximately 1.8 million shares of Aquila Merchant common stock are also pursuing
their appraisal rights in connection with the recombination. We do not believe that any of these actions will have an outcome materially adverse to us.

A
number of companies that have engaged in energy trading activities, including us, have received requests from various regulatory agencies to furnish data and answer questions relating
to the possible inaccurate reporting of gas trade information to various industry publications in 2000 and 2001. In response to such inquiries, we initiated a review of our reported information
relative to recorded data and are fully cooperating with these investigations. Additionally, we have reported to the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission
that we have been unable to reconcile all of the gas trade data reported to various trade publications with the gas trade data in our internal records and that our former traders may have reported
inaccurate information. A lawsuit was filed against us and numerous other energy trading companies in November 2002 by the Lieutenant Governor of the State of California alleging that we
misreported gas trade data that, in turn, affected the market price of electricity in California.

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

There were no matters submitted to a vote of security holders in the fourth quarter of 2002.

Part 2

Item 5. Market for Registrant's Common Equity and Related Shareholder Matters

Our common stock (par $1) is listed on the New York Stock Exchange under the symbol ILA. Through March 15, 2002, the symbol was UCU. At March 14, 2003, we had
approximately 40,000 common shareholders of record. Information relating to market prices of common stock on the New York Stock Exchange and cash dividends on common stock is set forth below.

Market Price

|              |  | High |       | Low |   | Cash
Dividends
|------------- |  | ---- | ----- | --- | - | --------------
|
|              |  |      |       |     |   |               
|2002 Quarters |  |      |       |     |   |               
|First         |  | $    | 26.95 |     | $ | 21.77         
|Second        |  |      | 25.23 |     |   | 7.26          
|Third         |  |      | 8.23  |     |   | 2.04          
|Fourth        |  |      | 4.25  |     |   | 1.56          
|             
|2001 Quarters |  |      |       |     |   |               
|First         |  | $    | 32.40 |     | $ | 24.81         
|Second        |  |      | 37.85 |     |   | 29.35         
|Third         |  |      | 33.00 |     |   | 26.60         
|Fourth        |  |      | 31.80 |     |   | 21.85         
|             

27

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Item 6. Selected Financial Data

|In millions, except per share amounts                                 |                       | 2002 |          | 2001   |   | 2000     |      | 1999 |          | 1998 |  
|--------------------------------------------------------------------- | --------------------- | ---- | -------- | ------ | - | -------- | ---- | ---- | -------- | ---- | -
|
|                                                                      |                       |      |          |        |   |          |      |      |          |      |  
|Sales                                                                 |                       | $    | 2,377.1  |        | $ | 3,711.0  |      | $    | 3,194.5  |      | $
|Gross profit                                                          |                       |      | 833.7    |        |   | 1,688.1  |      |      | 1,313.5  |      |  
|Earnings (loss) from continuing operations(1)                         |                       |      | (1,722.8 | )(2)   |   | 245.3    | (3)  |      | 194.3    | (4)  |  
|Basic earnings (loss) per common share                               |                       |      |          |        |   |          |      |      |          |      |  
|                                                                      | Continuing operations |      | $        | (10.65 | ) | $        | 2.19 |      | $        | 2.09 |  
|Diluted earnings per common share                                    |                       |      |          |        |   |          |      |      |          |      |  
|                                                                      | Continuing operations |      | $        | (10.65 | ) | $        | 2.12 |      | $        | 2.08 |  
|Cash dividends per common share                                       |                       | $    | .775     |        | $ | 1.20     |      | $    | 1.20     |      | $
|Total assets                                                          |                       | $    | 9,259.2  |        | $ | 11,966.5 |      | $    | 14,026.9 |      | $
|Short-term debt                                                       |                       |      | 301.0    |        |   | 548.6    |      |      | 501.0    |      |  
|Long-term debt (including current maturities)                         |                       |      | 2,928.7  |        |   | 2,327.0  |      |      | 2,397.6  |      |  
|Company-obligated preferred securities (including current maturities) |                       |      |         |        |   | 350.0    |      |      | 450.0    |      |  
|Common shareholders' equity                                           |                       |      | 1,607.9  |        |   | 2,551.6  |      |      | 1,799.6  |      |  

The following notes reflect the pre-tax effect of items affecting the comparability of the Selected Financial Data above:

(1)  Depreciation
and amortization expense included (in millions) $19.1, $10.9, $2.7 and $1.2 of goodwill amortization for the years ended December 31, 2001, 2000,
1999 and 1998, respectively. Goodwill amortization was not recorded in the year ended December 31, 2002 as a result of the implementation of a new accounting standard that discontinued the
amortization of goodwill beginning January 1, 2002. Additionally, included in earnings from equity method investments for those periods was approximately (in millions) $17.6, $10.5, $6.6 and
$7.3, respectively, of goodwill amortization.

(2)  Included
in earnings (loss) from continuing operations for the year ended December 31, 2002, is (a) a $696.1 million impairment charge on our
investment in Quanta Services due to a continued drop in its share price, the termination of our proxy contest for control of Quanta Services and the decline of the telecommunications industry;
(b) a $247.5 million impairment charge on our investment in Midlands Electricity due to the indicated fair value being substantially below our carrying value as suggested by recent sale
negotiations and analysis, as well as a corresponding
impairment charge being taken at the investment level; (c) a $127.2 million impairment charge on our investment in Multinet and AlintaGas based on the status of negotiations to sell our
interest in these businesses, as well as a corresponding impairment charge being taken at the investment level; (d) a $227.6 million impairment charge related to our 96% owned investment
in Everest Connections due to our decision to significantly reduce our funding to this business and lower values for certain technology related investments; (e) a $178.6 million
write-down of Wholesale Services' goodwill in connection with our exit of the energy trading business; (f) other impairment charges and losses on sale of assets of
$106.2 million, primarily as a result of our decision to sell $1 billion in assets to improve our liquidity position; and (g) $210.2 million of restructuring charges from
our exit from the wholesale energy trading business and the restructure of our utility business.

(3)  In
the year ended December 31, 2001, we (a) recorded a $110.8 million gain on the sale of 5.75 million shares of Aquila Merchant
Services, Inc. Class A common stock (EBIT and net income reflect our 80% ownership of Aquila Merchant from April 27, 2001 to December 31, 2001); (b) wrote off
exposure related to the Enron bankruptcy of $35.0 million in Merchant Services and

28

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$31.8 million in Domestic Networks; (c) recorded charges of $16.5 million in our communications business related to preliminary system design and leases in markets we do not
intend to develop; and (d) recorded charges of $11.5 million in our Australian networks related to valuation allowances on certain deferred taxes and collectibility of certain
receivables.

(4)  In
the year ended December 31, 2000, we recorded $19.4 million of reserves for impairments and other charges relating to investments in retail assets in
the United Kingdom, certain information technology assets, corporate intangibles and our construction of communications fiber-optic networks. We also recorded a $44.0 million gain on the sale
of a 34% interest in Uecomm Limited to the public.

(5)  In
1998 we recorded (a) asset impairment charges of $13.2 million reflecting a plan to curtail our retail activities, (b) an $8.0 million
charge relating to our plan to dissolve the EnergyOne, LLC partnership and (c) a $6.5 million impairment related to our investment in a power plant project.

29

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

Financial Review

This review of performance is organized by business segment, reflecting the way we managed our business during the periods covered by this report. Each business group leader is
responsible for operating results down to earnings before interest and taxes (EBIT). We use EBIT as a performance measure as it captures the income and expenses within the management control of our
segment business leaders. Corporate management is responsible for making all financing decisions. Therefore, each segment discussion focuses on the factors affecting EBIT, while financing and income
taxes are separately discussed at the corporate level.

The
use of EBIT as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with
generally accepted accounting principles (GAAP), as an indicator of operating performance or as a measure of liquidity, or other performance measures used under GAAP. In addition, the term may not be
comparable to similarly titled measures used by other entities.

See
page 64 for cautionary statements and risk factors concerning forward looking statements contained in this analysis.

|                                                         |                                        | Year Ended December 31,     |         
|-------------------------------------------------------- | -------------------------------------- | --------------------------- | --------
|
|
|                                                         |                                        |                             |         
|Earnings (Loss) Before Interest and Taxes:               |                                        |                             |         
|                                                         | Domestic Networks                      |                             | $       
|                                                         | International Networks                 |                             |         
|                                                         |                                       
|                                                         |                                        | Total Global Networks Group |         
|                                                         |                                       
|                                                         | Capacity Services                      |                             |         
|                                                         | Wholesale Services                     |                             |         
|                                                         | Minority interest                      |                             |         
|                                                         |                                       
|                                                         |                                        | Total Merchant Services     |         
|                                                         | Corporate and other                    |                             |         
|                                                         |                                       
|Total EBIT                                               |                                        |                             | (1,608.4
|                                                         |                                       
|Interest expense                                         |                                        |                             | 249.5   
|Income tax expense (benefit)                             |                                        |                             | (135.1  
|                                                         |                                       
|Earnings (loss) from continuing operations               |                                        |                             | (1,722.8
|Earnings (loss) from discontinued operations, net of tax |                                        |                             | (329.6  
|Cumulative effect of accounting change, net of tax       |                                        |                             | (22.7   
|                                                         |                                       
|Net income (loss)                                        |                                        | $                           | (2,075.1
|                                                         |                                       
|Diluted earnings (loss) per share:                       |                                        |                             |         
|                                                         | Continuing operations                  |                             | $       
|                                                         | Discontinued operations                |                             |         
|                                                         | Cumulative effect of accounting change |                             |         
|                                                         |                                       
|                                                         | Net income (loss)                      |                             | $       
|                                                         |                                       

30

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Key Factors Impacting EBIT

Our total EBIT decreased significantly in 2002 compared to 2001. Key factors affecting 2002 results were as follows:



Cumulative Effect of Accounting Change

In October 2002, the Emerging Issues Task Force (EITF) reached a consensus to rescind EITF No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." By rescinding EITF 98-10, all contracts that would have otherwise been accounted for under EITF 98-10 and that do not fall within the
scope of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS 133) should no longer be
marked-to-market through earnings. We elected to adopt this requirement in October 2002 and thus reversed $37.5 million (or $22.7 million on an
after-tax basis) of earnings previously recognized.

31

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Restructuring Charges

As further discussed in Note 4 to the Consolidated Financial Statements, we recorded restructuring charges for the year ended December 31, 2002 that consisted of
the following:

|In millions                         |                                                    | Year Ended
December 31, 2002
|----------------------------------- | -------------------------------------------------- | ----------------------------
|
|                                    |                                                    |                             
|Domestic Networks:                  |                                                    |                             
|                                    | Severance costs                                    |                             
|                                    | Disposition of corporate aircraft                  |                             
|                                   
|Total Domestic Networks             |                                                    |                             
|                                   
|Capacity Services:                  |                                                    |                             
|                                    | Interest rate swap reductions                      |                             
|                                   
|Total Capacity Services             |                                                    |                             
|                                   
|Wholesale Services:                 |                                                    |                             
|                                    | Severance costs                                    |                             
|                                    | Retention payments                                 |                             
|                                    | Lease agreements                                   |                             
|                                    | Write-down of leasehold improvements and equipment |                             
|                                    | Loss on termination of aggregator loan program     |                             
|                                    | Disposition of corporate aircraft                  |                             
|                                    | Other                                              |                             
|                                   
|Total Wholesale Services            |                                                    |                             
|                                   
|Corporate and Other severance costs |                                                    |                             
|                                   
|Total restructuring charges         |                                                    | $                           
|                                   

32

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Impairment Charges and Net Loss on Sale of Assets

As further discussed in Note 5 to the Consolidated Financial Statements, we recorded the following impairment charges and net loss on sale of assets for the years ended
December 31, 2002, 2001 and 2000:

|                                                        |                                                         | Year Ended December 31,
|------------------------------------------------------- | ------------------------------------------------------- | -----------------------
|
|
|                                                        |                                                         |                        
|Domestic Networks:                                      |                                                         |                        
|                                                        | Quanta Services                                         |                        
|                                                        | Everest Connections and other communication investments |                        
|                                                        | Enron exposure                                          |                        
|                                                        | Gas distribution system                                 |                        
|                                                       
|Total Domestic Networks                                 |                                                         |                        
|                                                       
|International Networks:                                 |                                                         |                        
|                                                        | Midlands                                                |                        
|                                                        | Multinet and AlintaGas                                  |                        
|                                                        | Other                                                   |                        
|                                                       
|Total International Networks                            |                                                         |                        
|                                                       
|Capacity Services:                                      |                                                         |                        
|                                                        | Turbines                                                |                        
|                                                        | Exit from Lodi gas storage investment                   |                        
|                                                        | Termination of Cogentrix acquisition                    |                        
|                                                        | Capacity Services goodwill                              |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Capacity Services                                 |                                                         |                        
|                                                       
|Wholesale Services:                                     |                                                         |                        
|                                                        | Wholesale Services goodwill                             |                        
|                                                        | Enron exposure                                          |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Wholesale Services                                |                                                         |                        
|                                                       
|Corporate and Other:                                    |                                                         |                        
|                                                        | Information technology assets                           |                        
|                                                        | Corporate identity intangibles                          |                        
|                                                       
|Total Corporate and Other                               |                                                         |                        
|                                                       
|Total impairment charges and net loss on sale of assets |                                                         | $                      
|                                                       

During
2002, we also incurred a $426.6 million loss on an impairment charge and net losses on asset sales that are reflected in discontinued operations and is not included in the
table above. See the paragraph below for further discussion of these charges.

Discontinued Operations

As further discussed in Note 6 to the Consolidated Financial Statements, in connection with the sales of our gas storage facility, our gas gathering and pipeline assets,
our Merchant loan portfolio

33

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and our coal handling facility, we have reported the results of these businesses in discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Statements
of Income.

Operating
results of discontinued operations are as follows:

|                                             |                                                   | Year Ended December 31, |       
|-------------------------------------------- | ------------------------------------------------- | ----------------------- | ------
|
|
|                                             |                                                   |                         |       
|Sales                                        |                                                   | $                       | 235.3 
|Cost of sales                                |                                                   |                         | 164.8 
|                                             |                                                  
|Gross profit                                 |                                                   |                         | 70.5  
|                                             |                                                  
|Operating expenses:                          |                                                   |                         |       
|                                             | Operating expense                                 |                         |       
|                                             | Impairment charges and net loss on sale of assets |                         |       
|                                             | Depreciation and amortization expense             |                         |       
|                                             |                                                  
|Total operating expenses                     |                                                   |                         | 510.7 
|                                             |                                                  
|Other income (expense)                       |                                                   |                         |       
|                                             | Equity in (losses) earnings of investments        |                         |       
|                                             | Other income (expense)                            |                         |       
|                                             |                                                  
|Earnings (loss) before interest and taxes    |                                                   |                         | (386.5
|Interest expense                             |                                                   |                         | 5.6   
|                                             |                                                  
|Earnings (loss) before income taxes          |                                                   |                         | (392.1
|Income tax expense (benefit)                 |                                                   |                         | (62.5 
|                                             |                                                  
|Earnings (loss) from discontinued operations |                                                   | $                       | (329.6
|                                             |                                                  

2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $224.2 million, $194.8 million and $29.4 million, respectively, in 2002 compared to 2001. These decreases
were primarily due to lower natural gas liquids prices and throughput volumes for the first three quarters of 2002 as compared to the same period in 2001. As a result, sales, cost of sales and gross
profit from our gas gathering and pipeline business all decreased by $165.4 million, $149.9 million and $15.5 million, respectively. The
sale of these operations on October 1, 2002, as compared to a full fourth quarter of operations in 2001, caused a further reduction in sales, cost of sales and gross profit of
$66.0 million, $44.9 million and $21.1 million, respectively.

Impairment Charges and Net Loss on Sale of Assets

In 2002, we incurred a $240.3 million loss on the sale of our gas gathering and pipeline assets, a $184.0 million loss on the sale of our Merchant loan portfolio,
a $6.6 million impairment of our coal handling facility and a $4.3 million pretax gain on sale of our gas storage assets.

34

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Depreciation and Amortization Expense

Depreciation and amortization expense decreased in 2002 by $8.3 million primarily as a result of the sale of our gas gathering and pipeline assets in
October 2002.

Income Tax Expense (Benefit)

Our current year losses resulted in an income tax benefit in 2002, as compared to income tax expense in 2001 due to earnings. In 2002, $190.9 million of our losses will
be treated as capital losses for income tax purposes. Because capital losses can only offset capital gains, and we do not have sufficient capital gains in prior years to offset all of these losses,
nor can we be assured of generating any future capital gains, we recorded a $75.4 million valuation allowance against our capital loss carryforward. In addition, the above impairment charges
and net loss on sale of assets include the effects of $31.9 million of goodwill and other intangibles that were not deductible for income tax purposes.

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $54.1 million, $38.8 million and $15.3 million, respectively, for the year ended December 31, 2001
compared to 2000. These decreases were primarily due to a 15% decline in natural gas throughput volumes from our gas gathering and pipeline assets in 2001 when compared to 2000. In addition, lower
natural gas liquids prices caused further decreases to our sales, cost of sales and gross profit in 2001.

Operating Expense

Operating expense decreased $19.4 million in 2001 from 2000 primarily due to a decrease in provisions for bad debts in the Merchant Services loan portfolio.

Impairments and Net Loss on Sale of Assets

In 2000, we recognized asset impairment charges of $7.8 million with respect to our assessment of certain under-performing pipeline assets.

Interest Expense

Interest expense decreased $19.5 million in 2001 compared to 2000. The majority of interest expense represents inter-company interest charges from Corporate that are
eliminated in consolidation. Lower interest expense in 2001 resulted from the repayment of inter-company debt and the way interest expense was being allocated to the various business units.

Global Networks Group

Our Global Networks Group consists of our investments in domestic and international regulated electric, gas and communications networks. Domestic Networks is
principally made up of our electric and gas regulated utility businesses, which operate as Aquila Networks in Colorado, Iowa, Kansas, Michigan, Minnesota, Missouri and Nebraska. Also included is our
96% owned subsidiary, Everest Connections, a communications business which provides local and long-distance telephone, cable television and high speed internet service to areas of greater
Kansas City.

35

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Additionally, our results for the three years ended December 31, 2002 includes our ownership interest in Quanta Services, Inc., a provider of field services to electric utilities,
telecommunications and cable television companies, and governmental entities. We began selling down our ownership interest in Quanta in July 2002 and sold our remaining 11.6 million
shares in February 2003.

International
Networks includes our investments in Canada, Australia and the United Kingdom. Our wholly owned Canadian electric distribution companies have operations in the provinces of
Alberta and British Columbia. Our Australian investments include a 33.8% interest in United Energy Limited (UEL), an electric distribution company in the Melbourne area; a 25.5% interest in Multinet
Gas, a gas distribution company in the Melbourne area; and a 45% interest, held jointly with UEL, in AlintaGas Limited, a gas distribution company in Western Australia. Our United Kingdom investment
consists of a 79.9% interest in Avon Energy Partners Holding Company, the holding company for Midlands Electricity, an electric distribution company in central England. Midlands also owns a combined
884 megawatts of net generation capacity in the United Kingdom, Turkey and Pakistan. Included in our results for the three years ending December 31, 2002, are the earnings from our investment
in UnitedNetworks, a New Zealand gas and electric distribution company that was sold in October 2002.

Three-Year ReviewDomestic Networks

|                                                |                                                   | Year Ended December 31,
|----------------------------------------------- | ------------------------------------------------- | -----------------------
|
|
|                                                |                                                   |                        
|Sales                                           |                                                   | $                      
|Cost of sales                                   |                                                   |                        
|                                               
|Gross profit                                    |                                                   |                        
|                                               
|Operating expenses:                             |                                                   |                        
|                                                | Operating expense                                 |                        
|                                                | Restructuring charges                             |                        
|                                                | Impairment charges and net loss on sale of assets |                        
|                                                | Depreciation and amortization expense             |                        
|                                               
|Total operating expenses                        |                                                   |                        
|                                               
|Other income (expense):                         |                                                   |                        
|                                                | Equity in earnings of investments                 |                        
|                                                | Minority interest                                 |                        
|                                                | Other income (expense)                            |                        
|                                               
|Earnings (loss) before interest and taxes       |                                                   | $                      
|                                               
|Identifiable assets                             |                                                   | $                      
|Electric sales and transportation volumes (GWh) |                                                   |                        
|Gas sales and transportation volumes (Mcf)      |                                                   |                        
|Electric customers                              |                                                   |                        
|Gas customers                                   |                                                   |                        
|                                               

36

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2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Networks businesses decreased $394.3 million and $353.2 million, respectively, in 2002 compared to 2001. These decreases
were primarily the result of lower gas prices and mild winter weather in 2002, both of which impacted sales and cost of sales. Because gas purchase costs for our gas utility networks are passed
through to our customers, the change in gas prices did not have a corresponding impact on our gross profit. Gross profit decreased $41.1 million primarily as the result of $30.1 million
in 2001 off-system power sales that were not repeated in 2002. Gross profit decreased an additional $11.5 million due to the sale of our Missouri pipeline business in
January 2002.

Operating Expense

Operating expense decreased $9.5 million in 2002 compared to 2001. The decrease in operating expense was primarily due to reduced expenses in Everest Connections
resulting from the elimination of costs associated with our telecommunications consulting operation in early 2002, greater operating efficiencies and the suspension of incentive payments under the
long-term incentive plan. Although there were significant labor savings in our regulated business due to a reduction in workforce and annual incentives, these amounts were offset by
increased pension costs, costs associated with our proxy contest with Quanta Services and expenses related to certain regulatory matters.

Restructuring Charges

As a result of the restructuring of our domestic utility business to more closely align it with our state service areas, we incurred $21.3 million in restructuring
costs, primarily in the form of severance for terminated employees and the disposition of our corporate aircraft operation.

Impairment Charges and Net Loss on Sale of Assets

As further discussed in Note 5 to the Consolidated Financial Statements, Domestic Networks incurred $932.7 million of losses resulting from impairments and asset
sales in 2002. The impairments consisted primarily of $696.1 million of impairment losses related to our investment in Quanta Services and $227.6 million of impairment losses related to
Everest and other communication technology investments. In addition, we recorded a $9.0 million asset impairment charge related to a local natural gas distribution system deemed unrecoverable
in one of our regulatory jurisdictions.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $21.3 million, of which $11.4 million was due to the elimination of goodwill amortization attributed to our Quanta
Services investment and our acquisition of St. Joseph Light & Power Company. Also impacting depreciation and amortization expense was a $13.5 million decrease in depreciation resulting
from our recent Missouri electric rate case. These decreases were offset in part by a $5.0 million increase in depreciation expense on additional communication networks placed in service during
late 2001 and 2002.

37

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Equity in Earnings of Investments

Equity in earnings of investments decreased $26.6 million in 2002 compared to 2001. The decrease was primarily due to a decrease in equity earnings from our Quanta
Services investment resulting from Quanta Services lower earnings in 2002 and a reduction of our ownership percentage in Quanta Services from 38% to 10.2% during 2002. Partially offsetting Quanta
Services' lower earnings was the elimination of approximately $9.5 million of goodwill amortization that was previously in the financial statements of Quanta Services.

Other Income (Expense)

Other income (expense) decreased $6.3 million in 2002 from 2001. This decrease was primarily due to the loss of interest earned in 2001 on the note receivable from Enron
discussed below.

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for our Domestic Networks businesses increased (in millions) $295.0, $229.0 and $66.0, respectively, in 2001 compared to 2000. Increased
sales and cost of sales were mainly driven by higher natural gas prices in early 2001. Our acquisition of St. Joseph Light & Power Company in December 2000 contributed sales, cost of
sales and gross profit of (in millions) $104.1, $40.9 and $63.2, respectively. Gross profit in 2001 also increased $12.6 million due to stronger off-system power sales.

Operating Expense

Operating expense increased $68.2 million in 2001 compared to 2000 due to the inclusion of a full year's operations of St. Joseph Light & Power, which had
operating expenses of $21.9 million. Start-up operating expenses in connection with the build-out of Everest Connections contributed an additional $30.5 million
of the increase. Increased bad debt expenses related to higher natural gas costs in late 2000 and early 2001 and certain industrial customer bankruptcies in 2001 also contributed to higher operating
expenses.

Impairment Charges and Net Loss on Sale of Assets

In 2001, we recorded an impairment charge of $31.8 million on an unsecured note receivable from Enron Corporation that was written off following Enron's
December 2001 bankruptcy filing. In addition, we wrote off $16.5 million related to Everest Connections' abandonment of certain communication system assets and related leases in markets
it originally intended to develop.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $32.8 million in 2001 compared to 2000, primarily as the result of $16.4 million of increased depreciation related
to the assets acquired in the St. Joseph Light & Power merger that occurred in December 2000. Also contributing to the increase was $4.6 million of depreciation on additional
capital expenditures in our utility operations and $10.3 million of additional depreciation resulting from our Everest network build-out.

38

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Equity in Earnings of Investments

Equity in earnings of investments decreased $24.4 million in 2001 compared to 2000, primarily due to reduced equity earnings from our investment in Quanta Services and
the termination of our management fee agreement with Quanta Services in December 2000. Our reduced equity earnings from Quanta Services stemmed from a slowdown in the telecom market and the
write-off of certain receivables from its telecom customers.

Current Operating Developments

Quanta Services Ownership.During 2002 we wrote our investment in Quanta Services down to fair value and sold approximately
17.6 million of its shares which reduced our ownership from 38% to 10.2%. As a result, we now account for this asset as a cost method security available for sale in future periods. At
December 31, 2002, our carrying value of this investment was $40.6 million or $3.50 a share. We sold our remaining 11.6 million shares during the first quarter of 2003 at a net
price of $2.90 a share.

Everest Connections.During the fourth quarter of 2002, we restricted future funding of Everest to levels necessary to
complete construction in progress and serve existing customers. We evaluated the strategic alternatives for Everest and chose to restructure the business so that going forward it is
self-funded from operations.

Three Year ReviewInternational Networks

|                                          |                                                   | Year Ended December 31, |        
|----------------------------------------- | ------------------------------------------------- | ----------------------- | -------
|
|
|                                          |                                                   |                         |        
|Sales                                     |                                                   | $                       | 261.7  
|Cost of sales                             |                                                   |                         | 34.0   
|                                          |                                                  
|Gross profit                              |                                                   |                         | 227.7  
|                                          |                                                  
|Operating expenses:                       |                                                   |                         |        
|                                          | Operating expense                                 |                         |        
|                                          | Impairment charges and net loss on sale of assets |                         |        
|                                          | Depreciation and amortization expense             |                         |        
|                                          |                                                  
|Total operating expenses                  |                                                   |                         | 556.4  
|                                          |                                                  
|Other income (expense):                   |                                                   |                         |        
|                                          | Equity in earnings of investments                 |                         |        
|                                          | Minority interest in income of subsidiaries       |                         |        
|                                          | Gain on sale of subsidiary stock                  |                         |        
|                                          | Other income (expense)                            |                         |        
|                                          |                                                  
|Earnings (loss) before interest and taxes |                                                   | $                       | (70.1  
|                                          |                                                  
|Identifiable assets                       |                                                   | $                       | 1,607.1
|Electric sales volumes (GWh)              |                                                   |                         | 16,003 
|Canadian electric customers               |                                                   |                         | 483,000
|                                          |                                                  

39

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2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales increased $8.1 million in 2002 compared to 2001, primarily due to a $4.2 million rate increase in British Columbia and a $9.6 million interim rate
increase in Alberta. Offsetting the rate increases were the reduction in sales and cost of sales stemming from the sale of the Alberta retail operations in January 2001. Cost of sales decreased
an additional $9.0 million in 2002 due to the deferral of additional excess purchased power costs in Alberta that regulatory authorities have now approved for recovery in future periods.

Operating Expense

Operating expense increased $25.7 million in 2002 compared to 2001. This increase was primarily due to $6.0 million of business development costs,
$6.0 million of costs associated with the integration of our British Columbia and Alberta operations, $4.0 million of increased operating costs in our Canadian networks and
$2.8 million of transition costs related to our Midlands Electricity acquisition.

Impairment Charges and Net Loss on Sale of Assets

In 2002, impairment charges mainly consisted of $247.5 million related to our investment in Midlands Electricity in the U.K. and a $127.2 million impairment
charge related to our investments in Multinet Gas and AlintaGas in Australia. These impairments were determined based on the estimated fair value of these investments considering current market
information, which included recent offers to sell our interest in these businesses, as well as corresponding impairment charges being taken in the financial statements of the underlying business.

Equity in Earnings of Investments

Equity in earnings of investments increased $50.5 million in 2002 compared to 2001. Midlands, acquired in May 2002, contributed $41.9 million, excluding
impairments, of the increase. An additional $8.1 million of the increase was due to goodwill no longer being amortized in the financial statements of our equity method investments.

Gain on Sale of Subsidiary Stock

In October 2002, through a public tender offer in New Zealand, VECTOR Limited acquired all of the outstanding shares of UnitedNetworks Limited (UNL), in which we had a
70.2% indirect interest. We realized a $130.5 million pretax gain on the sale of this investment.

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our International Networks businesses decreased $238.8 million and $268.8 million, respectively, in 2001 compared to 2000. Gross
profit increased $30.0 million in 2001. These changes were primarily due to the following:



40

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Operating Expense

Operating expense increased $31.5 million in 2001 compared to 2000. The purchase of our Alberta network increased operating expenses by $39.7 million, while
deconsolidating our New Zealand business decreased operating expenses by $10.5 million.

Impairment Charges and Net Loss on Sale of Assets

In 2001, we recorded charges of $11.5 million relating to the realizability of deferred tax assets and interest receivable on shareholder loans in our Australian equity
investments.

Equity in Earnings of Investments

Equity in earnings of investments increased $17.3 million in 2001 compared to 2000. After the sale of a portion of our New Zealand investment in June 2000, we
were required to deconsolidate this investment and use the equity method of accounting to record our share of earnings. This increased equity earnings by $16.5 million.

Other Income (Expense)

Other income (expense) increased $12.8 million, primarily reflecting the allowed recovery of carrying costs on deferred excess purchased power costs in Alberta. Alberta
regulators approved the recovery of carrying costs in December 2001.

Gain on Sale of Subsidiary Stock

We recorded a $44.0 million gain when UEL completed an initial public offering of 34% of Uecomm Limited, its telecom business.

Current Operating Developments

United Kingdom.Recent downgrades in credit ratings assigned to the public debt in the Midlands ownership chain have called
into question the ability of Midlands to pay us management fees and dividends. Additionally, the local regulatory body, the Office of Gas and Electricity Markets (Ofgem), now requires
pre-approval of cash payments to the owners in the form of management fees or dividends. Accordingly, we intend to record equity earnings and management fees only to the extent of cash
received.

In
August 2002, Aquila and FirstEnergy initiated a process for the sale of Midlands with final bids due in December 2002. We received offers in early December and are
currently in negotiations with the prospective buyers.

Australia.We are currently exploring the possible sale of our investments in Australia and anticipate a sale being completed
in 2003, however, there can be no assurances that this will occur.

41

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Canada.In December 2001, we filed for an annual rate increase in Alberta of about $30.0 million along with an
application for a performance-based rate-setting mechanism. We subsequently modified that request and sought a $12.7 million increase for 2002 and a $6.0 million increase for
2003. In July 2002, an interim rate increase of approximately $9.6 million was approved. Hearings were held in September and October 2002 and a final order was issued in
February 2003, resulting in a decrease in rates of $21.0 million for 2002, and no increase in rates in 2003 (2002 rates carried forward to 2003). Almost all of the reduction in rates
related to depreciation on distribution assets (average asset lives were extended) and the related income tax effect. The decision did not adjust the allowed rate of return earned by the Company and
therefore, net income is not expected to be materially impacted by this decision. However, the decision is estimated to reduce annual cash flow from operations by approximately $17.0 million
for 2004 and
beyond. With regard to 2003, cash flow from operations will be reduced by approximately $33.0 million, which includes the effect of both the 2002 and 2003 reduction.

As
a result of the above action, we are currently reassessing the future recoverability of $188.6 million of recorded goodwill in Canada.

Merchant Services

We conduct our Merchant Services business through Aquila Merchant Services, Inc. (Aquila Merchant), which operates as two business segments, Capacity
Services and Wholesale Services. Capacity Services primarily owns, operates and contractually controls our non-regulated power generation assets. Wholesale Services includes our North
American and European commodity, client and capital businesses.

In
2000 and the first four months of 2001, we owned 100% of Aquila Merchant. In April 2001, approximately 20% of Aquila Merchant was sold to the public. For the remainder of 2001,
Aquila Merchant was consolidated with a minority interest reflected in the financial statements. In January 2002, we acquired the outstanding public shares of Aquila Merchant in an exchange
offer and merger. The following Capacity Services and Wholesale Services financial information includes 100% of Aquila Merchant before minority interest, which totaled $26.4 million for the
year ended December 31, 2001.

