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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, 2003
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.    ý

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, 2003 as reported on the New York Stock Exchange, was approximately $497,887,123. 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 1, 2004
|---------------------------------------------------- |  | ----------------------------
|Common Stock, par value $1.00 per share              |  | 195,409,644                 
|Documents Incorporated by Reference:                 |  | Where Incorporated:         
|Proxy Statement for 2004
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           |     
|                  | Item 9a |     | Controls and Procedures                                                                        |     
|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 |     | Principal Accountant Fees and Services                                                         |     
|Part 4            |         |     |                                                                                                |     
|                  | Item 15 |     | Exhibits, Reports on Form 8-K, and Financial Statement Schedules                               |     
|Index to Exhibits |         | 156
|Signatures        |         | 158

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 an 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 the United States and Canada. As of December 31, 2003, we had 3,235 employees in the United States and 1,202 employees in Canada. Our business is
organized into two groups: our Global Networks Group and Merchant Services. Through our Global Networks Group, we operate electric and natural gas distribution networks serving more than
1.8 million customers in seven mid-continent states and two Canadian provinces. Through Merchant Services, we own, operate and contractually control non-regulated
electric generation assets in the United States. See Management's Discussion and Analysis for further discussion of recent events.

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

Business Group Summary

Segment information for the three years ended December 31, 2003 is included in Note 20 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 generate, transmit and distribute electricity and sell it to approximately 446,000 customers in Colorado, Kansas and Missouri.
Our generation facilities supply electricity principally to our own distribution systems. Additionally, we sell a small volume of excess power to other utilities and marketing companies. Approximately
65% of our electric distribution customers are located in Missouri. We also distribute natural gas to approximately 901,000 customers in Colorado, Iowa, Kansas, Michigan, Minnesota, Missouri and
Nebraska. Our regulated assets located in Missouri represent approximately 50% of the book value of our domestic regulated assets. In addition, Domestic Networks includes Everest Connections, our 96%
owned domestic communications business that provides local and long-distance telephone, cable television, high-speed Internet and data services to areas of greater Kansas City.

3

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Properties

As of December 31, 2003, our owned or leased interests in domestic electric generation plants were as follows:

|Unit      |                      | Location |               | Year Installed |                  | Unit Capability
(MW) |     | Fuel  |          | 2003 Net
Generation
(MW Hours) |          
|--------- | -------------------- | -------- | ------------- | -------------- | ---------------- | -------------------- | --- | ----- | -------- | ------------------------------ | ---------
|          |                     
|Missouri: |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | Sibley #1-3          |          | Sibley        |                | 1960, 1962, 1969 |                      | 502 |       | Coal     |                                | 3,170,803
|          | Ralph Green #3       |          | Pleasant Hill |                | 1981             |                      | 69  |       | Gas      |                                | 4,733    
|          | Nevada               |          | Nevada        |                | 1974             |                      | 20  |       | Oil      |                                | 90       
|          | Greenwood #1-4       |          | Greenwood     |                | 1975-1979        |                      | 241 |       | Gas/Oil  |                                | 39,215   
|          | KCI #1-2             |          | Kansas City   |                | 1970             |                      | 31  |       | Gas      |                                | (145     
|          | Lake Road #1, 3      |          | St. Joseph    |                | 1951, 1962       |                      | 30  |       | Gas/Oil  |                                | 50,198   
|          | Lake Road #2, 4      |          | St. Joseph    |                | 1957, 1967       |                      | 122 |       | Coal/Gas |                                | 645,903  
|          | Lake Road #5         |          | St. Joseph    |                | 1974             |                      | 62  |       | Gas/Oil  |                                | (1,797   
|          | Lake Road #6-7       |          | St. Joseph    |                | 1989, 1990       |                      | 40  |       | Oil      |                                | 671      
|          | Iatan                |          | Iatan         |                | 1980             |                      | 121 |       | Coal     |                                | 898,638  
|Kansas:   |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | Judson Large #4      |          | Dodge City    |                | 1969             |                      | 142 |       | Gas      |                                | 308,427  
|          | Arthur Mullergren #3 |          | Great Bend    |                | 1963             |                      | 96  |       | Gas      |                                | 93,778   
|          | Cimarron River #1-2  |          | Liberal       |                | 1963, 1967       |                      | 72  |       | Gas      |                                | 78,727   
|          | Clifton #1-2         |          | Clifton       |                | 1974             |                      | 71  |       | Gas/Oil  |                                | 4,223    
|          | Jeffrey #1-3         |          | St. Mary's    |                | 1978, 1980, 1983 |                      | 354 |       | Coal     |                                | 2,542,784
|Colorado: |                      |          |               |                |                  |                      |     |       |          |                                |          
|          | W.N. Clark #1-2      |          | Canon City    |                | 1955, 1959       |                      | 43  |       | Coal     |                                | 267,608  
|          | Pueblo #6            |          | Pueblo        |                | 1949             |                      | 20  |       | Gas      |                                | 8,603    
|          | Pueblo #5            |          | Pueblo        |                | 1941, 2001       |                      | 9   |       | Gas      |                                | 24,886   
|          | AIP Diesel           |          | Pueblo        |                | 2001             |                      | 10  |       | Oil      |                                | 1,869    
|          | Diesel #1-5          |          | Pueblo        |                | 1964             |                      | 10  |       | Oil      |                                | 2,721    
|          | Diesel #1-5          |          | Rocky Ford    |                | 1964             |                      | 10  |       | Oil      |                                | 1,103    
|          |                     
|          |                      | Total    |               |                |                  |                      |     | 2,075 |          |                                |          
|          |                     

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

|Fuel SourceIn Megawatts (MW) |                             | 2003  |       | 2002  |       | 2001 
|----------------------------- | --------------------------- | ----- | ----- | ----- | ----- | -----
|                             
|Coal                          |                             | 1,142 |       | 1,142 |       | 1,184
|Gas and oil                   |                             | 933   |       | 950   |       | 931  
|                             
|                              | Total generation capability |       | 2,075 |       | 2,092 |      
|                             

At
December 31, 2003, Domestic Networks had 4,666 miles of electric transmission lines and 15,957 miles of electric distribution lines, and its gas utility operations had 1,569
miles of gas gathering and transmission pipelines and 19,301 miles of distribution mains and service lines.

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

|                               |             | 2003 |         | 2002    |   | 2001   
|------------------------------ | ----------- | ---- | ------- | ------- | - | -------
|                              
|Sales (in millions)            |             |      |         |         |   |        
|                               | Residential |      | $       | 292.2   |   | $      
|                               | Commercial  |      |         | 200.9   |   |        
|                               | Industrial  |      |         | 113.2   |   |        
|                               | Other       |      |         | 91.2    |   |        
|                              
|Total                          |             | $    | 697.5   |         | $ | 666.9  
|                              
|Volumes [Gigawatt hours (GWh)] |             |      |         |         |   |        
|                               | Residential |      |         | 4,107   |   |        
|                               | Commercial  |      |         | 3,391   |   |        
|                               | Industrial  |      |         | 2,570   |   |        
|                               | Other       |      |         | 1,765   |   |        
|                              
|Total                          |             |      | 11,833  |         |   | 12,373 
|                              
|Customers at Year End          |             |      |         |         |   |        
|                               | Residential |      |         | 381,033 |   |        
|                               | Commercial  |      |         | 60,531  |   |        
|                               | Industrial  |      |         | 457     |   |        
|                               | Other       |      |         | 3,869   |   |        
|                              
|Total                          |             |      | 445,890 |         |   | 437,965
|                              

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

|                                    |                | 2003 |         | 2002    |   | 2001   
|----------------------------------- | -------------- | ---- | ------- | ------- | - | -------
|                                   
|Sales (in millions)                 |                |      |         |         |   |        
|                                    | Residential    |      | $       | 620.1   |   | $      
|                                    | Commercial     |      |         | 263.5   |   |        
|                                    | Industrial     |      |         | 40.3    |   |        
|                                    | Other          |      |         | 45.6    |   |        
|                                   
|Total                               |                | $    | 969.5   |         | $ | 765.1  
|                                   
|Volumes [Thousand Cubic Feet (Mcf)] |                |      |         |         |   |        
|                                    | Residential    |      |         | 74,507  |   |        
|                                    | Commercial     |      |         | 34,889  |   |        
|                                    | Industrial     |      |         | 6,612   |   |        
|                                    | Transportation |      |         | 111,570 |   |        
|                                    | Other          |      |         | 417     |   |        
|                                   
|Total                               |                |      | 227,995 |         |   | 235,127
|                                   
|                                    |                |      |         |         |   |        

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|Customers at Year End |             |  |         |         |  |         |         |  |        
|--------------------- | ----------- |  | ------- | ------- |  | ------- | ------- |  | -------
|                      | Residential |  |         | 807,853 |  |         | 796,207 |  |        
|                      | Commercial  |  |         | 81,485  |  |         | 81,180  |  |        
|                      | Industrial  |  |         | 2,227   |  |         | 2,300   |  |        
|                      | Other       |  |         | 9,212   |  |         | 10,840  |  |        
|                     
|Total                 |             |  | 900,777 |         |  | 890,527 |         |  | 874,038
|                     

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 Domestic Networks' peak seasons.

Operations

PeakGas network operations

November through MarchElectric network operations

July and August


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, but 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

State Regulation

Our domestic utility operations are subject to the jurisdiction of the public service commissions in the states in which they operate. The commissions oversee
services and facilities, rates and charges, accounting, valuation of property, depreciation and various other matters. Certain commissions also have jurisdiction over the creation of liens on property
located in their state to secure bonds or other securities.

On
May 7, 2003, the State Corporation Commission of the State of Kansas issued an order in connection with its investigation into the affiliated transactions between our domestic
utilities and our other businesses. On June 26, 2003, the Kansas Commission modified the May 7 order. The May 7, 2003 and June 26, 2003 orders are filed as exhibits to our
Annual Report on Form 10-K. Among other things, the orders provide that without the approval of the Kansas Commission, we may not:



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The
following summarizes our recent rate case activity:

|(In millions) |  | Type of
Service |  | Date
Requested |  | Date
Approved |  | Amount
Requested |      | Amount
Approved
|------------- |  | --------------- |  | -------------- |  | ------------- |  | ---------------- | ---- | ---------------
|             
|Minnesota     |  | Gas             |  | 8/2000         |  | 7/2003        |  | $                | 9.8  |                
|Iowa          |  | Gas             |  | 6/2002         |  | 2/2003        |  |                  | 9.3  |                
|Michigan      |  | Gas             |  | 8/2002         |  | 3/2003        |  |                  | 14.3 |                
|Colorado      |  | Electric        |  | 10/2002        |  | 6/2003        |  |                  | 23.4 |                
|Nebraska      |  | Gas             |  | 6/2003         |  | 1/2004        |  |                  | 9.9  |                
|Missouri      |  | Electric        |  | 7/2003         |  | Pending       |  |                  | 80.9 |                
|Missouri      |  | Gas             |  | 8/2003         |  | Pending       |  |                  | 6.4  |                
|Colorado      |  | Electric        |  | 12/2003        |  | Pending       |  |                  | 11.4 |                
|             

We
filed a Minnesota gas rate case in August 2000 for an increase of $9.8 million. A settlement was reached with the intervenors in the case for $5.7 million. The
settlement was approved by the Minnesota Commission in July 2003. This rate increase had been collected on an interim basis since October 2000.

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

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 in
December 2002. We reached a settlement with the Michigan Commission staff and other intervening parties for an increase of $9.1 million. This settlement was approved by the Michigan
Commission and the new rates went into effect in March 2003. This increase was partially offset within a separate depreciation case docket which reduced our annual rates by $.7 million.
That decrease relates to our depreciation rates and reduced cash flow with little impact on earnings.

In
October 2002, we filed for a $23.4 million increase in our Colorado electric rates. In April 2003, we reached a settlement with the Colorado Commission staff and
other intervening parties for an increase of $16.0 million. The new rates became effective in June 2003 when the

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settlement
was approved by the Commission. In December 2003, we filed a "limited" rate filing in order to recover approximately $11.4 million in ongoing costs (e.g., capital
improvements) that have occurred in 2003 or will occur in 2004. The Colorado Commission is expected to review this filing and make its decision in the second half of 2004.

In
June 2003, we filed for gas rate increases totaling $9.9 million in three rate areas of Nebraska. We received approval to place an interim rate increase of
$9.9 million into effect beginning in October 2003, subject to refund. In December 2003, we reached a settlement with Nebraska's Public Advocate and other intervening parties for
an increase of $6.2 million. The settlement was approved by the Nebraska Commission in January 2004.

In
July 2003, we filed for rate increases totaling $80.9 million for our electric territories in Missouri. These applications were to recover increased costs of natural gas
used to fuel our power plants, necessary capital expenditures since our prior rate case, increased pension costs and decreased off-system sales. In December 2003, the Commission
staff recommended a $9.0 million increase for our electric and steam rates. We filed rebuttals to the staff and intervenor recommendations on January 26, 2004. Hearings began in late
February and are expected to be completed in March 2004.

In
August 2003, we filed a rate increase request totaling $6.4 million for our gas territories in Missouri. These increases are needed primarily to recover the cost of
system improvements and higher operating costs. Hearings are scheduled to be held in March and April 2004.

Our
domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute natural 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 gas 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 match the actual cost we incurred.

In
our regulated electric business, we generate approximately 60% of the power that we sell and we purchase the remaining 40% 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 that serves a purpose similar to the gas utility's PGAs. 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. In Colorado, we have an Incentive Clause Adjustment that
provides for recovery from the customer of 75% of the variability in energy costs. 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.

Federal Regulation

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, and long- and short-term debt, the sale, lease or other disposition of such facilities, and accounting matters.

8

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In
December 1999, the FERC issued Order 2000 addressing some significant regional electricity transmission issues. Among other things, Order 2000 required transmission-owning
utilities, including Aquila, that did 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. We have made the filings required by Order 2000, and are otherwise in compliance with the order, but our transmission facilities are not yet
controlled by a regional transmission organization.

In
November 2003, the FERC issued Order 2004 adopting new standards of conduct for transmission-owning utilities. Essentially, under the order, a transmission-owning utility must
separate its transmission function from its marketing function and from the operations of its affiliates engaged in energy-related activities. Also, every transmission-owning utility must treat all of
its transmission customers, whether affiliated or unaffiliated, on a non-discriminatory basis. The new standards become effective on June 1, 2004, and we are in the process of
determining the extent to which our operations must be modified to comply with the order.

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:



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 U.S. Environmental Protection Agency (EPA).

In
April 2002, the EPA proposed new rules for cooling water intake structures. The final action originally expected in 2003 did not take place but is expected in the first quarter
of 2004. The final action 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 our operations.

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The
Clean Water Act requires states to develop Total Maximum Daily Loads (TMDLs) for impaired surface waters in each state. TMDLs determine the maximum amount of pollutants that can be
discharged into impaired surface waters. In July 2000, the EPA issued a final rule for the implementation of the TMDL program. The EPA has since announced its intention to withdraw the TMDL Rule,
although it is anticipated that state agencies will continue to develop TMDLs for impaired waters in their respective states. The establishment of TMDL values may eventually result in more stringent
discharge limits for facilities that have wastewater discharge permits. We will not know the future impact of the TMDL program until applicable TMDLs are developed.

Air Emissions

Our facilities are subject to the Federal Clean Air Act and many state and local laws and regulations relating to the protection of air quality. These laws and
regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (SO2), nitrogen oxides (NOx) and particulate matter.
In addition, carbon dioxide is also included as a potential emission that may be regulated. Fossil-fueled power generating facilities are subject to substantial regulation and enforcement oversight by
various governmental agencies.

In
December 2003, the EPA proposed a rule known as the Interstate Air Quality Rule. The proposed rule suggests a "cap and trade" approach, which would effectively require coal-fired
power plants in 29 eastern states, including Kansas and Missouri, to reduce SO2 emissions by 70% and NOx emissions by 65% below current levels. The reductions would occur in a two-phased
approach beginning in 2010. The EPA also proposed a rule known as the Utility Mercury Reductions Rule in December 2003. The proposed Utility Mercury Reduction Rule would require coal-fired power
plants across the country to limit mercury emissions beginning in 2010. If these proposed rules are implemented, the costs of compliance could be material to us.