42

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Three-Year ReviewCapacity Services

|                                          |                                                   | Year Ended December 31,
|----------------------------------------- | ------------------------------------------------- | -----------------------
|
|                                         
|                                          |                                                   |                        
|Sales                                     |                                                   | $                      
|Cost of sales                             |                                                   |                        
|                                         
|Gross profit                              |                                                   |                        
|                                         
|Operating expenses:                       |                                                   |                        
|                                          | Operating expense                                 |                        
|                                          | Restructuring charges                             |                        
|                                          | Impairment charges and net loss on sale of assets |                        
|                                          | Depreciation and amortization expense             |                        
|                                         
|Total operating expenses                  |                                                   |                        
|                                         
|Other income (expense):                   |                                                   |                        
|                                          | Equity in earnings of investments                 |                        
|                                          | Other income (expense)                            |                        
|                                         
|Earnings (loss) before interest and taxes |                                                   | $                      
|                                         
|Identifiable assets                       |                                                   | $                      
|                                         

2002 versus 2001

Sales, Cost of Sales, and Gross Profit

Sales and cost of sales for our Capacity Services operations decreased $205.2 million and $101.1 million, respectively, in 2002 compared to 2001, resulting in a
decrease in gross profit of $104.1 million. These decreases were primarily due to the following factors:



43

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Operating Expense

Operating expense increased $16.6 million due to increased operating costs from additional power plants and gas storage coming on line. This was partially offset by
lower compensation expense resulting from the elimination of incentive compensation in 2002.

Restructuring Charges

In 2002, we recorded restructuring charges of $6.2 million relating to the termination of certain interest rate swaps associated with the construction financings for our
Clay County and Piatt County power plants. As debt related to these facilities was paid down earlier than anticipated, our swaps were in excess of our outstanding debt. We therefore reduced our
position and realized the loss associated with the cancelled portion of the unfavorable swap.

Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets of $90.3 million included $42.1 million relating to the expected loss associated with either the sale or
contract termination of four electric turbines that will be sold or returned to the manufacturer in 2003, $21.9 million related to our exit from the Lodi gas storage investment,
$12.2 million related to fees and expenses associated with the termination of the Cogentrix acquisition, $7.9 million of goodwill that was impaired under SFAS 142 and
$6.2 million of other impairments.

Equity in Earnings of Investments

Equity in earnings of investments increased $23.9 million due to $10.4 million of continued strong operating performance from various independent power projects
and $7.1 million of increased earnings resulting from the recovery of accounts receivable that were reserved for in 2001.

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our Capacity Services operations increased $307.0 million and $219.5 million, respectively, in 2001 compared to 2000. Gross profit
increased $87.5 million. These increases were primarily the result of the following factors:



44

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Operating Expense

Operating expense increased $25.6 million in 2001 compared to 2000, primarily as the result of our GPU International acquisition in December 2000.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $6.0 million in 2001 compared to 2000, primarily as the result of our GPU International acquisition in
December 2000.

Equity in Earnings of Investments

Equity earnings of investments increased $10.2 million in 2001 compared to 2000. Approximately $11.6 million of this increase relates to the equity investments in
four independent power plants that we added as part of our acquisition of GPU International in December 2000.

Merchant Power Capacity Payments

We have cash obligations under long-term fixed capacity contracts that entitle us to generate power at power plants owned by others over the next 18 years.
See Note 23 to the Consolidated Financial Statements for a summary of these contracts. Due to reduced spark spreads and an oversupply of generation that are expected to continue in the
foreseeable future, it is unlikely that we will be able to recover the $101.3 million of capacity payments in 2003. Using current forecasted spark spreads for 2003, we expect to generate gross
profit of approximately $3.0 million (before considering hedges and previous forward sales of $19.8 million) to offset these capacity payments. These losses and cash outflows negatively
impact our financial condition and liquidity position. Because resources are limited and these arrangements are inconsistent with our long-term strategy, we are attempting to restructure
or terminate certain of these contractual obligations on terms mutually acceptable to us and our counterparties. The expected impact of our power capacity payments for 2003 are summarized below:

In millionsAnnual capacity payments

$
101.3Pretax income statement expected loss


78.5Amount capacity payments exceed cash inflows


61.9


Earnings Trend and Impact of Changing Business Environment

The merchant energy sector has been negatively impacted by the increase in generation capacity that became operational in 2002 and by the continued construction of additional
power plants over the next 18-month horizon. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. As a
result of the above factors and our change in strategy, we do not expect our Capacity Services unit to be profitable in the next 2 to 3 years.

We
attempt to optimize and hedge our power plants with forward contracts which qualify as derivative instruments. When we enter into these positions, they are accounted for at fair
market value under mark-to-market accounting. The hedges are an offset to our power plants, which use

45

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accrual accounting. Because different accounting rules are used on each side of the transaction, this can cause significant fluctuations in earnings with limited impacts on cash flow.

Three-Year ReviewWholesale Services

|                                          |                                                   | Year Ended December 31, |        
|----------------------------------------- | ------------------------------------------------- | ----------------------- | -------
|
|                                          |                                                  
|                                          |                                                   |                         |        
|Sales                                     |                                                   | $                       | (99.7  
|Cost of sales                             |                                                   |                         |       
|                                          |                                                  
|Gross profit (loss)                       |                                                   |                         | (99.7  
|                                          |                                                  
|Operating expenses:                       |                                                   |                         |        
|                                          | Operating expense                                 |                         |        
|                                          | Restructuring charges                             |                         |        
|                                          | Impairment charges and net loss on sale of assets |                         |        
|                                          | Depreciation and amortization expense             |                         |        
|                                          |                                                  
|Total operating expenses                  |                                                   |                         | 475.9  
|                                          |                                                  
|Other income (expense):                   |                                                   |                         |        
|                                          | Equity in earnings of investments                 |                         |        
|                                          | Other income (expense)                            |                         |        
|                                          |                                                  
|Earnings (loss) before interest and taxes |                                                   | $                       | (566.0 
|                                          |                                                  
|Identifiable assets                       |                                                   | $                       | 3,092.1
|                                          |                                                  

2002 versus 2001

Sales and Gross Profit

Sales and gross profit for our Wholesale Services operations decreased $742.5 million and $726.3 million, respectively, in 2002 compared to 2001. These decreases
were primarily due to the following factors:



46

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Due
to the rescission of EITF 98-10 as previously discussed, our gains and losses from energy trading contracts are now required to be shown on a net basis. To the extent
losses exceeded gains, as was our case in 2002, sales are shown as a negative number.

Operating Expense

Operating expense decreased $219.5 million primarily due to the elimination of incentive compensation expense in 2002 and lower compensation expense due to staff
reductions related to our exit of Wholesale Services.

Restructuring Charges

In connection with the exit from our wholesale energy trading business in 2002, we incurred $173.8 million of restructuring charges. These charges included
$61.1 million of severance and retention payments to terminated employees, $58.8 million of excess leasehold improvements and equipment that were expensed when we vacated the related
leased properties, $38.5 million of lease costs connected to future lease commitments, $9.0 million of losses associated with the exit from our retail aggregator loan business and
$6.4 million of other charges.

Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets consisted primarily of an impairment charge of $178.6 million related to goodwill associated with Wholesale Services
that became unrealizable due to our exit from wholesale energy trading.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $9.6 million due to the elimination of goodwill amortization, the write-off in 2001 of certain interactive
web-based assets and the 2002 restructuring charge on leasehold improvements and equipment that have now been fully expensed and therefore no longer subject to depreciation and
amortization.

Other Income (Expense)

Other income (expense) increased by $27.4 million primarily due to a decrease in accounts receivable sale program fees due to the cancellation of the program in early
2002 and lower interest paid on customer margin deposits in 2002.

47

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2001 versus 2000

Sales and Gross Profit

Sales and cost of sales for our Wholesale Services operations increased $153.3 million and decreased $37.8 million, respectively, in 2001 compared to 2000, while
gross profit increased $191.1 million in the same period. These fluctuations were primarily due to the following:



Operating Expense

Operating expense increased $56.5 million because our merchant business expanded during 2001 and our stronger performance in 2001 resulted in higher incentive
compensation expense. Also impacting operating expenses was the allocation of $10.8 million of expenses from Corporate and Other.

Impairment Charges and Net Loss on Sale of Assets

Impairment charges in 2001 included the write-off of approximately $35.0 million related to our trading exposures with Enron. While the $35.0 million
write-off represents our best estimate of our exposure based on our contracts with Enron, the ultimate outcome is subject to review by the bankruptcy courts.

Earnings Trend and Impact of Strategy Change

As previously stated, we began winding down and terminating our trading positions with our various counterparties during the third quarter of 2002. However, it will take a
number of years to complete the wind down while we continue to deliver gas under our long-term gas contracts. Because our trading book is predominantly hedged, we should experience little
in the way of earnings or losses other than the impacts from counterparty credit, the discounting or accretion of interest, or the termination or liquidation of additional trading contracts. However,
there may be earnings volatility associated with the runoff of a portion of our trading book representing

48

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highly customized, actuarial based products. These transactions are typically hedged using an actuarial approach similar to that used by the insurance industry and could have negative outcomes as
book obligations settle over time. As of December 31, 2002, we had ten contracts remaining in this portion of the portfolio, with the last contract expiring in 2006. Using a
long-term value at risk methodology, with a 95% confidence level, we would estimate $47 million of total exposure (potential losses) through 2006 related to these contracts.

Corporate Matters

Corporate and Other

The table below summarizes the Corporate and Other EBIT for the three years ended December 31, 2002. Corporate and Other primarily contains the retained costs of the
Company that are not allocated to the business units.

|                                          |                                                   | Year Ended December 31, |      
|----------------------------------------- | ------------------------------------------------- | ----------------------- | -----
|
|                                          |                                                  
|                                          |                                                   |                         |      
|Operating expenses:                       |                                                   |                         |      
|                                          | Operating expense                                 |                         | $    
|                                          | Restructuring charges                             |                         |      
|                                          | Impairment charges and net loss on sale of assets |                         |      
|                                          | Depreciation and amortization expense             |                         |      
|                                          |                                                  
|Total operating expenses                  |                                                   |                         | 22.1 
|                                          |                                                  
|Other income (expense):                   |                                                   |                         |      
|                                          | Equity in earnings of investments                 |                         |      
|                                          | Gain on sale of subsidiary stock                  |                         |      
|                                          | Other income (expense)                            |                         |      
|                                          |                                                  
|Earnings (loss) before interest and taxes |                                                   | $                       | (37.7
|                                          |                                                  
|Identifiable assets                       |                                                   | $                       | 690.3
|                                          |                                                  

2002 versus 2001

Restructuring Charges

Restructuring charges in 2002 includes $8.9 million of executive severance in connection with the separation agreements with our former Chief Executive Officer and Chief
Financial Officer.

Other Income (Expense)

Other income (expense) decreased $29.9 million in 2002 when compared to 2001. Included in 2002 was $5.9 million of foreign exchange and interest rate losses
relating to our original planned financing structure that was not consummated in connection with the Midlands acquisition. Also impacting 2002 were $3.4 million of foreign currency losses on
inter-company loans and $4.0 million of write-downs on certain technology related investments. We also paid approximately $2.4 million of fees in the fourth quarter of 2002 in connection
with the waiver of a covenant default on several bank financing agreements. In addition, in 2001 we allocated

49

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$10.8 million of additional expense to our merchant business that had no effect on the consolidated results. However, it was a favorable adjustment in 2001 that did not occur in 2002.

Interest Expense

Interest expense and minority interest in income of partnership and trusts increased $33.1 million in 2002 compared to 2001. Interest expense was higher primarily as a
result of the following:



These
increases were offset in part by lower rates on variable rate short-term and long-term debt and the retirement of $350.0 million of company-obligated
preferred securities in 2002. In addition, we retired $100.0 million of company-obligated preferred securities and $204.1 million of other long-term notes in
June 2001.

Income Tax Expense (Benefit)

Income taxes decreased $316.2 million in 2002 compared to 2001, primarily as a result of our loss before income taxes in 2002 as compared to record earnings in 2001.
However, the 2002 expected income tax benefit was significantly reduced as a result of the following factors.



50

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2001 versus 2000

Impairment Charges and Net Loss on Sale of Assets

In 2000 we recognized charges of $10.0 million related to certain information technology assets that are no longer used in the business, and $2.4 million related
to our decision to discontinue use of certain corporate identity intangibles.

Gain on Sale of Subsidiary Stock

In connection with the initial public offering of Aquila Merchant in April 2001, we sold 5.75 million of previously issued shares and realized a pretax gain of
approximately $110.8 million.

Other Income (Expense)

Other income (expense) increased $13.1 million primarily due to the allocation of $10.8 million of expenses to our merchant business that had no effect on the
consolidated results, but was a favorable corporate adjustment in 2001.

Interest Expense

Interest expense and minority interests in income of partnership and trusts increased $27.6 million in 2001 compared to 2000. This was primarily due to increased
long-term borrowings in late 2000 and early 2001 related to the acquisitions of our Alberta network, AlintaGas, St. Joseph Light & Power and GPU International.

Income Tax Expense

Income taxes increased $69.4 million in 2001 compared to 2000. This was primarily due to the increased earnings before income taxes in 2001 resulting from the factors
previously discussed. Our overall effective tax rate increased from 36.5% in 2000 to 42.5% in 2001. The increase in our effective tax rate was due primarily to the effect of increased minority
interest in income of subsidiaries, taxes on the gain recognized on the sale of our shares in Aquila Merchant, and valuation allowances on certain international losses.

Critical Accounting Policies

We have prepared our financial statements in conformity with accounting principles generally accepted in the United States. These statements include some amounts that are based
on informed judgments and estimates of management. Our significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements. Our critical accounting policies are
subject to judgments and uncertainties that affect the application of such policies. As discussed below, while we believe these financial statements include the most likely outcomes with regard to
amounts that are based on our judgments and estimates, our financial position and results of operations may be materially different when reported under different conditions or when using different
assumptions in the application of such policies. In the event estimates or assumptions

51

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prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. Our critical accounting policies include:

Sales Recognition.The portion of our sales related to our trading activities that qualify as derivatives under
SFAS 133 is recorded under the mark-to-market method of accounting. The market prices or fair values used in determining the value of our portfolio are our best
estimates utilizing information such as closing exchange rates, over-the-counter quotes, historical volatility and the potential impact on market prices of liquidating our
positions in an orderly manner over a reasonable period of time under current market conditions. As additional information becomes available, or actual amounts are determinable, the recorded estimates
are revised. As a result, operating results can be affected by revisions to prior accounting estimates.

Unbilled Utility Revenues.Sales related to the delivery of energy are generally recorded when service is rendered, or energy
is delivered to customers. However, the determination of sales is based on reading customers' meters, which occurs systematically throughout the month. At the end of each month, an estimate is made of
the amount of energy delivered to the customer after the date of the last meter reading and recorded as unbilled revenue. The unbilled revenue is calculated each month based on estimated customer
usage, weather factors, line losses and applicable customer rates.

Impairment of Long-Lived Assets.We review the carrying value of long-lived assets whenever events or
changes in circumstances indicate that such carrying values may not be recoverable in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment
or Disposal of Long-lived Assets." Unforeseen events and changes in conditions could indicate that these carrying values may not be recoverable and result in impairment charges. An
impairment loss is recognized only if the carrying amount of the long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is
not recoverable if it exceeds its future undiscounted cash flows. Once deemed impaired, the long-lived asset is written down to its fair value, which could be considerably less than the
carrying amount of future undiscounted cash flows. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature, a highly subjective
judgment. Fair value is generally determined by calculating the discounted future cash flows using a discount rate based upon our weighted average cost of capital. Significant judgments and
assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows, including long-term forecasts of the amounts
and timing of overall market growth. Changes in these estimates could have a material effect on the assessment of our long-lived assets.

Investments in Unconsolidated Subsidiaries.We account for our equity investments in accordance with Accounting Principles
Board No. 18, "The Equity Method of Accounting for Investments in Common Stock" (APB 18). APB 18 states that a loss in value which is considered other than temporary should be recognized. APB
18 states that if the current fair value of an investment is less than its carrying amount, this may indicate an other than temporary loss in the value of the investment. As discussed above,
determining fair market value is highly subjective, requiring significant judgments and assumptions. Changes in estimates could have a material effect on the assessment of our equity investments.

Goodwill and Other Intangible Assets.On January 1, 2002, we adopted Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142 we no longer amortize goodwill, but instead test it for impairment each year on
November 30, and if impaired, write it off against earnings at that time. Other intangibles are to be tested for impairment in accordance with SFAS 144 as discussed above. Goodwill is
tested for

52

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impairment by comparing the fair value of a reporting unit, determined on a discounted cash flow basis or other fair market value methods, with its carrying amount, including goodwill. If the fair
value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, then an
impairment loss is measured by comparing the implied goodwill (excess of the fair value of the reporting unit over the fair value assigned to its assets and liabilities) with the carrying amount of
that goodwill.

We
believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a critical accounting estimate because: (1) it is highly
susceptible to change from period to period because it requires us to make cash flow assumptions about future sales, operating costs and discount rates over an indefinite life; and (2) the
impact of recognizing an impairment could be material. Management's assumptions about future sales margins and
volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins and expenses, we use our
internal budgets. We develop our budgets based on anticipated customer growth, rate cases, inflation and weather trends.

Regulatory Accounting Implications.We currently record the economic effects of regulation in accordance with the provisions
of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Accordingly, our balance sheet reflects certain costs as regulatory
assets. We expect our rates will continue to be based on historical costs for the foreseeable future. However, if we no longer qualified for treatment under SFAS 71, we would make adjustments to the
carrying value of our regulatory assets and liabilities and would be required to recognize them in current period earnings. Total net regulatory assets at December 31, 2002 were
$137.4 million, including deferred purchased power costs of $82.1 million related to our Alberta, Canada electricity business.

Valuation of Deferred Tax Assets.We are required to assess the ultimate realization of deferred tax assets generated from
capital losses incurred on the sale of assets. This assessment takes into consideration tax planning strategies within our control, including assumptions regarding the availability and character of
future taxable income. At December 31, 2002, we have recorded $381.6 million of valuation allowances against deferred tax assets for which the ultimate realization of the tax asset is
mainly dependent on the availability of future capital gains. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as impacted by political changes in
federal income tax laws and upon the actual realization of the related tax assets.

Pension Plans.Our reported costs of providing non-contributory defined pension benefits (described in
Note 19 to the Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension
costs, for example, are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plan and
earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial
assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs. Pension plan assets are primarily made
up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension costs in future
periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs. As of
September 30, 2002, our average assumed discount rate was 6.71% and our average expected return on plan assets was 9.15%.

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The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase or
decrease in the percentage for each assumption, we and our actuaries expect that the inverse of this change would impact the projected benefit obligation (PBO) at December 31, 2002, and our
estimated annual pension cost (APC) on the income statement for 2003 by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change
in that assumption.

|Dollars in millions           |  | Change in AssumptionInc(dec) |   | Impact
on PBOInc(dec) |       | Impact
on APCInc(dec) |  
|----------------------------- |  | ---------------------------- | - | --------------------- | ----- | --------------------- | -
|                              | 
|                              |  |                              |   |                       |       |                       |  
|Discount rate                 |  | .25                          | % | $                     | (11.7 | )                     | $
|Rate of return on plan assets |  | .25                          | % |                       |      |                       | $
|                              | 

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LIQUIDITY AND CAPITAL RESOURCES

Overall

We are currently operating in a business environment that has substantially limited our ability to raise incremental capital through the bank and capital markets. As of
March 14, 2003, we had $486.4 million of unrestricted cash on hand, no available capacity under our current revolver and the following short-term debt, net of any collateral
held:

|In millions                           |                                               | Debt
Outstanding at
December 31,
2002 |       | Debt
Outstanding at
March 14, 2003 |   | Cash Collateral Held at March 14, 2003 |       | Net Amount
Outstanding at
March 14, 2003
|------------------------------------- | --------------------------------------------- | ------------------------------------- | ----- | ---------------------------------- | - | -------------------------------------- | ----- | ----------------------------------------
|                                     
|                                      |                                               |                                       |       |                                    |   |                                        |       |                                         
|Short-term debt:                      |                                               |                                       |       |                                    |   |                                        |       |                                         
|                                      | Revolving credit facilityUnited States(a)(b) |                                       | $     | 244.4                              |   | $                                      | 189.8 |                                         
|                                      | Turbine facility(a)                           |                                       |       | 43.4                               |   |                                        | 33.8  |                                         
|                                      | Bank borrowings and otherCanada              |                                       |       | 13.2                               |   |                                        | 14.1  |                                         
|                                     
|                                      | Subtotal                                      |                                       |       | 301.0                              |   |                                        | 237.7 |                                         
|                                     
|Current maturities of long-term debt: |                                               |                                       |       |                                    |   |                                        |       |                                         
|                                      | Clay County project notes(a)                  |                                       |       | 98.4                               |   |                                        | 75.3  |                                         
|                                      | Piatt County project notes(a)                 |                                       |       | 146.7                              |   |                                        | 126.6 |                                         
|                                      | Canadian denominated credit facilities(a)     |                                       |       | 78.6                               |   |                                        | 84.2  |                                         
|                                      | Australian notes(d)                           |                                       |       | 83.8                               |   |                                        | 22.3  |                                         
|                                      | Canadian asset securitization(c)              |                                       |       | 91.6                               |   |                                        | 99.3  |                                         
|                                      | Miscellaneous                                 |                                       |       | 31.6                               |   |                                        | 31.9  |                                         
|                                     
|                                      | Subtotal                                      |                                       |       | 530.7                              |   |                                        | 439.6 |                                         
|                                     
|Total                                 |                                               | $                                     | 831.7 |                                    | $ | 677.3                                  |       | $                                       
|                                     



On April 11, 2003, we closed on a three-year senior secured financing of $430.0 million and a 364-day senior secured financing of
$100.0 million. The 364-day financing also includes an option under which we can, during a 30-day period following closing, at our discretion, increase the size of the financing by up to
$100.0 million. See Notes 12 and 13 to the Consolidated Financial Statements for additional information regarding the terms of the financings. Proceeds from the financings will be used
to retire debt and support existing and future letters of credit. The

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secured financings will eliminate the covenant violations stated below. With the above financings, we believe we will have sufficient liquidity to cover our operational needs through
June 2004. Our next significant need for outside capital relates to our need to retire senior notes maturing in 2004. We anticipate retiring these notes with proceeds from additional asset
sales. In the event we are not successful in closing the asset sales, we would need to obtain a bridge loan to meet these obligations. Although no assurance can be given on the above actions, we
expect to be successful in their execution.

Financing and Debt Covenants

On April 12, 2002, we entered into a new revolving credit facility totaling $650 million that replaced a $400 million credit facility. The new credit
facility consisted of two $325 million agreements, one with a maturity date of 364 days, the other three years. At December 31, 2002, we had $244.4 million of revolving
bank loan borrowings outstanding and $195.6 million of letters of credit issued against the facility.

As
explained in Note 12 of the Consolidated Financial Statements, we received waivers in the third quarter from lenders under our revolving credit facilities and other credit
arrangements from the requirement that we maintain a certain interest coverage ratio. In exchange, we agreed to use a portion of the proceeds we received from certain asset sales to reduce our
obligations to those lenders. Such prepayments on our revolving credit agreements reduced, on a dollar-for-dollar basis, the lenders' commitment to extend credit to us under
those agreements. As of December 31, 2002, we made payments of approximately $161.1 million against our revolver that in turn reduced our maximum borrowing limits to
$494.4 million and established a cash collateral balance of $5.5 million against our letters of credit. Between December 31, 2002 and March 14, 2003, we made additional
payments from asset sale proceeds of $109.2 million, further reducing our borrowing capacity to $439.8 million and increasing our cash collateral balance to $60.1 million. In
April 2003, debt outstanding under the 364-day credit facility was repaid in full and the unutilized portion of the three-year credit facility was terminated. The utilized portion of this facility is
only being used as support for our letters of credit currently outstanding. The lenders have agreed to (a) allow the letters of credit that are fully cash collateralized under the three-year
credit facility (and, thus, the facility itself) to remain outstanding and (b) waive certain restrictions for an additional three-week period. During the next three weeks, the Company intends
to replace the letters of credit issued under the three-year facility with new letters of credit under a different credit facility that will be fully cash collateralized.

Asset Sales Program

Earlier this year we initiated an extensive asset sales program to enhance our liquidity and, in light of our change in business strategy, dispose of non-core
assets. Following is a table of asset sales completed during 2002.

|In millions                       |       | Gross Proceeds
|--------------------------------- | ----- | --------------
|                                 
|                                  |       |               
|Gas gathering and pipeline assets |       | $             
|Lockport Energy                   |       |               
|UnitedNetworks                    |       |               
|U.K. gas storage                  |       |               
|Quanta Services investment        |       |               
|Gas storage facility              |       |               
|Merchant loan portfolio           |       |               
|Other assets                      |       |               
|                                 
|                                  | Total |               
|                                 

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Suspension of Dividend

In November 2002, the Board of Directors suspended the annual dividend on our common stock for an undetermined time. This decision stems from a detailed analysis of our
current financial condition, its liquidity forecast and its earnings prospects after completion of the asset sales program discussed above. Based on this analysis, the Board of Directors decided that
the most prudent course of action was to suspend the dividend until our financial condition and stability is
clarified. At this time we cannot predict when or if the Board of Directors will reinstate the dividend or, if reinstated, what the annualized dividend rate will be in the future. Our three-year
senior secured credit facility described in Note 13 to the Consolidated Financial Statements prohibits us from paying dividends if our senior unsecured debt is not rated at least Ba2 by Moody's
and BB by S&P.

Current Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing and the execution of our commercial strategies. Our financial
flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment grade borrowers. As of April 11, 2003, our senior unsecured
long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency                              |  | Rating |  | Commentary      
|----------------------------------- |  | ------ |  | ----------------
|                                   
|                                    |  |        |  |                 
|Moody's Investors Service (Moody's) |  | Caa1   |  | Negative Outlook
|Standard & Poor's Corporation (S&P) |  | B      |  | Negative Outlook
|Fitch Ratings (Fitch)               |  | B-     |  | Negative Outlook

During 2002, Moody's lowered our credit rating from investment grade of Baa3 to Ba2 negative outlook, a non-investment grade. Additionally, S&P
downgraded us to BB, a non-investment grade rating, from BBB, with a negative outlook and Fitch downgraded us to BB, from BBB -, with a negative outlook. In 2003, Moody's further
downgraded us to Caa1 and Fitch and S&P downgraded us to B- and B, respectively. As a result of these downgrades, we were required to post additional collateral to support certain loan and
operating contracts discussed below.

Ratings Triggers

We do not have any trigger events (e.g., an acceleration of repayment of outstanding indebtedness, an increase in interest costs or the posting of cash collateral) tied to our
stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events. Certain of our subsidiaries have trigger events tied to
specified credit ratings. Because of guarantee and cross default provisions between Aquila, Inc. and these subsidiaries, the ratings triggers of our subsidiaries discussed below should be
viewed as if they are directly applicable to Aquila, Inc.

In
2002, we retired $91.7 million of our Australian denominated notes that were put to us after the credit downgrades. Our Australian subsidiaries have three other outstanding
series of Australian denominated notes totaling $78.6 million at December 31, 2002. The holders of $62.9 million of these notes exercised their put rights and were repaid in
January 2003. The remaining notes totaling $15.7 million were repaid in April 2003.

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Aquila
Merchant also has three "tolling agreements," a construction loan and certain margining agreements that have trigger events tied to Aquila's credit ratings. Under the tolling
agreements, our subsidiary uses a third party's generation assets to convert fuel into electric power for its subsequent resale. As of March 14, 2003, we have posted collateral due to our
downgrades by Moody's and S&P of $82.3 million related to the tolling agreements, $27.5 million related to the construction loan, and $60.0 million related to standard margining
agreements.

Other Potential Demands for Collateral Due to Downgrades

Although we have substantially exited the wholesale energy trading business of Aquila Merchant, a number of energy trading agreements remain to be settled or liquidated. These
contracts consist of various long-term gas contracts, forward purchases and sales of gas and electricity, weather derivatives, alternative risk contracts, coal and other commodity trading
contracts that are difficult to liquidate. These contracts typically include provisions that allow counterparties to request additional collateral to support underlying transactions if events occur
that cause counterparties to believe that there has been deterioration in our creditworthiness. As a result of the downgrades, we provided collateral to certain counterparties in the form of cash
deposits or letters of credit totaling $145.0 million through March 14, 2003. While it is difficult to predict how many additional parties may successfully demand some form of
collateral, we currently estimate that the amount of additional cash collateral if S&P or Moody's were to downgrade us further would be minimal.

The
following table summarizes the collateral posted or debt repaid due to credit downgrades through March 14, 2003, and additional collateral or debt that may be required to be
posted or repaid in the future:

|In millions                   |       | Potential Amount |       | Amounts Posted/
Paid to Date
|----------------------------- | ----- | ---------------- | ----- | ----------------------------
|                             
|                              |       |                  |       |                             
|Australian denominated bonds  |       | $                | 170.3 |                             
|Tolling agreements            |       |                  | 82.3  |                             
|Construction loan             |       |                  | 27.5  |                             
|Standard margining agreements |       |                  | 62.0  |                             
|Other collateral demands      |       |                  | 145.0 |                             
|                             
|                              | Total |                  | $     | 487.1                       
|                             

In addition to collateral calls made due to credit downgrades, fluctuations in commodity prices can also cause both significant inflows and outflows of
collateral. This will vary depending on the magnitude of the price movement and the current position of our portfolio.

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Contractual Obligations

Long-Term Gas Contracts

Our obligations under our long-term gas delivery contracts that were paid to us in advance, will result in cash outflows and losses as outlined in the table below.
We are committed to meeting these obligations.

|In millions |  | Long-Term Gas Contract
Settlement(1) |       | Long-Term Gas Contract
Margin Loss(2) |   | Total Long-Term Gas Contract
Cash Payments(3)
|----------- |  | ------------------------------------ | ----- | ------------------------------------- | - | ---------------------------------------------
|           
|            |  |                                      |       |                                       |   |                                              
|2003        |  | $                                    | 81.5  |                                       | $ | 45.9                                         
|2004        |  |                                      | 84.9  |                                       |   | 48.1                                         
|2005        |  |                                      | 87.6  |                                       |   | 49.8                                         
|2006        |  |                                      | 90.9  |                                       |   | 52.2                                         
|2007        |  |                                      | 91.9  |                                       |   | 53.0                                         
|Thereafter  |  |                                      | 315.9 |                                       |   | 196.5                                        
|           
|Total       |  | $                                    | 752.7 |                                       | $ | 445.5                                        
|           



We
accounted for the cash payments in advance related to these contracts as long-term obligations. We recognize the relief of our obligation for these long-term
gas contracts as the gas is delivered to the customer under the units of revenue method. If we were to default on these obligations, or were unable to perform on them, we may be asked to pay the
issuers of the surety bonds on these arrangements an amount that is greater than the long-term gas contract balance on our Consolidated Balance Sheet. As of December 31, 2002, our
best estimate of this additional amount ranges from $68.0 million to $101.0 million, depending on the discount rate used. This difference arises due to our use of the units of revenue
method of relieving the long-term obligation versus a present value method that would likely be used by the sureties.

Merchant Power Plant Capacity Obligations

Our scheduled capacity payments for power generation in our Capacity Services business during 2003 aggregate approximately $101.3 million. Because it is generally
expected that the fuel and start-up costs of operating merchant power plants will exceed the revenues that would be generated from the power sales, we believe that our capacity to generate
power will largely be unutilized. If our tolling agreements that comprise a substantial portion of our capacity payments are not terminated or restructured on terms acceptable to our counterparties
and us, our

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earnings and liquidity will be severely impacted. We have communicated to certain counterparties the necessity that these agreements be terminated or restructured.

In millions

Capacity Payments2003

$
101.32004


101.32005


112.42006


120.22007


120.2Thereafter


1,508.1Total

$
2,063.5


Other Obligations

We also have contractual cash obligations including maturities of long-term debt, minimum payments on operating leases and regulated power, gas and coal purchase
contracts. See Note 23 to the Consolidated Financial Statements for further discussion of these obligations.

The
amounts of contractual cash obligations maturing in each of the next five years and thereafter are shown below:

|In millions                             |  | 2003 |       | 2004 |   | 2005  |  | 2006 |       | 2007 |   | Thereafter |  | Total
|--------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------- |  | -----
|                                       
|                                        |  |      |       |      |   |       |  |      |       |      |   |            |  |      
|Long-term debt obligations              |  | $    | 530.7 |      | $ | 431.8 |  | $    | 69.6  |      | $ | 103.8      |  | $    
|Operating leases obligations            |  |      | 47.4  |      |   | 41.6  |  |      | 22.6  |      |   | 16.9       |  |      
|Merchant gas transportation obligations |  |      | 8.8   |      |   | 8.8   |  |      | 8.8   |      |   | 8.6        |  |      
|Regulated purchase obligations          |  |      | 292.0 |      |   | 227.5 |  |      | 189.4 |      |   | 156.7      |  |      
|                                       
|Total                                   |  | $    | 878.9 |      | $ | 709.7 |  | $    | 290.4 |      | $ | 286.0      |  | $    
|                                       

Capital Expenditures

We estimate future cash requirements for capital expenditures for property, plant and equipment additions will be as follows:

|                    |                            | Actual |       | Future Cash Requirements
|------------------- | -------------------------- | ------ | ----- | ------------------------
|
|
|                   
|                    |                            |        |       |                         
|Domestic Utilities  |                            | $      | 154.5 |                         
|Everest Connections |                            |        | 101.0 |                         
|Canadian Utilities  |                            |        | 112.4 |                         
|Merchant Services   |                            |        | 168.5 |                         
|Corporate and Other |                            |        | 8.9   |                         
|                   
|                    | Total capital expenditures |        | $     | 545.3                   
|                   

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Legal Proceeding

On February 19, 2002, we filed a suit against Chubb Insurance Group, the issuer of surety bonds in support of certain of our long-term gas contracts.
Previously, Chubb had demanded that it be released from its surety obligation of up to $540 million or, alternatively, that we provide collateral to secure its obligation. We do not believe
that Chubb is entitled to be released from its surety obligations or that we are obligated to provide collateral to secure its obligations unless it is likely we will default on the contracts. Chubb
has not alleged that we are likely to default on the contracts. If Chubb were to prevail, it would have a material adverse impact on our liquidity and financial position. We rely on other sureties in
support of long-term gas supply contracts similar to those described above. There can be no assurance that these sureties will not make claims similar to those raised by Chubb. We have
performed under these contracts since their inception and intend to continue to fully perform on the contracts.

Cash Flows

Cash Flows from Operating ActivitiesCash flows from operating activities were significantly lower in 2002 compared to 2001,
primarily due to net losses in 2002 and the termination of our accounts receivable sales programs. Also impacting cash flows from operating activities was the payment of higher annual and
long-term incentive compensation based on the record earnings in 2001. In addition, we made payments of $39.3 million to our defined benefit pension plans to offset declines in plan
asset values due to market performance. Partially offsetting decreased cash flows in 2002 were cash collections related to price risk management assets.

Cash Flows from Investing ActivitiesCash flows used for investing activities included increased capital expenditures for
utility plant additions and merchant power generation construction. In addition, the acquisition of our interest in Midlands Electricity in May 2002 increased cash used for investing
activities. Offsetting these cash flows was $1.1 billion of cash received on the sale of assets and a reduction in Merchant capital expenditures.

Cash Flows from Financing ActivitiesCash flows from financing activities came primarily from our issuance of common stock and
senior notes. In January 2002, we issued 12.5 million shares of our common stock to the public, which raised approximately $277.7 million in net proceeds. We also sold
$287.5 million of 7.875% senior notes due in March 2032. The issuance of 37.5 million common shares and $500.0 million of senior notes in July 2002 raised
approximately $764 million. We used the proceeds of these issuances primarily to replace the liquidity formerly provided by the accounts receivables sale programs and to retire debt and
preferred securities.

Significant Balance Sheet Movements

Total assets decreased $2.7 billion in 2002 compared to 2001. This decrease is primarily due to the following:



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In
2002, total liabilities decreased by $1.5 billion, while company-obligated preferred securities decreased by $250.0 million and common shareholders' equity decreased
$943.7 million. These changes were primarily due to the following:



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New Accounting Standards

In 2002, the Emerging Issues Task Force issued EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 02-3). In 2002 and 2001, the Financial Accounting Standards Board (FASB) issued four new Statements of Financial Accounting
Standards (SFAS) that have potential impacts on our financial results: SFAS No. 142, "Goodwill and Other Intangible Assets;" SFAS No. 143, "Accounting for Asset Retirement Obligations,"
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and SFAS No. 148, "Accounting for Stock-Based CompensationTransition and
Disclosure." The FASB also issued Interpretation No. 45 regarding guarantees and Interpretation No. 46 regarding variable interest entities in 2002. See Note 2 to the Consolidated
Financial Statements for a further discussion.

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Effects of Inflation

In the next few years, we anticipate that the level of inflation, if moderate, will not have a significant effect on operations.

Forward-Looking Information And Risk Factors

This report contains forward-looking information, including statements that (i) our hedging activities will minimize losses in our remaining trading portfolio,
(ii) significant amounts of cash collateral provided to counterparties will be returned to us, (iii) our long-term liquidity plan calls for sales of international assets, the
restructuring of generation capacity obligations and refinancing of maturing debt and (iv) we do not believe that pending litigation or governmental investigations will result in outcome that
is materially adverse to us. The words "may," "will," "should," "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate," or the negative of these terms or similar expressions identify
further forward-looking statements.

These
forward-looking statements involve risks and uncertainties, and there are certain important factors that can cause actual results to differ materially from those anticipated. Some
of the important factors and risks that could cause actual results to differ materially from those anticipated include:



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Item 7a. Quantitative and Qualitative Disclosures About Market Risk

Market RiskTrading

We are exposed to market risk, including changes in commodity prices, interest rates and currency exchange rates. To manage the volatility relating to these exposures, we enter
into various derivative transactions in accordance with our policy approved by the Board of Directors. Our trading portfolios consist of natural gas, electricity, coal, global liquids, weather
derivatives and interest rate contracts that are settled by the delivery of the commodity or cash. These contracts take many forms, including futures, forwards, swaps and options. As we are winding
down our trading portfolio, many of these risks have been significantly reduced as the majority of our positions are hedged.

We
measure the risk in our trading portfolio using a value-at-risk methodology. The value at risk calculation utilizes statistics to determine the relationship
between the size of a potential loss and the probability of its occurrence, from holding an individual instrument or portfolio of instruments for a given period of time. The quantification of market
risk using value-at-risk methodologies provides a consistent measure of risk across diverse energy markets and products and is considered a "best practice" standard for this
application. The use of this methodology requires a number of key assumptions, including:



The
average value at risk for all commodities during the first six months of 2002 was $5.7 million, $1.8 million during the second half of the year and $3.8 million
for the full year. The $15.0 million value at risk limit approved by the Board of Directors has been revised downward at various times during 2002 by our Risk Management Committee and is
currently limited to $3.0 million for the remaining trading portfolio and a $5.0 million target for the aggregate book that includes the first 18 months of Capacity Services'
asset positions. In addition to value at risk, we also apply other risk control measures that incorporate volumetric limits by commodity, loss limits, durational limits and we perform stress testing
to our various risk portfolios.

All
Merchant interest and foreign currency risks are monitored within the commodity portfolios and value-at-risk calculation. The Merchant commodity portfolios
are valued on a mark-to-market basis that requires that the trading book be discounted on a net present value basis utilizing current interest rates. Because interest rate
movements impact the value of our trading portfolio, we actively hedge our interest rate exposures to limit these fluctuations.

65

---

The
table below shows the expected net cash flows associated with the interest rate financial instruments related to our trading portfolio at December 31, 2002.

|Dollars in millions    |  | 2003 |       | 2004 |   | 2005 |   | 2006 |     
|---------------------- |  | ---- | ----- | ---- | - | ---- | - | ---- | ----
|                       | 
|                       |  |      |       |      |   |      |   |      |     
|Variable to fixed rate |  | $    | (13.0 | )    | $ | (8.0 | ) | $    | (4.0
|Average rate paid      |  |      | 5.26  | %    |   | 5.47 | % |      | 5.97
|Average rate received  |  |      | 2.93  | %    |   | 2.93 | % |      | 3.03
|                       | 

Certain Trading Activities

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading activities that are
derivatives under SFAS 133 are accounted for under the mark-to-market method of accounting. Through October 2002, these contracts were accounted for under EITF
98-10 which also required the use of the mark-to-market method. Under SFAS 133, our energy commodity trading contracts, including physical transactions
(mainly gas and power) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of
counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market
prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. In addition, the market prices or fair values used in
determining the value of the portfolio are our best estimates utilizing information such as historical volatility, time value, counterparty credit and the potential impact on market prices of
liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When market prices are not readily available or determinable, certain contracts are
recorded at fair value using an alternative approach such as model pricing.

The
changes in fair value of our trading and other contracts for 2002 are summarized below:

|In millions                                                    |  | Wholesale
Services |        | Capacity
Services |   | Total |  
|-------------------------------------------------------------- |  | ------------------ | ------ | ----------------- | - | ----- | -
|                                                               | 
|                                                               |  |                    |        |                   |   |       |  
|Fair value at December 31, 2001                                |  | $                  | 415.2  |                   | $ | 175.7 |  
|Reduction in fair value during the year                        |  |                    | (65.6  | )                 |   | (24.4 | )
|Contracts realized or cash settledentered into in 2002        |  |                    | (4.4   | )                 |   | 29.5  |  
|Contracts realized or cash settledentered into in prior years |  |                    | (165.0 | )                 |   | (76.5 | )
|                                                               | 
|Fair value at December 31, 2002                                |  | $                  | 180.2  |                   | $ | 104.3 |  
|                                                               | 

66

---

The
fair value of contracts maturing in each of the next four years and thereafter are shown below:

|In millions                      |                                                    | 2003 |      | 2004 |   | 2005 |      | 2006 |      | Thereafter(a) |   | Total
|-------------------------------- | -------------------------------------------------- | ---- | ---- | ---- | - | ---- | ---- | ---- | ---- | ------------- | - | -----
|                                
|                                 |                                                    |      |      |      |   |      |      |      |      |               |   |      
|Wholesale Services:              |                                                    |      |      |      |   |      |      |      |      |               |   |      
|                                 | Prices actively quoted                             |      | $    | 45.9 |   | $    |     |      | $    |              |   | $    
|                                 | Prices provided by other external sources          |      |      |     |   |      | 30.7 |      |      | 27.3          |   |      
|                                 | Priced based on models and other valuation methods |      |      | 1.2  |   |      |     |      |      |              |   |      
|                                
|                                 | Fair value of contracts                            |      |      | 47.1 |   |      | 30.7 |      |      | 27.3          |   |      
|                                
|Capacity Services:               |                                                    |      |      |      |   |      |      |      |      |               |   |      
|                                 | Prices actively quoted                             |      |      | 28.6 |   |      |     |      |      |              |   |      
|                                 | Prices provided by other external sources          |      |      |     |   |      | 19.0 |      |      | 7.7           |   |      
|                                 | Priced based on models and other valuation methods |      |      |     |   |      |     |      |      |              |   |      
|                                
|                                 | Fair value of contracts                            |      |      | 28.6 |   |      | 19.0 |      |      | 7.7           |   |      
|                                
|Net price risk management assets |                                                    | $    | 75.7 |      | $ | 49.7 |      | $    | 35.0 |               | $ | 45.1 
|                                



Credit Risk

In conducting our network, energy marketing and risk management activities, we regularly transact business with a broad range of entities and a wide variety of end users,
energy merchants, producers and financial institutions. Credit risk is measured by the loss we would record if our counterparties failed to perform pursuant to the terms of their contractual
obligations less the value of any collateral held.

We
have established policies, systems and controls to manage our exposure to credit risk. This infrastructure allows us to assess counterparty creditworthiness, monitor credit exposures,
stress test the portfolio to quantify future potential credit exposures and catalogue collateral received by the company. In addition, to enhance the ongoing management of credit exposure, we have
used master netting agreements whenever possible. Master netting agreements enable us to net certain assets and liabilities by counterparty. In situations where the credit quality of counterparties
have deteriorated to certain levels, we will assert any contractual rights that allow us to secure our exposures by requesting collateral against these obligations.

A
natural result from our prior business strategy is the concentration of energy sector credit risk. Factors affecting this industry segment will affect the general credit quality of our
aggregate portfolio both positively and negatively. The result of energy industry downgrades of certain companies with significant energy merchant activity has reduced the overall credit quality of
our exposures in general.

The
following table details our credit exposures at December 31, 2002, associated with our forward positions within our trading portfolio and our billed receivables (excluding
residential

67

---

customers), netted by counterparty where master netting agreements exist and by collateral to the extent any is held.

|In millions             |       | Investment Grade |       | Non-investment Grade |   | Total
|----------------------- | ----- | ---------------- | ----- | -------------------- | - | -----
|                       
|                        |       |                  |       |                      |   |      
|Utilities and merchants |       | $                | 378.9 |                      | $ | 230.6
|Financial institutions  |       |                  | 271.0 |                      |   |     
|Oil and gas producers   |       |                  | 40.8  |                      |   | 48.6 
|Commercial/industrial   |       |                  | 12.0  |                      |   | 32.2 
|                       
|                        | Total |                  | $     | 702.7                |   | $    
|                       

Our
credit exposure will diminish significantly in April 2003 and April 2004 as contracts expire and the winter season concludes.

Currency Rate Exposure

We do not currently hedge our net investment in foreign operations. As a result, our foreign denominated assets and liabilities will fluctuate in value. Historically, our net
exposure to changes in foreign currency has been limited as our foreign investments have been financed largely through the local currency. However, as a result of our recent credit downgrades and debt
maturities, we have been required to repay certain foreign debt with other than local currency.

We
hedge the earnings of our foreign operations through financial "put" transactions. On average, we hedge 75% of our annual expected earnings from foreign operations. To the extent that
foreign currency dollars change in value against the U.S. dollar in countries in which we operate, the foreign currency "put" will offset the majority of this change.

The
table below summarizes the average value of foreign currencies used to value sales and expenses along with the related sensitivity.

|               |  |   |       |  |   |   | Average Currency Unit Value in U.S. Dollars
|-------------- |  | - | ----- |  | - | - | -------------------------------------------
|
|
|              
|               |  |   |       |  |   |   |                                            
|Australia      |  | $ | 512.7 |  | ± | $ | 2.8                                        
|Canada         |  |   | 264.7 |  | ± |   | 3.6                                        
|United Kingdom |  |   | 75.5  |  | ± |   | 2.7                                        
|              
|Total          |  |   |       |  | ± | $ | 9.1                                        
|              



Interest Rate Exposure

We have about $833.4 million in unhedged variable rate financial obligations. A 100-basis-point change in the variable rate financial instruments would
affect net income by approximately $5.0 million.

68

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Item 8. Financial Statements and Supplementary Data

|                                                                                                   |  |                                                      |  | Page No.
|-------------------------------------------------------------------------------------------------- |  | ---------------------------------------------------- |  | --------
|                                                                                                  
|                                                                                                   |  |                                                      |  |         
|Consolidated Statements of Income for the three years ended December 31, 2002                      |  | 70                                                  
|Consolidated Balance Sheets at December 31, 2002 and 2001                                          |  | 71                                                  
|Consolidated Statements of Common Shareholders' Equity for the three years ended December 31, 2002 |  | 72                                                  
|Consolidated Statements of Comprehensive Income for the three years ended December 31, 2002        |  | 73                                                  
|Consolidated Statements of Cash Flows for the three years ended December 31, 2002                  |  | 74-75                                               
|Notes to Consolidated Financial Statements:                                                        |  | 76                                                  
|Note 1:                                                                                            |  | Summary of Significant Accounting Policies           |  | 76      
|Note 2:                                                                                            |  | New Accounting Standards                             |  | 81      
|Note 3:                                                                                            |  | Risk Management                                      |  | 86      
|Note 4:                                                                                            |  | Restructuring Charges                                |  | 90      
|Note 5:                                                                                            |  | Impairment Charges and Net Loss on Sale of Assets    |  | 91      
|Note 6:                                                                                            |  | Discontinued Operations                              |  | 96      
|Note 7:                                                                                            |  | Restricted Cash                                      |  | 98      
|Note 8:                                                                                            |  | Accounts Receivable                                  |  | 99      
|Note 9:                                                                                            |  | Property, Plant and Equipment                        |  | 100     
|Note 10:                                                                                           |  | Investments in Unconsolidated Subsidiaries           |  | 100     
|Note 11:                                                                                           |  | Regulatory Assets                                    |  | 106     
|Note 12:                                                                                           |  | Short-Term Debt                                      |  | 108     
|Note 13:                                                                                           |  | Long-Term Debt                                       |  | 112     
|Note 14:                                                                                           |  | Long-Term Gas Contracts                              |  | 118     
|Note 15:                                                                                           |  | Company-Obligated Preferred Securities               |  | 119     
|Note 16:                                                                                           |  | Capital Stock and Stock Compensation                 |  | 119     
|Note 17:                                                                                           |  | Earnings Per Share                                   |  | 124     
|Note 18:                                                                                           |  | Income Taxes                                         |  | 125     
|Note 19:                                                                                           |  | Employee Benefits                                    |  | 127     
|Note 20:                                                                                           |  | Mergers, Acquisitions and Divestitures               |  | 130     
|Note 21:                                                                                           |  | Restatement of Consolidated Statements of Cash Flows |  | 131     
|Note 22:                                                                                           |  | Segment Information                                  |  | 133     
|Note 23:                                                                                           |  | Commitments and Contingencies                        |  | 137     
|Note 24:                                                                                           |  | Quarterly Financial Data (Unaudited)                 |  | 143     
|Report of Management                                                                               |  | 144                                                 
|Independent Auditors' Report                                                                       |  | 145                                                 

69

---

Aquila, Inc.
Consolidated Statements of Income

|                                                               |                                                      | Year Ended December 31,     
|-------------------------------------------------------------- | ---------------------------------------------------- | ----------------------------
|
|                                                              
|Sales:                                                         |                                                      |                             
|                                                               | Electricityregulated                                |                             
|                                                               | Natural gasregulated                                |                             
|                                                               | Electricitynon-regulated                            |                             
|                                                               | Natural gasnon-regulated                            |                             
|                                                               | Othernon-regulated                                  |                             
|                                                              
|Total sales                                                    |                                                      |                             
|                                                              
|Cost of sales:                                                 |                                                      |                             
|                                                               | Electricityregulated                                |                             
|                                                               | Natural gasregulated                                |                             
|                                                               | Electricitynon-regulated                            |                             
|                                                               | Natural gasnon-regulated                            |                             
|                                                               | Othernon-regulated                                  |                             
|                                                              
|Total cost of sales                                            |                                                      |                             
|                                                              
|Gross profit                                                   |                                                      |                             
|                                                              
|Operating expenses:                                            |                                                      |                             
|                                                               | Operating expense                                    |                             
|                                                               | Restructuring charges                                |                             
|                                                               | Impairment charges and net loss on sale of assets    |                             
|                                                               | Depreciation and amortization expense                |                             
|                                                              
|                                                               |                                                      | Total operating expenses    
|                                                              
|Other income (expense):                                        |                                                      |                             
|                                                               | Equity in earnings of investments                    |                             
|                                                               | Minority interest in income of subsidiaries          |                             
|                                                               | Gain on sale of subsidiary stock                     |                             
|                                                               | Other income (expense)                               |                             
|                                                              
|                                                               |                                                      | Total other income (expense)
|                                                              
|Interest expense:                                              |                                                      |                             
|                                                               | Interest expense                                     |                             
|                                                               | Minority interest in income of partnership and trust |                             
|                                                              
|                                                               |                                                      | Total interest expense      
|                                                              
|Earnings (loss) from continuing operations before income taxes |                                                      |                             
|Income tax expense (benefit)                                   |                                                      |                             
|                                                              
|Earnings (loss) from continuing operations                     |                                                      |                             
|Earnings (loss) from discontinued operations, net of tax       |                                                      |                             
|Cumulative effect of accounting change, net of tax             |                                                      |                             
|                                                              
|Net income (loss)                                              |                                                      | $                           
|                                                              
|Basic earnings (loss) per common share:                        |                                                      |                             
|                                                               | Continuing operations                                |                             
|                                                               | Discontinued operations                              |                             
|                                                               | Cumulative effect of accounting change               |                             
|                                                              
|                                                               | Net income (loss)                                    |                             
|                                                              
|Diluted earnings (loss) per common share:                      |                                                      |                             
|                                                               | Continuing operations                                |                             
|                                                               | Discontinued operations                              |                             
|                                                               | Cumulative effect of accounting change               |                             
|                                                              
|                                                               | Net income (loss)                                    |                             
|                                                              

See accompanying notes to consolidated financial statements.

70

---

Aquila, Inc.
Consolidated Balance Sheets

|                                            |                                               | December 31,
|------------------------------------------- | --------------------------------------------- | ------------
|
|                                           
|                                            |                                               |             
|Assets                                      |                                               |             
|Current assets:                             |                                               |             
|                                            | Cash and cash equivalents                     |             
|                                            | Restricted cash                               |             
|                                            | Funds on deposit                              |             
|                                            | Accounts receivable, net                      |             
|                                            | Inventories and supplies                      |             
|                                            | Price risk management assets                  |             
|                                            | Prepayments and other                         |             
|                                           
|Total current assets                        |                                               |             
|                                           
|                                            | Property, plant and equipment, net            |             
|                                            | Investments in unconsolidated subsidiaries    |             
|                                            | Price risk management assets                  |             
|                                            | Goodwill, net                                 |             
|                                            | Deferred charges and other assets             |             
|                                            | Non-current assets of discontinued operations |             
|                                           
|Total Assets                                |                                               | $           
|                                           
|Liabilities and Shareholders' Equity        |                                               |             
|Current liabilities:                        |                                               |             
|                                            | Current maturities of long-term debt          |             
|                                            | Short-term debt                               |             
|                                            | Accounts payable                              |             
|                                            | Accrued liabilities                           |             
|                                            | Price risk management liabilities             |             
|                                            | Current portion of long-term gas contracts    |             
|                                            | Customer funds on deposit                     |             
|                                           
|Total current liabilities                   |                                               |             
|                                           
|Long-term liabilities:                      |                                               |             
|                                            | Long-term debt, net                           |             
|                                            | Deferred income taxes and credits             |             
|                                            | Price risk management liabilities             |             
|                                            | Long-term gas contracts                       |             
|                                            | Minority interest                             |             
|                                            | Deferred credits                              |             
|                                           
|Total long-term liabilities                 |                                               |             
|                                           
|Company-obligated preferred securities, net |                                               |             
|Common shareholders' equity                 |                                               |             
|                                           
|Total Liabilities and Shareholders' Equity  |                                               | $           
|                                           

See
accompanying notes to consolidated financial statements.

71

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Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

|                                                                                                                                                                                                                                                                                                                                                          |                                                                                       | Year Ended December 31, |         
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------- | ----------------------- | --------
|
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                       |                         |         
|Common Stock:authorized 400,000,000 at December 31, 2002 and 2001, and 200,000,000 shares at December 31, 2000, par value $1 per share, 193,782,782 shares issued at December 31, 2002 (115,941,120
at December 31, 2001 and 100,350,977 at December 31, 2000); authorized 20,000,000 shares of Class A common stock, par value $1 per share, none issued |                                                                                       |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Balance beginning of year                                                             |                         | $       
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares in public offerings                                                |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares through Premium Equity Participating Security conversion           |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares through Aquila Merchant exchange offer                             |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares to acquire St. Joseph Light & Power                                |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares under compensation arrangements                                    |                         |         
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Balance end of year                                                                                                                                                                                                                                                                                                                                       |                                                                                       |                         | 193.8   
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Premium on Capital Stock:                                                                                                                                                                                                                                                                                                                                 |                                                                                       |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Balance beginning of year                                                             |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares in public offerings                                                |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares through Premium Equity Participating Security conversion           |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares through Aquila Merchant exchange offer                             |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of subsidiary common stock                                                   |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares to acquire St. Joseph Light & Power                                |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Issuance of shares under compensation arrangements                                    |                         |         
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Balance end of year                                                                                                                                                                                                                                                                                                                                       |                                                                                       |                         | 3,158.6 
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Retained Earnings (Deficit):                                                                                                                                                                                                                                                                                                                              |                                                                                       |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Balance beginning of year                                                             |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Net income (loss)                                                                     |                         |         
|                                                                                                                                                                                                                                                                                                                                                          | Dividends on common stock, $.775 per share in 2002 ($1.20 per share in 2001 and 2000) |                         |         
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Balance end of year                                                                                                                                                                                                                                                                                                                                       |                                                                                       |                         | (1,711.5
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Treasury stock, at cost 7,443 shares at December 31, 2002 (447 shares at December 31, 2001 and 40,441 shares at December 31, 2000)                                                                                                                                                                                                                        |                                                                                       |                         |        
|Accumulated other comprehensive losses                                                                                                                                                                                                                                                                                                                    |                                                                                       |                         | (33.0   
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      
|Total Common Shareholders' Equity                                                                                                                                                                                                                                                                                                                         |                                                                                       | $                       | 1,607.9 
|                                                                                                                                                                                                                                                                                                                                                          |                                                                                      

See accompanying notes to consolidated financial statements.

72

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Aquila, Inc.
Consolidated Statements of Comprehensive Income

|                                                                                                                                       |  | Year Ended December 31, |         
|-------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | --------
|
|                                                                                                                                       | 
|                                                                                                                                       |  |                         |         
|Net income (loss)                                                                                                                      |  | $                       | (2,075.1
|Unrealized translation adjustments, net                                                                                                |  |                         | 74.0    
|Unrealized cash flow hedges (net of deferred tax benefit (expense) of $10.8 million and $(.6) million for 2002 and 2001, respectively) |  |                         | (18.9   
|Unrealized market value gains on securities held for sale                                                                              |  |                         | 7.3     
|Additional minimum pension liability                                                                                                   |  |                         | (4.8    
|                                                                                                                                       | 
|Comprehensive income (loss)                                                                                                            |  | $                       | (2,017.5
|                                                                                                                                       | 

See accompanying notes to consolidated financial statements.

73

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Aquila, Inc.
Consolidated Statements of Cash Flows

|                                                   |                                                                                                       | Year Ended December 31, |                                                                                            
|-------------------------------------------------- | ----------------------------------------------------------------------------------------------------- | ----------------------- | -------------------------------------------------------------------------------------------
|
|
|
|                                                   |                                                                                                       |                         |                                                                                            
|Cash Flows From Operating Activities:              |                                                                                                       |                         |                                                                                            
|                                                   | Net income (loss)                                                                                     |                         | $                                                                                          
|                                                   | Adjustments to reconcile net income (loss) to net cash provided from (used for) operating activities: |                         |                                                                                            
|                                                   |                                                                                                       |                         | Depreciation and amortization expense                                                      
|                                                   |                                                                                                       |                         | Gain on sale of subsidiary stock                                                           
|                                                   |                                                                                                       |                         | Restructuring charges                                                                      
|                                                   |                                                                                                       |                         | Cash paid for restructuring charges                                                        
|                                                   |                                                                                                       |                         | Impairment charges and net loss on sale of assets                                          
|                                                   |                                                                                                       |                         | Net changes in price risk management assets and liabilities                                
|                                                   |                                                                                                       |                         | Deferred income taxes and investment tax credits                                           
|                                                   |                                                                                                       |                         | Equity in earnings of investments                                                          
|                                                   |                                                                                                       |                         | Dividends and fees from investments                                                        
|                                                   |                                                                                                       |                         | Minority interests in income of subsidiaries                                               
|                                                   |                                                                                                       |                         | Changes in certain assets and liabilities, net of effects of acquisitions and divestitures:
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                      
|Cash (used for) provided from operating activities |                                                                                                       |                         | (297.0                                                                                     
|                                                   |                                                                                                      
|Cash Flows From Investing Activities:              |                                                                                                       |                         |                                                                                            
|                                                   | Additions to utility plant                                                                            |                         |                                                                                            
|                                                   | Merchant capital expenditures                                                                         |                         |                                                                                            
|                                                   | Net increases in merchant notes receivable                                                            |                         |                                                                                            
|                                                   | Investments in international businesses                                                               |                         |                                                                                            
|                                                   | Investments in domestic businesses                                                                    |                         |                                                                                            
|                                                   | Cash proceeds on sale of assets and subsidiary stock                                                  |                         |                                                                                            
|                                                   | Other                                                                                                 |                         |                                                                                            
|                                                   |                                                                                                      
|Cash provided from (used for) investing activities |                                                                                                       |                         | 344.8                                                                                      
|                                                   |                                                                                                      

74

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Aquila, Inc.
Consolidated Statements of Cash Flows (continued)

|                                                 |                                                                 | Year Ended December 31, |      
|------------------------------------------------ | --------------------------------------------------------------- | ----------------------- | -----
|
|
|
|                                                 |                                                                 |                         |      
|Cash Flows From Financing Activities:            |                                                                 |                         |      
|                                                 | Issuance of common stock                                        |                         |      
|                                                 | Issuance of subsidiary common stock                             |                         |      
|                                                 | Issuance (retirement) of company-obligated preferred securities |                         |      
|                                                 | Issuance of long-term debt                                      |                         |      
|                                                 | Retirement of long-term debt                                    |                         |      
|                                                 | Short-term borrowings, net                                      |                         |      
|                                                 | Cash received on long-term gas contracts                        |                         |      
|                                                 | Cash paid on long-term gas contracts                            |                         |      
|                                                 | Cash dividends paid                                             |                         |      
|                                                 | Other                                                           |                         |      
|                                                 |                                                                
|Cash provided from financing activities          |                                                                 |                         | 131.0
|                                                 |                                                                
|Increase (decrease) in cash and cash equivalents |                                                                 |                         | 178.8
|Cash and cash equivalents at beginning of year   |                                                                 |                         | 262.9
|                                                 |                                                                
|Cash and Cash Equivalents at End of Year         |                                                                 | $                       | 441.7
|                                                 |                                                                
|Supplemental cash flow information:              |                                                                 |                         |      
|                                                 | Interest paid, net of amount capitalized                        |                         | $    
|                                                 | Income taxes paid (refunded), net                               |                         |      
|                                                 |                                                                
|Liabilities assumed in acquisitions:             |                                                                 |                         |      
|                                                 | Fair value of assets acquired                                   |                         | $    
|                                                 | Cash paid for acquisitions                                      |                         |      
|                                                 | Stock issued for acquisitions                                   |                         |      
|                                                 |                                                                
|Liabilities assumed                              |                                                                 | $                       |     
|                                                 |                                                                

See
accompanying notes to consolidated financial statements.

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Aquila, Inc.
Notes to the Consolidated Financial Statements

Note 1: Summary of Significant Accounting Policies

Description of Business

Aquila, Inc. (Aquila), formerly UtiliCorp United Inc., is an international energy provider headquartered in Kansas City, Missouri. We operate in two business
groups, the Global Networks Group and Merchant Services, with four financial reporting segments. Global Networks Group is comprised of our Domestic Networks and International Networks segments, while
Merchant Services conducts business through two segments, Capacity Services and Wholesale Services.

Domestic
Networks operates primarily as Aquila Networks in the distribution and transmission of electricity and natural gas to retail and wholesale customers in seven states. Our
electric generation facilities supply electricity to our own distribution systems in three states. We also sell excess power to wholesale customers outside our service areas. During peak periods, we
buy energy in the wholesale market for our utility load. Domestic Networks also includes our communications business, Everest Connections, which provides local and long distance telephone, cable
television and high-speed Internet service to areas of greater Kansas City, and our investment in Quanta Services, Inc. (Quanta Services), based in Houston, Texas. Quanta Services
provides specialized construction and maintenance services to the utility, telecommunications and cable television industries. International Networks owns or has interests in foreign businesses that
distribute and transmit electricity and natural gas to retail and wholesale customers. International Networks operates in two Canadian provinces and has investments in Australia and the United
Kingdom. Our Canadian electric generation facilities supply electricity to our own distribution systems in Canada. In October 2002, we sold our investment in New Zealand.

Our
Merchant Services business operates as Aquila Merchant Services, Inc. (Aquila Merchant), which, until we began to wind down these operations during the second quarter of 2002,
marketed natural gas, electricity and other commodities throughout North America and Western Europe through its Wholesale Services business segment, which also included our capital services business.
We sold substantially all of the assets of our capital services business in December 2002 and now report its results as discontinued operations. Through the Capacity Services business segment,
Aquila Merchant currently owns, operates or contractually controls non-regulated electric power generation assets. Although we sold these businesses in 2002, we formerly owned natural gas
and gas liquids gathering, transportation, storage and processing assets. These operations are also reported as discontinued operations.

In
2000 and through April 2001, we owned 100% of Aquila Merchant. In April 2001, approximately 20% of Aquila Merchant's ownership was sold to the public. In
January 2002, we acquired all the outstanding public shares of Aquila Merchant in an exchange offer and merger. Aquila Merchant was consolidated in each year with a minority interest reflected
in 2001.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States required that we make certain estimates and
assumptions that affect: the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of December 31, 2002 and 2001, and the reported amounts of
sales and expenses during the three years ended December 31, 2002. Significant items subject to such estimates and

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assumptions include the carrying value of property, plant and equipment; the valuation of derivative instruments; valuation allowances for receivables and deferred income taxes; and assets and
liabilities related to employee benefits. Actual results could differ from those estimates and assumptions.

Principles of Consolidation

Our consolidated financial statements include all of our operating divisions and majority-owned subsidiaries for which we maintain controlling interests. We use equity
accounting for investments in which we have significant influence but do not control. We do not control certain investments in which our partners have substantive participating and protective rights.
This does not allow us to consolidate those investments. We eliminate inter-company accounts and transactions.

We
evaluate the carrying value of our equity method investments periodically or when there are specific indications of potential impairment, such as continuing operating losses or a
substantial
decline in market price if publicly traded. In assessing these investments, we consider the following factors, among others, relating to the investment: financial performance and near-term
prospects of the company, condition and prospects of the industry and our investment intent.

Issuances of Subsidiary Stock

In accordance with Securities Exchange Commission Staff Accounting Bulletin No. 51, we record the difference between the carrying amount of the parent's investment in a
subsidiary and the underlying net book value of the subsidiary, after a subsidiary stock issuance, as a gain or loss in our consolidated financial statements.

Property, Plant and Equipment

We initially record property, plant and equipment at cost. Repairs of property and replacements of items not considered to be units of property are expensed as incurred, except
for certain major repairs at our generating facilities that are accrued in advance as allowed by regulatory authorities. Depreciation is provided on a straight-line basis over the
estimated lives of the assets. When regulated property, plant and equipment is replaced, removed or abandoned, its cost, together with the costs of removal less salvage, is charged to accumulated
depreciation. See Note 9 for further information.