The
EPA has been conducting enforcement initiatives nationwide to determine whether certain activities conducted at electric generating facilities were subject to the EPA's New Source
Review (NSR) requirements under the Clean Air Act, which the EPA is interpreting to require coal-fired power plants to update emission controls at the time of major maintenance or capital
activity. Several utility companies have entered into settlement agreements with the EPA that resulted in fines and commitments to install the best available pollution controls at facilities alleged
to have violated the EPA's NSR requirements.

In
January 2004, Westar Energy, Inc. received a notification from the EPA that it had violated the EPA's NSR requirements and Kansas environmental regulations by making
modifications to the Jeffrey Energy Center without obtaining the proper permits. The Jeffrey Energy Center is a large coal-fired power plant located in Kansas that is 84% owned by Westar
and operated exclusively by Westar. We have a 16% interest in the Jeffrey Energy Center. The electric generation plants we own or lease are described in the table at Item 1, page 4. It is possible
that
Westar could be subject to an enforcement action by the EPA and required to make significant capital expenditures to install additional pollution controls at the Jeffrey Energy Center.

Past Operations

Some federal and state laws authorize the EPA and other agencies to issue orders and compel potentially responsible parties to clean up sites that are determined
to present an actual or potential threat to human health or the environment. We are named as a potentially responsible

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party
at two disposal sites for polychlorinated biphenyls (PCBs). In addition, we retain some environmental liability for several operations and investments that we no longer own. We also own or have
acquired liabilities from companies that once owned or operated 29 former manufactured gas plant sites, which are subject to the supervision of the EPA and various state environmental agencies.
Although these remediation costs will be significant, we are seeking to recover our costs from insurance carriers and other potentially responsible parties.

International Networks

The following discussion describes our International Networks businesses.

Canada

We own Aquila Networks Canada (British Columbia) Ltd. (ANCBC), a hydroelectric utility in British Columbia. ANCBC owns four hydroelectric generation
facilities with a combined capacity of 212 megawatts and approximately 4,368 miles of distribution and transmission lines that serve approximately 95,000 customers in south central British Columbia.
ANCBC generates about half its power needs and acquires the rest through power purchase contracts. We also own Aquila Networks Canada (Alberta) Ltd. (ANCA). ANCA serves approximately 401,000
electric customers through 59,648 miles of low-voltage distribution lines representing 50% of Alberta's distribution network. As part of our restructuring initiatives, in
September 2003, we agreed to sell our Canadian operations to Fortis Inc. We expect this sale to be closed in the second quarter of 2004. See Note 6 to the Consolidated Financial
Statements for further discussion of this agreement.

As
of December 31, 2003, our hydroelectric generation plants in British Columbia included the following:

|Unit  |       | Location         |  | Year Installed |  | Unit Capability
(MW) |       | 2003 Net
Generation
(MW Hours)(a)
|----- | ----- | ---------------- |  | -------------- |  | -------------------- | ----- | ---------------------------------
|     
|No. 1 |       | Lower Bonnington |  | 1924           |  | 44.4                 |       | 227,567                          
|No. 2 |       | Upper Bonnington |  | 1907           |  | 60.0                 |       | 178,438                          
|No. 3 |       | South Slocan     |  | 1928           |  | 56.4                 |       | 227,752                          
|No. 4 |       | Corra Linn       |  | 1932           |  | 51.3                 |       | 188,251                          
|     
|      | Total |                  |  |                |  |                      | 212.1 |                                  
|     



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

|                      |  | 2003 |         | 2002 |   | 2001   
|--------------------- |  | ---- | ------- | ---- | - | -------
|                     
|Sales (in millions)   |  | $    | 245.5   |      | $ | 258.7  
|Volumes (GWh)         |  |      | 16,486  |      |   | 16,003 
|Customers at Year End |  |      | 495,763 |      |   | 482,553
|                     

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Australia

In June 2003, a consortium of AlintaGas Limited, AMP Henderson and their affiliates (the AMP Consortium) acquired all of the outstanding shares of
AlintaGas Limited, in which we held a 22.5% indirect ownership interest. See Note 5 to the Consolidated Financial Statements for a more detailed discussion of this divestiture.

In
July 2003, the AMP Consortium acquired all of the issued and outstanding shares of United Energy Limited and a 100% ownership interest in Multinet Gas. Prior to this
transaction, we had a 33.8% ownership interest in United Energy Limited and a 25.5% equity interest in Multinet Gas. See Note 5 to the Consolidated Financial Statements for a more detailed
discussion of these related divestitures.

United Kingdom

In January 2004, a subsidiary of Powergen UK plc acquired from us and our partner, FirstEnergy Corp., a 100% equity interest in Aquila Sterling Limited,
the holding company for Midlands Electricity, a United Kingdom electric distribution network. See Note 5 to the Consolidated Financial Statements for a more detailed discussion of this
divestiture.

We
will not own or operate any network operations outside of the United States upon completion of the sale of our Canadian businesses.

Seasonal Variations of Business

Our Canadian electric business is weather-sensitive. Its peak season is from November through March.

Regulation

Our investments in electric distribution businesses in Canada 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 the Alberta Energy Utilities Board (AEUB),
respectively. Customer rates are generally set for one- or two-year periods based on a forecast 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 had access to alternate suppliers. We sold our Alberta retail supply business to an unaffiliated company in December 2000.

12

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The
following highlights our recent rate case activity in Canada:

|(In millions)    |  | Type of
Service |  | Date
Requested |  | Date
Approved |  | Amount
Requested |  | Amount
Approved
|---------------- |  | --------------- |  | -------------- |  | ------------- |  | ---------------- |  | ---------------
|                
|Alberta          |  | Electric        |  | 12/2001        |  | 3/2003        |  | $12.7            |  | $(21.0)        
|British Columbia |  | Electric        |  | 11/2002        |  | 2/2003        |  | 4.9              |  | 4.2            
|British Columbia |  | Electric        |  | 12/2003        |  | Pending       |  | 6.5              |  | Pending        
|                

Our
Alberta electric utility operated on interim tariff rates during the period January 1, 2002 through July 31, 2003 pending a regulatory decision. In its decision
rendered in early 2003, and through subsequent filings and reviews during 2003, the AEUB rendered a decision on 2002 and 2003 distribution tariff rates and ordered final revised rates for the period
August 1 through December 31, 2003 to adjust interim rates to final rates. The decision resulted 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. Because
the decision did not adjust the allowed rate of return we earn, we don't expect net income to be materially impacted by this decision. However, we expect the decision to reduce annual cash flow from
operations by approximately $27.2 million for 2004 and beyond. With regard to 2003, cash flow from operations was reduced by approximately $46.2 million, which includes the effect of
both the 2002 and 2003 reductions.

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. In late 2003, we filed an application with the BCUC to extend the existing settlement agreement and
performance-based rate-setting mechanism for 2004. Although 2004 was supposed to be a rebasing year for the performance-based rate-setting mechanism, we decided to seek an
extension of the existing rate arrangements due to ANCBC's proposed change of ownership. Negotiations were held on February 24 and 25, 2004. A negotiated settlement was reached in principle and
remains pending while the BCUC completes the process of writing the documentation that will be circulated for sign-off by the participants to the settlement.

Environmental Matters

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 are governed by the Canadian Fisheries Act and provincial water permits and licenses. The Department of Fisheries and Oceans is moving towards stricter
regulations under the Fisheries Act, which might lead to higher compliance costs in the future.

II.    Merchant Services

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

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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 1.7 million shares of Aquila Merchant Class A shares exercised their dissenters' rights to request an
appraisal of the fair value of their shares 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 implementation of our restructuring plan (including
the asset sales discussed below), our remaining Capacity Services assets are non-regulated power generation assets.

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.

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. The plant became operational 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 in December 2002. Concurrent with the 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 in December 2002. Concurrent with the financings described in Notes 12 and 13 to the Consolidated
Financial Statements, this debt was repaid in full during the second quarter of 2003.

Sale of Coal Terminal

In February 2003, we sold our West Virginia coal terminal.

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Sale of Turbines

In the second quarter of 2003, we completed the sale and contract termination of certain turbines that we wrote down to an estimated realizable value at
December 31, 2002.

Acadia Tolling Agreement

In May 2003, we terminated our 20-year tolling agreement for the Acadia power plant in Louisiana. After making a termination payment of
$105.5 million, we were released from the remaining aggregate payment obligation of $833.9 million, or approximately $43.5 million on an annual basis.

Sale of Independent Power Plants

In March 2004, we expect to close the sale of our interest in 12 contracted independent power plants to Teton Power Funding, LLC, an affiliate of ArcLight
Capital Partners, LLC. See Notes 5 and 6 to the Consolidated Financial Statements for a more detailed discussion of this divestiture. An additional plant was sold to another third party under a
separate agreement in January 2004.

Properties

Contracted Independent Power Plants

We own interests in a number of "qualifying facilities" (QFs) and "exempt wholesale generators" (EWGs) that 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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Our contracted independent power plants, as of December 31, 2003, are described below:

|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         |     | 305                 |  | 153               |  | 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) |                           | 1,815 |               | 967 |                     |  |                   | 
|                                                 

With the exception of Batesville and BAF Energy, all of our interests in the above plants are under contract to be sold or have been sold after
December 31, 2003.

Merchant Power Plants

We own or control 2,084 MW of net power generation capacity from merchant facilities. 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 the utilities 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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Our
merchant power plants are described below:

|Plant & Location                         |                     | Type of
Investment |       | Percent
Owned |       | Gross
Capacity
(MW) |  | Net
Capacity
(MW) |  | Heat
Rates(a) |  | Fuel |  | Date in
Service      
|---------------------------------------- | ------------------- | ------------------ | ----- | ------------- | ----- | ------------------- |  | ----------------- |  | ------------- |  | ---- |  | ---------------------
|                                        
|                                         |                     |                    |       |               |       |                     |  |                   |  |               |  |      |  |                      
|Aries L.L.C., Missouri (EWG)             |                     | Owned              |       | 50.0          |       | 580                 |  | 290               |  | 7.1           |  | Gas  |  | June 2001/(b)May 2002
|Elwood Energy L.L.C.,
Illinois (EWG)     |                     | Toll contract      |       |              |       | 604                 |  | 604               |  | 10.7          |  | Gas  |  | July 2001(c)         
|Coahoma Power Plant,
Mississippi (EWG)   |                     | Owned              |       | 100.0         |       | 340                 |  | 340               |  | 11.9          |  | Gas  |  | September 2002       
|Clay County Power Plant,
Illinois (EWG)  |                     | Owned              |       | 100.0         |       | 340                 |  | 340               |  | 11.9          |  | Gas  |  | November 2002        
|Piatt County Power Plant,
Illinois (EWG) |                     | Owned              |       | 100.0         |       | 510                 |  | 510               |  | 12.0          |  | Gas  |  | June 2003            
|                                        
|                                         | Total Capacity (MW) |                    | 2,374 |               | 2,084 |                     |  |                   |  |               | 
|                                        



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 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. Although we continue to
work in the marketplace to mitigate our costs, if such events do not occur, or the spread between the cost of gas and the price of power does not increase, we will incur significant losses related to
these plants.

Wholesale Services

Our Wholesale Services business historically consisted of our Capital Services, Client Services and Commodity Services businesses. Although we have exited the
wholesale energy trading

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business
and are winding down the activities related to Wholesale Services, an understanding of these operations continue to be relevant because this business historically represented a substantial
portion of our income, expense, assets and liabilities.

Commodity Services

Our Commodity Services business was a marketer and trader of wholesale natural gas, electricity and other commodities in North America and Western Europe. We
stopped increasing our wholesale trading portfolio during the third quarter of 2002, and 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. Commodity price volatility related to most of our
positions has been mitigated to limit our exposure to price movements.

The
following table reflects the decrease in the gross physical volumes for our trading portfolio over the past three years.

|                                  |  |       |  | 2002  |  | 2003 
|--------------------------------- |  | ----- |  | ----- |  | -----
|
|
|
|                                 
|Natural Gas (Bcf/d)               |  | 13.5  |  | 17.1  |  | 9.3  
|Power (MM MWh)                    |  | 350.0 |  | 266.6 |  | 219.0
|Coal (Million tons)               |  | 22.7  |  | 9.9   |  | 11.2 
|Trillion Btu equivalent per day * |  | 24.6  |  | 33.2  |  | 22.6 
|                                 

Power

We purchased 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 entered
into 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.

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 entered into transportation arrangements with affiliated
and

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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, 2003, we had obligations of
$671.1 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

Our Client Services business offered products to help our clients manage multiple risks, including price, liquidity, credit, 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. We exited this business in 2002.

Capital Services

Our Capital Services business 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 credit facilities, convertible preferred stock and volumetric production payments.

Our
Capital Services earnings were derived from the spread between the price we charged 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 merchant 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. The sale for
resale of natural gas in North America has substantially completed its evolution to an open access market.

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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 of 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 the owner imposes on itself.

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 (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 no 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, the facilities are exempt from otherwise applicable requirements of PUHCA, the FPA and state laws respecting rate and

20

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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.

In
1992, Congress passed the Energy Policy Act (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 rate-making 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 the Public Utility Regulatory Policies Act (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.

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Our Executive Team

|Name                          |  | Age |  | Position                                                      
|----------------------------- |  | --- |  | --------------------------------------------------------------
|                              |  |     |  |                                                               
|Richard C. Green (Rick)       |  | 49  |  | President, Chief Executive Officer and Chairman               
|Keith G. Stamm                |  | 43  |  | Senior Vice President and Chief Operating Officer             
|Rick J. Dobson                |  | 45  |  | Senior Vice President and Chief Financial Officer             
|Leo E. Morton                 |  | 58  |  | Senior Vice President and Chief Administrative Officer        
|Leslie J. Parrette, Jr. (Les) |  | 42  |  | Senior Vice President, General Counsel and Corporate Secretary
|Sally C. McElwreath           |  | 63  |  | Senior Vice President, Corporate Communications               
|Brock A. Shealy               |  | 42  |  | Senior Vice President, Corporate Compliance Officer           
|Jon R. Empson                 |  | 58  |  | Senior Vice President, Regulated Operations                   
|Robert L. Poehling (Bob)      |  | 40  |  | Senior Vice President, Energy Resources                       

Richard C. Green (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 University)

Keith joined our company in 1983 as a staff engineer at the 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, an
affiliated electric distribution company that was listed on the Australian Stock Exchange in 1998. From January 2000 to November 2001, he served as Chief Executive Officer of Aquila
Merchant. In November 2001, he was appointed President and Chief Operating Officer of our Global Networks Group. 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 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 in 1997 and served as Vice President Financial Management until November 2002, when he was appointed Interim Chief Financial Officer of Aquila. In
May 2003, Rick was appointed Senior Vice President and 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

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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., Sociology; 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.

Sally C. McElwreath (B.A., Social Sciences; M.B.A., Public Relations, Pace University)

Sally joined our company in 1994 as Senior Vice President, Corporate Communications. She left the company in 2001 and returned in the same position in
June 2003. Prior to joining our company, she was Vice President, Corporate Communications for Macmillan Inc. and for The Travel Channel; Director of Marketing Communications for
TransWorld Airlines; and Manager of Corporate Communications for United Airlines beginning in 1971. Prior to 1971, she held various positions with ARCO and Sinclair Oil Corporation. Sally also served
as a public affairs officer in the U.S. Naval Reserve, attaining the rank of captain.

Brock A. Shealy (A.B., Psychology; Drury College; J. D., University of Missouri-Kansas City)

Brock joined our company in August 1999 as Director, Employee and Labor Relations. He transferred to our Merchant operations in August 2000 and
became Vice President, Human Resources in January 2001. He was named Chief Administrative Officer for Aquila Merchant's European operations in December 2001, and became a director of
Aquila Energy Limited and its European Merchant affiliates in January 2002. He was appointed our Senior Vice President and Corporate Compliance Officer in August 2003. Prior to joining
our company, Brock was an associate then partner with the law firm of Blackwell Sanders Peper Martin LLP from 1989 through July 1999.

Jon R. Empson (B.A., Economics, Carleton College; M.B.A., Economics, University of Nebraska at Omaha)

Jon joined our company in 1986 as Vice President, Regulation, Finance and Administration of one of our major utility divisions. In 1993, Jon was appointed
Aquila's Senior Vice President, Gas Supply and Regulatory Services and in 1996 he was appointed Senior Vice President, Regulatory, Legislative and Environmental Services. In December 2003, Jon
was appointed Senior Vice President, Regulated Operations. Prior to joining the company, Jon worked for a predecessor company in various executive and management positions for seven years, held
executive management positions at the Omaha Chamber of Commerce and Omaha Economic Development Council and worked as an economist with the U.S. Department of Housing and Urban Development.

Robert L. Poehling (B.S., Business, University of Nebraska)

Bob joined our company in 1991 and served in various operating and management positions until 1996 when he was appointed Vice President, General Manager of an
affiliated merchant company in Australia. In 1999, he was appointed Senior Vice President of Aquila Merchant. In December 2003, Bob was appointed as our Senior Vice President, Energy Resources.

23

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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 the Consolidated Financial Statements for a description of the liens.

Item 3.  Legal Proceedings

Litigation

On February 19, 2002, we filed a suit which is currently pending in the U.S. District Court for the Western District of Missouri 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
$513.0 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 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 federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange
offer completed in January 2002. The suit raised 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. On December 9, 2003, the court denied
our motion to dismiss this lawsuit. Persons holding certificates formerly representing approximately 1.7 million shares of Aquila Merchant common stock are also pursuing their appraisal rights
in connection with the recombination. The dissenters' rights action is scheduled for trial in May 2004. We do not believe that either of these actions will have an outcome materially adverse to
us.

On
August 18, 2003, EPCOR filed a lawsuit against Aquila, Inc., Aquila Networks Canada Limited, and Aquila Networks Canada (Alberta) Ltd. in the Court of Queen's Bench of
Alberta. EPCOR alleges Aquila breached its agreements with EPCOR in which our Alberta utility is to provide EPCOR customer and billing information in connection with EPCOR's provision of retail
service to southern and central Alberta customers. EPCOR claims C$77 million for breach of the agreements and for negligence, including damage to its reputation, and C$6 million in
aggravated and punitive damages. In response to preliminary motions, EPCOR has provided particulars of its claims and we filed a Statement of Defense in late February 2004. This litigation will
be assumed by the purchaser of our Canadian operations upon the closing of the sale transaction, and an affiliate of the purchaser has agreed to indemnify us against any damages or liabilities arising
from this litigation after completion of the sale.

24

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In
August and November 2003, two class action lawsuits brought on behalf of entities which bought and sold natural gas futures and options contracts on the New York Mercantile
Exchange during the years 2000 through 2002 were filed in the U.S. District Court for the Southern District of New York. The suits are against numerous defendants, including the company's subsidiary,
Aquila Merchant, and seek damages for alleged violations of the Commodity Exchange Act and for allegedly aiding and abetting such violations. Plaintiffs claim that, during the referenced time period,
the defendants reported false and misleading trading information to trade publications, including inflated volume and price information, resulting in monetary losses to the plaintiffs. Plaintiffs seek
class action certification, actual damages in unspecified amounts, costs, attorneys' fees and other appropriate relief.

Other Matters

In January 2004, Aquila Merchant and the Commodity Futures Trading Commission (CFTC) trial staff reached a settlement regarding the reporting of natural
gas trading information to publications that compile and report index prices. The period of data reporting covered by the settlement was from at least January 1999 through May 2002. In
January 2004, the CFTC filed and simultaneously approved an order settling an administrative action against Aquila Merchant. The CFTC order states several of Aquila Merchant's trading desks
knowingly submitted reports containing non-existent trades, as well as certain actual trades in which the price and/or volume
was altered. Aquila Merchant agreed to pay a civil penalty of $26.5 million without admitting or denying the commission's findings.

On
April 30, 2003, the FERC issued an order requiring Aquila Merchant and 10 other companies to make written demonstrations regarding index price reporting practices. The order
required Aquila Merchant to state the disciplinary actions taken, identify its code of conduct for price submissions, show that its submission practices lack financial conflicts of interest, and show
that it is cooperating with related government investigations. The FERC announced on July 23, 2003 that it "accepted" Aquila Merchant's account of internal remedies for reporting natural gas
trading data and stated that Aquila Merchant met the order's requirements.

On
June 25, 2003, the FERC issued two orders to show cause concerning Enron-type gaming behavior in the western power markets during the region's 2000-2001
energy crisis. The FERC order encouraged parties to consider settlement of these issues through discussions with the FERC trial staff and on August 29, 2003, FERC trial staff and Aquila
Merchant entered into an agreement in which we agreed to pay $76,000 to bring full and final resolution of all issues related to Aquila Merchant in the orders to show cause. The agreement was approved
by the FERC in March 2004.

In
May 2003, the company's Board of Directors received an anonymous letter dated May 12, 2003. The May 12 letter alleges that (1) the company's 2000 and 2001 financial
results were manipulated in order to increase executive bonuses; (2) certain executives and employees of the company and three Australian corporations in which Aquila previously held an
indirect minority stock interest engaged in improper related-party or self-dealing transactions in Australia; (3) certain executives of the company engaged in unlawful efforts to influence
foreign government officials and provided false financial information to banks, investors and the Aquila Board in connection with the purchase of government-owned natural gas distribution assets in
the Melbourne area; and (4) the company engaged in undisclosed related-party real estate transactions with company executives. The Board referred the May 12 letter to the Audit Committee
for an independent investigation. A copy of the May 12, 2003, letter was sent to the Securities and Exchange Commission ("SEC"), which has opened an inquiry into the matter and

25

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asked
the company to retain documents relevant to the allegations made in the letter. Through its professional advisors, the Committee has been in contact with the SEC regarding the letter and the
Audit Committee's investigation. The Committee has completed its investigation into these matters and submitted a written report of the investigation. The company filed the Committee's report with the
SEC on March 8, 2004, as an exhibit to the company's Current Report on Form 8-K. Subject to any further developments, none of which are anticipated at this time, the Committee has
completed its investigation of this matter. In summary, the Committee found the allegations of the May 12 letter were without merit.

As
described in Item 1. BusinessEnvironmental Matters of this report, we are involved in the remediation of certain properties under the oversight of federal and
state environmental agencies.

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 2003.

26

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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 (NYSE) under the symbol ILA. Through March 15, 2002, the symbol was UCU. At March 1, 2004, we had approximately
34,000 common shareholders of record. Information relating to market prices of common stock on the NYSE and cash dividends on common stock is set forth below. On March 1, 2004, the reported last sale
price of the common stock on the NYSE was $4.10 per share.

Market Price Per Share

|              |  | High |       | Low |   | Cash
Dividends
|------------- |  | ---- | ----- | --- | - | --------------
|
|              |  |      |       |     |   |               
|2003 Quarters |  |      |       |     |   |               
|First         |  | $    | 2.50  |     | $ | 1.07          
|Second        |  |      | 3.22  |     |   | 1.63          
|Third         |  |      | 3.85  |     |   | 2.16          
|Fourth        |  |      | 4.37  |     |   | 3.17          
|             
|2002 Quarters |  |      |       |     |   |               
|First         |  | $    | 26.95 |     | $ | 21.77         
|Second        |  |      | 25.23 |     |   | 7.26          
|Third         |  |      | 8.23  |     |   | 2.04          
|Fourth        |  |      | 4.25  |     |   | 1.56          
|             

In
the third quarter of 2002, as part of our strategic and financial repositioning, our Board of Directors suspended the annual dividend on common stock indefinitely. This decision
followed a detailed analysis of our current financial condition and our liquidity forecast. 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 Aquila's credit profile. We can make no determination at this time as to whether, or when, we will begin to pay dividends in the future.

Item 6.  Selected Financial Data

|In millions, except per share amounts         |                       | 2003 |         | 2002  |   | 2001     |        | 2000 |          | 1999
|--------------------------------------------- | --------------------- | ---- | ------- | ----- | - | -------- | ------ | ---- | -------- | ----
|                                             
|Sales                                         |                       | $    | 1,674.0 |       | $ | 2,041.1  |        | $    | 3,375.8  |     
|Gross profit                                  |                       |      | 549.9   |       |   | 549.1    |        |      | 1,408.6  |     
|Earnings (loss) from continuing operations(a) |                       |      | (350.6  | )(b)  |   | (1,726.3 | )(c)   |      | 196.8    | (d) 
|Basic earnings (loss) per common share       |                       |      |         |       |   |          |        |      |          |     
|                                              | Continuing operations |      |         | (1.80 | ) |          | (10.67 | )    |          | 1.76
|Diluted earnings (loss) per common share     |                       |      |         |       |   |          |        |      |          |     
|                                              | Continuing operations |      |         | (1.80 | ) |          | (10.67 | )    |          | 1.70
|Cash dividends per common share               |                       |      |        |       |   | .775     |        |      | 1.20     |     
|Total assets                                  |                       |      | 7,719.1 |       |   | 9,376.0  |        |      | 11,966.5 |     
|Short-term debt                               |                       |      |        |       |   | 287.8    |        |      | 445.0    |     
|Long-term debt (including current maturities) |                       |      | 2,706.0 |       |   | 2,626.5  |        |      | 2,439.0  |     
|Common shareholders' equity                   |                       |      | 1,359.3 |       |   | 1,607.9  |        |      | 2,551.6  |     
|                                             

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The following notes reflect the pretax effect of items affecting the comparability of the Selected Financial Data above:

(a)   Depreciation
and amortization expense included (in millions) $13.1, $8.1 and $1.8 of goodwill amortization for the years ended December 31, 2001, 2000 and 1999,
respectively. Goodwill amortization was not recorded in the years ended December 31, 2003 and 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 and $6.6,
respectively, of goodwill amortization.

(b)   Included
in earnings (loss) from continuing operations for the year ended December 31, 2003, are (a) a $105.5 million termination payment regarding
our 20-year tolling agreement for the Acadia power plant; (b) an $87.9 million impairment charge on our equity method investments in 12 independent power plants; and
(c) $28.2 million of restructuring charges from exit from interest rate swaps related to our Clay County and Piatt County construction financing arrangements and additional severance and
retention payments related to the continued wind-down of our energy trading operations and the restructuring of Everest Connections.

(c)   Included
in earnings (loss) from continuing operations for the year ended December 31, 2002, are (a) a $696.1 million impairment charge on our
investment in Quanta Services; (b) a $247.5 million impairment charge on our investment in Midlands Electricity; (c) a $127.2 million impairment charge on our investment in
Multinet Gas and AlintaGas; (d) a $227.6 million impairment charge related to our 96% investment in Everest Connections; (e) a $178.6 million write-down of
Wholesale Services' goodwill; (f) other impairment charges and losses on sale of assets of $94.5 million, primarily as a result of our decision to sell non-core 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 restructuring of our utility business.

(d)   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 (net income reflects 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 $31.8 million in Domestic Networks; (c) recorded charges of $16.5 million in our
communications business; 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.

(e)   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.

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

Strategic and Financial Repositioning

There have been significant changes in the energy industry during the three years ended December 31, 2003. These changes were primarily a result of lower
prices in the power markets as new generation capacity continued 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 continued 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 the majority of our related activities and assets during
2002. We continued to unwind and restructure our remaining merchant contracts and sell non-core assets in 2003. Separately, we restructured Domestic Networks in 2002 to more closely align
it with its regulatory service areas. Staff reductions due to our ongoing restructuring efforts, 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 in 2002. With our exit from wholesale trading, we began to transition to a business comprised primarily of our
domestic regulated utility business and our merchant power plants. We consider our domestic utility assets our core business. As part of this transition, we took the following actions in 2002:



In
2003, we continued to execute on our transition plan through the following actions:



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Proceeds
from these asset sales were used to pay down debt, fund restructuring charges and support our continuing operations.

We
now plan to operate primarily as a regulated utility with various investments in non-regulated power generation facilities. As we continue our transition in 2004, we
intend to focus on the following areas:



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LIQUIDITY AND CAPITAL RESOURCES

Overall

Because of our non-investment grade credit rating and limitations on our ability to raise incremental capital through the bank and capital markets,
for short-term liquidity needs, we must rely primarily on our existing cash position combined with anticipated proceeds from pending asset sales. The following table reflects our
anticipated cash sources and key short-term contractual obligations for 2004 (including short-term debt reported in discontinued operations):

|In millions                                               |                                                 |  
|--------------------------------------------------------- | ----------------------------------------------- | -
|
|Anticipated Cash Sources:                                 |                                                 |  
|Cash at December 31, 2003                                 |                                                 | $
|Pending asset sale proceeds:                              |                                                 |  
|                                                          | Midlands                                        |  
|                                                          | Independent power plants                        |  
|                                                          | Canadian utility operations(a)                  |  
|                                                         
|Total                                                     |                                                 | $
|                                                         
|Anticipated Debt and Long-term Gas Contract Requirements: |                                                 |  
|Short-term debt:                                          |                                                 |  
|                                                          | Bank borrowingsCanada                          |  
|Current maturities of long-term debt:                     |                                                 |  
|                                                          | Senior notes due on July 15 and October 1, 2004 |  
|                                                          | Canadian asset securitization (b)               |  
|                                                          | Miscellaneous                                   |  
|                                                         
|                                                          | Subtotal                                        |  
|                                                         
|Long-term gas contract commitments                        |                                                 |  
|                                                         
|Total                                                     |                                                 | $
|                                                         



We plan to address our short-term obligations with cash on hand and the pending asset sale proceeds listed above. In the event the asset sales do not
occur prior to maturity of our short-term obligations, we will need to address the maturity of our senior notes listed above with existing cash and additional borrowings to bridge the
timing of the pending asset sale proceeds. The remaining liquidity, after the pending asset sales close and the short-term obligations are satisfied, will be used for future working
capital requirements and discretionary liability reductions. Liability reductions would most likely be in the form of reduction of our debt and contractual liabilities, including tolling contracts and
long-term gas contracts.

In
February 2004, we extinguished approximately $80.6 million, including principal and accrued interest, of a note payable. We paid $78.6 million to extinguish this
note resulting in other income related to this transaction of approximately $2.0 million. We originally issued this note to FirstEnergy Corp. in connection with our investment in Midlands
Electricity in 2002. This note required annual payments of $19.0 million through May 2008. In 2003, FirstEnergy sold this note to two unrelated third parties.

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Pending Asset Sales

In September 2003, we agreed to sell our Canadian utility businesses to Fortis Inc. for approximately C$1,360 million
(US$1,047 million at the December 31, 2003 exchange rate), including the repayment or assumption of C$174 million (US$134 million at the December 31, 2003 exchange
rate), or US$913 million in net proceeds to us before closing adjustments, transaction costs and taxes. We estimate that we will pay approximately US$80.0 million in cash taxes and
transaction costs. In addition, we will be required to repay US$215 million borrowed by our Canadian subsidiaries under a 364-day unsecured loan. The transaction is subject to
approval of the regulatory commissions in Alberta and British Columbia, among other regulatory bodies, as well as other customary closing conditions, and is expected to close in the first half of
2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate. We have a currency hedge on the anticipated Canadian asset sale proceeds. See discussion of
currency rate exposures under Item 7a. Quantitative and Qualitative Disclosures About Market Risk.

In
October 2003, we agreed to sell our 79.9% interest in ASL, the owner of Midlands Electricity plc, to a subsidiary of Powergen UK plc, for approximately
£36 million, before transaction costs. We completed the sale in January 2004 and received proceeds before transaction costs of $55.5 million.

In
November 2003, we agreed to sell our interest in 12 independent power projects to Teton Power Funding, LLC, an affiliate of Arclight Capital Partners, LLC. This sale is
expected to close in March 2004 and we expect to receive net cash proceeds of approximately $257.0 million, before transaction costs and taxes.