Goodwill

We have recorded goodwill, representing the excess of the cost of acquisitions over the fair value of the related net assets at the dates of acquisition. In accordance with
Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets", (SFAS 142) we no longer amortize goodwill effective January 1, 2002. These balances
are tested annually for impairment and if impaired, written off against earnings at that time. See Note 2 for further discussion.

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Sales Recognition

Utility Activities

Sales related to the delivery of gas or electricity are generally recorded when service is rendered or energy is delivered to customers. However, the determination of sales is
based on reading customers' meters, which occurs systematically throughout the month. At the end of each month, an estimate is made of the amount delivered to the customer after the date of the last
meter reading and recorded as unbilled revenue. The unbilled revenue is calculated each month based on estimated customer usage, weather factors, line losses and applicable customer rates.

Trading Activities

Transactions carried out in connection with trading activities that meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative and Hedging
Activities" (SFAS 133) are accounted for under the mark-to-market method of accounting. Through October 2002, these contracts were accounted for under Emerging
Issues Task Force Issue (EITF) No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 98-10) which also
required the use of the mark-to-market method. See Note 2 for further discussion regarding changes in the accounting for energy trading contracts in 2002. Under
SFAS 133, our energy commodity trading contracts, including both physical transactions and financial instruments, are recorded net in sales at fair value and shown on our Consolidated Balance
Sheets as Price Risk Management Assets and Price Risk Management Liabilities. As part of the valuation of our portfolio, we value our credit risks associated with the financial condition of
counterparties and the time value of money. We use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market prices are
not readily available, we contact brokers or other external sources or use comparable transactions to obtain current values of our contracts. When market prices are not readily available or
determinable, certain contracts are valued at fair value using an alternate approach such as model pricing. In addition, the market prices or fair values used in determining the value of our portfolio
are our best estimates utilizing information such as historical volatility and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time
under current market conditions. When the market value of the portfolio changes (primarily due to the effect of price changes, newly originated transactions and the settlement of existing
transactions), the change is immediately recognized as a gain or loss. We record the resulting unrealized gains or losses as Price Risk Management Assets or Price Risk Management Liabilities,
respectively.

Weather Derivatives

As part of our wholesale energy trading business, we historically entered into weather derivative contracts. However, due to our decision to exit this business, we no longer
enter into these types of transactions. We accounted for our weather derivatives in accordance with EITF No. 99-2, "Accounting for Weather Derivatives." This standard requires that
weather derivatives entered into for trading or speculative activities be accounted for at fair value, with subsequent changes in fair value reported in earnings.

Our
utility business also uses weather derivatives to offset inherent weather risks, but not for trading or speculative purposes. EITF No. 99-2 requires that we
account for these weather derivatives by recording an asset or liability for the difference between the actual and expected weather in the period (in cooling or heating degree days) multiplied by the
contract price.

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Funds on Deposit

Funds that we have on deposit with counterparties consist primarily of margin requirements related to commodity swaps and futures contracts. Pursuant to individual contract
terms with counterparties, deposit amounts required will vary with changes in market prices, credit provisions and various other factors. These are identified as Funds on Deposit in our Consolidated
Balance Sheets. Interest is earned on most funds on deposit. We also hold funds on deposit from counterparties in the same manner. These are identified as Customer Funds on Deposit in our Consolidated
Balance Sheets.

Accounts Receivable Sales Programs

We sold trade accounts receivables to third party issuers of receivable-backed securities on an ongoing basis and without recourse. The sale of the receivables was accounted
for under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (SFAS 140). We received a fee for the servicing of the receivables
sold. The loss on the sale of the receivables was based on their relative fair value at the date of the transfer and is included in Other Income (Expense) in our Consolidated Statements of Income. We
generally estimated fair value based on the present value of future expected cash flows, using our best estimate of the key assumptions, including credit losses, forward yield curves and discount
rates commensurate with the risks involved. These programs were terminated in 2002. See Note 8 for further discussion.

Inventories

Our inventories consist primarily of natural gas in storage, coal, materials and supplies that are valued at the lower of weighted average cost or market. See Note 2 for
further discussion of certain natural gas trading inventories that were accounted for at fair value during 2002.

Development Activity

We incur project-related development costs including feasibility studies, bid preparation, permitting and licensing that are expensed as incurred until the project is deemed to
be probable of development. At that point, we may capitalize costs incurred based on their nature. These costs may be recoverable through partners in the projects or other third parties, or classified
as an investment and recovered through future project cash flows.

Regulatory Matters

Our regulated utility operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Therefore our regulated utility operations recognize the effects of rate regulation and accordingly, have recorded regulated assets and liabilities to reflect the impact of regulatory orders or
precedent. See Note 11 for further discussion.

Long-Term Gas Contracts

We were paid in advance on certain long-term gas contracts for the future delivery of gas to municipal utilities over the subsequent 10 to 12 years. We
accounted for these contracts as long-term obligations. We recognize the relief of our obligations on these long-term gas contracts as gas is delivered to the customer under
the units of revenue method, which matches the

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revenue recognized with the forecasted volumes of gas to be delivered. See Note 14 for further discussion.

Income Taxes

We use the liability method to reflect income taxes on our financial statements. We recognize deferred tax assets and liabilities by applying enacted tax rates and regulations
to the differences between the carrying value of existing assets and liabilities and their respective tax basis and capital loss and tax credit carryforwards. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that the change in enacted. We amortize deferred investment tax credits over the lives of the related properties. See
Note 18 for further discussion.

Environmental Matters

We accrue environmental costs on an undiscounted basis when it is probable that a liability has been incurred and the liability can be reasonably estimated. Such accruals are
adjusted as further information develops or circumstances change.

Stock Based Compensation

We issue stock options to employees from time to time and account for these options under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" (APB 25). All stock options issued are granted at the common stock's then current market price. This means we record no compensation expense related to stock options. We also offer
employees a stock purchase plan that enables them to purchase our common stock at a 15% discount from the market price. See Note 16 for details of options granted each year.

Because
we record options and discounts under APB 25, we must disclose pro forma net income and earnings per share as if we reflected the estimated fair value of options and discounts as
compensation expense. For the years ended December 31, 2002, 2001 and 2000, our pro forma net income (loss) and diluted earnings (loss) per share would have been as follows:

|In millions, except per share amounts |                                                                                                        | 2002 |   | 2001     |   | 2000 |      
|------------------------------------- | ------------------------------------------------------------------------------------------------------ | ---- | - | -------- | - | ---- | -----
|                                      |                                                                                                       
|                                      |                                                                                                        |      |   |          |   |      |      
|Net income (loss):                    |                                                                                                        |      |   |          |   |      |      
|                                      | As reported                                                                                            |      | $ | (2,075.1 | ) | $    | 279.4
|                                      | Total stock-based employee compensation expense determined under fair value method, net of related tax |      |   | (6.2     | ) |      | (8.4 
|                                      |                                                                                                       
|                                      | Pro forma net income (loss)                                                                            |      | $ | (2,081.3 | ) | $    | 271.0
|                                      |                                                                                                       
|Basic earnings (loss) per share:      |                                                                                                        |      |   |          |   |      |      
|                                      | As reported                                                                                            |      | $ | (12.83   | ) | $    | 2.49 
|                                      | Pro forma                                                                                              |      |   | (12.87   | ) |      | 2.42 
|Diluted earnings (loss) per share:    |                                                                                                        |      |   |          |   |      |      
|                                      | As reported                                                                                            |      | $ | (12.83   | ) | $    | 2.42 
|                                      | Pro forma                                                                                              |      |   | (12.87   | ) |      | 2.34 
|                                      |                                                                                                       

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The
fair value of stock options granted in 2002, 2001 and 2000 was estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair values and
assumptions were as follows:

|                                      |  | 2002 |         | 2001 |   | 2000    |  
|------------------------------------- |  | ---- | ------- | ---- | - | ------- | -
|                                      | 
|                                      |  |      |         |      |   |         |  
|Weighted average fair value per share |  | $    | 1.03    |      | $ | 5.08    |  
|Expected volatility                   |  |      | 51.60   | %    |   | 19.75   | %
|Risk-free interest rate               |  |      | 3.53    | %    |   | 5.06    | %
|Expected lives                        |  |      | 7 years |      |   | 8 years |  
|Dividend yield                        |  |      | 0.00    | %    |   | 3.93    | %
|                                      | 

Stock
options granted in 2001 by our Merchant Services subsidiary had a weighted average fair value of $22.75 per share on the grant date. This value is included in the total stock-based
employee compensation expense determined under fair value method, net of related tax, in the pro forma table above.

Cash and Cash Equivalents

Cash includes cash in banks and temporary investments with an original maturity of three months or less. As of December 31, 2002 and 2001, our cash held in foreign
countries was (in millions) $179.5 and $93.7, respectively.

Currency Adjustments

For income statement items, we translate the financial statements of our foreign subsidiaries and operations into U.S. dollars using the average exchange rate during the
period. For balance sheet items, we use the year-end exchange rate. When translating foreign currency-based assets and liabilities to U.S. dollars, we show any differences between accounts
as unrealized translation adjustments in common shareholders' equity. Currency transaction gains or losses on transactions executed in a currency other than the functional currency are recorded in the
Consolidated Statements of Income.

Reclassifications

Certain prior year amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2002 presentation. In particular, sales and cost of
sales have been reclassified to report energy trading gains and losses on a net basis pursuant to EITF No. 02-3 "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 02-3) as discussed in Note 2. Also, as discussed in Note 6, certain assets that have been sold and the
results of operations from those assets have been reclassified as discontinued operations in the accompanying balance sheets and statements of income for all periods presented.

Note 2: New Accounting Standards

Goodwill and Other Intangible Assets

On January 1, 2002, we were required to adopt SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 142 requires that goodwill no
longer be amortized to expense. Instead,

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goodwill must be tested for impairment at least annually and, if impaired, be written off against earnings at that time. We completed an initial assessment of the realizability of our goodwill and
determined that as of January 1, 2002, no goodwill impairments existed.

At
December 31, 2002 and 2001, we had goodwill of $318.6 million and $363.5 million, net of accumulated amortization of $19.0 million and
$28.3 million, respectively. Amortization expense for the years ended December 31, 2001 and 2000 totaled $19.1 million and $10.9 million, respectively. In addition, our
earnings from equity method investments included $17.6 million and $10.5 million of amortization expense for the years ended December 31, 2001 and 2000, respectively.
Approximately $3.3 million of goodwill amortization expense is included in earnings from discontinued operations for the years ended December 31, 2001 and 2000.

As
discussed in Note 16, $218.7 million of goodwill was recorded on the repurchase of Aquila Merchant in January 2002. We allocated $175.0 million of that
amount to Wholesale Services and $43.7 million to Capacity Services based upon future expected cash flows. As a result of our second quarter decision to exit the wholesale energy trading
business, we determined that all of the goodwill in Wholesale Services was impaired. Therefore, we recorded an impairment charge of $178.6 million in the second quarter of 2002. In addition, as
further discussed in Note 5, we recorded a total impairment charge of $696.1 million related to our investment in Quanta Services, Inc., including a $328.0 million goodwill
impairment charge related to this investment. When performing our annual assessment of the realizability of our remaining goodwill on November 30, 2002, we concluded that our remaining Capacity
Services goodwill was impaired and thus recorded an impairment charge for $7.9 million. As discussed in Note 5, as a result of changes in our future funding of Everest, we assessed the
realizability of its $21.6 million of goodwill and determined that it was also impaired. This goodwill was written off as an impairment charge in the fourth quarter of 2002.

In
connection with the sale of our interest in Lockport Energy, allocated goodwill from the repurchase of Aquila Merchant of $14.0 million was included in the basis used in
determining the loss included in Impairment Charges and Net Loss on Sale of Assets. Also, in connection with the sale of our gas gathering and pipeline assets and our gas storage facility,
$19.0 million and $26.7 million of goodwill, respectively, was included in the basis used in determining the 2002 loss from discontinued operations. See Note 6 for further
discussion.

Our
goodwill allocated to each segment at December 31, 2002 and 2001 is as follows:

|                                                       |                        | December 31,
|------------------------------------------------------ | ---------------------- | ------------
|
|                                                      
|                                                       |                        |             
|Goodwill, net:                                         |                        |             
|                                                       | Domestic Networks      |             
|                                                       | International Networks |             
|                                                       | Wholesale Services     |             
|                                                       | Capacity Services      |             
|                                                      
|                                                       |                        |             
|Goodwill in investments in unconsolidated subsidiaries |                        |             
|                                                      
|Total                                                  |                        | $           
|                                                      

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Following are disclosures of net income and earnings per share for the years ended December 31, 2001 and 2000, had goodwill not been amortized in those periods:

|                                            |  | Year Ended
December 31, 2001 |       | Year Ended
December 31, 2000
|------------------------------------------- |  | ---------------------------- | ----- | ----------------------------
|
|
|                                           
|                                            |  |                              |       |                             
|Reported net income                         |  | $                            | 245.3 |                             
|Goodwill amortization                       |  |                              | 19.1  |                             
|Goodwill amortization in equity in earnings |  |                              | 17.6  |                             
|                                           
|Adjusted net income                         |  | $                            | 282.0 |                             
|                                           
|Adjusted earnings per share:                |  |                              |       |                             
|Basic                                       |  | $                            | 2.51  |                             
|Diluted                                     |  |                              | 2.43  |                             
|                                           

Asset Retirement Obligations

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires us to record the fair
value of an asset retirement obligation as a liability in the period in which a legal obligation associated with the retirement of tangible long-lived assets is incurred. When the
liability is initially recorded, we capitalize the estimated cost by increasing the carrying amount of the related long-lived asset. The liability will be accrued to its present value each
subsequent period. The capitalized cost will be depreciated over the life of the related asset. Upon satisfaction of the liability, we will record a gain or loss for the difference between the actual
cost incurred and the recorded liability. This standard became effective for us on January 1, 2003.

The
adoption of SFAS 143 required our regulated utility business to recognize, where it is possible to estimate, the future costs to settle legal liabilities. These legal
liabilities include the removal of water intake structures on rivers, capping/filling of piping at levees following steam power plant closures, capping/closure of ash ponds, capping/closure of coal
pile bases, removal and disposal of storage tanks and PCB-containing transformers. We measured these liabilities based on internal engineering estimates of third party costs to remove the
assets in satisfaction of legal obligations, discounted using our credit adjusted risk free rates depending on the anticipated settlement date.

In
connection with the adoption of SFAS 143 in January 2003, our regulated business recorded an asset retirement obligation of $2.2 million and increased property,
plant and equipment, net of accumulated depreciation, by less than $100,000. Because this business is a regulated utility subject to the provisions of SFAS 71, the $2.2 million cumulative
effect of adoption of SFAS 143 was recorded as a regulatory asset and therefore had no impact on net income. The asset retirement obligation related to our non-regulated generation
assets was immaterial as of January 2003.

We
also have legal asset retirement obligations for certain other assets. It is not possible to estimate the time period when these obligations will be settled. As a result, the
retirement obligations cannot be measured at this time. These assets include certain assets within our electric and gas transmission and distribution systems that, pursuant to an easement or franchise

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agreement, are required to be removed if we discontinue our utility service under such easement or franchise agreement.

If
the provisions of SFAS 143 had been applied to our Consolidated Balance Sheets presented, our liability for asset retirement obligations would have been $2.2 million and
$1.9 million as of December 31, 2002 and 2001, respectively.

Impairment or Disposal of Long-Lived Assets

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144
addresses how and when to measure impairment on long-lived assets and how to account for long-lived assets that an entity plans to dispose of either through sale, abandonment,
exchange or a distribution to owners. Additionally, this statement expands the scope of discontinued operations and requires expected future operating losses from discontinued operations to be
recorded in the period in which the losses are incurred rather than when the plan of disposal is approved. SFAS 144 also requires that the respective income statements for current and prior
periods for components of an entity that have been disposed of, or that are carried as held for sale, be shown as the results from discontinued operations, less applicable income taxes, as a separate
component of income in the consolidated income statement. In addition, assets held for sale shall be presented separately in the consolidated balance sheet. This standard became effective for us on
January 1, 2002. See Note 5 for further discussion regarding impairment of assets. See Note 6 for information regarding discontinued operations.

Gas Storage Inventory

Effective January 1, 2002, we changed our method of accounting for our Merchant Services gas storage inventory (inventory used in daily trading activities) from the
lower of cost or market method to a fair value method. In connection with the exit of our wholesale trading activities, we sold our entire gas storage inventory used in daily trading activities during
the third quarter of 2002.

In
October 2002, the EITF reached a consensus in EITF 02-3, that inventories should no longer be marked-to-market through earnings beginning on
October 25, 2002. As discussed below, we adopted this standard in the fourth quarter of 2002. This would have resulted in an accounting change
from carrying our inventory at current market prices back to carrying our inventory at historical cost. However, as we sold our entire gas storage inventory used in trading activities prior to the
effective date, this change had no impact on our results of operations or financial position.

Energy Trading Activities

In June 2002, the EITF reached a consensus in EITF No. 02-3 that all realized and unrealized gains and losses on energy trading contracts be shown net
on the income statement whether or not they are settled physically. The adoption of this standard requires the reclassification of all prior period sales and cost of sales to reflect the net gains and
losses on energy trading contracts. This requirement became effective for financial statements issued for periods beginning after December 15, 2002. We adopted this requirement as of
September 30, 2002. The adoption of this requirement had no impact on our gross profit, but did result in a reduction of sales and cost of sales for all periods presented in the financial
statements.

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The
following table reconciles gross sales and cost of sales previously reported to sales and cost of sales reported after the effects of EITF 02-3 and the reclassification
of discontinued operations discussed in Note 6 for the years ended December 31, 2001 and 2000:

|               |                                                       | Year Ended December 31, |  
|-------------- | ----------------------------------------------------- | ----------------------- | -
|
|
|               |                                                      
|               |                                                       |                         |  
|Sales:         |                                                       |                         |  
|               | Previously reported gross sales                       |                         | $
|               | Sales netted per EITF 02-3                            |                         |  
|               | Sales reclassified to discontinued operations         |                         |  
|               |                                                      
|               | Reported net sales                                    |                         | $
|               |                                                      
|Cost of Sales: |                                                       |                         |  
|               | Previously reported gross cost of sales               |                         | $
|               | Cost of sales netted per EITF 02-3                    |                         |  
|               | Cost of sales reclassified to discontinued operations |                         |  
|               |                                                      
|               | Reported net cost of sales                            |                         | $
|               |                                                      

In
October 2002, the EITF met again and reached a consensus to require that all energy trading contracts that do not fall within the scope of SFAS 133, no longer be
marked-to-market through earnings, but be accounted for on the accrual basis of accounting. The consensus was effective for all new contracts executed after October 25,
2002, and required a cumulative effect of an accounting change be recognized for all contracts executed prior to October 25, 2002. We elected early adoption of this requirement on
October 1, 2002. The cumulative effect of this change was reported in the Consolidated Statements of Income as an additional loss before income taxes of $37.5 million, or
$22.7 million after tax.

Stock-Based Compensation

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." This statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation," to provide alternative methods of transition for voluntary changes to the fair-value based method of accounting for stock-based employee
compensation. This statement also requires certain disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation. We issue stock options
to employees and account for these options under the intrinsic value method under APB No. 25. Therefore, we record no compensation expense related to these options. We currently do not expect
to change our method of accounting for stock options and therefore, do not expect this standard to affect our financial results.

Guarantees

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34." This interpretation elaborates on the disclosures to be
made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The interpretation also clarifies that a guarantor is required to recognize, at
inception of a

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guarantee, a liability for the fair value of its obligation undertaken. The initial recognition and measurement provisions are applicable to guarantees issued or modified after December 31,
2002 and are not expected to have a material effect on our financial statements. The disclosure requirements are effective for financial statements for periods ending after December 15, 2002.
See Note 23 for further discussion.

Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51." This interpretation
addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately to interests in variable interest entities
created or obtained after January 31, 2003. The application of this interpretation is not expected to have an impact on our financial statements because no such entities currently exist.

Note 3: Risk Management

Overview

We use derivative financial instruments to reduce our exposure to adverse fluctuations in interest rates, foreign exchange rates, commodity prices and other market risks. We
also enter into derivative instruments in our energy trading business. Below we discuss these various types of instruments and our objectives for holding them.

Effective
January 1, 2001, we adopted SFAS 133 as amended, which requires us to recognize all derivative instruments on the balance sheet at fair value. It also established
new accounting rules
for hedging instruments, which depend on the nature of the hedge relationship. The adoption of SFAS 133 resulted in our recording transition adjustments to recognize derivative instruments at
fair value and to recognize the ineffective portion of the change in the fair value of the derivatives. The cumulative effect of these transition adjustments at January 1, 2001, was a reduction
to accumulated other comprehensive income (OCI) of approximately $4.5 million ($2.7 million net of tax). The reduction in OCI was related to cash flow hedges of forecasted foreign
currency transactions, future natural gas liquids production and variable interest rate obligations.

Trading Activities

During the second half of 2002, we exited from the wholesale energy trading business. Because of this decision, we liquidated many of our energy trading contracts in the
market. However, we were not able to liquidate all of our contracts. Our remaining energy trading contracts have been significantly hedged against changes in commodity prices. We are no longer a
market maker and no longer trade to take advantage of market trends and arbitrage opportunities. Trading activities now consist of optimizing assets we own or contractually control.

Prior
to exiting this business, we traded energy commodity contracts daily. Our trading activities attempted to match our portfolio of physical and financial contracts to current or
anticipated market conditions. Within the trading portfolio, we took certain positions to hedge physical sale or purchase contracts and to take advantage of market trends and conditions. We continue
to use all forms of financial instruments, including futures, forwards, swaps and options. Each type of financial instrument involves different risks. We believe financial instruments help

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us manage our remaining contractual commitments and reduce our exposure to changes in market prices.

We
record most energy contractsboth physical and financialat fair value in accordance with SFAS 133. Changes in value are reflected in the Consolidated
Statements of Income in Sales and on the Consolidated Balance Sheets in Price Risk Management Assets or Liabilities. We refer to these transactions as price risk management activities.

Market Risk

Our price risk management activities involve offering fixed price commitments into the future. The contractual amounts and terms of these financial instruments at
December 31, 2002 are below:

|                    |                               | December 31, 2002
|------------------- | ----------------------------- | -----------------
|
|
|
|                    |                               |                  
|Energy Commodities: |                               |                  
|                    | Natural gas (trillion Btu's)  |                  
|                    | Electricity (megawatt-hours)  |                  
|                    | Crude oil (barrels)           |                  
|                    | Natural gas liquids (barrels) |                  
|                    | Coal (tons)                   |                  
|Financial Products: |                               |                  
|                    | Interest rate instruments     |                  
|                   

We
have attempted to balance our remaining physical and financial contracts in terms of quantities and contract performance as our remaining trading portfolio winds down. To the extent
we are not hedged, we are exposed to fluctuating market prices that may adversely impact our financial position or results from operations.

Market Valuation

The prices we use to value price risk management activities reflect our best estimate of fair values considering various factors, including closing exchange and
over-the-counter quotations, time value of money and price volatility factors underlying the commitments. The prices also reflect the potential impact of liquidating our
position in an orderly manner over a reasonable period of time under present market conditions.

We
consider a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial
condition of counterparties and the time value of money. The values of all forward contracts are discounted to December 31, 2002, using market interest rates for the contract term adjusted for
our credit rating or the credit rating of the counterparty. We continuously monitor the portfolio and value it daily based on present market conditions. The following table displays the fair values of
Price

87

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Risk Management Assets and Liabilities at December 31, 2002, and the average value for the year ended December 31, 2002:

|            |  | Price Risk Management Assets |         | Price Risk Management Liabilities
|----------- |  | ---------------------------- | ------- | ---------------------------------
|
|
|
|            |  |                              |         |                                  
|Natural gas |  | $                            | 854.9   |                                  
|Electricity |  |                              | 244.2   |                                  
|Coal        |  |                              | 32.2    |                                  
|Other       |  |                              | 25.7    |                                  
|           
|Total       |  | $                            | 1,157.0 |                                  
|           

Our
Price Risk Management Assets are concentrated in five contracts representing 37% of the total asset value of the portfolio. We hold collateral from these counterparties representing
approximately half of the asset value. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, since the counterparties may be similarly
affected by changes in economic, regulatory or other conditions.

Hedging Activities

When we enter into financial instruments for hedging purposes, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the
risk management objectives and strategies for undertaking the hedge transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged,
fluctuations in the value of the derivative instruments are generally offset by changes in the value or cash flows of the underlying exposures being hedged. The fair values of derivatives used to
hedge or modify our risks fluctuate over time. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions
and the overall reduction in our risk relating to adverse fluctuations in foreign exchange rates, interest rates, commodity prices and other market factors. We also formally assess, both at the
inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the
related underlying exposures. Any ineffective portion of a financial instrument's change in fair value is recognized in Other Income (Expense). We discontinue hedge accounting prospectively when we
determine that a derivative is no longer effective in offsetting changes in
the fair value or cash flows of a hedged item, if the derivative or hedged item is sold, expires, terminated or is exercised or when management determines that designating the item as a hedging
instrument is no longer appropriate.

In
all cases, when hedge accounting is discontinued and the derivative remains outstanding, the derivative is carried at fair value on our balance sheet and changes in fair value are
included in current period earnings. When we discontinue hedge accounting because the hedged item has been terminated or sold, the accumulated gain or loss in OCI is reclassified into current-period
earnings.

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Fair Value Hedges

We use foreign currency hedging to reduce the risk that our eventual inflows or outflows of net U.S. dollar cash (resulting from inter-company financing transactions outside
the U.S.) will be adversely affected by changes in exchange rates. These contracts are accounted for as fair value hedges with changes in fair value recorded in Other Income (Expense) and Price Risk
Management Assets or Liabilities. The underlying financing transaction is also accounted for at fair value. During the year ended December 31, 2002, these fair value hedges were not 100%
effective. The earnings impact due to ineffectiveness was a $3.4 million loss for 2002.

Cash Flow Hedges

Our long-term debt contains a combination of fixed and variable rate instruments. Our policy is to fix the future cash flows related to this debt within defined
parameters. To accomplish this we use floating to fixed rate swaps. These swaps related to debt with a principal amount of $214.5 million and had maturities ranging from approximately two to
five years at December 31, 2002.

Changes
in the fair value of a derivative that is highly effective, that is designated and qualifies as a cash flow hedge are recorded in OCI to the extent that the derivative is
effective as a hedge. We recorded an $18.9 million decrease in OCI related to cash flow hedges in 2002, net of both taxes and reclassifications to earnings. This will generally offset future
cash flow gains relating to the underlying exposures being hedged. We estimate that we will reclassify into earnings $14.5 million of losses that are reported in OCI within the next
12 months. As of December 31, 2002, the fair value of cash flow hedges resulted in $28.2 million of unfavorable OCI ($18.0 million net of tax).

Regulated Commodity Management

Our domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute gas in seven states. All of our gas distribution utilities
have Purchased Gas Cost Adjustment (PGA) provisions that allow them to pass the cost of the commodity to the customer. To the extent that gas prices are higher or lower than amounts in our current
billing rates, adjustments are made on a periodic basis to "true-up" billed amounts to actual cost incurred.

In
our regulated electric business, we generate approximately 56% of the power that we sell and purchase the remaining 44% through long-term contracts or in the open market.
The regulatory provisions for recovering power costs vary by state. In Kansas, we have an Energy Cost Adjustment (ECA) that serves a similar purpose as the PGAs in place for the gas utility. To the
extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. For Colorado, we have an Incentive Clause
Adjustment (ICA) that provides for an equal sharing of the variability of energy costs between us and the customer. In Missouri, there is no provision to pass through changes in costs except through a
rate case filing. Variability in the cost of natural gas and coal used for the production of electricity and the price of power purchased in the open market can impact the stability of utility
earnings. We manage this commodity risk through a purchasing strategy designed to minimize the effect of variability in energy costs on earnings.

Our
other wholly owned distribution businesses are located in Canada. Our electric utility business in Alberta is a distribution company only, so fluctuations in power prices have no
direct

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effect on its earnings. In British Columbia, we generate and distribute power to the consumer and substantially all of the variation between our actual power cost and amounts billed is passed through
to the consumer on an annual basis during the following year.

To
the extent that recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

Note 4: Restructuring Charges

During 2002, we restructured Domestic Networks to align it more closely with its regulatory service areas and substantially exited our wholesale energy trading business due to
recent events in that industry and the increasing cost of capital required for that business. The reductions in employees that resulted from the restructuring, including employees transferred with the
sale of
businesses, consisted of approximately 1,205 Merchant Services employees, 75 Corporate employees, and 550 Domestic Networks employees.

Because
of these decisions, we recorded severance costs of $55.7 million during the year. Severance costs were accrued and charged to expense, but will be paid
bi-weekly over the term of the severance benefit. The amount of severance costs paid for the year ended December 31, 2002, was $39.1 million. The remaining liability for
severance costs as of December 31, 2002, was $16.6 million and is included in Accrued Liabilities in the Consolidated Balance Sheets. Certain employees of the wholesale energy trading
operations had retention agreements to ensure an orderly exit of the business. During 2002, we paid approximately $30.5 million of retention payments to these employees.

As
a result of these actions, we recorded the following restructuring charges during 2002:

|In millions                         |                                                    | Year Ended
December 31, 2002
|----------------------------------- | -------------------------------------------------- | ----------------------------
|                                   
|                                    |                                                    |                             
|Domestic Networks:                  |                                                    |                             
|                                    | Severance costs                                    |                             
|                                    | Disposition of corporate aircraft                  |                             
|                                   
|Total Domestic Networks             |                                                    |                             
|                                   
|Capacity Services:                  |                                                    |                             
|                                    | Interest rate swap reductions                      |                             
|                                   
|Total Capacity Services             |                                                    |                             
|                                   
|Wholesale Services:                 |                                                    |                             
|                                    | Severance costs                                    |                             
|                                    | Retention payments                                 |                             
|                                    | Lease agreements                                   |                             
|                                    | Write-down of leasehold improvements and equipment |                             
|                                    | Loss on termination of aggregator loan program     |                             
|                                    | Disposition of corporate aircraft                  |                             
|                                    | Other                                              |                             
|                                   
|Total Wholesale Services            |                                                    |                             
|Corporate and Other severance costs |                                                    |                             
|                                   
|Total restructuring charges         |                                                    | $                           
|                                   

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The disposition of the corporate aircraft primarily included the termination of applicable lease agreements and losses associated with the sale of our corporate aircraft. During 2002, we
also expensed certain leasehold improvements and equipment in our wholesale energy trading business that were no longer realizable based on management's best estimate of their fair value. As we began
downsizing our operations to match the future direction of the Company, we vacated various office facilities that were used in the wholesale energy trading operations with future lease commitments of
$86.7 million. During the year, we determined that $38.5 million of these leases would no longer be used and therefore recorded a restructuring charge for the estimated future net lease
cost after estimated sublease recoveries. Approximately $6.3 million of these excess lease costs were paid in 2002. The remaining liability for excess lease costs as of December 31,
2002, was $32.2 million and is included in Accrued Liabilities in the Consolidated Balance Sheets.

We
incurred a $6.2 million charge to exit portions of interest rate swaps related to the Clay County and Piatt County construction financing arrangements. As debt related to these
facilities was paid down earlier than anticipated due to debt covenant violations resulting from the restructure of our business, our interest rate swaps exceeded the outstanding debt. Thus we reduced
our position and realized the loss associated with the cancelled portion of the unfavorable swap. In connection with our exit from our wholesale energy trading business, we also incurred a
$9.0 million loss on the negotiated termination of certain aggregator loans to substantially complete our exit from that business.

Note 5: Impairment Charges and Net Loss on Sale of Assets

We recorded the following impairment charges and net loss on sale of assets for the years ended December 31, 2002, 2001 and 2000. After-tax losses in the
following paragraphs are reported after giving consideration to the effects of non-deductible goodwill or intangibles and capital loss

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carryback and carryforward limitations. As a result, the net tax effect may differ substantially from our expected statutory tax rates.

|                                                        |                                                         | Year Ended December 31,
|------------------------------------------------------- | ------------------------------------------------------- | -----------------------
|
|                                                       
|                                                        |                                                         |                        
|Domestic Networks:                                      |                                                         |                        
|                                                        | Quanta Services                                         |                        
|                                                        | Everest Connections and other communication investments |                        
|                                                        | Enron exposure                                          |                        
|                                                        | Gas distribution system                                 |                        
|                                                       
|Total Domestic Networks                                 |                                                         |                        
|                                                       
|International Networks:                                 |                                                         |                        
|                                                        | Midlands                                                |                        
|                                                        | Multinet and AlintaGas                                  |                        
|                                                        | Other                                                   |                        
|                                                       
|Total International Networks                            |                                                         |                        
|                                                       
|Capacity Services:                                      |                                                         |                        
|                                                        | Turbines                                                |                        
|                                                        | Exit from Lodi gas storage investment                   |                        
|                                                        | Termination of Cogentrix acquisition                    |                        
|                                                        | Capacity Services goodwill                              |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Capacity Services                                 |                                                         |                        
|                                                       
|Wholesale Services:                                     |                                                         |                        
|                                                        | Wholesale Services goodwill                             |                        
|                                                        | Enron exposure                                          |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Wholesale Services                                |                                                         |                        
|                                                       
|Corporate and Other:                                    |                                                         |                        
|                                                        | Information technology assets                           |                        
|                                                        | Corporate identity intangibles                          |                        
|                                                       
|Total Corporate and Other                               |                                                         |                        
|                                                       
|Total impairment charges and net loss on sale of assets |                                                         | $                      
|                                                       

During
2002, we also incurred $426.6 million of impairment charges and net loss on sale of assets relating to our discontinued operations. These charges are reflected in
discontinued operations and are not included in the table above. See Note 6 for further discussion.