Working Capital Requirements

Due to our non-investment grade credit rating and lack of short-term lines of credit, we must maintain cash on hand at all times to cover
the peak working capital requirements of our business. The most significant activity impacting working capital is the purchase of natural gas for our gas utility customers. We could experience
significant working capital requirements during peak winter heating months due to higher natural gas consumption, potential periods of high natural gas prices and the fact that we are currently
required to prepay certain of our gas commodity suppliers and pipeline transportation companies. We are currently working on solutions to shorten the time lag between our procurement of the commodity
and the collection of our revenue. This could be accomplished through a combination of establishing an accounts receivable sales program, or establishing credit lines with our commodity vendors.

Cash Flows

Cash Flows from Operating Activities

Our 2003 cash flows from operations were negative due to significant cash impacts resulting primarily from our non-investment grade credit rating and
the continued exit from our wholesale energy trading business. Our negative 2003 cash flows were driven by the following events and factors:



32

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Cash
flows from operations in 2002 were also negative. These cash flows were negative primarily as a result of our significant losses in 2002, our non-investment grade credit
rating and our actions taken to exit from the wholesale energy trading business. Our negative 2002 operating cash flows were driven by the following events and factors:



We
also have material margin losses related to our long-term gas contracts in our operating cash flows. These margin losses represent the cash payments for gas purchased to settle these
contracts on a monthly basis, net of the contract amortization reported in financing activities discussed below. These obligations and our capacity tolling contracts will have a material negative
impact on our operating cash flows for the foreseeable future. We are attempting to restructure

33

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or
terminate these obligations. Any cash payments made to exit these obligations will have a negative impact on operating cash flows in the year the payment is made, but are expected to improve
operating cash flows in future periods.

Our
significant debt load relative to our overall capitalization and the 14.875% interest rate we pay on $500 million of our long-term bonds has substantially increased our interest
costs and will continue to negatively impact our operating cash flows. We expect to reduce our overall interest expense in 2004 by retiring a portion of our debt through the use of proceeds that will
be generated from the sale of our Canadian utility businesses and independent power projects. These interest savings will be partially offset, however, by the loss of cash flows from the businesses
that are sold.

It
will be important for us to substantially improve our operating cash flows. We are attempting to do this by improving the efficiency of our remaining businesses, increasing revenues
through utility rates, retiring debt and restructuring the obligations discussed above.

Cash Flows from Investing Activities

Cash flows provided from investing activities increased in 2003 compared to 2002. This increase mainly stemmed from reduced capital expenditures in 2003,
primarily in the merchant business, as merchant plant construction was significantly completed in 2002. We also made a significant investment in Midlands Electricity in 2002 which did not recur in
2003. In addition, we sold our merchant loan portfolio in December 2002. This portfolio generated net cash outflows in 2002. These decreased cash outflows were partially offset by a decrease in
cash received from the sale of assets and subsidiary stock in 2003 compared to 2002.

Cash
provided from investing activities in 2002 increased from 2001. This increase primarily stemmed from $1.1 billion of cash received on the sale of assets and a reduction in
merchant capital expenditures. Partially offsetting these cash sources was increased capital expenditures for utility plant additions. In addition, the acquisition of our interest in Midlands
Electricity in May 2002 increased cash used for investing activities.

Cash Flows from Financing Activities

Cash flows from financing activities decreased in 2003 compared to 2002. Our 2003 net cash used for financing activities stems from the repayment of
short-term borrowings and from the reduction of long-term debt.

Cash
flows from financing activities in 2002 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 our accounts receivables sale programs that were terminated in 2002 and to retire debt and company-obligated preferred securities.

We
also have material cash outflows related to our long-term gas contracts in our financing activities. These cash outflows represent the amortization of our recorded
liability based on the units of revenue method of accounting. The combined operating cash outflow and financing cash outflow related to long-term gas contracts represents the total cost to
purchase gas to service

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these
contracts. If we do not terminate or restructure these contracts, we will continue to have similar cash outflows related to these contracts in our financing activities in future periods.

Current Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and vendor payment terms. Our financial
flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment
grade borrowers. As of December 31, 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
|                                   

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.

Collateral Positions

As of December 31, 2003, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:

|In millions                          |  | December 31,
2003
|------------------------------------ |  | -----------------
|
|Trading positions                    |  | $                
|Utility cash collateral requirements |  |                  
|Tolling agreements                   |  |                  
|Insurance and other                  |  |                  
|                                    
|Total Funds on Deposit               |  | $                
|                                    

Collateral requirements for our remaining trading positions will fluctuate based on movement in commodity prices. This will vary depending on the magnitude of the
price movement and the current position of our portfolio. We will receive our posted collateral related to trading positions as we settle our trading positions in the future.

We
are required to post collateral to certain of our commodity and pipeline transportation vendors. This amount will fluctuate depending on gas prices and projected volumetric
deliveries. The ultimate return of this collateral is dependent on our successful strengthening of our credit profile.

We
have been required to post collateral related to our Elwood tolling contract until we either successfully restructure the contact or obtain investment-grade ratings from certain major
rating agencies. We will not be required to post any additional collateral related to this contract.

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Contractual Obligations

Our contractual cash obligations include maturities of long-term debt, cash payments for long-term gas contracts, minimum payments on
operating leases and regulated power, gas and coal purchase contracts, as well as merchant tolling obligations and gas transportation obligations. See Notes 13, 14 and 21 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                             |  | 2004 |       | 2005 |   | 2006  |  | 2007 |       | 2008 |   | Thereafter |  | Total
|--------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------- |  | -----
|
|Long-term debt obligations              |  | $    | 414.8 |      | $ | 54.8  |  | $    | 532.8 |      | $ | 55.1       |  | $    
|Long-term gas contracts                 |  |      | 132.9 |      |   | 137.4 |  |      | 143.1 |      |   | 144.9      |  |      
|Lease and maintenance obligations       |  |      | 27.4  |      |   | 20.1  |  |      | 14.7  |      |   | 13.4       |  |      
|Merchant tolling obligations            |  |      | 57.7  |      |   | 68.9  |  |      | 76.7  |      |   | 76.7       |  |      
|Merchant gas transportation obligations |  |      | 8.8   |      |   | 8.8   |  |      | 8.3   |      |   | 5.8        |  |      
|Regulated purchase obligations          |  |      | 271.6 |      |   | 239.6 |  |      | 212.7 |      |   | 183.9      |  |      
|                                       
|Total                                   |  | $    | 913.2 |      | $ | 529.6 |  | $    | 988.3 |      | $ | 479.8      |  | $    
|                                       

In addition, we have contractual obligations related to our discontinued operations. See Note 6 to the Consolidated Financial Statements.

Long-Term Gas Contracts

We accounted for the cash payments in advance related to these contracts as liabilities. 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 would be required to pay the
issuers of the surety bonds or the counterparties on these arrangements approximately $860.0 million. This amount is greater than the long-term gas contract balance on our
Consolidated Balance Sheet due to our use of the units of revenue method of relieving the long-term obligation versus a present value method applied under default provisions based on
contractual agreements.

Merchant Tolling Obligations

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, during the foreseeable future, we believe that under our merchant tolling agreements our capacity to generate power will largely be unutilized. After including existing forward
sales contracts, we expect to incur pretax losses and negative operating cash flows of approximately $38.0 million in 2004 related to these contracts. We are attempting to terminate or
restructure these obligations. 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 future earnings and cash flow will be negatively impacted.

36

---

Off-Balance Sheet Arrangements

The term "off-balance sheet arrangement" generally means any transaction, agreement or other contractual arrangement to which an entity that we do not
consolidate is a party, under which we have (i) any obligation arising under a guarantee contract, derivative instrument or variable interest; or (ii) a retained or contingent interest
in assets transferred to
such entity or similar arrangement that serves as credit, liquidity or market risk support for such assets. As of December 31, 2003, we have obligations under certain off-balance
sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations,
liquidity, capital expenditures or capital resources that may be material to investors as follows:

Merchant Loan Portfolio

In connection with our former portfolio of merchant loans to energy-related businesses, we 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 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. As of December 31, 2003 we have collected $27.3 million related to these swaps, of which we have reserved $10.5 million to cover this obligation. The value
of the unsettled portion of these swaps was $26.5 million at December 31, 2003.

Guarantees

We have guaranteed the performance of certain gas aggregators in connection with loans that were made by our 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. We have terminated all of these agreements
as of December 31, 2003. Our exposure is limited to the outstanding payable balances of the aggregators as of the termination dates of these agreements. Our guarantees for these agreements at
December 31, 2003 totaled $9.2 million.

Equity Put Rights

Certain shareholders of Everest Connections have the option to sell their share interests to us if Everest Connections does not meet certain financial and
operational performance measures (target-based put rights) as of December 31, 2004. If the target-based put rights were exercised, we would be obligated to purchase up to 4.0 million and
4.75 million share 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 probability-weighted expense of $7.1 million. As of December 31, 2003, we reserved $7.8 million for
this obligation. Such shareholders also have the option to sell their share interests to us at fair market value (market-based put rights) if they have not exercised their target-based put rights. The
market-based put rights expire on December 31, 2005 for 9.5 million shares and do not expire for the remaining 3.25 million shares. We have not provided for this potential
obligation as the exercise would represent an equity transaction at fair value.

37

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Capital Expenditures

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

|                      |                            | Actual |       | Estimated Future
Cash Requirements
|--------------------- | -------------------------- | ------ | ----- | ----------------------------------
|
|
|                     
|                      |                            |        |       |                                   
|Domestic utilities    |                            | $      | 125.5 |                                   
|Everest Connections   |                            |        | 12.2  |                                   
|Canadian utilities(a) |                            |        | 121.7 |                                   
|Merchant Services     |                            |        | 20.5  |                                   
|Corporate and Other   |                            |        | 6.6   |                                   
|                     
|                      | Total capital expenditures |        | $     | 286.5                             
|                     



Regulatory Approvals Required for Financing

We are required to obtain the prior approval of the FERC, Kansas Corporation Commission and Colorado Public Utilities Commission prior to issuing
long-term debt or stock. We currently have approval from the Kansas Commission and Colorado Commission to issue up to $100 million of common stock and $150 million of
long-term debt that is convertible into our common stock. Our application with the FERC for similar authority is pending.

We
are required to obtain the prior approval of the FERC and Kansas Corporation Commission to issue short-term debt. We have submitted an application to these agencies for
approval to have outstanding up to $500 million of secured or unsecured short-term debt. These applications are pending.

The
use of our utility assets as collateral generally requires the prior approval of the FERC and the regulatory commission in the state in which the utility assets are located.

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. Because financing for the various business segments is generally completed at the parent company level, EBIT provides our management and third parties an
indication of how well individual business segments are performing. 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

38

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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 69 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                                               |                                        |                             | (219.2
|                                                         |                                       
|Interest expense                                         |                                        |                             | 273.1 
|Income tax expense (benefit)                             |                                        |                             | (141.7
|                                                         |                                       
|Earnings (loss) from continuing operations               |                                        |                             | (350.6
|Earnings (loss) from discontinued operations, net of tax |                                        |                             | 14.2  
|Cumulative effect of accounting change, net of tax       |                                        |                             |      
|                                                         |                                       
|Net income (loss)                                        |                                        | $                           | (336.4
|                                                         |                                       
|Diluted earnings (loss) per share:                       |                                        |                             |       
|                                                         | Continuing operations                  |                             | $     
|                                                         | Discontinued operations                |                             |       
|                                                         | Cumulative effect of accounting change |                             |       
|                                                         |                                       
|                                                         | Net income (loss)                      |                             | $     
|                                                         |                                       

Key Factors Impacting Continuing Operating Results

Our total loss before interest and taxes decreased significantly in 2003 compared to 2002. Key factors affecting 2003 improved results were as follows:



39

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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.

40

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Restructuring Charges

As further discussed in Note 4 to the Consolidated Financial Statements, we recorded the following restructuring charges:

|                                    |                                                    | Year Ended December 31,
|----------------------------------- | -------------------------------------------------- | -----------------------
|
|                                   
|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         |                                                    | $                      
|                                   

41

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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:

|                                                        |                                                         | Year Ended December 31,
|------------------------------------------------------- | ------------------------------------------------------- | -----------------------
|
|
|                                                        |                                                         |                        
|Domestic Networks:                                      |                                                         |                        
|                                                        | Quanta Services                                         |                        
|                                                        | Everest Connections and other communication investments |                        
|                                                        | Enron exposure                                          |                        
|                                                        | Gas distribution system                                 |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Domestic Networks                                 |                                                         |                        
|                                                       
|International Networks:                                 |                                                         |                        
|                                                        | Midlands                                                |                        
|                                                        | Australia                                               |                        
|                                                        | Other                                                   |                        
|                                                       
|Total International Networks                            |                                                         |                        
|                                                       
|Capacity Services:                                      |                                                         |                        
|                                                        | Acadia tolling agreement                                |                        
|                                                        | Turbines                                                |                        
|                                                        | Independent power plants                                |                        
|                                                        | 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                                |                                                         |                        
|                                                       
|Total impairment charges and net loss on sale of assets |                                                         | $                      
|                                                       

During
2003 and 2002, we also incurred impairment charges and net losses on asset sales of $47.5 million and $438.2 million, respectively, that are reflected in
discontinued operations and are not included in the table above.

Discontinued Operations

As further discussed in Note 6 to the Consolidated Financial Statements, we have reported the results of operations of the following assets in discontinued
operations in the Consolidated Statements of Income: (1) our Texas natural gas storage facility, 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, our West Virginia coal terminal and

42

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our
merchant loan portfolio that were all sold in 2002 and early 2003, and (2) our Canadian network businesses and our consolidated independent power plants, Lake Cogen and Onondaga, that we
are in the process of selling. We have reported the results of these businesses in discontinued operations in the Consolidated Statements of Income.

Operating
results of discontinued operations are as follows:

|                                             |                                                   | Year Ended December 31,
|-------------------------------------------- | ------------------------------------------------- | -----------------------
|
|
|                                             |                                                   |                        
|Sales                                        |                                                   | $                      
|Cost of sales                                |                                                   |                        
|                                            
|Gross profit                                 |                                                   |                        
|                                            
|Operating expenses:                          |                                                   |                        
|                                             | Operating expense                                 |                        
|                                             | 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    |                                                   |                        
|Interest expense                             |                                                   |                        
|                                            
|Earnings (loss) before income taxes          |                                                   |                        
|Income tax expense (benefit)                 |                                                   |                        
|                                            
|Earnings (loss) from discontinued operations |                                                   | $                      
|                                            

2003 versus 2002

Sales, Cost of Sales and Gross Profit

Sales and cost of sales decreased $249.0 million and $161.5 million, respectively, resulting in a gross profit decrease of $87.5 million in
2003 compared to 2002. These decreases were primarily due to the sale of our gas gathering and pipeline assets and our coal terminal in the fourth quarter of 2002 and early 2003. In addition, sales
and gross profit for our Canadian network businesses decreased $12.9 million and $20.6 million, respectively, due to the decision by the AEUB to decrease our 2002 and 2003 customer
billing rates.

Operating Expense

Operating expense decreased $46.2 million in 2003 compared to 2002 primarily due to the sale of our gas gathering and pipeline assets, our merchant loan
portfolio and our coal terminal in 2002 and early 2003.

43

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Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets consisted of $47.5 million related to our consolidated independent power plants, Lake Cogen and Onondaga.
In the third quarter of 2003, we decided to proceed with the sale of these assets and therefore wrote these assets down to estimated fair value less costs to sell, which was less than their carrying
value. For a discussion of 2002 impairment charges and net loss on sales of assets, see "2002 versus 2001" below.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $73.6 million in 2003 compared to 2002. When we classified our Canadian utility as held for sale, we
stopped recording depreciation expense for that business. This decreased depreciation expense by $20.5 million. Approximately $23.2 million of the decrease in depreciation and
amortization was due to the sale of our gas gathering and pipeline assets and our coal terminal in the fourth quarter of 2002 and early 2003. The remaining decrease was primarily due to the decision
by the AEUB to reduce the depreciation rates on most of our distribution assets in Alberta.

Equity in Earnings of Investments

Equity in earnings of investments decreased $5.3 million due to the sale of our investment in the Oasis Pipe Line Company in the fourth quarter of 2002.

Other Income

Other income decreased $74.0 million in 2003 compared to 2002, primarily due to the sale of our merchant loan portfolio in the fourth quarter of 2002. This
business generated $47.1 million of other income in 2002. In 2003, we incurred an $18.5 million charge related to a currency put option purchased to protect us from unfavorable currency
movements on the Canadian asset sale proceeds and $3.2 million of foreign currency losses related to U.S. dollar denominated debt issued by our Canadian subsidiaries.

Income Tax Benefit

Income tax benefit decreased $1.8 million primarily due to pretax income in 2003 compared to a pretax loss in 2002 and the AEUB decision discussed above.
This decision decreased sales and depreciation; however, only the sales impact is tax-effected for Canadian regulatory purposes. In 2002, $190.9 million of our losses were 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 future capital gains, we recorded a $75.4 million valuation allowance against our capital loss carryforward. In addition, the 2002 impairment charges and net loss on sale
of assets included the effects of $31.9 million of goodwill and other intangibles that were not deductible for income tax purposes. These benefits were offset by income tax expense that was
recorded for our Canadian operations. Due to our decision to sell this business, we can no longer represent that cash from this business will be permanently reinvested. Therefore, additional deferred
tax was recorded to account for taxes that will arise when we bring asset sales proceeds back to the United States. In addition, approximately $28.0 million of the 2003 impairment charge on our
consolidated independent power plants is expected to be a capital loss for which we have provided additional valuation allowances.

44

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2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales and cost of sales decreased $223.4 million and $203.8 million, respectively, resulting in a decrease in gross profit of $19.6 million
in 2002 compared to 2001. These decreases were primarily due to lower natural gas liquids prices and throughput volumes for 2002 compared to 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, 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. Also decreasing sales and cost of sales was 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 later approved for recovery in future periods. These decreases were
offset by a $4.2 million rate increase in British Columbia and a $9.6 million interim rate increase in Alberta.

Operating Expense

Operating expense increased $17.9 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 and $4.0 million of increased operating costs in our Canadian networks.

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 terminal, a $4.3 million pretax gain on sale of our gas storage assets, a $6.4 million impairment charge on a Canadian power
plant and $5.2 million of other impairment charges.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased in 2002 by $6.7 million primarily as a result of the sale of our gas gathering and pipeline assets in
October 2002.

Income Tax Expense (Benefit)

Our 2002 losses resulted in an income tax benefit, as compared to income tax expense in 2001 due to earnings. See discussion of significant valuation allowances
recorded in 2002 on capital losses incurred by our discontinued operations under "2003 versus 2002."

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. Additionally, our results for the two years ended December 31, 2002 include our

45

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ownership
interest in Quanta Services, Inc., a provider of field services to electric utilities, telecommunications and cable television companies, and governmental entities. We began
decreasing our ownership interest in Quanta Services in July 2002 and sold our remaining shares in February 2003.

International
Networks included our equity method investments in Australia, New Zealand, the United Kingdom and our wholly-owned utility businesses in Canada. Because we are currently in
the process of selling our Canadian utility businesses, the results of those operations have been reclassified as discontinued operations and are not included below (see Note 6 to the
Consolidated Financial Statements). Our Australian investments included 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 45.0% interest, held jointly with UEL, in AlintaGas Limited, a gas distribution company in Western Australia. We sold our
Australian investments in May and July 2003. Our United Kingdom investment consisted of an indirect 79.9% interest in Aquila Sterling Limited, the holding company for Midlands Electricity, an
electric distribution company in central England. We sold our United Kingdom investment in January 2004. Our results for the two years ended December 31, 2002, include the earnings from
our investment in UnitedNetworks Limited, a New Zealand gas and electric distribution company that we sold in October 2002.

46

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Three-Year ReviewDomestic Networks

|                                                |                                                          | Year Ended December 31,
|----------------------------------------------- | -------------------------------------------------------- | -----------------------
|
|
|                                                |                                                          |                        
|Sales:                                          |                                                          |                        
|                                                | Electricityregulated                                    |                        
|                                                | Natural gasregulated                                    |                        
|                                                | Natural gasnon-regulated                                |                        
|                                                | Othernon-regulated                                      |                        
|                                               
|Total sales                                     |                                                          |                        
|                                               
|Cost of sales:                                  |                                                          |                        
|                                                | Electricityregulated                                    |                        
|                                                | Natural gas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 (gain) on sale of assets |                        
|                                                | Depreciation and amortization expense                    |                        
|                                               
|Total operating expenses                        |                                                          |                        
|                                               
|Other income (expense):                         |                                                          |                        
|                                                | Equity in earnings of investments                        |                        
|                                                | Minority interest in loss of subsidiaries                |                        
|                                                | Other income                                             |                        
|                                               
|Earnings (loss) before interest and taxes       |                                                          | $                      
|                                               
|Electric sales and transportation volumes (GWh) |                                                          |                        
|Gas sales and transportation volumes (Mcf)      |                                                          |                        
|Electric customers                              |                                                          |                        
|Gas customers                                   |                                                          |                        
|                                               

2003 versus 2002

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Networks businesses decreased $71.7 million and $92.4 million, respectively, resulting in a gross profit
increase of $20.7 million in 2003 compared to 2002. These changes were primarily due to the following factors:



47

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Operating Expense

Operating expense decreased $29.6 million in 2003 compared to 2002, primarily due to approximately $15.6 million of lower labor, benefits and
administrative expenses resulting from the restructuring of our domestic utility operations and $6.5 million of cost savings in Everest Connections associated with the restructuring of its
operations in 2003. We also incurred approximately $5.5 million of expenses in 2002 primarily related to the proxy contest for control of Quanta Services.

Restructuring Charges

Restructuring charges decreased $19.2 million in 2003 compared to 2002. In the first half of 2003, we completed restructuring the operations of Everest
Connections. This resulted in the termination of approximately 160 employees and $2.1 million of severance and related restructuring costs. For 2002 restructuring charges see "2002 versus 2001"
below.

Impairment Charges and Net (Gain) Loss on Sale of Assets

As further discussed in Note 5 to the Consolidated Financial Statements, Domestic Networks incurred losses of $932.7 million resulting from
impairments in 2002 compared to a net $.2 million gain in 2003 on several minor asset dispositions or impairments. For discussion of 2002 impairment charges and net loss on sale of assets see
"2002 versus 2001" below.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $6.6 million in 2003 compared to 2002, primarily due to the reduced depreciable base at Everest Connections
resulting from the impairment charge recorded in the fourth quarter of 2002.

Minority Interest in Loss of Subsidiaries

Minority interest in loss of subsidiaries decreased $7.8 million in 2003 compared to 2002 due to the reduction of Everest Connections' minority capital
balances to zero in October 2002. In accordance with Everest Connections' limited liability company agreement, losses were allocated first to the membership units held by minority shareholders
until their capital accounts were

48

---

depleted.
After all minority accounts were reduced to zero, losses were allocated to us. As a result, we have recorded all of Everest Connections' losses in 2003.

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 $358.0 million, respectively, in 2002 compared to 2001,
resulting in a decrease in gross profit of $36.3 million. These changes were primarily due to the following factors:



Operating Expense

Operating expense decreased $4.6 million in 2002 compared to 2001. The decrease 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 reductions 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.

49

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Impairment Charges and Net Loss on Sale of Assets

As further discussed in Note 5 to the Consolidated Financial Statements, Domestic Networks incurred losses of $932.7 million 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 Connections 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 2002 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.

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 reduced equity earnings from our
Quanta Services investment resulting
from Quanta Services' lower earnings in 2002 and a reduction of our ownership 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 Quanta Services' financial statements.

Other Income

Other income 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, which was written off in 2001.

50

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Three-Year ReviewInternational Networks

The operating results for our Canadian utility businesses have been reclassified as discontinued operations for all periods presented. The table below summarizes
our former investments in International Networks, including our equity method investments in Australia (sold in the second and third quarters of 2003), New Zealand (sold in the fourth quarter of 2002)
and the United Kingdom (sold in January 2004).

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

2003 versus 2002

Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets for 2003 included a $1.8 million pretax loss on the sale of our interests in AlintaGas, United Energy and
Multinet Gas in Australia and a $4.0 million impairment charge related to our investment in Midlands resulting from the sale agreement with Powergen. In 2002, we recorded impairment charges of
$127.2 million related to our investment in Multinet Gas and AlintaGas and $247.5 million related to our investment in Midlands. See Note 5 to the Consolidated Financial
Statements for further explanation.

Equity in Earnings of Investments

Equity in earnings of investments decreased $95.9 million in 2003 compared to 2002. This decrease was primarily due to the sale of our interest in
UnitedNetworks Limited in New Zealand in October 2002, which contributed equity earnings of $30.9 million in 2002, the recent sale of our Australian investments which contributed
$39.2 million of equity earnings in 2002 compared to $16.1 million in 2003, and not recording equity earnings in 2003 from our Midlands investment due to regulatory limitations on cash
payments by Midlands to its owners. In 2003, we received no cash dividends or payments for 2003 management fees which would have enabled us to recognize earnings on this investment. Our share of
undistributed net earnings from Midlands was $55.9 million in 2003. During 2002, we recorded equity earnings of $41.9 million related to our Midlands investment.

Other Income

Other income increased $11.7 million in 2003 compared to 2002. This increase was primarily due to $12.3 million of foreign currency gains recognized
in the second quarter of 2003 due to the

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strengthening
of the Canadian dollar on U.S. dollar obligations of a former Canadian finance subsidiary not included in discontinued operations.

2002 versus 2001

Operating Expense

Operating expense increased $6.2 million in 2002 compared to 2001. This increase was primarily due to 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 Midlands investment and a $127.2 million impairment charge related to
our investments in Multinet Gas and AlintaGas in Australia. We determined these impairments based on the estimated fair value of these investments considering current market information, which
included offers to purchase our interests in these businesses, as well as corresponding impairment charges being taken in the financial statements of the underlying business. See Note 5 for
further explanation.

Equity in Earnings of Investments

Equity in earnings of investments increased $50.5 million in 2002 compared to 2001. Midlands, which was acquired in May 2002, contributed
$41.9 million 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 due
to the adoption of SFAS 142.

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.

Current Operating Developments

Midlands

In October 2003, we and FirstEnergy Corp. agreed to sell 100% of the Aquila Sterling Limited (ASL) shares outstanding to a subsidiary of Powergen UK plc
for approximately £36 million. As a result of this agreement and our analysis of fair value surrounding this investment, in the third quarter of 2003, we recorded an additional
$4.0 million pretax and
after-tax impairment charge to write this investment down to its estimated fair value. We completed the sale of ASL in January 2004 and received proceeds before transaction costs of
$55.5 million. We estimate we will pay approximately $7.6 million in transaction fees. We expect to record a pretax and after-tax gain of approximately $3.0 million due to changes
in the British pound exchange rate primarily in the fourth quarter of 2003 and early 2004.

Canada

In September 2003, we agreed to sell our Canadian utility businesses for approximately C$1,360 million (US$1,047 million at the
December 31, 2003 exchange rate) before the assumption or repayment of certain debt, closing adjustments, transaction costs and taxes. The

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transaction
is subject to approval of the regulatory commissions in Alberta and British Columbia, among other regulatory bodies, as well as other customary closing conditions, and is expected to close
in the second quarter of 2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate. We expect to record a gain on this sale at the date of close. The
results of operations and related assets and liabilities of our Canadian utility businesses are included in discontinued operations. See Note 6 to the Consolidated Financial Statements for
further discussion.

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
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 and the minority interest was 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.

Three-Year ReviewCapacity Services

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

Due to the rescission of EITF 98-10 as previously discussed, we must now show our gains and losses from energy trading contracts on a
net basis. To the extent losses exceeded gains, as was our case in 2003, sales are shown as a negative number.

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2003 versus 2002

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our Capacity Services operations decreased approximately $345.4 million and $275.5 million, respectively, in 2003
compared to 2002, resulting in a decrease in gross profit of $69.9 million. These decreases were primarily due to the following factors:



Operating Expense

Operating expense decreased $11.9 million primarily due to labor, benefit savings and lower corporate costs resulting from the restructuring of this
business in 2002.

Restructuring Charges

During 2003 and 2002, we recorded restructuring charges of $23.1 million and $6.2 million, respectively, relating to the termination of our
remaining interest rate swaps associated with the construction financings for our Clay County and Piatt County power plants. As debt related to these facilities was retired earlier than anticipated,
our swaps exceeded our outstanding debt. We therefore reduced our position and realized the loss associated with the cancelled portion of the swaps.

Impairment Charges and Net Loss on Sale of Assets

During 2003, we recorded $189.1 million of impairment charges and net loss on sale of assets. These charges consisted of $87.9 million related to
the write-down of our equity method investments in independent power plants. In the third quarter of 2003, we decided to sell our interest in these plants and therefore wrote our
investments down to estimated fair value, which was less than their carrying value. Impairment charges also includes a $105.5 million payment for the termination our 20-year tolling
contract for the Acadia power plant, partially offset by a $5.1 million gain related to the contract termination and sale of certain turbines that we had

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previously
written down to estimated fair value. For 2002 impairment charges and net loss on sale of assets see "2002 versus 2001" below.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $19.7 million in 2003 compared to 2002. Approximately $12.3 million of this increase was due to a
decrease in the estimated amortizable life of certain plant premiums relating to our acquisition of GPU International in December 2000. In addition, the start of commercial operations at three
owned power plants contributed an additional $9.6 million of depreciation and amortization expense in 2003.

2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our Capacity Services operations decreased $197.9 million and $101.0 million, respectively, in 2002 compared to 2001,
resulting in a decrease in gross profit of $96.9 million. These decreases were primarily due to the following factors:



Operating Expense

Operating expense increased $14.7 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 exceeded our outstanding debt. We therefore reduced
our position and realized the loss associated with the cancelled portion of the swap.

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Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets of $85.0 million included $42.1 million relating to the expected loss associated with either the
sale or contract termination of four electric turbines that were 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, $2.6 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 we reserved for in 2001.

Current Operating Development

Independent Power Plants

In the third quarter of 2003, we decided to proceed with the sale of our investments in independent power plants and in November 2003, we entered into an
agreement to sell our interest in 12 of these plants. We recorded an impairment charge to reduce the carrying amount of our interests in these plants to their estimated fair value based on preliminary
bids received in the third quarter of 2003. Two of the power plants, Lake Cogen and Onondaga, are consolidated on our balance sheet. We have included the results of operations from these plants in
discontinued operations. The remaining plants are equity method investments and their results of operations are included in continuing operations. We expect to close this sale in March 2004.

Aries Power Project

We are currently in discussions with our joint venture partner regarding the transfer of our 50% interest in the Aries Power Project and other consideration to
our partner in exchange for the release from our remaining capacity tolling obligation. If such a transaction were consummated, we would incur a loss.

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 2003. This increase in supply
has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. Because it is generally expected that the fuel and start-up costs of
operating our merchant power plants will exceed the revenues that would be generated from the power sold we believe that during the foreseeable future we will have limited ability to generate power at
a gross profit. We will continue to have operating and maintenance cost associated with our owned merchant generation plants, whether the facilities are being utilized to generate power or are idle.
Additionally, we will be required to make capacity payments related to our contracted merchant generating assets and expect to incur pretax losses and negative operating cash flows of approximately
$38.0 million in 2004 related to these contracts. We are attempting to terminate or restructure these obligations. As a result of the above factors and our change in strategy, we do not expect
Capacity Services to be profitable in the next two to three years.

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

Capacity
Services has one long-term power supply contract, discussed under "2003 versus 2002Sales, Cost of Sales and Gross Profit." We may experience earnings
volatility from this contract through 2009 due to its customized nature.