Quanta Services

At June 30, 2002, the cost basis in our 38% equity investment in Quanta Services was approximately $26.69 per share and was significantly above the trading price of
Quanta Services' stock. On July 1, 2002, Quanta Services announced that it had reduced its earnings forecast due to a continued decline in the telecommunications industry, reduced utility
construction spending and financial difficulties surrounding Quanta Services' two largest customers. Quanta Services' share price dropped to approximately $3.00 per share after this announcement.
Because of these

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factors and the termination of our proxy contest for control of Quanta Services in May 2002, we concluded that there was an other-than-temporary decline in the fair
value of this investment. Accordingly, in the second quarter of 2002, we wrote the investment down by $692.9 million before tax, or $627.3 million after tax, to its estimated fair value
of $3.00 a share, or $87.7 million in total.

In
the second half of 2002, we sold approximately 17.6 million shares of Quanta stock at an average price of $2.75 per share for an additional pretax and after-tax
loss of $3.2 million, reducing our ownership percentage from 38% to 10.2%. As a result, we accounted for this asset as an available-for-sale security in accordance SFAS
No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS 115). Accordingly, at December 31, 2002, we recorded a $7.3 million increase in our investment and other comprehensive income to write our
investment up to $3.50 per share, the market price of Quanta's common stock at December 31, 2002. We sold our remaining 11.6 million shares in February 2003 at a net price of
$2.90 per share.

Everest Connections and Other Communication Investments

Due to liquidity concerns and our renewed focus on our North American utility operations, we made a decision in the fourth quarter of 2002 to reduce the future funding of
Everest Connections' (Everest) network build-out to levels necessary to complete construction in progress and serve existing customers. We evaluated the strategic alternatives for Everest
and chose to restructure the business so that going forward it is self-funded from operations. As a result of this change in strategy, we assessed this asset in accordance with
SFAS 144 using an undiscounted cash flow test. This test indicated that the asset was impaired. We then performed a probability-weighted discounted cash flow analysis and used other market
methods to estimate the fair value of this asset and recorded an impairment charge of $175.8 million before tax, or $107.6 million after tax, for the excess carrying value over fair
value.

We
also assessed the realizability of Everest's recorded goodwill and other intangibles in accordance with SFAS 142. This test indicated that the goodwill was impaired as the
carrying value of the business after the asset impairment above was greater than the enterprise fair value. We then performed a probability-weighted discounted cash flow analysis and used other market
methods to estimate the fair value of the assets and liabilities other than goodwill and intangibles. This assessment indicated that the goodwill of $21.6 million was fully impaired. We
therefore recorded a pretax and after-tax impairment charge of $21.6 million to write off the goodwill balance.

During
2002, we determined that certain cost and equity method investments in our communication technology-related businesses were impaired based on continuing losses in these
businesses, their continued failure to achieve operational goals, the inability of these businesses to obtain additional capital, and our assessment of the long-term prospects of these
businesses. Accordingly, we recorded a $23.1 million pretax impairment charge, or $13.9 million after-tax, relating to these investments in June 2002.

Certain
members of Everest have the option (put right) to sell their membership interests to us if Everest does not meet certain financial and operational performance measures as of
December 31, 2004. If the put rights were exercised, we would be obligated to purchase up to 4.0 million and 4.75 million membership interests at a price of $1.00 and $1.10,
respectively, for a total potential cost of $9.2 million. As a result of our reduced funding of this business, management assessed the likelihood of achieving these metrics and during 2002
recorded a

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probability-weighted expense of $7.1 million. As of December 31, 2002, we have provided for $7.8 million related to this obligation.

During
2001, we decided to limit our fiber-optic communications business to the Kansas City market. As a result, we wrote off $16.5 million related to network design,
long-term leases and other development costs related to markets outside of Kansas City that we currently do not intend to develop. In 2000, we recorded charges of $4.0 million
related to the construction of our communications networks.

Enron Exposure

In connection with the bankruptcy filing of Enron Corporation in December 2001, we evaluated our overall exposure with Enron and wrote off $31.8 million related
to an unsecured note receivable in Domestic Networks and $35.0 million related to trading activity in Wholesale Services. While these write-offs represent our best estimate of our
exposure based on our contracts with Enron, the ultimate outcome is subject to review by the bankruptcy courts.

Gas Distribution System

In the course of evaluating the need for rate relief in one of our gas jurisdictions, it became evident that certain costs would not be recoverable in rates. This was further
supported by commission orders. Accordingly, we assessed this asset in accordance with SFAS 144 using an undiscounted cash flow test. This test indicated that the asset was impaired. We then
performed a probability-weighted discounted cash flow analysis to estimate the fair value of this asset and recorded an impairment charge for the excess of the asset carrying value over fair value.
Accordingly, we recorded a pretax charge of $9.0 million, or $5.5 million after tax, related to this system.

Midlands

We purchased this investment in May 2002. See Note 10 for further discussion. The purchase price was based on our ability to hold the investment
long-term, which would allow us to use this investment as a base to extract synergies in future acquisitions and to continue to develop certain of its non-regulated businesses.
However, our liquidity situation in 2002 caused us to revise our strategic view of this investment. As a result, in August 2002, we initiated a bid process for the sale of our interest in
Midlands Electricity. We received offers in early December and are currently in negotiations with prospective buyers. Our evaluation of these offers indicated that this investment was impaired. The
impairment stems from our inability to hold the investment long-term and thus realize the benefits anticipated in our original analysis. We believe the decrease in value is other than
temporary. As a result, we recorded a pretax and after-tax
impairment charge of $247.5 million related to this investment. This impairment charge was determined based on the estimated fair value of this investment based on current market information,
which included offers obtained during the bid process, and is consistent with a corresponding impairment charge taken in the financial statements of the underlying business.

Multinet and AlintaGas

In 2002, we recorded a pretax impairment charge of $127.2 million, or $93.0 million after tax, related to our investments in Multinet Gas and AlintaGas in
Australia. Approximately $109 million of this pretax charge related to the Multinet Gas business in Melbourne, Australia. We acquired our interest in the Multinet gas distribution business in
1999. We have extracted

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significant synergies from this business as its service territory overlaps our existing electric distribution business in Melbourne. However, gas volumes normalized for the mild weather experienced
since 1999 have not met the expectations set for this business based on the historical information provided to us during the purchase process. Our liquidity situation and change in strategic direction
has caused us to change our intention to hold this investment for the long-term. As a result, we considered the current market value of this business, which included a recent proposal to
sell our interest in this business, as well as an impairment charge taken in the financial statements of the underlying business, to assess the realizability of our investment. We believe the decrease
in fair value was other than temporary.

The
remaining impairment charge was related to our investment in AlintaGas. We acquired this cornerstone stake in AlintaGas in October 2000 from the government of Western
Australia at a substantial premium over that paid by the public shareholders for the remaining shares. Our ability to recover this premium was based on our ability to optimize the operating
efficiencies in this business with our other Australian investments and to hold this investment for the long-term. While this business has performed very well, our liquidity situation and
change in strategic direction has caused us to change our view concerning the long-term nature of this investment. As a result, we considered the current market value of this business,
which included a recent proposal to sell this business, to assess the realizability of our investment. Our evaluation of these offers indicated the decrease in fair value was other than temporary.

In
2001, we recorded $11.5 million of pretax and after-tax charges in International Networks relating to certain Australian equity investments. We recorded charges
related to the collectibility of interest on shareholder loans to Multinet and the realizability of Multinet's deferred tax assets. Multinet also wrote off its interest receivable on shareholder loans
to Pulse Energy, an equity investment of both United Energy and Multinet. In addition, through our investment in United Energy, which owns approximately 66% of Uecomm, write-downs and provisions were
taken during the year related to the realizability of loans and interest due from Uecomm.

Turbines

As discussed in Note 12, we had a contract to acquire four GE turbines. Our intent was to place these turbines into future power plant development projects. However, due
to the restructuring of our business and change in our business strategy, we made the decision in the fourth quarter of 2002 to cease these development projects and to sell these turbines or return
them to the manufacturer. As a result, we incurred a $42.1 million pretax charge, or $25.5 million after tax, related to the expected loss on sale or contract termination related to
these turbines. During the first quarter of 2003, we sold two of these turbines for approximately their impaired value.

Exit from Lodi Gas Storage Investment

In August 2001, Aquila Merchant and a partner agreed to acquire a 12 Bcf gas storage facility under construction near Lodi, California. In October 2002, we exited
our investment in the Lodi project due to our exit from the wholesale energy trading business. We owned 50% of WHP Acquisition Company LLC, a company jointly established with an affiliate of ArcLight
Energy Partners Fund I, L.P. in 2001 to purchase Western Hub Properties LLC, the developer of the Lodi gas storage project. Under the settlement, WHP Acquisition Company LLC redeemed Aquila's
ownership interest for cash payments totaling $5.0 million over a five-year period. We were also released from all of our guarantee obligations relating to this transaction. We
recorded a $21.9 million pretax, or $21.6 million after-tax loss on this transaction.

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Termination of Cogentrix Acquisition

In August 2002, we agreed to terminate the purchase agreement we signed in April 2002 to acquire Cogentrix Energy, Inc., an independent power producer. We
agreed with Cogentrix that due to the current uncertainty of the electric power market, the deterioration of the creditworthiness of some of Cogentrix's customers and our exit from the wholesale
energy trading business, proceeding with the transaction was impractical and not in either company's interest. In connection with the termination of this transaction we expensed legal, consulting and
termination fees of $12.2 million, or $7.4 million after tax.

Capacity Services Goodwill

SFAS 142 requires that we test goodwill at least annually for impairment. We performed our annual SFAS 142 testing as of November 30, 2002. Due to reduced
spark spreads and an
oversupply of generation, the results of this test indicated a goodwill impairment. Therefore, we recorded an impairment charge of $7.9 million in the fourth quarter of 2002 to write off
Capacity Service's remaining goodwill balance.

Capacity ServicesOther

Included in other impairments for Capacity Services are three additional impairments or losses. In December 2002, we recorded a $4.2 million impairment charge on
one of our equity investments in a non-regulated power plant based on an other-than-temporary decline in fair value of this investment. In September 2002, we
completed the sale of our 16.58% interest in the Lockport Energy facility for $37.5 million. We recorded a $1.1 million pretax loss and a $5.8 million after-tax loss
on this sale. In October 2002, we sold our Hole House natural gas storage assets in the United Kingdom for $36.9 million. In connection with this sale, we recorded a pretax and
after-tax loss on disposal of $.9 million.

Wholesale Services Goodwill

In connection with our decision to exit our wholesale energy trading operations, we assessed our ability to realize the goodwill associated with our Wholesale Services
business. This assessment was based on our best estimate of the value of this business in a liquidation, which we determined was less than the carrying value of its net assets. Because future earnings
or sufficient sales proceeds could no longer support this asset, we wrote off the entire $178.6 million of unamortized goodwill in the second quarter of 2002.

Corporate and Other

In 2000, we recognized charges of $10.0 million related to certain information technology assets that are no longer used in the business and $2.4 million related
to our decision to discontinue use of certain corporate identity intangibles.

Note 6: Discontinued Operations

Consistent with our announced intention to sell $1 billion of assets, we have sold the following assets that are considered discontinued operations in accordance with
SFAS 144. See Note 2 for further discussion of this new standard. After-tax losses discussed below are reported after giving consideration to the effect of
non-deductible goodwill or intangibles and capital loss carryback and

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carryforward limitations. As a result, the net tax effect may differ substantially from our expected statutory tax rates.

Gas Storage Facility

In August 2002, we signed an agreement to sell our Texas natural gas storage facility for $180.0 million. After pricing adjustments, this transaction closed in
the fourth quarter of 2002 for $160.4 million. We recorded a pretax and after-tax gain of $4.3 million.

Gas Gathering and Pipeline Assets

In August 2002, we signed an agreement to sell our Texas and Mid-Continent natural gas pipeline systems, including our natural gas and natural gas liquids
processing assets, and our ownership interest in the Oasis Pipe Line Company, for $262.9 million. The transaction closed in October 2002. In connection with this sale, we recorded a
pretax loss of $240.3 million, or a $152.0 million after-tax loss.

Merchant Loan Portfolio

Historically, we provided capital to energy-related businesses seeking financing to fund energy projects. We offered this financing as an additional service as we continued to
expand as a risk management company. After we made the decision to exit the wholesale energy trading business, it was decided to sell our loan portfolio due to this business no longer being a part of
our core strategy. We sold substantially all of the loan portfolio in December 2002 for $258.5 million. In connection with this sale, we recorded a pretax loss of $184.0 million,
or $193.6 million after tax. Given the environment of the industry and our liquidity needs, we sold these loans at a substantial discount to their carrying value.

Coal Handling Facility

During the fourth quarter of 2002, we decided to dispose of our coal terminal and handling facility, Aquila Dock, Inc. As a result of the expected disposition of this
business, we recorded an estimated pretax impairment charge of $6.6 million and after-tax loss of $4.9 million, to reduce the carrying value of the assets to their fair value
less estimated selling costs. We sold this facility in February 2003.

Summary

We have reported the results of operations from these assets in discontinued operations for the three years ended December 31, 2002 in the Consolidated Statements of
Income. The related assets to be sold from these businesses have been reclassified as Non-Current Assets of Discontinued Operations on the December 31, 2002 and 2001 Consolidated
Balance Sheets.

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Non-Current
Assets of Discontinued Operations as of December 31, 2002 and 2001 are as follows:

|                                           |       | December 31,
|------------------------------------------ | ----- | ------------
|
|                                          
|                                           |       |             
|Property, plant and equipment, net         |       | $           
|Investments in unconsolidated subsidiaries |       |             
|Notes receivable, net                      |       |             
|Goodwill, net                              |       |             
|Deferred charges and other assets          |       |             
|                                          
|                                           | Total |             
|                                          

Operating
results of discontinued operations for the years ended December 31, 2002, 2001 and 2000 are as follows:

|                                             |                                                   | Year Ended December 31, |       
|-------------------------------------------- | ------------------------------------------------- | ----------------------- | ------
|
|                                             |                                                  
|                                             |                                                   |                         |       
|Sales                                        |                                                   | $                       | 235.3 
|Cost of sales                                |                                                   |                         | 164.8 
|                                             |                                                  
|                                             | Gross profit                                      |                         |       
|                                             |                                                  
|Operating expenses:                          |                                                   |                         |       
|                                             | Operating expense                                 |                         |       
|                                             | Impairment charges and net loss on sale of assets |                         |       
|                                             | Depreciation and amortization expense             |                         |       
|                                             |                                                  
|Total operating expense                      |                                                   |                         | 510.7 
|                                             |                                                  
|Other income (expense):                      |                                                   |                         |       
|                                             | Equity in earnings (losses) of investments        |                         |       
|                                             | Other income (expense)                            |                         |       
|                                             |                                                  
|Earnings (loss) before interest and taxes    |                                                   |                         | (386.5
|Interest expense                             |                                                   |                         | 5.6   
|                                             |                                                  
|Earnings (loss) before taxes                 |                                                   |                         | (392.1
|Income tax expense (benefit)                 |                                                   |                         | (62.5 
|                                             |                                                  
|Earnings (loss) from discontinued operations |                                                   | $                       | (329.6
|                                             |                                                  

Note 7: Restricted Cash

Our restricted cash is made up of margin deposits, asset sale proceeds held in escrow and cash collateral. During the year, certain counterparties required us to segregate the
customer funds on deposit that they had advanced to us from our daily cash accounts. This amount is considered "restricted cash" and not available for day-to-day operations.
The amount of these deposits at December 31, 2002 was $171.7 million. Also included in restricted cash is $239.9 million of cash proceeds from the sale of our Merchant loan
portfolio. These funds were temporarily placed in an escrow account until final resolution of sale contingencies. In January 2003, these funds were released from escrow. We used 50% of the
proceeds to pay down debt in accordance with our

98

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default waiver agreements with our lenders. The remaining 50% was used to provide additional liquidity. See Note 12 for further explanation of the waiver agreements.

Lastly,
under the terms of our leases surrounding the turbine facility and the Piatt County power plant as described in Notes 12 and 13, we were required to post cash collateral related
to the construction financing. As of December 31, 2002, we had posted cash collateral of $28.0 million and $54.3 million related to the turbine facility and Piatt County power
plant, respectively. The $82.3 million of cash collateral was applied against the debt on these projects in connection with the payoff of these loans in April 2003.

Note 8: Accounts Receivable

Our Accounts Receivable on the Consolidated Balance Sheets are comprised as follows:

|                                      |       | December 31, |        
|------------------------------------- | ----- | ------------ | -------
|
|                                      |      
|Merchant Services accounts receivable |       | $            | 1,485.1
|Regulated utility accounts receivable |       |              | 103.2  
|Other accounts receivable             |       |              | 7.9    
|Allowance for doubtful accounts       |       |              | (30.6  
|Unbilled utility revenue              |       |              | 107.2  
|Accounts receivable sale programs     |       |              |       
|                                      |      
|                                      | Total |              | $      
|                                      |      

Previously
we had two agreements allowing us to periodically transfer undivided ownership interests in a revolving pool of our trade receivables to multi-seller conduits administered by
independent financial institutions. One of these agreements was for up to $275 million of our Merchant Services receivables. The second, totaling up to $130 million, related to accounts
receivable generated from sales of gas and power by our domestic regulated utilities. However, due to the downgrades of our credit rating to non-investment grade, the buyers of these
receivables could no longer participate in the programs. As a result, these programs were cancelled in 2002.

Under
the terms of the agreements, we would sell trade receivables to bankruptcy-remote special purpose entities (SPEs). The SPEs were related to the financial institutions and were not
related to us. The percentage ownership interest in receivables purchased by the SPEs would increase or decrease over time, depending on the characteristics of the trade receivables, including
delinquency rates and debtor concentrations. We serviced the receivables transferred to the SPEs and received servicing fees that approximated market rates totaling (in millions) $.6, $2.9 and $3.0 in
2002, 2001 and 2000, respectively. Collections on these receivables were reinvested on behalf of the buyers in newly created receivables. We had gross sales of accounts receivable of (in billions)
$1.4, $4.1 and $4.5 during 2002, 2001 and 2000, respectively. Our Consolidated Statements of Income include the loss on the sale of receivables of (in millions) $2.5, $15.6 and $26.6 in 2002, 2001 and
2000, respectively.

The
allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable. We determine the allowance based on historical
write-off experience and detailed reviews of our accounts receivable agings.

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Note 9: Property, Plant and Equipment

The components of property, plant and equipment are listed below:

|                                                       |                                          | December 31,
|------------------------------------------------------ | ---------------------------------------- | ------------
|
|                                                      
|                                                       |                                          |             
|Electric utility                                       |                                          | $           
|Gas utility                                            |                                          |             
|Non-regulated electric power generation                |                                          |             
|Communications                                         |                                          |             
|Corporate                                              |                                          |             
|Electric and gas utility plantconstruction in process |                                          |             
|                                                      
|                                                       |                                          |             
|Lessaccumulated depreciation and amortization         |                                          |             
|                                                      
|                                                       | Total property, plant and equipment, net |             
|                                                      

|                                        |  | Composite Depreciation Rates |  
|--------------------------------------- |  | ---------------------------- | -
|                                        | 
|                                        |  |                              |  
|Electric utility                        |  | 4.0                          | %
|Gas utility                             |  | 3.4                          | %
|Non-regulated electric power generation |  | 2.9                          | %
|Communications                          |  | 10.4                         | %
|Other                                   |  | 9.3                          | %
|                                        | 

Note 10: Investments in Unconsolidated Subsidiaries

Our Consolidated Balance Sheets contain various equity investments as shown in the table below. The table below summarizes our investments, including shareholder loans, and
related equity earnings:

|                                       |       |         |  |                |  | Investment at December 31, |       | Equity EarningsYear Ended December 31, |  
|-------------------------------------- | ----- | ------- |  | -------------- |  | -------------------------- | ----- | --------------------------------------- | -
|
|
|                                       |      
|United Energy Limited                  |       | 33.8%   |  | Australia      |  | $                          | 252.0 |                                         | $
|Multinet Gas *                         |       | 25.5%   |  | Australia      |  |                            | 175.5 |                                         |  
|AlintaGas Limited                      |       | 22.5%   |  | Australia      |  |                            | 85.2  |                                         |  
|UnitedNetworks Limited                 |       | Sold    |  | New Zealand    |  |                            |      |                                         |  
|Midlands Electricity plc *             |       | 79.9%   |  | United Kingdom |  |                            | 75.5  |                                         |  
|Quanta Services, Inc. *                |       | 10.2%   |  | United States  |  |                            | 40.6  |                                         |  
|Independent power project partnerships |       | 20%-50% |  | U.S. & Jamaica |  |                            | 281.2 |                                         |  
|Other                                  |       | Various |  |                |  |                            | 4.9   |                                         |  
|                                       |      
|                                       | Total |         |  |                |  |                            | $     | 914.9                                   |  
|                                       |      

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United Energy Limited, Multinet Gas and AlintaGas LimitedWe acquired our initial investment in Australia in 1995. Our current
ownership interest in United Energy Limited (UEL), a publicly owned electric distribution company in Melbourne, Australia is 33.8%. UEL also owns a 66% interest in Uecomm Limited (UEC), a
communications business, and a 22.5% interest in AlintaGas Limited, a gas utility in Western Australia. At December 31, 2002, the market value of our net effective ownership in UEL was
$225.9 million.

In
March 1999, we acquired a 25.5% interest in Multinet Gas and Ikon Energy Pty Ltd (Ikon), a natural gas retail and distribution network in Melbourne, Australia. In
December 2001, we advanced an additional $81.9 million in the form of a loan to enable Multinet to repay certain external debt.

In
June 2000, UEL and Ikon closed a transaction that resulted in the formation of Pulse Energy, a joint venture with Shell Australia Ltd and Woodside Energy Ltd. UEL
contributed its electric retail customers in exchange for $210 million and Ikon contributed its gas retail customers in exchange for $281 million. UEL and Ikon each loaned Pulse
$70 million, and held a combined 50% ownership of Pulse.

In
September 2000, UEC, formerly a wholly owned subsidiary of UEL, sold 34% of its common stock to the public, reducing UEL's ownership share of UEC to 66%. As a
result, we recorded a $44.0 million gain from the public offering in Gain on Sale of Subsidiary Stock.

In
October 2000, we closed on our $166 million joint acquisition with UEL of a 45% cornerstone interest in AlintaGas Limited, a gas distribution utility in Western
Australia. The remaining 55% of the shares of AlintaGas were sold to the Australian public in an initial public offering in October 2000. Our 22.5% interest is reflected as an equity investment
with the remaining 22.5% reflected as part of our interest in UEL. At December 31, 2002, the market value of our net effective ownership in AlintaGas was $84.9 million.

In
2001, we also recognized charges totaling $11.5 million related to our investment in Multinet and Pulse that we classified in Impairment Charges and Net Loss on Sale of Assets.
See Note 5 for further discussion.

In
July 2002, UEL and Ikon sold their combined 50% interest in Pulse Energy, a retail electric and gas company. Through our 33.8% ownership in United Energy and our 25.5%
ownership in Ikon, we had an approximate 15% ownership in Pulse. UEL also sold its interests in EdgeCap, a marketing and trading business, and Utili-Mode, a provider of back office support
services for UEL and others. The sales of these three businesses closed in the third quarter and resulted in a $3.0 million pretax and after-tax gain.

As
discussed in Note 5, we recorded a pretax impairment charge of $127.2 million or $93.0 million after tax, related to our investments in Multinet Gas and AlintaGas
during the fourth quarter of 2002. We are currently exploring the possible sale of our Australian investments.

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Following
is the summarized financial information for UEL:

|                             |                         | December 31,
|---------------------------- | ----------------------- | ------------
|
|                            
|                             |                         |             
|Assets:                      |                         |             
|                             | Current assets          |             
|                             | Non-current assets      |             
|                            
|Total Assets                 |                         | $           
|                            
|Liabilities and Equity:      |                         |             
|                             | Current liabilities     |             
|                             | Non-current liabilities |             
|                             | Equity                  |             
|                            
|Total Liabilities and Equity |                         | $           
|                            

|                   |                    | Year Ended December 31,
|------------------ | ------------------ | -----------------------
|
|                  
|                   |                    |                        
|Operating Results: |                    |                        
|                   | Sales              |                        
|                   | Costs and expenses |                        
|                  
|Net Income         |                    | $                      
|                  

UnitedNetworks LimitedOur New Zealand investment represented our interest in UnitedNetworks Limited (UNL), New Zealand's
largest electric distribution company. We acquired our interests in the companies that became UNL between 1993 and 1998. In April 2000, UNL expanded its presence in the New Zealand energy
market by purchasing the natural gas distribution network and North Island contracting business of Orion New Zealand Limited for approximately $274 million.

Our
New Zealand investments were reflected on a consolidated basis from October 1998 to June 2000. In June 2000, we sold a portion of our New Zealand investment to a
private equity investor (minority shareholder) reducing our effective ownership in UNL to approximately 62%. In connection with the transaction, the minority shareholder received substantive
participating and protective rights. These rights included: the right to enforce 50% board representation at all times; super majority rights requiring 80% of the vote of the board and shareholders
regarding disposal of shares, capital expenditures, guarantees, securities issuances, amendments to by-laws, mergers and acquisitions, dividends and dissolution; and simple majority rights
requiring 51% of the vote regarding employment contracts, business plan and financial budget approval, disposal of property or investments, material capital expenditures, legal proceedings, tax claims
and appointment of the chairman of the board. We therefore did not consolidate these operations for financial statement purposes. In April 2001, additional shares of UNL were sold in New
Zealand to the public for net proceeds of approximately $41 million, reducing our effective interest in UNL to 55.5%. We recognized a $5.8 million pretax gain on this transaction.

In
October 2002, through a public tender offer in New Zealand, VECTOR Limited acquired all of the outstanding shares of UNL, in which we had a 70.2% indirect interest, for a
purchase

102

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price of NZ$9.90 per share. The sale resulted in US$489.1 million of net cash proceeds to us that were utilized to retire debt and pay associated income taxes. Prior to closing this
transaction, we repurchased our minority partner's 14.7% stake in UNL for approximately $38.5 million. We recorded a $130.5 million pretax gain, or $28.0 million
after-tax gain, in the fourth quarter of 2002 as a result of this sale.

Following
is the summarized financial information for UNL. The balance sheet as of December 31, 2002 is not included because we sold our investment in 2002:

|In millions                  |                         | December 31, 2001
|---------------------------- | ----------------------- | -----------------
|                            
|                             |                         |                  
|Assets:                      |                         |                  
|                             | Current assets          |                  
|                             | Non-current assets      |                  
|                            
|Total Assets                 |                         | $                
|                            
|Liabilities and Equity:      |                         |                  
|                             | Current liabilities     |                  
|                             | Non-current liabilities |                  
|                             | Equity                  |                  
|                            
|Total Liabilities and Equity |                         | $                
|                            

|                   |                    | Nine Months
Ended
September 30, |      | Year Ended
December 31,
|------------------ | ------------------ | ------------------------------- | ---- | -----------------------
|
|
|                   |                    |                                 |      |                        
|Operating Results: |                    |                                 |      |                        
|                   | Sales              |                                 | $    | 164.6                  
|                   | Costs and expenses |                                 |      | 119.0                  
|                  
|Net Income         |                    | $                               | 45.6 |                        
|                  

Midlands Electricity plcIn May 2002, we purchased from FirstEnergy Corporation a 79.9% economic interest in Avon
Energy Partners Holding Company, the holding company for Midlands Electricity, a United Kingdom electricity network. FirstEnergy retained the remaining 20.1% of Avon. Although we have since written
off substantially all of our investment, at the time of acquisition, the gross purchase price of the acquisition was valued at approximately $262 million, and was comprised of the following:

|In millions                                                                                                |                               |   |     |    
|---------------------------------------------------------------------------------------------------------- | ----------------------------- | - | --- | ---
|                                                                                                          
|Initial payment                                                                                            |                               | $ | 155 |    
|Transaction costs                                                                                          |                               |   | 20  |    
|Present value of promissory note to be paid in six annual payments of $19 million beginning on May 8, 2003 |                               |   | 87  |    
|                                                                                                          
|                                                                                                           | Total value of purchase price |   | $   | 262
|                                                                                                          

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Midlands is the fourth-largest regional electricity company in the United Kingdom, serving approximately 2.4 million network customers through a
38,000-mile distribution network. Midlands also owns a combined 884 megawatts of net generation capacity in the United Kingdom, Turkey and Pakistan. Pursuant to an operating services
agreement, we provide management and operating services to Midlands in exchange for a management fee.

In
connection with the acquisition, FirstEnergy retained substantive participating and protective rights as the minority partner. We and FirstEnergy each have 50% voting power and an
equal number of representatives on the Avon board of directors. Although we have the majority economic interest, FirstEnergy's participation in day-to-day business decisions is
significant, including approval of executive compensation, additional capital contributions, budgets, and the dissolution of the company. As such, we are required to account for this acquisition using
the equity method of accounting. FirstEnergy has the right to sell its interest in Midlands to us at fair market value if, at any time during the 30-day period prior to May 8, 2008,
the fair value of FirstEnergy's holdings is less than $72.8 million.

Recent
downgrades in credit ratings assigned to the public debt in the Midlands ownership chain have called into question the ability of Midlands to pay management fees and dividends to
us. Additionally, the local regulatory body, the Office of Gas and Electricity Markets (Ofgem), now
requires pre-approval of cash payments to the owners in the form of management fees or dividends. Accordingly, in 2003 and beyond, we intend to record equity earnings and management fees
only to the extent of cash received.

In
August 2002, Aquila and FirstEnergy initiated a bid process for the sale of Midlands. We received offers in early December and are currently in negotiations with prospective
buyers. As a result of these offers, our own internal analysis and the corresponding impairment charge at the investment level, we recorded a $247.5 million pretax and after-tax
impairment charge to write this investment down to its estimated fair value less costs to sell. See Note 5 for further discussion.

Following
is the summarized financial information for Midlands Electricity plc:

|In millions                  |                         | December 31,
2002
|---------------------------- | ----------------------- | -----------------
|                            
|                             |                         |                  
|Assets:                      |                         |                  
|                             | Current assets          |                  
|                             | Non-current assets      |                  
|                            
|Total Assets                 |                         | $                
|                            
|Liabilities and Equity:      |                         |                  
|                             | Current liabilities     |                  
|                             | Non-current liabilities |                  
|                             | Equity                  |                  
|                            
|Total Liabilities and Equity |                         | $                
|                            

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|In millions        |                    | Year Ended December 31, 2002 |       
|------------------ | ------------------ | ---------------------------- | ------
|                   |                   
|                   |                    |                              |       
|Operating Results: |                    |                              |       
|                   | Sales              |                              | $     
|                   | Costs and expenses |                              |       
|                   |                   
|Net Loss           |                    | $                            | (212.7
|                   |                   

Quanta Services, Inc.Between 1999 and 2001, we acquired voting convertible preferred and common stock of Quanta
Services, Inc. (Quanta Services) for approximately $719 million. Our fully converted beneficial voting interest in Quanta Services was approximately 38% at December 31, 2001. As
discussed in Note 5, during 2002 we determined that there was an other-than-temporary decline in the fair value of our Quanta Services investment and accordingly wrote
this asset down by $692.9 million to its estimated fair value of $3.00 a share. During the second half of 2002, we sold approximately 17.6 million shares at an average price of $2.75 per
share for an additional loss of $3.2 million, reducing our ownership from 38% to 10.2%. As a result, we accounted for this investment as an available-for-sale security
in accordance with SFAS 115. Accordingly, at December 31, 2002, we recorded a $7.3 million increase in our investment and other comprehensive income to write our investment up to
$3.50 a share, the market value of Quanta Services' stock at December 31, 2002. We sold our remaining 11.6 million shares of Quanta Services in February 2003 at a net price of
$2.90 per share.

Quanta
Services paid us management advisory fees of $36.2 million for 2000. The management fee agreement was terminated in December 2000. In addition, we used Quanta
Services as a construction contractor in our utility and communications businesses. These services were contracted under competitive bids at Quanta Services' standard rates for comparable services.
The cost of such services was (in millions) $24.8, $35.9 and $18.2 in 2002, 2001 and 2000, respectively.

Following
is the summarized financial information for Quanta Services. Due to the significance of the income statement impact from our investment in Quanta Services, we have attached
their financial statements for the three years ended December 31, 2002, as Exhibit 99.3.

|                             |                         | December 31,
|---------------------------- | ----------------------- | ------------
|
|                            
|                             |                         |             
|Assets:                      |                         |             
|                             | Current assets          |             
|                             | Non-current assets      |             
|                            
|Total Assets                 |                         | $           
|                            
|Liabilities and Equity:      |                         |             
|                             | Current liabilities     |             
|                             | Non-current liabilities |             
|                             | Equity                  |             
|                            
|Total Liabilities and Equity |                         | $           
|                            

105

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|                   |                    | Year Ended December 31,
|------------------ | ------------------ | -----------------------
|
|                  
|                   |                    |                        
|Operating Results: |                    |                        
|                   | Sales              |                        
|                   | Costs and expenses |                        
|                  
|Net Income (Loss)  |                    | $                      
|                  

Independent Power Project PartnershipsWe own interests in 12 independent power projects located in eight states and Jamaica.
These investments are aggregated because the individual investments are not significant. In 2002, we sold our interests in one of these projects, Lockport Energy, resulting in a $1.1 million
pretax loss. See Note 5 for further discussion of this sale.