Three-Year ReviewWholesale Services

|                                          |                                                   | Year Ended December 31, |      
|----------------------------------------- | ------------------------------------------------- | ----------------------- | -----
|
|                                          |                                                  
|                                          |                                                   |                         |      
|Sales                                     |                                                   | $                       | (49.7
|Cost of sales                             |                                                   |                         |     
|                                          |                                                  
|Gross profit (loss)                       |                                                   |                         | (49.7
|                                          |                                                  
|Operating expenses:                       |                                                   |                         |      
|                                          | Operating expense                                 |                         |      
|                                          | Restructuring charges                             |                         |      
|                                          | Impairment charges and net loss on sale of assets |                         |      
|                                          | Depreciation and amortization expense             |                         |      
|                                          |                                                  
|Total operating expenses                  |                                                   |                         | 68.1 
|                                          |                                                  
|Other income (expense):                   |                                                   |                         |      
|                                          | Equity in earnings of investments                 |                         |      
|                                          | Other income (expense)                            |                         |      
|                                          |                                                  
|Earnings (loss) before interest and taxes |                                                   | $                       | (92.2
|                                          |                                                  

Due
to the rescission of EITF 98-10 as previously discussed, we must now show our gains and losses from energy trading contracts on a net basis. To the extent
losses exceeded gains, as was our case in 2003 and 2002, sales are shown as a negative number.

2003 versus 2002

Sales and Gross Profit (Loss)

Gross loss for our Wholesale Services operations for 2003 was $49.7 million, primarily due to the following factors:



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For
a description of 2002 sales and gross profit for Wholesale Services operations see "2002 versus 2001" below.

Operating Expense

Operating expense decreased $50.1 million primarily due to labor, benefit savings and related operating cost reductions resulting from the exit from our
wholesale energy trading operations in
2002, partially offset by $26.5 million of accrued expense related to our January 2004 settlement with the CFTC, and other regulatory review costs in 2003.

Restructuring Charges

Restructuring charges decreased $172.2 million in 2003 compared to 2002. This decrease stemmed from significant charges taken in 2002. For a description of
2002 restructuring charges see "2002 versus 2001" below.

Impairment Charges and Net Loss on Sales of Assets

Impairment charges decreased $182.1 million in 2003 from 2002. This decrease is a result of significant impairments taken in 2002. For a description of
2002 impairment charges and net loss on sale of assets see "2002 versus 2001" below.

Other Income (Expense)

Other income increased $16.0 million in 2003 primarily due to two items. On January 12, 2004, the Eighth Circuit Court of Appeals overturned a prior
adverse decision of the United States Tax Court regarding the proper depreciable life of certain of our natural gas gathering and pipeline assets. As a result of the appeals court's decision, we
reversed the accrual of $7.7 million of interest expense that would have been payable had the Internal Revenue Service prevailed in

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the
dispute. We also realized foreign currency translation gains of $12.5 million on the wind-down of our European merchant operations.

2002 versus 2001

Sales and Gross Profit (Loss)

Gross loss for our Wholesale Services operations for 2002 was $99.7 million versus 2001 gross profit of $626.6 million. The following describes the
major components of 2002 sales and gross loss:



A
volatile pricing environment in 2001 for gas and electricity provided opportunities to profitably execute our trading strategies and increase sales of our risk management products and
services to our clients. The volatility, particularly in the first half of 2001, provided the strongest two quarters in Wholesale Services history.

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 the wholesale energy trading business.

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.

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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 are 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 following cancellation of the
program in early 2002 and lower interest paid on customer margin deposits in 2002.

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 most of our trading positions are hedged, we
should experience limited fluctuation in 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. We have one remaining highly customized actuarial-based contract in Wholesale Services which expires in 2006. There may be earnings volatility associated with this contract due to
its highly customized nature and our inability to completely hedge the associated risk. Using a long-term value at risk methodology, with a 95% confidence level, we estimate
$15.5 million of total exposure (potential losses) related to this contract.

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Corporate Matters

Corporate and Other EBIT

The table below summarizes EBIT for Corporate and Other, which primarily contains the retained costs of the company that are not allocated to our operating
businesses.

|                                          |                                       | Year Ended December 31, |     
|----------------------------------------- | ------------------------------------- | ----------------------- | ----
|
|                                          |                                      
|                                          |                                       |                         |     
|Operating expenses:                       |                                       |                         |     
|                                          | Operating expense                     |                         | $   
|                                          | Restructuring charges                 |                         |     
|                                          | Depreciation and amortization expense |                         |     
|                                          |                                      
|Total operating expenses                  |                                       |                         | 37.1
|                                          |                                      
|Other income (expense):                   |                                       |                         |     
|                                          | Equity in earnings of investments     |                         |     
|                                          | Gain on sale of subsidiary stock      |                         |     
|                                          | Other income (expense)                |                         |     
|                                          |                                      
|Earnings (loss) before interest and taxes |                                       | $                       | 6.4 
|                                          |                                      

2003 versus 2002

Operating Expense

Operating expense increased $23.3 million in 2003 compared to 2002, primarily due to an additional $12.5 million of restructuring consulting fees
and $21.4 million of increased insurance and other costs associated with having non-investment grade credit ratings. This increase was partially offset by $3.7 million of
costs incurred in 2002 associated with retiring debt and company-obligated preferred securities. In addition, our losses on investments associated with the cash surrender value of certain life
insurance policies were greater in 2002 than in 2003.

Restructuring Charges

Restructuring charges decreased $7.5 million in 2003 compared to 2002. This decrease was primarily due to $8.9 million of executive severance costs
recorded in 2002 in connection with the separation agreements with our former Chief Executive Officer and Chief Financial Officer.

Other Income (Expense)

Other income increased $59.5 million, mainly due to $42.1 million of foreign currency gains in 2003 resulting from favorable movements in the
Australian and New Zealand dollar against the U.S. dollar. In addition, 2002 included $5.9 million of foreign exchange and interest rate hedge losses relating to our original planned financing
structure that was not consummated in connection with our Midlands acquisition, and more than $4.0 million of losses related to technology-related fund investments.

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2002 versus 2001

Restructuring Charges

Restructuring charges in 2002 includes $8.9 million of executive severance in connection with the separation agreements discussed above.

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 fund investments. We also paid approximately $2.4 million in 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 $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 Corporate and Other in 2001 that did not occur in 2002.

Interest Expense and Income Tax Expense (Benefit)

The table below summarizes our consolidated interest expense and income tax benefit:

|                             |  | Year Ended December 31,
|---------------------------- |  | -----------------------
|
|                            
|                             |  |                        
|Interest expense             |  | $                      
|                            
|Income tax expense (benefit) |  | $                      
|                            

2003 versus 2002

Interest Expense

Interest expense increased $40.2 million in 2003 compared to 2002. The increase was primarily the result the following:



These
increases were offset in part by the retirement of our prior revolving credit facility, debt outstanding in Australia, New Zealand and the United Kingdom in late 2002 and early
2003, and the conversion of the premium equity participating securities to common equity in November 2002.

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Income Tax Expense (Benefit)

The income tax benefit decreased $51.7 million in 2003 compared to 2002, primarily as a result of lower losses before income taxes in 2003 compared to
2002, and due to the removal of our permanent investment elections in Australia and Canada in 2002. Also impacting 2003 income tax benefits were a valuation allowance on anticipated capital losses
associated with the sale of our equity method independent power plants, a valuation allowance on certain state tax loss carryforwards and a non-deductible fine. Tax benefits were not
recognized on a significant amount of the 2002 losses as a result of valuation allowances provided on capital losses and certain non-deductible expenses.

2002 versus 2001

Interest Expense

Interest expense increased $45.1 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 $345.1 million in 2002 compared to 2001, primarily as a result of our loss before income taxes in 2002 compared to record earnings
in 2001. However, the 2002 expected income tax benefit was significantly reduced as a result of the following factors:



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OTHER ITEMS

Critical Accounting Policies and Estimates

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

Energy Trading and Derivative Accounting

The portion of 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 amount 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.
Operating results can also be affected by changes in underlying factors used in the determination of fair value of our portfolio such as the following:



We
also have other activities in our utility operations that are accounted for under SFAS 133. The majority of these activities consist of the purchasing of gas, power and coal
for our utility operations, which fall under the normal purchases and sales exception, and entering into transactions to hedge our risk associated with these purchases, which are accounted for as cash

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flow
hedges. These activities require that management make certain judgments regarding: election of the normal purchases and sales exceptions and qualification of hedge accounting by identifying hedge
relationships and assessing hedge effectiveness.

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 customers after the date of
the last meter reading. The unbilled revenue is calculated each month based on estimated customer usage, weather factors, line losses and applicable customer rates. Total unbilled revenues at
December 31, 2003 were $122.3 million.

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 may therefore 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. 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 determined by calculating the discounted future cash flows using a discount rate based upon our weighted average cost of capital, third
party contracted bids or appraisals performed by a qualified party. 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.

During
2003, we evaluated the carrying value of three power peaking plants we own. As of December 31, 2003, the carrying value of these plants was $481.3 million. We
performed this evaluation due to reduced spark spreads and an oversupply of generation that we expect will continue for the foreseeable future. This situation has prevented these plants from firing
and, in turn, has created losses for us. It is forecasted that these losses will continue for the next few years. We separately tested the cash flows for each plant based on estimated margin
contributions and forecasted operating expenses over their remaining plant lives. These peaking plants were placed into service in 2002 and 2003 and we depreciate these facilities over
35 years. In evaluating future estimated margin contributions, we used external price curves based on four different future price environments. In each environment, we calculated an average
margin contribution based on a multi-simulation scenario analysis and then equally weighted each price environment. Based on this analysis and the level of probability we would sell these assets, the
undiscounted probability weighted cash flows for these plants exceeded their current book value. Therefore, under SFAS 144 no impairment was required as of December 31, 2003. We have
evaluated these assets as held and used. If at some future date we determine these assets are held for sale, based on current market values, we would likely record a material impairment charge.

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Goodwill and Other Intangible Assets

On January 1, 2002, we adopted Statement of Financial Accounting Standards 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 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. Total goodwill at December 31, 2003 was $111.0 million.

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 regulatory assets and liabilities at December 31, 2003 were $107.6 million and $108.6 million, respectively. See
Note 11 to the Consolidated Financial Statements for further details.

Valuation of Deferred Tax Assets

We are required to assess the ultimate realization of deferred tax assets generated from net operating losses and 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,
2003, we have recorded $341.7 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 and taxable income in certain states. The ultimate amount of deferred tax assets realized could be materially different from that recorded, as impacted by changes in federal income tax
laws and upon the generation of future capital gains to enable us to realize the related tax assets.

At
December 31, 2003, we also had approximately $113.0 million of net operating loss carryforwards that can be carried forward for 20 years to offset future taxable
income. We did not record valuation allowances against the deferred tax assets related to net operating losses. This

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determination
was based on our assessment that it is more likely than not that we will realize these deferred assets during the carryforward period. This assessment considered the forecast reversal of
existing temporary differences and taxable income expected to be generated in the carryforward period.

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, 2003, our average assumed discount rate was 6.00% and our average expected return on plan assets was 8.50%.

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 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, 2003, and our estimated annual
pension cost (APC) on the income statement for 2004 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 AssumptionIncr.(decr.) |   | Impact
on PBOIncr.(decr.) |       | Impact
on APCIncr.(decr.) |  
|----------------------------- |  | -------------------------------- | - | ------------------------- | ----- | ------------------------- | -
|                              | 
|                              |  |                                  |   |                           |       |                           |  
|Discount rate                 |  | .25                              | % | $                         | (10.9 | )                         | $
|Rate of return on plan assets |  | .25                              | % |                           |      |                           | $
|                              | 

Legal Proceeding

In February 2002, we filed a suit which is currently pending in the U.S. District Court for the Western District of Missouri 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
$513.0 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

67

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claims
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

Significant Balance Sheet Movements

Total assets decreased by $1,656.9 million since December 31, 2002. This decrease is primarily due to the following:



Total
liabilities decreased by $1,408.3 million and common shareholders' equity decreased by $248.6 million since December 31, 2002. These changes are primarily
attributable to the following:



68

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New Accounting Standards

In 2003, the Financial Accounting Standards Board (FASB) issued a revised Interpretation No. 46, "Consolidation of Variable Interest Entities," and the
FASB issued two new Statements of Financial Accounting Standards (SFAS) that have potential impacts on our financial results: SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities" and SFAS No. 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity." 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 the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations." See Note 2 to the Consolidated Financial Statements for further discussion.

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) we expect to complete the sales of our investments in 12 independent
power plants in March 2004 and our Canadian operations in the second quarter of 2004, (ii) we believe our liquidity will be sufficient in 2004, (iii) we expect our utility rates to be
increased in certain states where we have utility operations, (iv) our long-term liquidity depends upon the sale of assets, return of collateral posted, restructuring of capacity
tolling obligations, our ability to refinance or retire maturing obligations, and our ability to issue equity or convertible debt securities, and (v) we do not expect that any of the currently
pending litigation will have a materially adverse outcome to us. The

69

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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. Similar statements that identify our objectives, plans and goals are 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:



70

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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 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,
most of our positions have been hedged to limit our exposure to the above risks.

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 2003 was $3.2 million. The value at risk limit is set by our Board of Directors. We are 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 application of 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 risk adjusted current interest rates based on our
credit standing and those of our counterparties. Because interest rate movements impact the value of our trading portfolio, we actively hedge our interest rate exposures to limit these fluctuations.

The
table below shows the expected net cash flows associated with the interest rate financial instrument related to our trading portfolio at December 31, 2003.

|Dollars in millions    |  | 2004 |      | 2005 |   | 2006 |   | 2007 |     
|---------------------- |  | ---- | ---- | ---- | - | ---- | - | ---- | ----
|                       | 
|                       |  |      |      |      |   |      |   |      |     
|Variable to fixed rate |  | $    | (2.2 | )    | $ | (.5  | ) | $    | .1  
|Average rate paid      |  |      | 3.91 | %    |   | 3.91 | % |      | 3.91
|Average rate received  |  |      | 2.54 | %    |   | 2.54 | % |      | 2.54
|                       | 

71

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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 2003 are summarized below:

|In millions                             |  | Total |      
|--------------------------------------- |  | ----- | -----
|                                        | 
|                                        |  |       |      
|Fair value at December 31, 2002         |  | $     | 160.5
|Reduction in fair value during the year |  |       | (26.1
|Contracts realized or cash settled      |  |       | (4.4 
|                                        | 
|Fair value at December 31, 2003         |  | $     | 130.0
|                                        | 

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

|In millions                      |                                                    | 2004 |      | 2005 |   | 2006 |     | 2007 |      | Thereafter |   | Total
|-------------------------------- | -------------------------------------------------- | ---- | ---- | ---- | - | ---- | --- | ---- | ---- | ---------- | - | -----
|                                
|                                 |                                                    |      |      |      |   |      |     |      |      |            |   |      
|                                 | Prices actively quoted                             |      | $    | 20.9 |   | $    | 9.1 |      | $    |           |   | $    
|                                 | Prices provided by other external sources          |      |      |     |   |      |    |      |      | 23.4       |   |      
|                                 | Priced based on models and other valuation methods |      |      |     |   |      |    |      |      |           |   |      
|                                
|Net price risk management assets |                                                    | $    | 20.9 |      | $ | 9.1  |     | $    | 23.4 |            | $ | 29.2 
|                                

The
following table reflects our fixed-price volumetric positions for our remaining portfolio for both gas and electricity as of December 31, 2003. Positive volumes represent net
long positions and negative volumes represent net short positions.

|                |  | 2004  |  | 2005  |  | 2006  |  | 2007  |  | Thereafter |  | Total  
|--------------- |  | ----- |  | ----- |  | ----- |  | ----- |  | ---------- |  | -------
|               
|                |  |       |  |       |  |       |  |       |  |            |  |        
|GasBcf         |  | 6.9   |  | (7.7) |  | (4.7) |  | (.2)  |  | (1.7)      |  | (7.4)  
|ElectricityGWh |  | (626) |  | (506) |  | (203) |  | (438) |  | (878)      |  | (2,651)
|               

72

---

In
connection with the sale of our independent power plants, we expect to sell a large swap related to one of those projects. The sale of this contract will result in a net short
position in our portfolio as indicated by the table above. In the coming months, we will attempt to mitigate this exposure by flattening our positions in the marketplace. We may be exposed to
fluctuations in earnings during this period until our positions are flattened.

Credit Risk

In conducting our operations, 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
has deteriorated to certain levels, we will assert our contractual rights to minimize our exposures by requesting collateral against these obligations.

A
natural result of 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
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, 2003, associated with our forward positions within our trading portfolio and our billed receivables (excluding
residential
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   |       | $                | 204.6 |                      | $ | 165.2
|Financial institutions    |       |                  | 210.1 |                      |   |     
|Oil and gas producers     |       |                  | 8.2   |                      |   | 31.5 
|Commercial and industrial |       |                  | 1.8   |                      |   | 7.2  
|                         
|                          | Total |                  | $     | 424.7                |   | $    
|                         

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

In
our domestic utility business, approximately 55% of our sales are to residential customers. Therefore, our credit risk associated with these sales is relatively low. See pages 5 and 6
under Properties for a breakout of our domestic utility customers by type.

73

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Currency Rate Exposure

In 2003, we reached an agreement to sell our Canadian utility businesses for approximately C$1,360 million (US$1,047 million at the
December 31, 2003 exchange rate), including the repayment or assumption of C$174 million (US$134 million at the December 31, 2003 exchange rate) or net proceeds of
approximately US$913 million in proceeds to us before closing adjustments, transaction costs and taxes. In addition, we will be required to repay US$215 million borrowed by our Canadian
subsidiaries under a 364-day unsecured loan. We expect to close this sale in the second quarter of 2004. In connection with this sale, we entered into a foreign currency put option on
C$800 million of the expected cash proceeds from this sale to minimize the effects of declines in the Canadian dollar against the U.S. dollar. This put option creates a floor of .73 at which we
can exchange C$800 million, for a minimum of US$584 million in cash. This means that a 10% increase in the value of the Canadian dollar from the December 31, 2003 rate would
increase the proceeds by approximately US$62 million, while a 10% decline in the Canadian dollar from the December 31, 2003 rate would be limited to US$32 million of decreased
proceeds. The remaining approximate C$300 million has also been hedged with a forward contract to lock in the repayment of US$215 million of U.S. dollar denominated debt at our Canadian
subsidiaries.

We
are in the process of winding down our remaining United Kingdom and Canadian merchant trading businesses, which are included in our Wholesale Services segment.

After
the close of the sale of our Canadian utility businesses and the wind-down of our United Kingdom and Canadian merchant trading operations, we expect to have limited
exposure to currency rates in the foreseeable future.

Interest Rate Exposure

We have approximately $694.6 million in unhedged variable rate financial obligations. A 100-basis-point change in the variable rate financial
instruments would affect net income by approximately $4.2 million.

74

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Item 8. Financial Statements and Supplementary Data

|                                                                                                   |          |       |                                                   | Page No.
|-------------------------------------------------------------------------------------------------- | -------- | ----- | ------------------------------------------------- | --------
|
|Consolidated Statements of Income for the three years ended December 31, 2003                      |          | 76   
|Consolidated Balance Sheets at December 31, 2003 and 2002                                          |          | 77   
|Consolidated Statements of Common Shareholders' Equity for the three years
ended December 31, 2003 |          | 78   
|Consolidated Statements of Comprehensive Income for the three years ended December 31, 2003        |          | 79   
|Consolidated Statements of Cash Flows for the three years ended
December 31, 2003                  |          | 80-81
|Notes to Consolidated Financial Statements:                                                        |          | 82   
|                                                                                                   | Note 1:  |       | Summary of Significant Accounting Policies        |         
|                                                                                                   | Note 2:  |       | New Accounting Standards                          |         
|                                                                                                   | Note 3:  |       | Risk Management                                   |         
|                                                                                                   | Note 4:  |       | Restructuring Charges                             |         
|                                                                                                   | Note 5:  |       | Impairment Charges and Net Loss on Sale of Assets |         
|                                                                                                   | Note 6:  |       | Discontinued Operations                           |         
|                                                                                                   | Note 7:  |       | Restricted Cash                                   |         
|                                                                                                   | Note 8:  |       | Accounts Receivable                               |         
|                                                                                                   | Note 9:  |       | Property, Plant and Equipment                     |         
|                                                                                                   | Note 10: |       | Investments in Unconsolidated Subsidiaries        |         
|                                                                                                   | Note 11: |       | Regulatory Assets                                 |         
|                                                                                                   | Note 12: |       | Short-Term Debt                                   |         
|                                                                                                   | Note 13: |       | Long-Term Debt                                    |         
|                                                                                                   | Note 14: |       | Long-Term Gas Contracts                           |         
|                                                                                                   | Note 15: |       | Capital Stock and Stock Compensation              |         
|                                                                                                   | Note 16: |       | Accumulated Other Comprehensive Income (Loss)     |         
|                                                                                                   | Note 17: |       | Earnings (Loss) Per Share                         |         
|                                                                                                   | Note 18: |       | Income Taxes                                      |         
|                                                                                                   | Note 19: |       | Employee Benefits                                 |         
|                                                                                                   | Note 20: |       | Segment Information                               |         
|                                                                                                   | Note 21: |       | Commitments and Contingencies                     |         
|                                                                                                   | Note 22: |       | Quarterly Financial Data (Unaudited)              |         
|Independent Auditors' Report                                                                       |          | 150  

75

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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                                                    |                                                    |                          | 1,674.0
|                                                               |                                                   
|Cost of sales:                                                 |                                                    |                          |        
|                                                               | Electricityregulated                              |                          |        
|                                                               | Natural gasregulated                              |                          |        
|                                                               | Electricitynon-regulated                          |                          |        
|                                                               | Natural gasnon-regulated                          |                          |        
|                                                               | Othernon-regulated                                |                          |        
|                                                               |                                                   
|Total cost of sales                                            |                                                    |                          | 1,124.1
|                                                               |                                                   
|Gross profit                                                   |                                                    |                          | 549.9  
|                                                               |                                                   
|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 loss (income) of subsidiaries |                          |        
|                                                               | Gain on sale of subsidiary stock                   |                          |        
|                                                               | Other income                                       |                          |        
|                                                               |                                                   
|                                                               |                                                    | Total other income       |        
|                                                               |                                                   
|Interest expense                                               |                                                    |                          | 273.1  
|                                                               |                                                   
|Earnings (loss) from continuing operations before income taxes |                                                    |                          | (492.3 
|Income tax expense (benefit)                                   |                                                    |                          | (141.7 
|                                                               |                                                   
|Earnings (loss) from continuing operations                     |                                                    |                          | (350.6 
|Earnings (loss) from discontinued operations, net of tax       |                                                    |                          | 14.2   
|Cumulative effect of accounting change, net of tax             |                                                    |                          |       
|                                                               |                                                   
|Net Income (Loss)                                              |                                                    | $                        | (336.4 
|                                                               |                                                   
|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.

76

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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                              |             
|                                           | Current assets of discontinued operations          |             
|                                          
|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                          |             
|                                           | Current liabilities of discontinued operations     |             
|                                          
|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                                   |             
|                                           | Non-current liabilities of discontinued operations |             
|                                          
|Total long-term liabilities                |                                                    |             
|                                          
|Common shareholders' equity                |                                                    |             
|                                          
|Total Liabilities and Shareholders' Equity |                                                    | $           
|                                          

See
accompanying notes to consolidated financial statements.

77

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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, 2003, 2002 and 2001, par value $1 per share, 195,252,630 shares issued at December 31, 2003 (193,782,782 at December 31, 2002 and 115,941,120
at December 31, 2001); 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 under compensation arrangements                                              |                         |         
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Balance end of year                                                                                                                                                                                                                                                                                                |                                                                                                 |                         | 195.3   
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|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 under compensation arrangements                                              |                         |         
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Balance end of year                                                                                                                                                                                                                                                                                                |                                                                                                 |                         | 3,161.3 
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Retained earnings (deficit):                                                                                                                                                                                                                                                                                       |                                                                                                 |                         |         
|                                                                                                                                                                                                                                                                                                                   | Balance beginning of year                                                                       |                         |         
|                                                                                                                                                                                                                                                                                                                   | Net income (loss)                                                                               |                         |         
|                                                                                                                                                                                                                                                                                                                   | Dividends on common stock, ($.775 per share and $1.20 per share in 2002 and 2001, respectively) |                         |         
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Balance end of year                                                                                                                                                                                                                                                                                                |                                                                                                 |                         | (2,047.9
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Treasury stock, at cost, 129 shares at December 31, 2003 (7,443 shares at December 31, 2002 and 447 shares at December 31, 2001)                                                                                                                                                                                   |                                                                                                 |                         |        
|Accumulated other comprehensive income (loss)                                                                                                                                                                                                                                                                      |                                                                                                 |                         | 50.6    
|                                                                                                                                                                                                                                                                                                                   |                                                                                                
|Total Common Shareholders' Equity                                                                                                                                                                                                                                                                                  |                                                                                                 | $                       | 1,359.3 
|                                                                                                                                                                                                                                                                                                                   |                                                                                                

See
accompanying notes to consolidated financial statements.

78

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Aquila, Inc.  Consolidated Statements of Comprehensive Income

|                                                                                                       |                                                                                                                                                                                                           | Year Ended December 31,            |       
|------------------------------------------------------------------------------------------------------ | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------- | ------
|
|                                                                                                       |                                                                                                                                                                                                          
|                                                                                                       |                                                                                                                                                                                                           |                                    |       
|Net income (loss)                                                                                      |                                                                                                                                                                                                           | $                                  | (336.4
|Other comprehensive income (loss), net of related tax:                                                 |                                                                                                                                                                                                           |                                    |       
|Foreign currency adjustments:                                                                          |                                                                                                                                                                                                           |                                    |       
|                                                                                                       | Foreign currency translation adjustments, net of deferred tax expense of $50.3 million for 2003                                                                                                           |                                    |       
|                                                                                                       | Reclassification of foreign currency (gains) losses to income due to sale of businesses, net of deferred tax (expense) of $(9.5) million for 2003                                                         |                                    |       
|                                                                                                       |                                                                                                                                                                                                          
|                                                                                                       |                                                                                                                                                                                                           | Total foreign currency adjustments |       
|                                                                                                       |                                                                                                                                                                                                          
|Cash flow hedges:                                                                                      |                                                                                                                                                                                                           |                                    |       
|                                                                                                       | Unrealized gains (losses) on hedging instruments during the period, net of deferred tax expense (benefit) of $(.4) million, $(10.9) million and $.6 million for 2003, 2002 and 2001, respectively         |                                    |       
|                                                                                                       | Unrealized gains (losses) on hedging instruments of equity method investments, net of deferred tax expense (benefit) of $(5.6) million, $(1.7) million for 2003 and 2002, respectively                    |                                    |       
|                                                                                                       | Unrealized gain on initial adoption of Statement of Financial Accounting Standards No. 133, net of deferred tax expense of $1.8 million in 2001                                                           |                                    |       
|                                                                                                       | Reclassification of net losses (gains) on hedging instruments to net income, net of deferred tax benefit (expense) of $9.1 million, $2.4 million and $(1.8) million for 2003, 2002 and 2001, respectively |                                    |       
|                                                                                                       | Reclassification of net losses on hedging instruments to net income due to sale of businesses, net of deferred tax benefit (expense) of $(.6) million for 2002                                            |                                    |       
|                                                                                                       | Reclassification of net losses to income on cash flow hedges in equity method investments due to sale, net of deferred tax benefit (expense) of $1.8 million for 2003                                     |                                    |       
|                                                                                                       |                                                                                                                                                                                                          
|                                                                                                       |                                                                                                                                                                                                           | Total cash flow hedges             |       
|                                                                                                       |                                                                                                                                                                                                          
|Held for sale securities:                                                                              |                                                                                                                                                                                                           |                                    |       
|                                                                                                       | Unrealized gain on securities held for sale                                                                                                                                                               |                                    |       
|                                                                                                       | Reclassification of net losses (gains) on sales of securities to income                                                                                                                                   |                                    |       
|                                                                                                       |                                                                                                                                                                                                          
|                                                                                                       |                                                                                                                                                                                                           | Total held for sale securities     |       
|                                                                                                       |                                                                                                                                                                                                          
|Decrease (increase) in minimum pension liability, net of deferred tax benefit of $2.7 million for 2003 |                                                                                                                                                                                                           |                                    | .4    
|                                                                                                       |                                                                                                                                                                                                          
|Other comprehensive income (loss)                                                                      |                                                                                                                                                                                                           |                                    | 83.6  
|                                                                                                       |                                                                                                                                                                                                          
|Total Comprehensive Income (Loss)                                                                      |                                                                                                                                                                                                           | $                                  | (252.8
|                                                                                                       |                                                                                                                                                                                                          

See
accompanying notes to consolidated financial statements.

79

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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 and impairment charges                                         
|                                                   |                                                                                                       |                         | Impairment charges and net loss on sale of assets                                          
|                                                   |                                                                                                       |                         | Foreign currency gains                                                                     
|                                                   |                                                                                                       |                         | 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 (loss) income of subsidiaries                                        
|                                                   |                                                                                                       |                         | Changes in certain assets and liabilities, net of effects of acquisitions and divestitures:
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                       |                         |                                                                                            
|                                                   |                                                                                                      
|Cash (used for) provided from operating activities |                                                                                                       |                         | (132.3                                                                                     
|                                                   |                                                                                                      
|Cash Flows From Investing Activities:              |                                                                                                       |                         |                                                                                            
|                                                   | Additions to utility plant                                                                            |                         |                                                                                            
|                                                   | Merchant capital expenditures                                                                         |                         |                                                                                            
|                                                   | Net increases in merchant loans                                                                       |                         |                                                                                            
|                                                   | Investments in international businesses                                                               |                         |                                                                                            
|                                                   | Investments in communication services                                                                 |                         |                                                                                            
|                                                   | Cash proceeds on sale of assets and subsidiary stock                                                  |                         |                                                                                            
|                                                   | Merchant investment in unconsolidated subsidiary                                                      |                         |                                                                                            
|                                                   | Other                                                                                                 |                         |                                                                                            
|                                                   |                                                                                                      
|Cash provided from (used for) investing activities |                                                                                                       |                         | 564.7                                                                                      
|                                                   |                                                                                                      

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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                  |                         |       
|                                                                                                                                                                                       | Retirement of company-obligated preferred securities |                         |       
|                                                                                                                                                                                       | Issuance of long-term debt                           |                         |       
|                                                                                                                                                                                       | Retirement of long-term debt                         |                         |       
|                                                                                                                                                                                       | Short-term borrowings, net                           |                         |       
|                                                                                                                                                                                       | Cash paid on long-term gas contracts                 |                         |       
|                                                                                                                                                                                       | Cash dividends paid                                  |                         |       
|                                                                                                                                                                                       | Other                                                |                         |       
|                                                                                                                                                                                       |                                                     
|Cash provided from (used for) financing activities                                                                                                                                     |                                                      |                         | (216.6
|                                                                                                                                                                                       |                                                     
|Increase (decrease) in cash and cash equivalents                                                                                                                                       |                                                      |                         | 215.8 
|Cash and cash equivalents at beginning of year (includes $55.6 million, $45.0 million and $179.7 million, respectively, of cash included in current assets of discontinued operations) |                                                      |                         | 441.7 
|                                                                                                                                                                                       |                                                     
|Cash and Cash Equivalents at End of Year (includes $55.8
million, $55.6 million and $45.0 million, respectively, of cash included in current assets of discontinued operations)        |                                                      | $                       | 657.5 
|                                                                                                                                                                                       |                                                     
|Supplemental cash flow information:                                                                                                                                                    |                                                      |                         |       
|                                                                                                                                                                                       | Interest paid, net of amount capitalized             |                         | $     
|                                                                                                                                                                                       | Income taxes paid (refunded), net                    |                         |       
|                                                                                                                                                                                       |                                                     

See
accompanying notes to consolidated financial statements.