Following
is the summarized financial information for our other unconsolidated equity investments. These investments consist of Multinet, AlintaGas and our independent power project
partnerships for the applicable years in which they were equity investments.

|                             |                         | December 31,
|---------------------------- | ----------------------- | ------------
|
|                            
|                             |                         |             
|Assets:                      |                         |             
|                             | Current assets          |             
|                             | Non-current assets      |             
|                            
|Total Assets                 |                         | $           
|                            
|Liabilities and Equity:      |                         |             
|                             | Current liabilities     |             
|                             | Non-current liabilities |             
|                             | Equity                  |             
|                            
|Total Liabilities and Equity |                         | $           
|                            

|                   |                    | Year Ended December 31,
|------------------ | ------------------ | -----------------------
|
|                  
|                   |                    |                        
|Operating Results: |                    |                        
|                   | Sales              |                        
|                   | Costs and expenses |                        
|                  
|Net Income (Loss)  |                    | $                      
|                  

Note 11: Regulatory Assets

Federal, state, provincial or local authorities regulate certain of our utility operations. Our financial statements therefore include the economic effects of rate regulation
in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). This means our Consolidated Balance Sheets show some assets and liabilities that would not
be found on the balance sheets of a non-regulated company.

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The
following table lists our regulatory assets and liabilities at December 31, 2002 and 2001. We primarily show these as Deferred Charges and Other Assets and Deferred Credits on
our Consolidated Balance Sheets.

|In millions             |                              | 2002 |       | 2001 
|----------------------- | ---------------------------- | ---- | ----- | -----
|                       
|                        |                              |      |       |      
|Regulatory Assets:      |                              |      |       |      
|                        | Purchased power costs        |      | $     | 82.1 
|                        | Under-recovered gas costs    |      |       | 19.8 
|                        | Income taxes                 |      |       | 97.7 
|                        | Environmental                |      |       | 15.3 
|                        | Regulatory accounting orders |      |       | 15.0 
|                        | Other                        |      |       | 16.9 
|                       
|                        | Total Regulatory Assets      |      |       | 246.8
|                       
|Regulatory Liabilities: |                              |      |       |      
|                        | Income taxes                 |      |       | 80.9 
|                        | Revenue subject to refund    |      |       | 8.8  
|                        | Over-recovered gas costs     |      |       | 8.9  
|                        | Pensions                     |      |       | 10.8 
|                       
|                        | Total Regulatory Liabilities |      |       | 109.4
|                       
|Net Regulatory Assets   |                              | $    | 137.4 |      
|                       

Regulatory assets are either currently being collected in rates or are expected to be collected through rates in a future period.



107

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Regulatory
liabilities represent items we expect to pay to customers through billing reductions in future periods.



If
all or a separable portion of our operations were deregulated and no longer subject to the provisions of SFAS 71, we would be required to write off our related regulatory assets and
liabilities, net of the related income tax effect, unless some form of transition cost recovery (refund) was established.

Note 12: Short-Term Debt

Short-term debt includes the following components:

|                                           |       | December 31,
|------------------------------------------ | ----- | ------------
|
|                                          
|                                           |       |             
|Bank borrowings and otherUnited States    |       | $           
|Turbine facility                           |       |             
|Bank borrowings and otherCanada           |       |             
|Commercial paper                           |       |             
|                                          
|                                           | Total |             
|                                          
|Weighted average interest rate at year end |       |             
|                                          

Revolving Credit Facility

On April 12, 2002, we entered into a new revolving credit facility totaling $650 million that replaced a $400 million credit facility. The new credit
facility consisted of two $325 million credit agreements, one with a maturity date of 364 days, the other three years. Our credit agreement contained restrictive covenants and charged
annual commitment fees ranging from .65% to .75%.

Debt Covenants

Certain of our finance arrangements, including our $650 million revolving credit facility, required that, subject to certain exclusions of non-cash gains or
losses, our earnings before interest, taxes, depreciation and amortization during the previous four quarters must be at least 2.25 times our interest expense during that same period. We refer to this
as our interest coverage ratio. These

108

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agreements also required us to maintain a ratio of total debt to total capitalization of less than 62.5%. We refer to this as our capitalization ratio. As a result of our operating performance, the
winding down of our wholesale energy trading business and our asset sales program, we were not
in compliance with our interest coverage ratio since September 30, 2002, or our capitalization ratio covenant since December 31, 2002.

We
obtained waivers from the affected lenders from the requirement to comply with our interest coverage ratio until April 12, 2003. This waiver required that 50% of any net cash
proceeds under $1 billion and 100% of any net cash proceeds above $1 billion (that were received prior to April 12, 2003, from any sales of our North American assets) would be
used to reduce our obligations to those lenders on a pro rata basis. Any cash proceeds that are used to reduce borrowings under these financing arrangements permanently reduced, on a
dollar-for-dollar basis, the amount of credit available to us under those agreements. We also agreed to make reasonable efforts to obtain approvals that would allow us to
pledge our regulated assets as security for the benefit of our lenders. We were required to pay fees of approximately $2.4 million to the lenders in connection with these waivers. We also
received additional waivers until April 12, 2003 of a covenant that requires us to maintain a certain capitalization ratio. We paid our lenders fees of approximately $1.2 million for
these additional waivers.

As
of December 31, 2002, we made payments of approximately $161.1 million to those lenders that in turn reduced our borrowings under the revolving credit facility to
$244.4 million and reduced our revolver capacity to $494.4 million and established a cash collateral balance of $5.5 million against our letters of credit. In addition to the
borrowings as of December 31, 2002, we had $195.6 million of letters of credit outstanding against our credit facility. Subsequent to December 31, 2002, we made additional
payments from asset sale proceeds of $109.2 million which further reduced our revolver capacity to $439.8 million and increased our cash collateralization of letters of credit to
$60.1 million. In April 2003, debt outstanding under the 364-day credit facility was repaid in full and the unutilized portion of the three-year credit facility was terminated. The utilized
portion of this facility is being used solely as support for our letters of credit currently outstanding. The lenders have agreed to (a) allow the letters of credit that are fully cash
collateralized under the three-year credit facility (and, thus, the facility itself) to remain outstanding and (b) waive certain restrictions for an additional three-week period. During the
next three weeks, the Company intends to replace the letters of credit issued under the three-year facility with new letters of credit under a different credit facility that will be fully cash
collateralized.

At
December 31, 2001, $135.0 million of domestic commercial paper was outstanding. Because our credit has deteriorated, we are no longer able to borrow funds under our
commercial paper program. The commercial paper program was supported by our prior credit agreement. We also had $310.0 million of borrowings outstanding under various uncommitted, unsecured
bank facilities at December 31, 2001.

Our
debt arrangements include syndicated bank debt, uncommitted bank lines, bonds (secured and unsecured) and financial guarantees that support subsidiary financings. The syndicated bank
debt, most bonds outstanding and financial guarantees contain cross-default provisions, which are usual and customary for these types of arrangements.

Turbine Facility

In May 2001, we entered into a five-year operating lease through a special purpose entity for 10 electric power plant turbines plus related equipment. Under
this agreement, we could lease up to

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$265 million in turbines and equipment. In June 2002, six of these turbines were transferred to the Piatt County power plant discussed in Note 13 and reduced the above facility
to $120.0 million. In our negotiations at the end of the third quarter to obtain waivers of our interest coverage ratio breach, we agreed to use 50% of the proceeds from asset sales to reduce
our obligations to the affected lenders on a pro rata basis. Any cash proceeds that are used to reduce borrowings under these financing arrangements permanently reduced, on a dollar-for-dollar basis,
the amount of credit available to us under those agreements. During the fourth quarter of 2002, we repaid $3.0 million of debt related to the turbine facility. Through March 14, 2003, we
paid an additional $9.7 million on these notes. Because of these debt repayments and the redemption of a portion of the special purpose entity's equity, this special purpose entity no longer
qualified for off-balance sheet treatment at December 31, 2002. We therefore consolidated $47.9 million of these assets and $46.0 million of related debt in the fourth
quarter of 2002. As of December 31, 2002, the total debt outstanding on the turbines was $43.4 million. As discussed in Note 7, we have posted $28.0 million of cash
collateral in support of these notes. These notes are scheduled to mature in 2005, however, as these notes were repaid in full in April 2003, we have classified the notes as short-term
debt.

364-Day Senior Secured Credit Facility

On April 11, 2003, we closed on a 364-day senior secured financing of $100.0 million. The borrower under the facility is UtiliCorp Australia, Inc., a wholly-owned
subsidiary of Aquila. The facility has an option under which we can for a 30-day period following closing, at our discretion, increase the size of the financing by up to $100.0 million. The
interest rate on this financing is the London Inter Bank Offering Rate (LIBOR) (with a 3% floor) plus 4.0% for the first 90 days. After the first 90 days, the interest rate increases an
additional 2% and will increase an additional 2% every subsequent 90 days with a maximum rate at maturity of LIBOR (with a 3% floor) plus 10%. In addition, we were required to pay up front
commitment and arrangement fees of $4.1 million. If we increase the size of the financing under the above option, an additional fee of up to $4.1 million would be required. Proceeds from
the financing were used to retire debt.

The
364-day term loan facility is secured by (i) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our interests in independent power projects,
(ii) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our Australian utility investments, (iii) a pledge of the equity of our two subsidiaries that own our
interests in our power plants in Clay County and Piatt County, Illinois, and (iv) a pledge, junior to that in favor of the lenders under the three-year facility, of the equity of
subsidiaries that indirectly hold our Canadian utility business. If we default on this loan, the lenders would be entitled to be fully repaid from the proceeds of this collateral before other
creditors could assert their claims against the collateral.

We
are required to use certain funds to prepay amounts outstanding under the 364-day facility. These include:



110

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Among
other restrictions, the 364-day facility contains the following debt covenants:



We
can voluntarily prepay amounts under the 364-day facility without penalty at any time. However, amounts that are repaid cannot be reborrowed. To the extent we default on any of our
loan covenants, our interest rate will increase an additional 2% during the default period.

Canadian Denominated Credit Facilities

As of December 31, 2002, we had three different revolving demand lines totaling C$60 million with two different banks at our Canadian networks businesses. As of
December 31, 2002 and 2001, we had outstanding borrowings of US$13.2 million and US$37.0 million, respectively, against these lines. At December 31, 2002, we also had
US$11.2 million in letters of credit issued against these lines.

As
of December 31, 2001, we had in place a C$150 million commercial paper program at our Canadian networks business. This program was supported by a C$150 million
credit facility. At December 31, 2001, US$66.6 million of commercial paper was outstanding. Effective in June 2002, this agreement was amended to reduce the available commercial
paper program and credit facility to C$112.5 million with annual commitment fees of .185%. As of December 31, 2002, no borrowings or commercial paper were outstanding under this
facility.

111

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Note 13: Long-Term Debt

This table summarizes the Company's long-term debt:

|                                                              |                                                                                       | December 31,
|------------------------------------------------------------- | ------------------------------------------------------------------------------------- | ------------
|
|                                                             
|                                                              |                                                                                       |             
|First Mortgage Bonds:                                         |                                                                                       |             
|                                                              | Various, 9.44%, due annually through 2021(c)                                          |             
|Senior Notes:                                                 |                                                                                       |             
|                                                              | 2.89% Floating Rate Series, due May 15, 2002                                          |             
|                                                              | Aquila Southwest Energy 8.29% Series, due September 15, 2002                          |             
|                                                              | 7.0% Series, due July 15, 2004                                                        |             
|                                                              | 6.875% Series, due October 1, 2004                                                    |             
|                                                              | 9.03% Series, due December 1, 2005                                                    |             
|                                                              | 6.70% Series, due October 15, 2006                                                    |             
|                                                              | 8.2% Series, due January 15, 2007                                                     |             
|                                                              | 7.625% Series, due November 15, 2009                                                  |             
|                                                              | 9.95% Series, due February 1, 2011                                                    |             
|                                                              | 14.875% Series, due July 1, 2012                                                      |             
|                                                              | 8.27% Series, due November 15, 2021                                                   |             
|                                                              | 9.0% Series, due November 15, 2021                                                    |             
|                                                              | 8.0% Series, due March 1, 2023                                                        |             
|                                                              | 7.875% Series, due March 1, 2032                                                      |             
|Medium Term Notes:                                            |                                                                                       |             
|                                                              | Various, 7.77%*, due 2005-2023                                                        |             
|Convertible Subordinated Debentures:                          |                                                                                       |             
|                                                              | 6.625%, due July 1, 2011 (convertible into 224,429 common shares at $15.79 per share) |             
|Other:                                                        |                                                                                       |             
|                                                              | Note Payable to FirstEnergy, 8.15%, due annually through 2008                         |             
|                                                              | Clay County Project Notes, 8.47%, due November 3, 2003 and 2007(c)                    |             
|                                                              | Piatt County Project Notes, 6.44%, due May 16, 2005(c)                                |             
|                                                              | Canadian Asset Securitization, 3.458%, due monthly to February 15, 2004(c)            |             
|                                                              | Canadian Secured Debentures, 8.145%*, due 2003-2023(c)                                |             
|                                                              | Canadian Senior Notes (U.S. Denominated), 7.75%, due June 2011                        |             
|                                                              | Australian Senior Notes, 6.72%*, due October 2002                                     |             
|                                                              | Australian Medium-term Notes, 6.35%*, due January-April 2003                          |             
|                                                              | New Zealand Floating Rate Notes, 5.67%, due April-October 2002                        |             
|                                                              | New Zealand Denominated Credit Facility, due June 2002                                |             
|                                                              | Australian Denominated Credit Facilities, due March 2004                              |             
|                                                              | Canadian Denominated Credit Facilities, due April 2003 and May 2005                   |             
|                                                              | Other notes and obligations(c)                                                        |             
|                                                             
|Total Long-Term Debt                                          |                                                                                       |             
|Less current maturities(a)                                    |                                                                                       |             
|                                                             
|Long-term debt, net                                           |                                                                                       | $           
|                                                             
|Fair value of long-term debt, including current maturities(b) |                                                                                       | $           
|                                                             



112

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The amounts of long-term debt maturing in each of the next five years and thereafter are below:

In millions

Maturing Amounts2003

$
530.72004


431.82005


69.62006


103.82007


56.1Thereafter


1,736.7Total

$
2,928.7


Senior Notes

In February 2002, we issued $287.5 million of 7.875% senior notes due in March 2032. These notes are callable by us at par after February 28, 2007.
Net proceeds from the sale were used to replace liquidity of $220.0 million previously provided from receivables sold in connection with one of our accounts receivable sales programs and to
retire short-term debt incurred for general corporate purposes.

In
July 2002, we issued $500.0 million of 11.875% senior notes due in July 2012. We used the proceeds from these offerings to repay borrowings under the revolving
credit facility, to retire $100.0 million of current maturities of company-obligated preferred securities and to increase our liquidity. Because Moody's and Standard & Poor's have
downgraded our credit ratings, the interest rate on these notes has been adjusted to a maximum rate of 14.875%.

In
February 2001, we issued $250.0 million of 7.95% senior notes due in February 2011. Net proceeds from the sale were used to reduce short-term debt
incurred for acquisitions and general corporate purposes. Because Moody's and Standard & Poor's have downgraded our credit ratings, the interest rate on these notes has been adjusted to a
maximum rate of 9.95%.

Three-Year Senior Secured Credit Facility

On April 11, 2003, we closed on a three-year senior secured financing of $430.0 million. The initial interest rate on the facility will be LIBOR (which has a 3%
floor) plus 5.75%. In addition, we were required to pay up front commitment and arrangement fees of $17.8 million. Proceeds from the financing will be used to retire debt and support existing
and future letters of credit.

The
three-year facility is secured by (i) $430.0 million first mortgage bonds issued under a new indenture that constitutes a lien on our existing and future
Michigan and Nebraska tangible utility network assets, (ii) a pledge of the equity of two wholly-owned subsidiaries that indirectly hold our Canadian utility business, and (iii) a
pledge, junior to that in favor of the lenders under

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the 364-day senior secured credit facility, of the equity of a wholly-owned subsidiary that indirectly holds our interests in independent power projects. If we default on this loan, the
lenders would be entitled to be fully repaid from the proceeds of this collateral before other creditors could assert their claims against the collateral.

We
have also committed to use reasonable efforts to obtain approvals that would provide these lenders additional utility assets as collateral for their loans. If, as a result of the
addition of any such collateral, the value of the collateral securing the indenture exceeds 167% of the loan secured by the indenture, the pledge of the Canadian equity interest may be released and
the interest rate would be reduced to LIBOR (which has a 3% floor) plus 5.00%.

We
are required to use certain funds to prepay amounts outstanding under the three-year facility unless the value of the collateral will, absent such payment, remain equal to
at least 200% of the outstanding loan amount under this facility (subject to certain reductions following certain events). These funds include:



In
addition, the $430.0 million senior secured debt would become immediately due and payable if we do not complete an exchange offer, tender offer, refinancing or other retirement
transaction with regard to 80% of the outstanding principal of our 7% senior note series due July 15, 2004
and our 6.875% senior note series due October 1, 2004, at least two weeks prior to their respective maturity dates.

Among
other restrictions, the senior secured facility contains the following debt covenants:



The
three-year facility also contains covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisition
and sale transactions, and restrictions on the amount that we can fund our unregulated merchant businesses and our Everest telecommunications business. In addition, we are prohibited from paying
dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by S&P, or if such a payment would cause a default under the
three-year facility.

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Amounts
under the three-year facility cannot be voluntarily prepaid except with payment of a make-whole amount. Amounts that are repaid cannot be reborrowed. To the extent we default on
any of our loan covenants, our interest rate will increase an additional 2% during the default period.

Debt Refinancing Exchange Offer

In June 2001, we exchanged $189.5 million of senior notes with interest rates ranging from 8.0% to 9.0% for $200.0 million of new Canadian senior notes
with interest rates at 7.75%, maturing in June 2011. Additionally, during 2001, we retired $204.1 million of senior notes, mortgage bonds and company-obligated preferred securities.

Note Payable to FirstEnergy

In connection with the acquisition of our interest in Midlands Electricity from FirstEnergy Corporation, described in Note 10, we issued a note payable to the seller,
FirstEnergy, for a portion of the purchase price. This note requires us to make annual payments of $19.0 million through May 2008. The note obligation was recorded at its net present
value at the date of acquisition, discounted at our incremental borrowing rate at that time of 8.15%. If we sell our interest in Midlands prior to the maturity of the note we would be required to pay
the remaining unpaid installments to FirstEnergy on an undiscounted basis.

Clay County and Piatt County Construction Financing

In November 2000, we entered into a $145.0 million lease through a special purpose entity to finance the 340-megawatt Clay County power plant, then
under construction. This plant was completed in 2002. In February 2002, we entered into an agreement to lease from a special purpose entity a $235 million, 510-megawatt power
plant that is being constructed in Piatt County, Illinois. We expect construction to be completed in June 2003. As discussed in Note 12, in our negotiations to obtain waivers regarding
our interest coverage ratio breach and consents with respect to asset dispositions, we agreed to use 50% of the proceeds from asset sales to reduce our obligations to the affected lenders on a pro
rata basis. Any cash proceeds that are used to reduce borrowings under these financing arrangements permanently reduced, on a dollar for dollar basis, the amount of credit available to us under those
agreements. During the fourth quarter of 2002, we repaid $34.5 million and $30.0 million of debt related to Clay County and Piatt County, respectively. Because of these debt repayments
and the redemption of a portion of the SPEs' equity, these SPEs no longer qualified for off-balance sheet treatment. Therefore we consolidated these assets and the related debt in the
fourth quarter of 2002, as summarized below:

In millions

Clay County

Piatt CountyCash and cash equivalents

$


$
8.1Funds on deposit





9.9Property, plant and equipment, net


138.5


169.4Total Assets

$
138.5

$
187.4Long-term debt

$
132.9

$
175.0Minority interest


5.6


12.4Total Liabilities

$
138.5

$
187.4


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The debt outstanding on the Clay County power plant was $98.4 million as of December 31, 2002, $84.1 million which was scheduled to mature on
November 3, 2003 and $14.3 million which was scheduled to mature on November 3, 2007. However, as a result of cash proceeds received on asset sales through March 14, 2003,
an additional $23.2 million of debt was repaid prior to April 2003.

The
debt outstanding on the Piatt County power plant was $146.7 million as of December 31, 2002. The debt was scheduled to mature on May 16, 2005. However, as a
result of cash proceeds received on asset sales through March 14, 2003, an additional $21.0 million of debt has been repaid. As discussed in Note 7, we provided
$54.3 million of cash collateral in support of this debt. The collateral was applied against the loan in connection with the retirement of this debt in April 2003.

As
the remaining balance under both the Clay County and Piatt County facilities were repaid in April 2003, we have classified both facilities as current maturities of
long-term debt.

Canadian Asset Securitization

In 2002, our Canadian network in Alberta entered into a securitization agreement under which certain deferred purchase power costs that are being recovered from customers
through a rate increase were sold to an unrelated financial institution. This securitization has been recorded as a financing and is secured by future rate collections. The amount securitized as of
December 31, 2002 was US$107.6 million, which bears interest at a fixed rate of 3.458%.

Canadian Denominated Credit Facilities

Our Canadian networks business maintained a credit facility with five banks, which matured in April 2003. The interest rate on this facility fluctuated with changes in
the Bankers Acceptance Discount Rate. At December 31, 2002, US$78.6 million was outstanding at a rate of 4.96%. In April 2003, this debt was fully repaid.

Our
Canadian networks business also maintains a C$20 million credit facility that matures in May 2005. The interest rate on this facility fluctuates with changes in the
Bankers Acceptance Discount Rate. At December 31, 2002, US$12.7 million was outstanding at a rate of 3.70%.

In
June 2001, our wholly owned Canadian finance subsidiary, Aquila Networks Canada Finance Corporation, issued $200.0 million of 7.75% senior notes in the U.S. public debt
market. Aquila has fully and unconditionally guaranteed these notes.

Credit Rating Triggers

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing and the execution of our commercial strategies. Our financial
flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment grade borrowers. Because of guarantee and cross default provisions
between Aquila, Inc. and its subsidiaries, the ratings triggers of our subsidiaries discussed below should be viewed as if they are directly applicable to Aquila, Inc.

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As
of April 11, 2003, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency                              |  | Rating |  | Outlook         
|----------------------------------- |  | ------ |  | ----------------
|                                   
|                                    |  |        |  |                 
|Moody's Investors Service (Moody's) |  | Caa1   |  | Negative Outlook
|Standard & Poor's Corporation (S&P) |  | B      |  | Negative Outlook
|Fitch Ratings (Fitch)               |  | B-     |  | Negative Outlook
|                                   

During 2002, Moody's lowered our credit rating from investment grade of Baa3 to Ba2 negative outlook, a non-investment grade. Additionally, S&P
downgraded us to BB, a non-investment grade rating, from BBB, with a negative outlook and Fitch downgraded us to BB, from BBB-, with a negative outlook. In 2003, Moody's
downgraded us to Caa1 and Fitch and S&P downgraded us to B- and B, respectively. As a result of these downgrades, our interest costs have increased and we were required to repay certain
notes.

In
2002, we retired $91.7 million of our Australian denominated notes that were put to us after the credit downgrades. Our Australian subsidiaries have three other outstanding
series of Australian denominated notes totaling $78.6 million at December 31, 2002. The holders of $62.9 million of these notes exercised their put rights and were repaid in
January 2003. The remaining notes totaling $15.7 million were repaid in April 2003.

Secured Financing

Each state in which we have utility operations that have not been pledged as collateral, requires us to obtain the approval of their public service commission before pledging
utility assets located in their state. We currently do not have any approval from any of these public service commissions to pledge those utility operations as collateral.

In
addition, we are required to obtain the prior approval from FERC before we can issue long-term or short-term debt. We currently have authority from the FERC to have outstanding up to
$1.5 billion of short-term, unsecured debt, but do not have authority to issue any additional long-term debt. The FERC recently issued an order in which it announced that any future debt
authorization orders would prohibit companies subject to its jurisdiction from using their utility properties as collateral for loans unless the loan proceeds will be used to support their utility
operations.

Except
in limited circumstances, holders of our senior notes and bonds, which represent the majority of our unsecured obligations, do not have the right to restrict our use of collateral
or to be equally or ratably secured if we provide collateral to other creditors.

Repayment of Debt

With the April 11, 2003 financings previously described, we believe we will have sufficient liquidity to cover our operational needs through June 2004. Our next
significant need for outside capital relates to our need to retire senior notes maturing in 2004. We anticipate retiring these notes with proceeds from additional asset sales. In the event we are not
successful in closing the asset sales, we would need to obtain a bridge loan to meet these obligations. Although no assurance can be given on the above actions, we expect to be successful in their
execution.

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Note 14: Long-Term Gas Contracts

In 1997 through 2000, we were paid in advance on certain contracts to deliver gas to municipal utilities over the subsequent 10 to 12 years. These contracts are settled
monthly through the physical delivery of gas. We have hedged our exposure to changes in gas prices related to these contracts. See Note 21 for further discussion of the cash flow presentation
of these contracts.

Our
obligations under our long-term gas delivery contracts that were paid in advance will result in cash outflows and losses as outlined in the table below.

|In millions |       | Long-Term
Gas Contract
Settlement(1) |       | Long-Term
Gas Contract
Margin Loss(2) |   | Total Long-Term
Gas Contract
Cash Payments(3)
|----------- | ----- | ------------------------------------ | ----- | ------------------------------------- | - | ---------------------------------------------
|           
|            |       |                                      |       |                                       |   |                                              
|2003        |       | $                                    | 81.5  |                                       | $ | 45.9                                         
|2004        |       |                                      | 84.9  |                                       |   | 48.1                                         
|2005        |       |                                      | 87.6  |                                       |   | 49.8                                         
|2006        |       |                                      | 90.9  |                                       |   | 52.2                                         
|2007        |       |                                      | 91.9  |                                       |   | 53.0                                         
|Thereafter  |       |                                      | 315.9 |                                       |   | 196.5                                        
|           
|            | Total |                                      | $     | 752.7                                 |   | $                                            
|           



We
accounted for the cash payments in advance related to these contracts as long-term obligations. We recognize relief of our obligation on these long-term gas
contracts as gas is delivered to the customer under the units of revenue method. If we were to default on these obligations, or were unable to perform on them, we may be asked to pay the issuers of
the surety bonds on these arrangements an amount that is greater than the long-term gas contract balance on our Consolidated Balance Sheet. As of December 31, 2002, our best
estimate of this additional amount ranges from $68.0 million to $101.0 million, depending on the discount rate used. This difference arises due to our use of the units of revenue method
of relieving the long-term obligation versus a present value method that would likely be used by the sureties.

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Note 15: Company-Obligated Preferred Securities

Summarized information regarding our Company-Obligated Preferred Securities is as follows:

|                                                                                                                                                                             |  | December 31,
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------
|
|                                                                                                                                                                            
|                                                                                                                                                                             |  |             
|UtiliCorp Capital Trust I (UCT I) 9.75% Premium Equity Participating Security Units (PEPS Units) 465 shares at December 31, 2002 (10,000,000 shares at December 31, 2001)(a) |  | $           
|UtiliCorp Capital Trust II (UCT II) 3.68% Trust Preferred Securities (100,000 shares at December 31, 2001)(b)                                                                |  |             
|                                                                                                                                                                            
|Total company-obligated preferred securities                                                                                                                                 |  | $           
|                                                                                                                                                                            
|Fair value of company-obligated preferred securities(c)                                                                                                                      |  | $           
|                                                                                                                                                                            



Note 16: Capital Stock and Stock Compensation

Capital Stock

We have two types of authorized common stockunclassified common stock and Class A common stock. No Class A common stock is issued or outstanding. We
also have authorized 10,000,000 shares of preference stock, with no par value, none of which is issued or outstanding.

Aquila Merchant Equity Offering

An initial public offering of 19,975,000 Class A Aquila Merchant common shares, including an over-allotment of 2,475,000 shares, closed in April 2001.
The offering price was $24.00 per share and raised approximately $446 million in net proceeds. Of the 19,975,000 shares, Aquila Merchant sold 14,225,000 new shares and Aquila sold 5,750,000
previously issued shares. A pretax gain of $110.8 million, or $.51 per share, was recognized in the second quarter of 2001 on the shares sold by Aquila. Upon completion of the offering, Aquila
owned approximately 80% of Aquila Merchant's outstanding shares.

In
January 2002, we completed an exchange offer and merger in which we acquired all the outstanding publicly-held shares of Aquila Merchant in exchange for shares of
Aquila common stock. The public shareholders of Aquila Merchant received .6896 shares of Aquila common stock

119

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in a tax-free exchange for each outstanding share of Aquila Merchant Class A common stock. Aquila Merchant shareholders holding approximately 1.8 million shares of Aquila
Merchant Class A shares exercised dissenters' rights with respect to the merger.

We
accounted for this transaction as a purchase. The total purchase price of $369.7 million was determined based upon the market price of the approximately 12.6 million
Aquila common shares issued in the exchange, an estimated liability to dissenting shareholders at the same market price and transaction costs. The purchase price was in excess of our proportionate
interest in the fair value of the net assets of Aquila Merchant acquired by approximately $218.7 million. This excess was classified as goodwill and allocated as $175.0 million to our
Wholesale Services segment and $43.7 million to our Capacity Services segment based on future expected cash flows. We wrote off all of this goodwill in 2002. See Note 2 for further
discussion.

Equity Offerings

In January 2002, we sold 12.5 million shares of our common stock to the public, including an over-allotment of 1.5 million shares, which raised
approximately $277.7 million in net proceeds which were used to reduce short-term debt and for general corporate purposes. In July 2002, we sold an additional
37.5 million shares of our common stock to the public that raised approximately $271.2 million in net proceeds. We used the proceeds of this offering to repay borrowings under the
revolving credit facility and to increase our liquidity.

Suspension of Dividend

In November 2002, the Board of Directors suspended the annual dividend on common stock for an undetermined time period. This decision stems from a detailed analysis of
the Company's current financial condition, its liquidity forecast and its earnings prospects after completion of the asset sales program discussed above. Based on this analysis, the Board decided that
the most prudent course of action was to suspend the dividend as part of our strategy to strengthen the credit profile of the Company.

Stockholder Rights Plan

Our Board of Directors has adopted a rights plan and declared a dividend distribution of one right for each outstanding share of our common stock. The rights become exercisable
if a person acquires beneficial ownership of 15% or more of our outstanding common stock. If the rights were exercised, the value of the shares of our common stock held by the acquiring person would
be substantially diluted. The purpose of the rights plan is to encourage a person desiring to acquire 15% or more of our outstanding common stock to negotiate the terms of their acquisition with our
Board of Directors.

Dividend Reinvestment and Stock Purchase Plan

We offer current and potential shareholders the option to participate in a Dividend Reinvestment and Common Stock Purchase Plan (the Stock Plan). The Stock Plan allows
participants to purchase up to $10,000 per month of common stock at the average market price on the date of the transaction, with minimal sales commissions. The Stock Plan also allows members to
reinvest dividends into additional common shares at a 5% discount. For the years ended December 31, 2002, 2001 and 2000, 2,168,892, 843,201 and 1,286,515 shares were issued, respectively, under
the Stock Plan. As of December 31, 2002, there were 609,248 shares still available to be issued under this plan.

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Employee Stock Purchase Plan

Participants in our Employee Stock Purchase Plan have the opportunity to buy shares of common stock at a reduced price through regular payroll deductions and/or lump sum
deposits of up to 20% of the employee's base salary, but not more than $25,000. Contributions are credited to the participant's account throughout an option period. At the end of the option period,
the participant's total account balance is applied to the purchase of common stock. The shares are purchased at 85% of the lower of the market price on the first day or the last day of the option
period. Participants must be enrolled in the Plan as of the first day of an option period in order to participate in that option period. For the years ended December 31, 2002, 2001 and 2000,
281,534, 260,046 and 297,772 shares were purchased, respectively, under the Employee Stock Purchase Plan.

Retirement Investment Plan

A defined contribution plan, the Retirement Investment Plan (Savings Plan), covers all of our full-time and eligible part-time employees. Participants
may generally elect to contribute up to 50% of their annual pay on a before- or after-tax basis subject to certain limitations. The Company generally matches contributions up to 6% of pay.
Participants may direct their contributions into various investment options. Through 2002, all company-matching contributions were in Aquila stock. Effective in 2003, company-matching contributions
will be made in cash and invested as directed by the employee. Company contributions were $11.5 million, $11.2 million and $9.9 million during the years ended December 31,
2002, 2001 and 2000, respectively. The Savings Plan also includes a discretionary contribution fund to which the Company historically contributed stock equal to 3% of base wages for eligible
full-time employees. Beginning in 2003, these contributions will be made in cash and invested as directed by the employee. Vesting occurs ratably over five years of employment with
distribution upon termination of employment. All dividends are reinvested in the respective investment elections. For 2002, 2001 and 2000, compensation expense (in millions) of $5.9, $5.0 and $4.7,
respectively, was recognized, which approximates 3% of eligible employees' base wages. Any Aquila common shares that have been elected by the employee related to this program are classified as
outstanding when calculating earnings per share.

Long-Term Incentive Plan

Our Long-Term Incentive Plan (LTIP) enables the company to reward key executives who have an ongoing company-wide impact. Eligible executives are
awarded performance units based on experience and responsibilities in the company. Incentives earned are based on a comparison of our total shareholder return over three years to a specific group of
companies with operations similar to ours. Incentives have been paid in cash, restricted stock, restricted stock units or deferred compensation agreements funding stock option grants based on the
executives' total shareholdings of the company common stock and their elections. Total compensation expense for the years ended December 31, 2001 and 2000, was $19.6 million and
$8.5 million, respectively. Due to the company's 2002 performance, no awards were earned for the year ended December 31, 2002, no new awards were granted in 2002, and potential awards
for the year ended December 31, 2003 were suspended.

Stock Incentive Plan

Through 2001 our Stock Incentive Plan enabled the company to grant common shares to certain employees as restricted stock awards, restricted stock unit awards and as stock
options. We hold

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shares issued as restricted stock or restricted stock unit awards until certain restrictions lapse, generally on the first or third award anniversary depending on the specific terms of the award.
Stock options granted under the Plan allow the purchase of common shares at a price not less
than fair market value at the date of grant. Options granted under this Plan vest 25% after two years, 50% after three years and 100% after four years. They expire 10 years after the date of
grant. The Omnibus Incentive Compensation Plan discussed below has replaced this plan.

Employee Stock Option Plan

The Board approved the establishment of an Employee Stock Option Plan in 1991 and readopted the plan in 2001. Through 2001 this Plan provided for the granting of up to
3.0 million stock options to eligible employees other than those eligible to receive options under the Stock Incentive Plan. Stock options granted under the Employee Stock Option Plan carry the
same provisions as those issued under the Stock Incentive Plan. Broad-based option grants have been made under this plan in only two years. During 1998 and 1992, respectively, options for 1,278,713
and 1,114,350 shares were granted to employees. The exercise prices of these options are $24.02 and $18.21, respectively. The options granted in 1992 have been exercised or expired in 2002. As of
December 31, 2002, 411,118 shares granted in 1998 remained outstanding. The Omnibus Incentive Compensation Plan discussed below has replaced this plan.

Omnibus Incentive Compensation Plan

In 2002, the Board and our shareholders approved the Omnibus Incentive Compensation Plan. This plan authorizes the issuance of 9,000,000 shares of Aquila common stock as stock
options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, stock awards, cash-based awards and annual incentive awards to all
eligible employees and directors of the company. This plan was created to replace the Stock Incentive Plan and Employee Stock Option Plan. All new awards will be issued under this plan. However,
options and awards existing under the previous plans will remain issued under those plans. Stock options under the Plan will generally vest evenly over three years and expire after seven years.
However, in December 2002, options for 1,789,152 shares were granted to employees other than company officers under this plan. These options vest in one year and are exercisable for seven
years.

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Summary of Stock Options

This table summarizes all stock options as of December 31, 2002, 2001 and 2000:

|                             |  | 2002       |   | 2001       |   | 2000      |  
|---------------------------- |  | ---------- | - | ---------- | - | --------- | -
|
|
|
|                             |  |            |   |            |   |           |  
|Beginning balance            |  | 6,118,123  |   | 7,156,600  |   | 7,347,961 |  
|Granted                      |  | 1,789,152  |   | 825,069    |   | 1,153,487 |  
|Converted from Merchant plan |  | 2,641,369  |   |           |   |          |  
|Exercised                    |  | (270,028   | ) | (1,779,548 | ) | (610,345  | )
|Cancelled                    |  | (1,370,108 | ) | (83,998    | ) | (734,503  | )
|                             | 
|Ending balance               |  | 8,908,508  |   | 6,118,123  |   | 7,156,600 |  
|                             | 
|Weighted average prices:     |  |            |   |            |   |           |  
|Beginning balance            |  | $22.37     |   | $21.39     |   | $21.80    |  
|Granted price                |  | 1.83       |   | 28.75      |   | 18.84     |  
|Converted price              |  | 34.82      |   |           |   |          |  
|Exercised price              |  | 24.14      |   | 21.42      |   | 20.73     |  
|Cancelled price              |  | 29.49      |   | 21.69      |   | 21.91     |  
|                             | 
|Ending balance               |  | $20.75     |   | $22.37     |   | $21.39    |  
|                             | 

This table summarizes all outstanding and exercisable stock options as of December 31, 2002:

|             |       | Outstanding Options |           | Exercisable Options
|------------ | ----- | ------------------- | --------- | -------------------
|
|            
|             |       |                     |           |                    
|$1.83-16.30  |       | 1,782,352           |           | 6.96               
|$16.31-23.99 |       | 4,245,603           |           | 5.02               
|$24.00-29.99 |       | 1,043,208           |           | 6.59               
|$30.00-42.34 |       | 1,837,345           |           | 7.55               
|            
|             | Total |                     | 8,908,508 |                    
|            

In connection with the recombination of Aquila Merchant with Aquila, Aquila Merchant stock options were converted into 2,641,369 options to purchase Aquila common
stock at prices ranging from $24.80 to $42.34.

Total
restricted stock awards granted during the year were 923,937 shares at a weighted average fair value of $24.08 at grant date.

123

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Note 17: Earnings Per Share

The table below shows how we calculated diluted earnings per share and diluted shares outstanding. Basic earnings per share and basic weighted average shares are the starting
point in calculating the dilutive measures. To calculate basic earnings per share, divide earnings available for common shares by weighted average shares outstanding without adjusting for dilutive
items. Diluted earnings per share are calculated by dividing earnings available for common shares after assumed conversion of dilutive securities by weighted average shares outstanding adjusted for
the effect of dilutive securities. As a result of the net loss in 2002, the potential issuances of common stock were anti-dilutive and therefore not included in the calculation of diluted
earnings per share.

|In millions, except per share amounts                                                                                  |                                              | 2002 |           | 2001   |   | 2000  
|---------------------------------------------------------------------------------------------------------------------- | -------------------------------------------- | ---- | --------- | ------ | - | ------
|                                                                                                                      
|                                                                                                                       |                                              |      |           |        |   |       
|Earnings (loss) available for common shares from continuing operations                                                 |                                              | $    | (1,722.8) |        | $ | 245.3 
|Interest on convertible bonds                                                                                          |                                              |      |          |        |   | .2    
|                                                                                                                      
|Earnings (loss) available for common shares from continuing operations after assumed conversion of dilutive securities |                                              |      | (1,722.8) |        |   | 245.5 
|Earnings (loss) from discontinued operations                                                                           |                                              |      | (329.6)   |        |   | 34.1  
|Cumulative effect of accounting change                                                                                 |                                              |      | (22.7)    |        |   |      
|                                                                                                                      
|Earnings (loss) available for common shares after assumed conversion of dilutive securities                            |                                              | $    | (2,075.1) |        | $ | 279.6 
|                                                                                                                      
|Basic earnings (loss) per share:                                                                                       |                                              |      |           |        |   |       
|                                                                                                                       | Earnings (loss) from continuing operations   |      | $         | (10.65 | ) | $     
|                                                                                                                       | Earnings (loss) from discontinued operations |      |           | (2.04  | ) |       
|                                                                                                                       | Cumulative effect of change in accounting    |      |           | (.14   | ) |       
|                                                                                                                      
|                                                                                                                       | Net income (loss)                            |      | $         | (12.83 | ) | $     
|                                                                                                                      
|Diluted earnings (loss) per share:                                                                                     |                                              |      |           |        |   |       
|                                                                                                                       | Earnings (loss) from continuing operations   |      | $         | (10.65 | ) | $     
|                                                                                                                       | Earnings (loss) from discontinued operations |      |           | (2.04  | ) |       
|                                                                                                                       | Cumulative effect of change in accounting    |      |           | (.14   | ) |       
|                                                                                                                      
|                                                                                                                       | Net income (loss)                            |      | $         | (12.83 | ) |       
|                                                                                                                      
|Weighted average number of common shares used in basic earnings per share                                              |                                              |      | 161.72    |        |   | 112.10
|Effect of dilutive securities:                                                                                         |                                              |      |           |        |   |       
|                                                                                                                       | Stock options and restricted stock           |      |           |       |   |       
|                                                                                                                       | Convertible bonds                            |      |           |       |   |       
|                                                                                                                       | Company-obligated preferred securities       |      |           |       |   |       
|                                                                                                                      
|Weighted average number of common shares and dilutive common stock used in diluted earnings per share                  |                                              |      | 161.72    |        |   | 115.71
|                                                                                                                      

124

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Note 18: Income Taxes

Earnings (loss) from continuing operations before income taxes consisted of:

|         |       | Year Ended December 31,
|-------- | ----- | -----------------------
|
|        
|         |       |                        
|Domestic |       | $                      
|Foreign  |       |                        
|        
|         | Total |                        
|        

Our
income tax expense (benefit) consisted of the following:

|                                                             |                                                                | Year Ended December 31, |       
|------------------------------------------------------------ | -------------------------------------------------------------- | ----------------------- | ------
|
|                                                             |                                                               
|                                                             |                                                                |                         |       
|Current:                                                     |                                                                |                         |       
|                                                             | Federal                                                        |                         | $     
|                                                             | Foreign                                                        |                         |       
|                                                             | State                                                          |                         |       
|Deferred:                                                    |                                                                |                         |       
|                                                             | Federal                                                        |                         |       
|                                                             | Foreign                                                        |                         |       
|                                                             | State                                                          |                         |       
|                                                             | Change in valuation allowance                                  |                         |       
|                                                             | Investment tax credit amortization                             |                         |       
|                                                             |                                                               
|Income tax expense (benefit) from continuing operations      |                                                                |                         | (135.1
|                                                             |                                                               
|Income tax expense (benefit) from discontinued operations:   |                                                                |                         |       
|                                                             | Current                                                        |                         |       
|                                                             | Deferred (net of valuation allowance of $75.4 million in 2002) |                         |       
|                                                             |                                                               
|Income tax expense (benefit) from discontinued operations    |                                                                |                         | (62.5 
|Income tax benefit on cumulative effect of accounting change |                                                                |                         | (14.8 
|                                                             |                                                               
|                                                             |                                                                | Total                   |       
|                                                             |                                                               

125

---

The
principal components of deferred income taxes consist of the following:

|                                           |                                                             | December 31, 
|------------------------------------------ | ----------------------------------------------------------- | -------------
|
|                                          
|                                           |                                                             |              
|Deferred Tax Assets:                       |                                                             |              
|                                           | Alternative minimum tax credit carryforward                 |              
|                                           | Mark-to-market losses                                       |              
|                                           | Accrued bonuses and deferred compensation                   |              
|                                           | Allowance for uncollectible accounts                        |              
|                                           | Realized capital loss carry forward for income tax purposes |              
|                                           | Unrealized capital losses                                   |              
|                                           | Less: valuation allowance                                   |              
|                                          
|Total deferred tax assets                  |                                                             |              
|                                          
|Deferred Tax Liabilities and Credits:      |                                                             |              
|                                           | Accelerated depreciation and other plant differences:       |              
|                                           |                                                             | Regulated    
|                                           |                                                             | Non-regulated
|                                           | Basis difference in international investments               |              
|                                           | Regulatory asset                                            |              
|                                           | Other, net                                                  |              
|                                          
|Total deferred tax liabilities and credits |                                                             |              
|                                          
|Deferred income taxes and credits, net     |                                                             | $            
|                                          

Our
effective income tax rate from continuing operations differed from the statutory federal income tax rate primarily due to the following:

|                                  |                                               | December 31, |     
|--------------------------------- | --------------------------------------------- | ------------ | ----
|
|                                  |                                              
|                                  |                                               |              |     
|Statutory Federal Income Tax Rate |                                               | (35.0        | )%  
|Tax effect of:                    |                                               |              |     
|                                  | State income taxes, net of federal benefit    |              | (3.4
|                                  | Revocation of permanent foreign reinvestments |              | 8.0 
|                                  | Change in valuation allowance                 |              | 16.5
|                                  | Minority interest                             |              |    
|                                  | Goodwill                                      |              | 3.8 
|                                  | Other                                         |              | 2.8 
|                                  |                                              
|Effective Income Tax Rate         |                                               | (7.3         | )%  
|                                  |                                              

At
December 31, 2002, we have alternative minimum tax credit carryforwards of $56.9 million. These credits do not expire and can be used to decrease future cash tax
payments.

Change in Valuation Allowance.In 2002, we realized $618.2 million of capital losses (for income tax purposes) on the
sale of assets and recognized impairment charges of $539.1 million that we expect to realize (for income tax purposes) as capital losses when the assets are sold. We carried back
$170.9 million of the realized capital losses to offset capital gains in 1999 through 2001. At

126

---

December 31, 2002, we had approximately $447.3 million of net realized capital loss carryforwards that were available for federal income tax purposes and expire in 2007. We assessed the
likelihood that all or a portion of the deferred tax assets relating to the remaining capital losses would not be realized. This assessment included consideration of positive and negative factors,
including our current financial position and results of operations, projected future taxable income, including projected capital gains, and available tax planning strategies. As a result of such
assessment, we determined that it was more likely than not that deferred tax assets relating to capital losses would not be realized. Therefore, we recorded a total valuation allowance of
$381.6 million in our 2002 deferred income tax provision.

Revocation of Permanent Foreign Reinvestments.Due to our need for capital and our change in business strategy to transition
the Company to a domestic regulated utility with some non-regulated generation, we sold our New Zealand investment and are in the process of exploring the sale of our other foreign
investments. As a result, we can no longer represent that cash from our international investments will be permanently invested. Therefore, additional deferred tax
was recorded to account for taxes that will arise when we bring asset sale proceeds back to the United States. As a result, we recorded additional taxes of $148.3 million in 2002.

Goodwill.Included in impairment charges and net loss on sales of assets was $178.6 million and $21.9 million
of Wholesale Services and Capacity Services goodwill, respectively, which is not deductible for income tax purposes and therefore does not result in the recognition of a tax benefit.

In
addition to the capital losses carried back to prior years discussed above, we generated a net operating loss of $528.9 million in 2002. This net operating loss was carried
back in our federal income tax return for 2002 to offset taxable income in 1997 through 2000. As a result of these capital and operating loss carrybacks, we had a federal income tax receivable of
$191.1 million at December 31, 2002, which was included in Prepayments and Other in our Consolidated Balance Sheet. This receivable was collected in March 2003.

Note 19: Employee Benefits

We provide defined benefit pension plans for our employees in the United States and Canada. Benefits under these plans reflect the employees' compensation, years of service and
age at retirement. We satisfy the minimum funding requirements under the Employee Retirement Income Security Act of 1974, as amended. In addition to pension benefits, we provide certain
post-retirement health care and life insurance benefits for substantially all retired employees. We accrue the cost of post-retirement benefits during an employee's service. We
fund the portion of the net periodic post-retirement benefit costs that are tax deductible. For measurement purposes, projected benefit obligations and the fair value of plan assets were
determined as of September 30, 2002 and 2001.

Effective
September 30, 2002, we changed our actuarial assumptions for the average expected rate of return on plan assets from 9.58% to 9.15% to reflect recent market performance
and expected long-term returns for the types of assets generally held in our plans. We also changed the average assumed discount rates from 7.42% to 6.71%.

127

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The following table shows the funded status of our pension and post-retirement benefit plans and the amounts included in the Consolidated Balance Sheets and Consolidated
Statements of Income:

|                                                       |  | Pension Benefits |        | Other Post-retirement Benefits |  
|------------------------------------------------------ |  | ---------------- | ------ | ------------------------------ | -
|
|                                                       | 
|Change in Projected Benefit Obligation:                |  |                  |        |                                |  
|Benefit obligation at start of year                    |  | $                | 316.8  |                                | $
|Service cost                                           |  |                  | 11.9   |                                |  
|Interest cost                                          |  |                  | 23.0   |                                |  
|Plan participants' contribution                        |  |                  | .8     |                                |  
|Amendments                                             |  |                  | (2.7)  |                                |  
|Actuarial (gain) loss                                  |  |                  | 32.9   |                                |  
|Curtailment (gain) loss                                |  |                  | (6.5)  |                                |  
|Benefits paid                                          |  |                  | (18.4) |                                |  
|Foreign currency exchange changes                      |  |                  | .4     |                                |  
|                                                       | 
|Projected benefit obligation at end of year            |  | $                | 358.2  |                                | $
|                                                       | 
|Change in Plan Assets:                                 |  |                  |        |                                |  
|Fair value of plan assets at start of year             |  | $                | 319.4  |                                | $
|Actual return on plan assets                           |  |                  | (38.8) |                                |  
|Employer contribution                                  |  |                  | 39.3   |                                |  
|Plan participants' contribution                        |  |                  | 1.1    |                                |  
|Transfers                                              |  |                  | (2.8)  |                                |  
|Benefits paid                                          |  |                  | (18.4) |                                |  
|Foreign currency exchange changes                      |  |                  | .5     |                                |  
|                                                       | 
|Fair value of plan assets at end of year               |  | $                | 300.3  |                                | $
|                                                       | 
|Funded status:                                         |  |                  |        |                                |  
|Funded status                                          |  | $                | (57.9) |                                | $
|Unrecognized transition amount                         |  |                  | (3.6)  |                                |  
|Unrecognized net actuarial (gain) loss                 |  |                  | 153.5  |                                |  
|Unrecognized prior service cost                        |  |                  | 27.7   |                                |  
|Employer contribution                                  |  |                  | .3     |                                |  
|                                                       | 
|Net amount recognized                                  |  | $                | 120.0  |                                | $
|                                                       | 
|Amounts Recognized in the Consolidated Balance Sheets: |  |                  |        |                                |  
|Prepaid benefit cost                                   |  | $                | 123.0  |                                | $
|Accrued benefit liability                              |  |                  | (18.7) |                                |  
|Intangible asset                                       |  |                  | 10.9   |                                |  
|Accumulated other comprehensive income                 |  |                  | 4.8    |                                |  
|                                                       | 
|Net amount recognized                                  |  | $                | 120.0  |                                | $
|                                                       | 
|Reconciliation of Net Amount Recognized:               |  |                  |        |                                |  
|Net amount recognized at start of year                 |  | $                | 87.3   |                                | $
|Net periodic benefit cost                              |  |                  | (8.2)  |                                |  
|Curtailment (gain) loss                                |  |                  |       |                                |  
|Contributions                                          |  |                  | 38.9   |                                |  
|Expense adjustment                                     |  |                  | 2.0    |                                |  
|                                                       | 
|Net amount recognized at end of year                   |  | $                | 120.0  |                                | $
|                                                       | 
|Weighted Average Assumptions as of September 30:       |  |                  |        |                                |  
|Discount rate for expense                              |  |                  | 7.42   | %                              |  
|Discount rate for disclosure                           |  |                  | 6.71   | %                              |  
|Expected return on plan assets for expense             |  |                  | 9.58   | %                              |  
|Rate of compensation increase                          |  |                  | 5.10   | %                              |  
|                                                       | 

128

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For measurement purposes, to calculate the annual rate of increase in the per capita cost of covered health benefits for each future fiscal year,
we used a graded rate starting at 11% in 2003 and decreasing 1% annually until the rate levels out at 5% for years 2009 and thereafter.

|                                         |  | Pension Benefits |       | Other Post-retirement Benefits |  
|---------------------------------------- |  | ---------------- | ----- | ------------------------------ | -
|
|                                         | 
|Components of Net Periodic Benefit Cost: |  |                  |       |                                |  
|Service cost                             |  | $                | 11.9  |                                | $
|Interest cost                            |  |                  | 23.0  |                                |  
|Expected return on plan assets           |  |                  | (29.9 | )                              |  
|Amortization of transition amount        |  |                  | (1.5  | )                              |  
|Amortization of prior service cost       |  |                  | 1.8   |                                |  
|Recognized net actuarial (gain) loss     |  |                  | 2.9   |                                |  
|Curtailment (gain) loss                  |  |                  |      |                                |  
|Regulatory adjustment                    |  |                  | (1.8  | )                              |  
|                                         | 
|Net Periodic Benefit Cost                |  | $                | 6.4   |                                | $
|                                         | 

The Supplemental Executive Retirement Plan was amended in 2001 to include certain participants' annual incentive compensation in the calculation of plan benefits.

We
maintain defined benefit pension plans in the United States and Canada. The actuarial assumptions used to calculate the benefit obligation and periodic pension costs for those plans
are essentially the same. The funded status for those individual plans that have obligations in excess of plan assets and the corresponding amounts recognized in the Consolidated Balance Sheets for
the United States and Canada plans are summarized below:

|                                                          |  | United States |       | Canada |  
|--------------------------------------------------------- |  | ------------- | ----- | ------ | -
|
|                                                          | 
|Projected Benefit Obligations in Excess of Plan Assets:   |  |               |       |        |  
|Fair value of plan assets at end of year                  |  | $             | 248.4 |        | $
|Projected benefit obligation at end of year               |  |               | 301.7 |        |  
|                                                          | 
|Funded status                                             |  | $             | (53.3 | )      | $
|                                                          | 
|Accumulated Benefit Obligations in Excess of Plan Assets: |  |               |       |        |  
|Fair value of plan assets at end of year                  |  | $             |      |        | $
|Accumulated benefit obligation at end of year             |  |               | 13.8  |        |  
|                                                          | 
|Funded status                                             |  | $             | (13.8 | )      | $
|                                                          | 

Pension costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the
plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key
actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in

129

---

determining the projected benefit obligation and pension costs. Pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well
as changes in general interest rates may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of
return on plan assets could also increase or decrease recorded pension costs.

The
following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase or
decrease in the percentage for each assumption, we and our actuaries expect that the inverse of this change would impact the projected benefit obligation (PBO) at December 31, 2002, and our
estimated annual pension cost (APC) on the income statement for 2003 by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change
in that assumption.

|Dollars in millions           |  | Change in AssumptionInc(dec) |   | Impact
on PBOInc(dec) |       | Impact
on APCInc(dec) |  
|----------------------------- |  | ---------------------------- | - | --------------------- | ----- | --------------------- | -
|                              | 
|                              |  |                              |   |                       |       |                       |  
|Discount rate                 |  | .25                          | % | $                     | (11.7 | )                     | $
|Rate of return on plan assets |  | .25                          | % |                       |      |                       |  
|                              | 

Our health care plans are contributory, with participants' contributions adjusted annually. The life insurance plans are non-contributory. In
estimating future health care costs, we have assumed future cost-sharing changes. The expense recognition for health care costs does not necessarily match the cost estimates due to certain
differences in regulatory accounting at our domestic utility operations. The assumed health care cost trends significantly affect 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 for 2002.

|                                                        |  | 1 Percentage-Point |    
|------------------------------------------------------- |  | ------------------ | ---
|
|                                                        | 
|                                                        |  |                    |    
|Effect on total of service and interest cost components |  | $                  | .6 
|Effect on post-retirement benefit obligation            |  |                    | 7.8
|                                                        | 

Note 20: Mergers, Acquisitions and Divestitures

In addition to the acquisitions and divestitures discussed in Notes 5, 6 and 10, we completed the following transactions.

Pipeline Operations

In January 2002, we completed the sale of an intrastate pipeline for our net book value of $65.9 million, including a $5.0 million deposit received in
2001.

St. Joseph Light & Power Company

Effective December 31, 2000, St. Joseph Light & Power Company (SJL&P) merged with us. Under the merger agreement, SJL&P shareholders received $23.00 in Aquila
common shares for

130

---

each SJL&P common share held. We issued approximately 6.6 million shares of Aquila common stock with a total value of $190.2 million in connection with this merger. We also assumed
short-term debt of $23.6 million and long-term debt of $68.1 million. We accounted for the transaction as a purchase. We paid a premium for the purchase of SJL&P
as we anticipated the realization of certain synergies with our existing network in Missouri, including reduced general and administrative costs, joint dispatching of power in the region and
off-system sales of power. In addition, SJL&P possessed a strong balance sheet that we believed would strengthen our credit position. These factors supported a purchase price for the
business in excess of the underlying fair value of the assets and liabilities acquired.

GPU International

In December 2000, Aquila Merchant purchased GPU International for $225 million, a company holding interests in six independent U.S.-based generation plants. We
accounted for the transaction as a purchase.

TransAlta Assets

In August 2000, we completed our acquisition of TransAlta Corporation's Alberta-based electricity distribution and retail assets for approximately $480 million.
We operate this business as Aquila Networks Canada (Alberta) Ltd. In November 2000, we sold the retail assets to Epcor, an Edmonton-based utility, for approximately $75 million. A
premium was paid for the company as we anticipated the realization of certain synergies with our existing network in Canada, a reduction in executive and corporate services, as well as workforce
efficiencies. These factors supported a purchase price for the business in excess of the underlying fair value of the assets and liabilities acquired.

Pro Forma Operating Results

The following reflects our results for the year ended December 31, 2000, assuming the above transactions occurred as of the beginning of 2000:

In millions, except per share amounts

Year Ended December 31, 2000(Unaudited)Sales

$
3,637.8Net income


243.1Diluted earnings per common share

$
2.42


The pro forma results of operations are not necessarily indicative of the actual results that would have been obtained had we made the acquisitions at the
beginning of the period, or of results that may occur in the future. The 2000 pro forma operating results include certain unusually large mark-to-market gains. The pro forma
operating results do not include adjustments for synergies or other adjustments to the business operations.

Note 21: Restatement of Consolidated Statements of Cash Flows

As disclosed in our 2001 Annual Report, we reported a $110.8 million gain on the sale of Aquila Merchant shares in connection with their initial public offering in
April 2001. Cash proceeds from

131

---

the sale were included in Cash Flows From Operating Activities, but should have been reported as Cash Flows From Investing Activities. Accordingly, we decreased Cash Flows From Operating Activities
by $110.8 million and increased the Cash Flows From Investing Activities by the same amount. This reclassification was included in our Form 10-K/A that was filed in
August 2002.

As
more fully discussed in Note 14, as part of our wholesale energy trading business, we entered into long-term gas contracts that require us to deliver natural gas to
municipal utility customers over a period of 10 to 12 years. In exchange for our commitment to deliver the natural gas, we were paid in advance. We consider these contracts part of our energy
trading operations. As such, both the receipt of the advance cash payments and the monthly cash outflows to purchase the gas to be delivered to the customers in satisfaction of our commitments were
included in our Consolidated Statements of Cash Flows under the caption Net Changes in Price Risk Management Assets and Liabilities and included in Cash Flows From Operating Activities. These
contracts were also included under the caption Price Risk Management Liabilities in our Consolidated Balance Sheets.

In
2002, the EITF in its deliberations regarding EITF 02-3 discussed a number of items related to energy trading and risk management activities. In order to more fully
address certain of the items discussed, the EITF formed a working group. One of the items discussed by the working group was "prepaid gas contracts." These discussions included the cash flow
presentation of contracts similar to our long-term gas contracts. Based on this discussion, and other accounting and industry discussions and guidance occurring in 2002, we believe that
the current industry and accounting consensus is to report these contracts as financing activities in the statement of cash flows. As a result, we have reported these cash flows in accordance with the
current accounting interpretations and guidance for all years presented in our Consolidated Statements of Cash Flows. This resulted in an $82.2 million increase in Cash Flows From Operating
Activities for the year ended December 31, 2001, and a $396.1 million decrease in Cash Flows From Operating Activities for the year ended December 31, 2000, as compared to the
amounts previously reported. Cash Flows From Financing Activities in each year changed by the corresponding amounts, resulting in no change in total cash flows. This change had no impact on earnings
or losses.

The
net effect of the changes discussed above are shown in the following table:

|                                                     |  | For the Year Ended December 31, |       
|---------------------------------------------------- |  | ------------------------------- | ------
|
|
|                                                     | 
|Cash provided from operating activities              |  | $                               | 223.7 
|Cash used for investing activities                   |  |                                 | (886.5
|Cash provided from financing activities              |  |                                 | 533.1 
|                                                     | 
|Net increase (decrease) in cash and cash equivalents |  | $                               | (129.7
|                                                     | 

132

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Note 22: Segment Information

We manage our business in two distinct groups, Global Networks Group and Merchant Services. Global Networks is managed as two segments, Domestic Networks and International
Networks. Merchant Services is also managed in two segments, Capacity Services and Wholesale Services. Each segment is managed based on operating results, expressed as earnings before interest and
taxes. Generally, decisions on finance, dividends and taxes are made at the Corporate level.

A. Business Lines

|                            |                        | Year Ended December 31,
|--------------------------- | ---------------------- | -----------------------
|
|                           
|                            |                        |                        
|Sales:*                     |                        |                        
|Global Networks Group      |                        |                        
|                            | Domestic Networks      |                        
|                            | International Networks |                        
|                           
|Total Global Networks Group |                        |                        
|                           
|Merchant Services          |                        |                        
|                            | Capacity Services      |                        
|                            | Wholesale Services     |                        
|                           
|Total Merchant Services     |                        |                        
|                           
|                            | Total                  |                        
|                           



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|                                                               |                        | Year Ended December 31, |         
|-------------------------------------------------------------- | ---------------------- | ----------------------- | --------
|
|                                                               |                       
|                                                               |                        |                         |         
|Earnings Before Interest and Taxes:*                           |                        |                         |         
|Global Networks Group                                         |                        |                         |         
|                                                               | Domestic Networks      |                         | $       
|                                                               | International Networks |                         |         
|                                                               |                       
|Total Global Networks Group                                    |                        |                         | (899.7  
|                                                               |                       
|Merchant Services **                                          |                        |                         |         
|                                                               | Capacity Services      |                         |         
|                                                               | Wholesale Services     |                         |         
|                                                               | Minority Interest      |                         |         
|                                                               |                       
|Total Merchant Services                                        |                        |                         | (671.0  
|Corporate and other                                            |                        |                         | (37.7   
|                                                               |                       
|Total EBIT                                                     |                        |                         | (1,608.4
|Interest expense                                               |                        |                         | 249.5   
|                                                               |                       
|Earnings (loss) from continuing operations before income taxes |                        | $                       | (1,857.9
|                                                               |                       



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|                                       |                        | Year Ended December 31,
|-------------------------------------- | ---------------------- | -----------------------
|
|
|                                      
|                                       |                        |                        
|Depreciation and Amortization Expense: |                        |                        
|Global Networks Group                 |                        |                        
|                                       | Domestic Networks      |                        
|                                       | International Networks |                        
|                                      
|Total Global Networks Group            |                        |                        
|                                      
|Merchant Services *                   |                        |                        
|                                       | Capacity Services      |                        
|                                       | Wholesale Services     |                        
|                                      
|Total Merchant Services                |                        |                        
|Corporate and other                    |                        |                        
|                                      
|                                       | Total                  |                        
|                                      



|                            |                        | December 31,
|--------------------------- | ---------------------- | ------------
|
|                           
|                            |                        |             
|Identifiable Assets: *      |                        |             
|Global Networks Group      |                        |             
|                            | Domestic Networks      |             
|                            | International Networks |             
|                           
|Total Global Networks Group |                        |             
|                           
|Merchant Services **       |                        |             
|                            | Capacity Services      |             
|                            | Wholesale Services     |             
|                           
|Total Merchant Services     |                        |             
|Corporate and other         |                        |             
|                           
|                            | Total                  |             
|                           



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|                            |                        | Year Ended December 31,
|--------------------------- | ---------------------- | -----------------------
|
|                           
|                            |                        |                        
|Capital Expenditures:       |                        |                        
|Global Networks Group      |                        |                        
|                            | Domestic Networks      |                        
|                            | International Networks |                        
|                           
|Total Global Networks Group |                        |                        
|                           
|Merchant Services          |                        |                        
|                            | Capacity Services      |                        
|                            | Wholesale Services     |                        
|                           
|Total Merchant Services     |                        |                        
|Corporate and other         |                        |                        
|                           
|                            | Total                  |                        
|                           

B. Geographical Information

|                    |       | Year Ended December 31,
|------------------- | ----- | -----------------------
|
|                   
|                    |       |                        
|Sales:              |       |                        
|United States       |       | $                      
|Canada              |       |                        
|Other international |       |                        
|                   
|                    | Total |                        
|                   

|                    |       | December 31,
|------------------- | ----- | ------------
|
|                   
|                    |       |             
|Long-Lived Assets:* |       |             
|United States       |       | $           
|Canada              |       |             
|Other international |       |             
|                   
|                    | Total |             
|                   



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Note 23: Commitments and Contingencies

Commitments

We have various commitments relating to power, gas and coal supply commitments and lease commitments as summarized below.

|In millions                                            |                             | 2003 |       | 2004  |   | 2005  |       | 2006 |       | 2007 |   | Thereafter |      | Total
|------------------------------------------------------ | --------------------------- | ---- | ----- | ----- | - | ----- | ----- | ---- | ----- | ---- | - | ---------- | ---- | -----
|                                                      
|                                                       |                             |      |       |       |   |       |       |      |       |      |   |            |      |      
|Future minimum lease paymentsfacilities and equipment |                             | $    | 47.4  |       | $ | 41.6  |       | $    | 22.6  |      | $ | 16.9       |      | $    
|Merchant power plant obligations                       |                             |      | 101.3 |       |   | 101.3 |       |      | 112.4 |      |   | 120.2      |      |      
|Merchant gas transportation obligations                |                             |      | 8.8   |       |   | 8.8   |       |      | 8.8   |      |   | 8.6        |      |      
|Regulated business purchase obligations:               |                             |      |       |       |   |       |       |      |       |      |   |            |      |      
|                                                       | Purchased power obligations |      |       | 119.8 |   |       | 117.5 |      |       | 95.5 |   |            | 83.9 |      
|                                                       | Purchased gas obligations   |      |       | 81.8  |   |       | 40.4  |      |       | 29.6 |   |            | 21.5 |      
|                                                       | Coal contracts              |      |       | 90.4  |   |       | 69.6  |      |       | 64.3 |   |            | 51.3 |      
|                                                      

Future minimum lease payments.Future minimum lease payments primarily relate to operating leases of coal
rail cars, vehicles and office space over terms of up to 20 years. In connection with our exit from the wholesale energy trading business we have leases of office space and other facilities
that we no longer need. In 2002, we recorded restructuring charges for the cost of these minimum lease commitments on such space as discussed in Note 4. Rent expense for the years 2002, 2001
and 2000 was (in millions) $41.9, $35.6 and $23.9, respectively.

Merchant power plant obligations.In connection with our Merchant power generation business, we have entered into
long-term power purchase agreements for a portion of the total output of certain merchant power plants owned by others. These agreements are treated as operating leases for accounting
purposes.

Merchant gas transportation obligations.We have long-term commitments for gas transportation capacity remaining
from our wholesale energy trading business. We may terminate these commitments and may incur losses in future periods.

Regulated business purchase obligations.Our integrated electric utility operations in the U.S. and British Columbia, Canada,
generate 56% and 54% of the power delivered to their customers, respectively. Our domestic utility operations purchase coal and natural gas as fuel for its generating power plants under
long-term contracts. Our British Columbia electric utility owns hydroelectric dams to generate power for its customers. Both of these operations also purchase power and gas to meet
customer needs under short-term and long-term power purchase contracts.

Contingent Obligations

Midlands ElectricityIn connection with our purchase of a 79.9% interest in Midlands Electricity from FirstEnergy Corporation,
we entered into certain agreements that expose us to contingent payment obligations. FirstEnergy has the right to sell its interest in Midlands to us at fair market value if, at any time during the
30-day period prior to May 8, 2008, the fair value of FirstEnergy's holdings is less than $72.8 million. In addition, as part of the purchase price, we executed a note
payable to FirstEnergy that requires us to make six annual payments of
$19.0 million. We recorded this obligation at its fair value of $87.4 million. If at any time prior to the repayment of this obligation we transfer 33% or more of our interest in
Midlands to an

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unrelated third party, we would be required to make all remaining payments to FirstEnergy on an undiscounted basis.

Merchant Loan PortfolioIn connection with our former portfolio of Merchant loans to energy-related businesses, we also
entered into commodity and interest rate swaps with the borrowers. Because of increases in natural gas prices and declines in interest rates, these swaps have increased in market value. When we sold
the portfolio of loans we retained these swaps. As part of the sale agreement, we agreed under certain conditions that in the event these borrowers fail to meet their note obligations to the buyer of
the portfolio, we could be required to share a portion of any proceeds we receive on these swaps with the buyer. At December 31, 2002, the value of these swaps was $33.8 million.

Aquila,
Inc has entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. These Guarantees have been grouped
based on similar characteristics and are described below.

Standby Letters of CreditWe have entered into various agreements that require letters of credit for financial assurance
purposes. These letters of credit are available to fund the payment of such obligations. At December 31, 2002, we had $195.6 million of letters of credit outstanding with expiration
dates ranging from one month to 13 months.

Guarantee of Subsidiary ObligationsIn the normal course of business, we guarantee certain payment obligations of our wholly
owned subsidiaries including certain operating leases as discussed above and short and long-term debt as discussed in Notes 12 and 13.

Aggregator LoansWe have guaranteed the performance of certain gas aggregators in connection with our aggregator loans that
were made in connection with our wholesale energy trading business. We terminated all but two of these agreements upon our exit from the wholesale energy trading business. In connection with these
agreements, we guarantee to pay the aggregators' counterparties if the aggregators are unable to make their payments for the gas they have purchased. Our exposure is limited to the outstanding payable
balances of the aggregators as of the termination dates for those agreements that have been terminated. Our total guarantees for these agreements at December 31, 2002 was $126.5 million.
As of March 31, 2003, our guarantees have been reduced to $43.3 million. We currently estimate $2.8 million of potential exposure related to these guarantees.

Independent Power ProjectsWe assumed certain guarantees for two of our IPPs upon purchase of these investments. These
guarantees require that we make payment of certain obligations of the IPPs under various circumstances. Our total exposure from these assumed guarantees totals $11.5 million, of which we have
reserved for $6.6 million on our Consolidated Balance Sheet at December 31, 2002.

Legal

In February 2002, we filed a suit against Chubb Insurance Group, the issuer of surety bonds in support of certain of our long-term gas supply contracts.
Previously, Chubb had demanded that it be released from its surety obligation of up to $540 million or, alternatively, that we post collateral to secure its obligation. We do not believe that
Chubb is entitled to be released from its surety obligations or that we are obligated to post collateral to secure its obligations unless it is likely we will default on the contracts. Chubb has not
alleged that we are likely to default on the contracts. If Chubb were to prevail, it would have a material adverse impact on our liquidity and

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financial position. We rely on other sureties in support of long-term gas supply contracts similar to those described above. There can be no assurance that these sureties will not make
claims similar to those raised by Chubb. We have performed under these contracts since their inception and intend to continue to fully perform on the contracts.

A
consolidated lawsuit was filed against us in Delaware Chancery Court in connection with the recombination of Aquila with our Aquila Merchant subsidiary that occurred pursuant to an
exchange offer completed in January 2002, raising allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange
offer on behalf of the public shareholders of Aquila Merchant. The Delaware Chancery Court denied the plaintiffs' claims for equitable relief in January 2002, and there has been no further
activity with the lawsuit. Securities fraud complaints seeking damages based on the same conduct were also filed against us in federal court in Missouri. Persons holding certificates formerly
representing approximately 1.8 million shares of Aquila Merchant common stock are also pursuing their appraisal rights in connection with the recombination. We do not believe that any of these
actions will have an outcome materially adverse to us.

A
number of companies that engaged in energy trading activities, including Aquila, have received requests from various regulatory agencies to furnish data and answer questions relating
to the possible inaccurate reporting of gas trade information to various industry publications in 2000 and 2001. In response to such inquiries, we have initiated a review of our reported information
relative to recorded data and are cooperating fully with these investigations. Additionally, we have reported to the Federal Energy Regulatory Commission and Commodity Futures Trading Commission that
we have been unable to reconcile all of the gas trade data reported to various trade publications with the gas trade data in our internal records and that our former traders may have reported
inaccurate information. A lawsuit was filed against us and numerous other energy trading companies in November 2002 by the Lieutenant Governor of the State of
California alleging that we misreported gas trade data that, in turn, affected the market price of electricity in California.

The
Company is subject to various other legal proceedings and claims that arise in the ordinary course of business operations. We do not expect the amount of liability, if any, from
these actions to materially affect our consolidated financial position or results of operations.

Environmental

We are subject to various environmental laws. These include regulations governing air and water quality and the storage and disposal of hazardous or toxic wastes. We
continually assess ways to ensure we comply with laws and regulations on hazardous materials and hazardous waste and remediation activities.

We
own or previously operated former manufactured gas plant (MGP) sites which may, or may not, require some form of environmental remediation. We have contacted appropriate federal and
state agencies and are working to determine what, if any, specific cleanup activities these sites may require. As of December 31, 2002, we estimate probable undiscounted cleanup costs on our
identified MGP sites to be $7.3 million. This amount is our best estimate of the costs of investigation and remediation of our identified MGP sites, and is the amount we consider to be probable
for future investigation and remediation of these sites. This estimate is based upon a comprehensive review of the potential costs associated with conducting investigative and remedial actions at our
identified MGP sites, as well as the likelihood of whether such actions will be necessary. There are also additional costs that we consider to be less likely but still "reasonably

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possible" to be incurred at these sites. Based upon the results of studies at these sites and our knowledge and review of potential remedial action options, it is reasonably possible that these
additional costs could exceed our best estimate by approximately $13.8 million. This estimate could change materially once we have investigated further. It could also be affected by the actions
of environmental agencies and the financial viability of other responsible parties. Ultimate liability also may be affected significantly if we are held responsible for parties unable to contribute
financially to the cleanup effort.

We
have received favorable rate orders that enable us to recover environmental cleanup costs in certain jurisdictions. In other jurisdictions, there are favorable regulatory precedents
for recovery of these costs. We are also pursuing recovery from insurance carriers and other potentially responsible parties.

In
connection with the sale of our gas gathering, processing and pipeline operations in 2002, we retained certain environmental liabilities associated with the past operation of these
businesses.
We are also named as a potentially responsible party at two disposal sites for PolyChlorinated Biphenyls (PCBs). We estimate our share of the probable cleanup costs to be approximately
$1.4 million.

In
May 2000, the state of Missouri adopted a revised regulation that requires reduction of nitrous oxide (NOx) from our power plants. At that time, we estimated the cost of
compliance to be $21.9 million in capital costs and $2.2 million in annual operation and maintenance expense. However, in July 2002, the state adopted a law enabling changes in
the regulation. There is a proposed amendment to the regulation that, if approved, would allow us to comply with the NOx reductions without incurring significant capital or operating expenses. In
2003, several of our power plants will come under a NOx budget requirement. However, this will not significantly impact the business.

In
December 2000, the U.S. Environmental Protection Agency (EPA) announced that it would regulate mercury emissions from coal- and oil-fired power plants.
The EPA is expected to propose regulations by December 2003 and issue final regulations by December 2004. The impact of this action on our power plants cannot be determined until final
regulations are issued.

Regulatory Matters

Canada.In December 2001, we filed for an annual rate increase in Alberta of approximately $30.0 million along
with an application for a performance-based rate-setting mechanism. We subsequently modified that request and sought a $12.7 million increase for 2002 and a $6.0 million
increase for 2003. In July 2002, an interim rate increase of approximately $9.6 million was approved. Hearings were held in September and October 2002 and a final order was issued
in February 2003, resulting in a decrease in rates of $21.0 million for 2002, and no increase in rates in 2003 (2002 rates carry forward to 2003). Almost all of the reduction in rates
related to depreciation on distribution assets (average asset lives were extended) and the related income tax effect. The decision did not adjust the allowed rate of return earned and therefore, net
income is not expected to be materially impacted by this decision. However, the decision is estimated to reduce annual cash flow from operations by approximately $17 million for 2004 and
beyond. With regard to 2003, cash flow from operations will be reduced by approximately $33.0 million, which includes the effect of both the 2002 and 2003 reduction.

As
a result of the above action, we are currently reassessing the future recoverability of $188.6 million of recorded goodwill in Canada.

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Ratings Triggers

We do not have any trigger events (e.g., an acceleration of repayment of outstanding indebtedness, an increase in interest costs or the posting of cash collateral) tied to our
stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events. Certain of our subsidiaries have trigger events tied to
specified credit ratings. Because of guarantee and cross default provisions between Aquila, Inc. and its subsidiaries, the ratings triggers of our subsidiaries discussed below should be viewed
as if they are directly applicable to Aquila, Inc.

In
2002, we retired $91.7 million of our Australian denominated notes that were put to us after the credit downgrades. Our Australian subsidiaries have three other outstanding
series of Australian denominated notes totaling $78.6 million at December 31, 2002. The holders of $62.9 million of these notes exercised their put rights and were repaid in
January 2003. The remaining notes totaling $15.7 million were repaid in April 2003.

Aquila
Merchant also has three "tolling agreements," a construction loan and certain margining agreements that have trigger events tied to Aquila's credit ratings. Under the tolling
agreements, our subsidiary uses a third party's generation assets to convert fuel into electric power for its subsequent resale. As of March 14, 2003, we have posted collateral due to our
downgrades by Moody's and S&P of $82.3 million related to the tolling agreements, $27.5 million related to the construction loan, and $60.0 million related to standard margining
agreements.

Other Potential Demands for Collateral

Although we have substantially exited the wholesale energy trading business of Aquila Merchant, a number of energy trading agreements remain to be settled or liquidated. These
contracts consist of various long-term gas contracts, forward purchases and sales of gas and electricity, weather derivatives, alternative risk contracts, coal and other commodity trading
contracts that are difficult to liquidate. These contracts typically include provisions that allow counterparties to request additional collateral to support underlying transactions if events occur
that cause counterparties to believe that there has been deterioration in our creditworthiness. As a result of the downgrades, we provided collateral to certain counterparties in the form of cash
deposits or letters of credit totaling $145.0 million through March 14, 2003. While it is difficult to predict how
many additional parties may successfully demand some form of collateral, we currently estimate that the amount of additional cash collateral if S&P or Moody's were to downgrade us further would be
minimal.

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The
following table summarizes the collateral posted and debt repaid due to credit downgrades through March 14, 2003, and additional collateral or debt that may be required to be
posted or repaid in the future:

|In millions                   |       | Potential Collateral |       | Amounts Posted/
Paid to Date
|----------------------------- | ----- | -------------------- | ----- | ----------------------------
|                             
|                              |       |                      |       |                             
|Australian denominated bonds  |       | $                    | 170.3 |                             
|Tolling agreements            |       |                      | 82.3  |                             
|Construction loan             |       |                      | 27.5  |                             
|Standard margining agreements |       |                      | 62.0  |                             
|Other collateral demands      |       |                      | 145.0 |                             
|                             
|                              | Total |                      | $     | 487.1                       
|                             

In
addition to collateral calls made due to credit downgrades, fluctuations in commodity prices can also cause both significant inflows and outflows of collateral. This will vary
depending on the magnitude of the price movement and the current position of our portfolio.

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Note 24: Quarterly Financial Data (Unaudited)

Financial results for interim periods do not necessarily indicate trends for any 12-month period. Quarterly results can be affected by the timing of acquisitions,
the effect of weather on sales, and other factors typical of utility operations and energy related businesses. All periods presented have been adjusted to reflect the reclassification of discontinued
operations.

|                                             |                                           | 2002 Quarters |       | 2001 Quarters |  
|-------------------------------------------- | ----------------------------------------- | ------------- | ----- | ------------- | -
|
|
|                                             |                                          
|Sales(1)                                     |                                           | $             | 767.4 |               | $
|Gross profit                                 |                                           |               | 329.3 |               |  
|Earnings (loss) from continuing operations   |                                           | $             | 40.0  |               | $
|Earnings (loss) from discontinued operations |                                           |               | 4.4   |               |  
|Cumulative effect of change in accounting    |                                           |               |      |               |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | 44.4          |  
|                                             |                                          
|Basic earnings per common share:(2)          |                                           |               |       |               |  
|                                             | From continuing operations                |               | $     | .29           |  
|                                             | From discontinued operations              |               |       | .03           |  
|                                             | Cumulative effect of change in accounting |               |       |              |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | .32           |  
|                                             |                                          
|Diluted earnings per common share:(2)        |                                           |               |       |               |  
|                                             | From continuing operations                |               | $     | .29           |  
|                                             | From discontinued operations              |               |       | .03           |  
|                                             | Cumulative effect of change in accounting |               |       |              |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | .32           |  
|                                             |                                          



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Report of Management

The management of Aquila, Inc. is responsible for the information that appears in this annual report, including its accuracy. We prepared the accompanying consolidated
financial statements in accordance with accounting principles generally accepted in the United States. In addition to selecting appropriate accounting principles, we are responsible for the way
information is presented and for its reliability. To report financial results we must often make estimates based on currently available information and judgments of current conditions and
circumstances.

We
have set up well-developed systems of internal control to ensure the integrity and objectivity of the consolidated financial information in this report. These systems are
designed to provide reasonable assurance that Aquila's assets are safeguarded and that the transactions are properly authorized and recorded in accordance with the appropriate accounting principles.

Through
its Audit Committee, the Board of Directors participates in the process of reporting financial information. The Audit Committee selects our independent accountants. It also
reviews, along with management, our financial reporting and internal accounting controls, policies and practices.

|/s/ Gerald L. ShaheenGerald L. Shaheen
Audit Committee Chairman |  | /s/ Rick J. DobsonRick J. Dobson
Interim Chief Financial Officer
|--------------------------------------------------------------- |  | ----------------------------------------------------------------

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Independent Auditors' Report

To the Board of Directors and Shareholders of Aquila, Inc.:

We have audited the accompanying consolidated balance sheets of Aquila, Inc. and subsidiaries as of December 31, 2002 and 2001 and the related consolidated
statements of income, common shareholders' equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2002. In connection with
our audits of the consolidated financial statements, we also have audited the consolidated financial statement schedule, "Schedule IIValuation and Qualifying Accounts," for each of
the years in the three-year period ended December 31, 2002. These consolidated financial statements and the financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Quanta Services, Inc., a
38%, and 36% owned investee company at December 31, 2001, and 2000, respectively. The Company's investment in Quanta Services, Inc. at December 31, 2001 was $773.6 million
and its equity earnings of Quanta Services, Inc. was $30.6 and $53.7 million, respectively for the years ended December 31, 2001, and 2000. The financial statements of Quanta
Services, Inc. as of December 31, 2001 and for the two years ended December 31, 2001 were audited by other auditors whose report has been furnished to us, and our opinion, insofar
as it relates to the amounts included for Quanta Services, Inc., is based solely on the report of the other auditors who have ceased operations.

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

In
our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated
financial position of Aquila, Inc. and subsidiaries as of December 31, 2002 and 2001 and the consolidated
results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002 in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, the related financial statement schedules when considered in relation to the basic consolidated financial statements taken as a whole, present
fairly in all material respects, the information set forth there in.

As
discussed in Note 21, the Company restated its Statement of Cash Flows for the years ended December 31, 2001 and 2000. The 2001 and 2000 consolidated financial
statements were previously audited by other independent auditors who have ceased operations.

As
discussed in Note 2, the Company changed its method of accounting for goodwill and for reporting certain energy trading activities.

/s/
KPMG, LLP
KPMG, LLP
Kansas City, Missouri
April 11, 2003

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

On May 21, 2002, our Board of Directors, upon the recommendation of its Audit Committee, approved the dismissal of Arthur Andersen LLP ("Arthur Andersen") as the
Company's independent auditors and the appointment of KPMG LLP to serve as the Company's independent auditors for the year ending December 31, 2002. The change was effective May 21,
2002.

Arthur
Andersen's reports on the Company's consolidated financial statements for each of the years ended December 31, 2001 and 2000 did not contain an adverse opinion or
disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principles.

During
the years ended December 31, 2001 and 2000 and through the date hereof, there were no disagreements with Arthur Andersen on any matter of accounting principle or practice,
financial statement disclosure, or auditing scope or procedure which, if not resolved to Arthur Andersen's satisfaction would have caused them to make reference to the subject matter of the
disagreement in connection with the audit reports on the Company's consolidated financial statements for such years; and there were no reportable events as defined in Item 304(a)(1)(v) of
Regulation S-K.

We
provided Arthur Andersen with a copy of the foregoing disclosures. A copy of Arthur Andersen's letter dated May 21, 2002, stating its agreement with such statements was filed
as Exhibit 16 to our Current Report on Form 8-K dated May 21, 2002.

During
the years ended December 31, 2001 and 2000 and through May 21, 2002, we did not consult KPMG LLP with respect to the application of accounting principles to a
specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's consolidated financial statements, or any other matters or reportable events
as set forth in Items 304(a)(2)(i) and (ii) of Regulation S-K.

Part 3

Items 10, 11, 12 and 13. Directors and Executive Officers of the Company, Executive Compensation, Security Ownership of Certain Beneficial Owners and  Management and Related Shareholder Matters, and
Certain Relationships and Related Transactions

Information
regarding these items appears in our proxy statement and is hereby incorporated by reference in this Annual Report on Form 10-K. For information regarding our executive
officers, see "Executive Officers of the Registrant" in Item 1, Part 1 of this Form 10-K.

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Equity Compensation Plan Information

The following table provides information as of December 31, 2002 about our compensation plans under which shares of stock have been authorized.

|Plan Category                                              |       | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |           | Weighted-average exercise price of outstanding options, warrants and rights (b) |       | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |          
|---------------------------------------------------------- | ----- | ----------------------------------------------------------------------------------------------- | --------- | ------------------------------------------------------------------------------- | ----- | ----------------------------------------------------------------------------------------------------------------------------------------------- | ---------
|                                                           |      
|Equity compensation plans approved by security holders     |       | 8,497,390                                                                                       | (1)       | $                                                                               | 20.59 |                                                                                                                                                 | 7,117,657
|Equity compensation plans not approved by security holders |       | 411,118                                                                                         | (3)       | $                                                                               | 24.02 |                                                                                                                                                 |         
|                                                           |      
|                                                           | Total |                                                                                                 | 8,908,508 |                                                                                 |       |                                                                                                                                                 |          
|                                                           |      



Item 14. Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining the company's disclosure controls and procedures. These
controls and procedures were designed to ensure that material information relating to the company and its subsidiaries are communicated to the CEO and the CFO. We evaluated these disclosure controls
and procedures within the last 90 days under the supervision of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in
timely alerting them to material information required to be included in our periodic SEC reports. There have been no significant changes in our internal controls and procedures or in other factors
that could significantly affect these controls and procedures subsequent to the date of this evaluation.

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Part 4

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

The following documents are filed as part of this report:

(a)(1) Financial Statements:

The consolidated financial statements required under this item are included under Item 8.

(a)(2) Financial Statement Schedules

Schedule IIValuation and Qualifying Accounts for the years 2002, 2001 and 2000 on page 151.

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

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(a)(3) List of Exhibits *

The following exhibits relate to a management contract or compensatory plan or arrangement:

|10(a)(5)  |  | Amended and Restated 1986 Stock Incentive Plan.                                                                                                        
|--------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------
|10(a)(6)  |  | First Amendment and Second Amendment to Amended and Restated 1986 Stock Incentive Plan.                                                                
|10(a)(7)  |  | Third Amendment to Amended and Restated 1986 Stock Incentive Plan.                                                                                     
|10(a)(8)  |  | Annual and Long-Term Incentive Plan.                                                                                                                   
|10(a)(9)  |  | First Amendment to Annual and Long-Term Incentive Plan.                                                                                                
|10(a)(10) |  | 1990 Non-Employee Director Stock Plan, including all amendments.                                                                                       
|10(a)(11) |  | Form of Severance Compensation Agreement of Certain Executives.                                                                                        
|10(a)(12) |  | Life Insurance Program for Officers.                                                                                                                   
|10(a)(13) |  | Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001.                                                               
|10(a)(14) |  | Employment Agreement for Richard C. Green, Jr.                                                                                                         
|10(a)(15) |  | Employment Agreement for Robert K. Green.                                                                                                              
|10(a)(16) |  | Amended and Restated Capital Accumulation Plan.                                                                                                        
|10(a)(17) |  | First Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                 
|10(a)(18) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Keith Stamm.    
|10(a)(19) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Dan J. Streek.  
|10(a)(20) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Edward K. Mills.
|10(a)(21) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan.                                                                                                 
|10(a)(22) |  | Second Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                
|10(a)(23) |  | UtiliCorp United Inc. Executive Security Trust Amended and Restated as of April 4, 2002.                                                               
|10(a)(24) |  | Agreement dated October 1, 2002 by and between the Company and Robert K. Green.                                                                        
|10(a)(25) |  | Retention Agreement dated as of July 1, 2002 by and between Aquila Merchant Services, Inc. and Edward K. Mills.                                        
|10(a)(26) |  | Retention Agreement dated as of August 13, 2002 by and between the Company and Leslie J. Parrette, Jr.                                                 
|10(a)(27) |  | Severance Payment Agreement Release and Waiver of Claims dated October 17, 2002 by and between the Company and Dan J. Streek.                          
|10(a)(28) |  | Severance Payment Agreement Release and Waiver of Claims dated October 11, 2002 by and between the Company and Edward K. Mills.                        

(b) Reports on Form 8-K

Reports on Form 8-K for the quarter ended December 31, 2002, were as follows:

A
Current Report on Form 8-K with respect to Item 5, dated October 1, 2002, was filed with the Securities and Exchange Commission by the Registrant.

(c) Exhibits

The Index to Exhibits follows on page 152.

149

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(d) Financial Statements of Subsidiaries Not Consolidated and Fifty Percent or Less Owned Persons

The financial statements of Quanta Services, Inc. for the three years ended December 31, 2002, are filed as Exhibit 99.3. These financial statements are
included as filed by Quanta Services, Inc. We take no responsibility for these financial statements.

150

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AQUILA, INC.
SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS
For the Three Years Ended December 31, 2002
(in millions)

|Column A                             |      | Column B |   | Column C |  | Column D |      | Column E
|------------------------------------ | ---- | -------- | - | -------- |  | -------- | ---- | --------
|
|
|                                    
|                                     |      |          |   |          |  |          |      |         
|Allowance for Doubtful Accounts (a) |      |          |   |          |  |          |      |         
|                                     | 2002 |          | $ | 75.8     |  | $        | 38.4 |         
|                                     | 2001 |          |   | 62.8     |  |          | 83.5 |         
|                                     | 2000 |          |   | 35.1     |  |          | 63.1 |         
|Maintenance Reserves (b)            |      |          |   |          |  |          |      |         
|                                     | 2002 |          | $ | 3.2      |  | $        | 2.6  |         
|                                     | 2001 |          |   | 13.5     |  |          | .7   |         
|                                     | 2000 |          |   | 6.6      |  |          | 7.5  |         
|Other Reserves (c)                  |      |          |   |          |  |          |      |         
|                                     | 2002 |          | $ | 17.8     |  | $        | 37.4 |         
|                                     | 2001 |          |   | 21.9     |  |          | 30.3 |         
|                                     | 2000 |          |   | 22.7     |  |          | 25.2 |         
|Restructuring Reserves (d)          |      |          |   |          |  |          |      |         
|                                     | 2002 |          | $ |         |  | $        | 96.0 |         



151

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AQUILA, INC.
INDEX TO EXHIBITS

|Exhibit Number |  | Description                                                                                                                                                                                                    
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|               |  |                                                                                                                                                                                                                
|*3(a)(1)       |  | Restated Certificate of Incorporation of the Company. (Exhibit 3(a) to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.)                                                       
|*3(b)          |  | By-laws of the Company, as amended. (Exhibit 3(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 2001.)                                                                           
|*4(a)          |  | Long-term debt instruments of the Company in amounts not exceeding 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis will be furnished to the Commission upon request.
|10(a)(1)       |  | Indenture of Mortgage and Deed of Trust between the Company and Bank One Trust Company, N.A. dated April 1, 2003.                                                                                              
|10(a)(2)       |  | First Supplemental Indenture to the Indenture of Mortgage and Deed of Trust.                                                                                                                                   
|10(a)(3)       |  | $430 million Credit Agreement among the Company, the lenders and Credit Suisse First Boston dated April 9, 2003.                                                                                               
|10(a)(4)       |  | $200 million Credit Agreement among the Company, the lenders and Credit Suisse First Boston dated April 9, 2003.                                                                                               
|*10(a)(5)      |  | Amended and Restated 1986 Stock Incentive Plan. (Exhibit 10(a)(2) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999.)                                                           
|*10(a)(6)      |  | First Amendment and Second Amendment to Amended and Restated 1986 Stock Incentive Plan. (Exhibit 10(a)(2) to the Company's Annual Report on Form 10-K for the year ended December 31, 2000.)                   
|*10(a)(7)      |  | Third Amendment to Amended and Restated 1986 Stock Incentive Plan. (Exhibit 10(a)(3) to the Company's Annual Report on Form 10-K for the year ended December 31, 2001.)                                        
|*10(a)(8)      |  | Annual and Long-Term Incentive Plan. (Exhibit 10(a)(3) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999.)                                                                      
|*10(a)(9)      |  | First Amendment to Annual and Long-Term Incentive Plan. (Exhibit 10(a)(5) to the Company's Annual Report on Form 10-K for the year ended December 31, 2001.)                                                   
|*10(a)(10)     |  | 1990 Non-Employee Director Stock Plan, including all amendments. (Exhibit 10(a)(4) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999.)                                          
|*10(a)(11)     |  | Form of Severance Compensation Agreement between the Company and certain Executives of the Company. (Exhibit 10(a)(7) to the Company's Annual Report on Form 10-K for the year ended December 31,
2001.)       
|*10(a)(12)     |  | Life Insurance Program for Officers. (Exhibit 10 (a)(13) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995.)                                                                    
|*10(a)(13)     |  | Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001. (Exhibit 10(a)(1) to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2001.)                
|*10(a)(14)     |  | Employment Agreement for Richard C. Green, Jr. (Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.)                                                         
|*10(a)(15)     |  | Employment Agreement for Robert K. Green. (Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998.)                                                                   

152

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|*10(a)(16) |  | Amended and Restated Capital Accumulation Plan. (Exhibit 10(a)(14) to the Company's Annual Report on Form 10-K for the year ended December 31, 2000.)                                                                                                                                         
|---------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*10(a)(17) |  | First Amendment to the Amended and Restated Capital Accumulation Plan. (Exhibit 10(a)(2) to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001.)                                                                                                                 
|*10(a)(18) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Keith Stamm. (Exhibit 10.7 to Registration Statement
No. 333-51718, filed April 18, 2001 by Aquila Merchant Services, Inc. (formerly Aquila, Inc.))    
|*10(a)(19) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Dan J. Streek. (Exhibit 10.8 to Registration Statement
No. 333-51718, filed April 18, 2001 by Aquila Merchant Services, Inc. (formerly Aquila, Inc.))  
|*10(a)(20) |  | Severance Compensation Agreement dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Edward K. Mills. (Exhibit 10.9 to Registration Statement
No. 333-51718, filed April 18, 2001 by Aquila Merchant Services, Inc. (formerly Aquila, Inc.))
|*10(a)(21) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan. (Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)                                                                                                                                 
|*10(a)(22) |  | Second Amendment to the Amended and Restated Capital Accumulation Plan. (Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.)                                                                                                               
|*10(a)(23) |  | UtiliCorp United Inc. Executive Security Trust Amended and Restated as of April 4, 2002. (Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.)                                                                                              
|*10(a)(24) |  | Agreement dated October 1, 2002 by and between the Company and Robert K. Green. (Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.)                                                                                                       
|*10(a)(25) |  | Retention Agreement dated as of July 1, 2002 by and between Aquila Merchant Services, Inc. and Edward K. Mills. (Exhibit 10(a)(2) to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002.)                                                                        
|10(a)(26)  |  | Retention Agreement dated as of August 13, 2002 by and between the Company and Leslie J. Parrette, Jr.                                                                                                                                                                                        
|10(a)(27)  |  | Severance Payment Agreement Release and Waiver of Claims dated October 17, 2002 by and between the Company and Dan J. Streek.                                                                                                                                                                 
|10(a)(28)  |  | Severance Payment Agreement Release and Waiver of Claims dated October 11, 2002 by and between the Company and Edward K. Mills.                                                                                                                                                               
|21         |  | Subsidiaries of the Company.                                                                                                                                                                                                                                                                  
|23.1       |  | Consent of KPMG, LLP.                                                                                                                                                                                                                                                                         
|23.2       |  | Consent of PricewaterhouseCoopers LLP                                                                                                                                                                                                                                                         
|99.1       |  | Certification of Chief Executive Officer.                                                                                                                                                                                                                                                     
|99.2       |  | Certification of Chief Financial Officer.                                                                                                                                                                                                                                                     
|99.3       |  | Financial Statements of Quanta Services, Inc. for the years ended December 31, 2002, 2001 and 2000.                                                                                                                                                                                           



153

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized as of April 11, 2003.

| |  | Aquila, Inc.
| |  | ------------
| |  |             
| |  | By:         

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities
indicated, as of April 11, 2003.

|By: |  | /s/ Richard C. Green, Jr.Richard C. Green, Jr.       |  | President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer)
|--- |  | ---------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------
|By: |  | /s/ Rick J. DobsonRick J. Dobson                     |  | Interim Chief Financial Officer (Principal Financial and Accounting Officer)                           
|By: |  | /s/ John R. BakerJohn R. Baker                       |  | Director                                                                                               
|By: |  | /s/ Herman CainHerman Cain                           |  | Director                                                                                               
|By: |  | s/ Irvine O. Hockaday, Jr.Irvine O. Hockaday, Jr.    |  | Director                                                                                               
|By: |  | /s/ Heidi E. HutterHeidi E. Hutter                   |  | Director                                                                                               
|By: |  | /s/ Dr. Stanley O. IkenberryDr. Stanley O. Ikenberry |  | Director                                                                                               
|By: |  | /s/ Gerald L. ShaheenGerald L. Shaheen               |  | Director                                                                                               

154

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Aquila, Inc.  Chief Executive Officer  Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Richard C. Green, Jr., certify that:





|April 11, 2003 |  | /s/ RICHARD C. GREEN, JR.Richard C. Green, Jr.
Chairman, President and
Chief Executive Officer, Aquila, Inc.
|-------------- |  | ------------------------------------------------------------------------------------------------------------

155

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Aquila, Inc.
Chief Financial Officer
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Rick J. Dobson, certify that:





|April 11, 2003 |  | /s/ RICK J. DOBSONRick J. Dobson
Interim Chief Financial Officer,
Aquila, Inc.
|-------------- |  | ------------------------------------------------------------------------------

156

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