81

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Aquila, Inc.  Notes to Consolidated Financial Statements

Note 1: Summary of Significant Accounting Policies

Description of Business

Aquila, Inc. (Aquila), formerly UtiliCorp United Inc., is an 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 consists 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 a small amount of 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 former investment in Quanta Services, Inc. (Quanta Services). Quanta Services
provides specialized construction and maintenance services to the utility, telecommunications and cable television industries. We sold our investment in Quanta Services in late 2002 and early 2003.
International Networks owns and operates electric utilities in two Canadian provinces, which are currently in the process of being sold and are reported in discontinued operations. We also formerly
had investments in Australia, New Zealand and the United Kingdom. We sold our investment in New Zealand in October 2002, our investments in
Australia in the second and third quarters of 2003, and our investment in the United Kingdom in January 2004.

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. This segment 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, contractually controls or has investments in non-regulated merchant power plants. Our investments in 13 independent power plants are expected to be
sold in 2004. Two of these consolidated plants are reported in discontinued operations. Capacity Services also formerly owned natural gas and gas liquids gathering, transportation, storage and
processing assets, which were sold in 2002. These operations are also reported as discontinued operations.

Through
April 2001, we owned 100% of Aquila Merchant. In April 2001, we sold approximately 20% of Aquila Merchant's ownership 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

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that
affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of December 31, 2003 and 2002, and the reported amounts of sales and
expenses during the three years ended December 31, 2003. Significant items subject to such estimates and 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
eliminate inter-company accounts and transactions. We use equity accounting for investments in which we have significant influence but do not control. We did not control certain formerly owned
investments in which our partners had substantive participating and protective rights. This did not allow us to consolidate those investments.

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, 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. We completed an initial assessment of the realizability of our goodwill and determined
that as of January 1, 2002, no goodwill impairments existed. Our annual assessment date is November 30. At December 31, 2003, we had goodwill in continuing operations of
$113.6 million, net of accumulated amortization of $2.6 million and goodwill in discontinued operations of $244.1 million, net of accumulated amortization of $14.6 million.

83

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Our goodwill was allocated to each segment as follows:

|In millions                |                                         | Domestic Networks |       | International Networks |   | Wholesale Services |      | Capacity Services |     | Total Continuing Operations |   | Total Discontinued Operations |      
|-------------------------- | --------------------------------------- | ----------------- | ----- | ---------------------- | - | ------------------ | ---- | ----------------- | --- | --------------------------- | - | ----------------------------- | -----
|
|Balance, December 31, 2001 |                                         | $                 | 130.6 |                        | $ | 5.0                |      | $                 | 3.6 |                             | $ | 2.6                           |      
|                           | Repurchase of Aquila Merchant shares(a) |                   |       |                       |   |                    |     |                   |     | 175.0                       |   |                               | 14.0 
|                           | Wholesale Services impairment(b)        |                   |       |                       |   |                    |     |                   |     | (178.6                      | ) |                               |     
|                           | Capacity Services impairment(b)         |                   |       |                       |   |                    |     |                   |     |                            |   |                               | (2.6 
|                           | Everest Connections impairment(b)       |                   |       | (21.6                  | ) |                    |     |                   |     |                            |   |                               |     
|                           | Sales of businesses(c)                  |                   |       |                       |   |                    | (5.0 | )                 |     |                            |   |                               | (14.0
|                           | Exchange rate change and other          |                   |       | 2.0                    |   |                    |     |                   |     |                            |   |                               |     
|                           |                                        
|Balance, December 31, 2002 |                                         |                   | 111.0 |                        |   |                   |      |                   |    |                             |   |                              |      
|                           |                                        
|                           | Exchange rate change and other          |                   |       |                       |   |                    |     |                   |     |                            |   |                               |     
|                           |                                        
|Balance, December 31, 2003 |                                         | $                 | 111.0 |                        | $ |                   |      | $                 |    |                             | $ |                              |      
|                           |                                        



Following are disclosures of net income and earnings per share for the year ended December 31, 2001, had goodwill not been amortized in
that period:

|                                            |         | Year Ended December 31, 2001
|------------------------------------------- | ------- | ----------------------------
|
|
|
|Reported net income                         |         | $                           
|Goodwill amortization                       |         |                             
|Goodwill amortization in equity in earnings |         |                             
|                                           
|Adjusted net income                         |         | $                           
|                                           
|Adjusted earnings per share:                |         |                             
|                                            | Basic   |                             
|                                            | Diluted |                             
|                                           

84

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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 customers after
the date of the last meter reading. 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.

85

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Funds on Deposit

Funds that we have on deposit with counterparties consist primarily of margin requirements related to commodity purchases, 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. In connection with our
364-day letter of credit agreement, we are required to secure all letters of credit issued with cash deposits. See Note 12 for further discussion. 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

Before 2003, we sold trade accounts receivable 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 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.

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 revenue recognized with the forecast 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

86

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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 is enacted. We amortize deferred investment tax credits over the lives of the related properties. We assess the realizability
of deferred tax assets for capital and operating loss carryforwards and provide valuation allowances when we determine it is more likely than not that such losses will not be realized within the
applicable carryforward period. 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
historically offered employees a stock purchase plan that enabled them to purchase our common stock at a 15% discount from the market price. This program was suspended during the second quarter of
2003 when all authorized shares in the plan were issued. Shareholder approval is required to authorize additional shares for this program to continue. See Note 15 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, as follows:

|In millions, except per share amounts |                                                                                                        | 2003 |   | 2002   |   | 2001 |         
|------------------------------------- | ------------------------------------------------------------------------------------------------------ | ---- | - | ------ | - | ---- | --------
|
|Net income (loss):                    |                                                                                                        |      |   |        |   |      |         
|                                      | As reported                                                                                            |      | $ | (336.4 | ) | $    | (2,075.1
|                                      | Total stock-based employee compensation expense determined under fair value method, net of related tax |      |   | (5.4   | ) |      | (6.2    
|                                      |                                                                                                       
|                                      | Pro forma net income (loss)                                                                            |      | $ | (341.8 | ) | $    | (2,081.3
|                                      |                                                                                                       
|Basic earnings (loss) per share:      |                                                                                                        |      |   |        |   |      |         
|                                      | As reported                                                                                            |      | $ | (1.73  | ) | $    | (12.83  
|                                      | Pro forma                                                                                              |      |   | (1.76  | ) |      | (12.87  
|Diluted earnings (loss) per share:    |                                                                                                        |      |   |        |   |      |         
|                                      | As reported                                                                                            |      | $ | (1.73  | ) | $    | (12.83  
|                                      | Pro forma                                                                                              |      |   | (1.76  | ) |      | (12.87  
|                                      |                                                                                                       

87

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

|                                      |  | 2003 |         | 2002 |   | 2001   
|------------------------------------- |  | ---- | ------- | ---- | - | -------
|
|Weighted average fair value per share |  | $    | ..85    |      | $ | 1.03   
|Expected volatility                   |  |      | 54.60%  |      |   | 51.60% 
|Risk-free interest rate               |  |      | 3.53%   |      |   | 3.53%  
|Expected lives                        |  |      | 7 years |      |   | 7 years
|Dividend yield                        |  |      |        |      |   |       
|                                     

Stock options granted in 2001 by Aquila Merchant 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.

In
April 2003, the Financial Accounting Standards Board (FASB) announced that it would require all companies to expense the value of employee stock options. The FASB plans to
issue a new statement in the second half of 2004 that will further define the method of determining fair value and recognizing compensation expense.

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, 2003 and 2002, our cash held in
foreign countries was $104.6 million and $151.8 million, 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 2003 presentation. In particular, as
discussed in Note 6, certain assets that have been classified as held for sale 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

Variable Interest Entities

In December 2003, the FASB issued a revised Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB
No. 51." This interpretation addresses the

88

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consolidation
by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately to companies that have entities considered to be special-
purpose entities. Other public companies are required to apply this interpretation by the end of the first reporting period that ends after March 31, 2004. We are currently evaluating the
impact of this interpretation. However, we do not expect this interpretation to have a material effect on our financial statements.

Derivative Instruments

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" (SFAS 149). This Statement clarified under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). It also clarified when a derivative contains a financing component that
warrants special reporting in the statement of cash flows. SFAS 149 also amended certain other existing pronouncements regarding derivatives. It is effective for contracts entered into or
modified after June 30, 2003, and we applied it prospectively. The adoption of this standard had no material impact on our financial position or results of operations.

Financial Instruments

In May 2003, the FASB issued SFAS No. 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity"
(SFAS 150). This statement established standards for the classification and measurement of certain financial instruments that have the characteristics of both liabilities and equities. It
requires that an issuer classify a financial instrument that is within the scope of the standard as a liability. This standard is effective for all financial instruments entered into or modified after
May 31, 2003, and for the first interim reporting period beginning after June 15, 2003. The adoption of this standard had no impact on our financial position or results of operations.

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.

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In
connection with the adoption of SFAS 143 in January 2003, our regulated business recorded an asset retirement obligation of $.8 million and increased property,
plant and equipment, net of accumulated depreciation, by an immaterial amount. Because this business is a regulated utility subject to the provisions of SFAS 71, the $.8 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
agreement, are required to be removed if we discontinue our utility service under such easement or franchise agreement.

Our
liability for asset retirement obligations was approximately $1.0 million as of December 31, 2003.

Depreciation
rates approved by regulatory commissions in certain states include a provision for the cost of future removal of assets for which there is no legal removal obligation.
Concurrent with the adoption of SFAS 143, the net provision for these "non-legal" removal costs has been reclassified from accumulated depreciation, where it has been recorded previously, to a
regulatory liability. See Note 11 for further discussion.

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.

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 2002 in the Consolidated Statements of Income as an additional loss before income taxes of $37.5 million, or
$22.7 million after tax.

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

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into
derivative instruments in our energy trading business. Below we discuss these various types of instruments and our objectives for holding them.

Trading Activities

During the second half of 2002, we began exiting 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. 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 the decision to exit 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 to help hedge our remaining portfolio. Each type of financial instrument involves different risks. We
believe financial instruments help 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, 2003 are below:

|                    |                             | December 31, 2003
|------------------- | --------------------------- | -----------------
|
|
|
|Energy Commodities: |                             |                  
|                    | Natural gas(trillion Btu's) |                  
|                    | Electricity(megawatt-hours) |                  
|                    | Crude oil(barrels)          |                  
|                    | Coal(tons)                  |                  
|Financial Products: |                             |                  
|                    | Interest rate instruments   |                  
|                   

We have attempted to balance our remaining physical and financial contracts in terms of quantities, commodities 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.

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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, 2003, using market interest rates for the contract term adjusted for
our credit rating for liabilities or the credit rating of the counterparty for assets. We continuously monitor the portfolio and value it daily based on present market conditions. The following table
displays the fair values of price risk management assets and liabilities at December 31, 2003, and the average value for the year ended December 31, 2003:

|            |  | Price Risk Management Assets |       | Price Risk Management Liabilities
|----------- |  | ---------------------------- | ----- | ---------------------------------
|
|
|
|Natural gas |  | $                            | 792.6 |                                  
|Electricity |  |                              | 95.7  |                                  
|Coal        |  |                              | 18.5  |                                  
|Other       |  |                              | 2.7   |                                  
|           
|Total       |  | $                            | 909.5 |                                  
|           

Our price risk management assets are concentrated in five contracts representing 75% of the total asset value of the portfolio. These five counterparties are
investment-grade financial institutions. We hold collateral from these counterparties representing approximately 41% of the asset value. This concentration of customers may impact our overall exposure
to credit risk, either positively or negatively, because 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

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change
in fair value is recognized in other income (expense) on the Consolidated Statements of Income. 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 from
that point forward 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 other
comprehensive income (OCI) is reclassified into current-period earnings.

Cash Flow Hedges

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 a $9.2 million increase in OCI related to cash flow hedges in 2003, 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 within the next 12 months approximately $2.8 million of
losses that are reported in OCI. As of December 31, 2003, the fair value of cash flow hedges resulted in $14.2 million of unfavorable accumulated OCI ($8.8 million net of tax).

Normal Purchases and Sales Exception

As part of our utility business, we enter into contracts to purchase or sell electricity, gas and coal using contracts that are considered derivatives under
SFAS 133. The majority of these contracts, however, qualify for normal purchases and sales treatment under SFAS 133. These contracts are exempt from
mark-to-market accounting treatment as they are for the purchase and sale of energy to meet the requirements of our customers. At the initiation of the contract, we make a
determination as to whether or not the contract meets the criteria as a normal purchase or normal sale. These contracts include short-term and long-term commitments to purchase
and sell energy and energy related products in the retail and wholesale markets with the intent and ability to deliver or take delivery in quantities we expect to use over a reasonable period in the
normal course of business. Derivatives qualifying as normal purchases or sales are recorded and recognized in income using accrual accounting.

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 60% of the power that we sell and purchase the remaining 40% 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 that serves a purpose similar to the PGAs in place for the gas utilities. To the extent
that our fuel and purchased power energy costs vary from the energy cost built into our

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tariffs,
the difference is passed through to the customer. For Colorado, we have an Incentive Clause Adjustment that provides the recovery from the customer of 75% of the variability of energy costs.
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 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

In connection with our continued exit from Wholesale Services and the restructuring of our Domestic Networks, we have recorded the following restructuring charges
(we had no restructuring charges in 2001):

|                                    |                                                    | Year Ended December 31,
|----------------------------------- | -------------------------------------------------- | -----------------------
|
|
|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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Severance Costs and Retention Payments

We incurred severance and other related costs of $2.1 million for the year ended December 31, 2003 in connection with the restructuring of Everest
Connections, our communications business within Domestic Networks. This resulted from the termination of approximately 160 employees. We also incurred $2.2 million of retention payments in 2003
related to the continued wind-down of our domestic and international energy trading operations in Wholesale Services, and $1.4 million of Corporate and Other severance costs related
to our continued exit from Wholesale Services and the restructuring of Domestic Networks. We expect to
incur additional restructuring charges as we continue to wind down our wholesale trading operations.

We
incurred $55.7 million of total severance costs in 2002 related to the restructuring of Domestic Networks in order to more closely align it with its regulatory service areas
and the decision to exit our energy trading business in Wholesale Services. These actions resulted in the termination of approximately 1,205 energy trading employees, 500 Domestic Networks employees
and 75 Corporate employees in 2002. These charges were expensed and accrued in 2002 and paid out bi-weekly over the term of the severance benefit. In addition, certain employees in
wholesale energy trading operations had retention agreements in 2002 to ensure an orderly exit of this business. During 2002, we paid approximately $30.5 million of retention payments to these
employees.

Disposal of Corporate Aircraft

The $7.1 million charge for disposal of corporate aircraft in 2002 primarily included the termination of applicable lease agreements and losses associated
with the sale of our corporate aircraft.

Interest Rate Swap Reductions

We incurred $23.1 million and $6.2 million of restructuring charges in 2003 and 2002, respectively to exit interest rate swaps related to our Clay
County and Piatt County construction financing arrangements. As debt related to these facilities was paid down, our interest rate swaps exceeded the outstanding debt. Thus we reduced our position and
realized the loss associated with the cancelled swaps.

Aggregator Loan Program

During the year ended December 31, 2002, we incurred a $9.0 million loss on the negotiated termination of certain aggregator loans to substantially
complete our exit from that business.

Lease Agreements

During 2002, we recorded a $38.5 million restructuring charge for operating leases for various office facilities used in the wholesale energy trading
operations that we determined would no longer be used. This charge represented the estimated future net lease costs of these facilities after estimated sublease recoveries.

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Leasehold Improvements and Equipment

During 2002, we wrote down $58.8 million of leasehold improvements and equipment in our wholesale energy trading business that were no longer realizable
based on our best estimate of their fair value.

Restructuring Reserve Activity

The following is a summary of the activity for accrued restructuring charges:

|                                                       |                                                          | Year Ended December 31, |     
|------------------------------------------------------ | -------------------------------------------------------- | ----------------------- | ----
|
|
|Severance and Retention Costs:                         |                                                          |                         |     
|                                                       | Accrued severance costs at beginning of period           |                         | $   
|                                                       | Additional expense during the period                     |                         |     
|                                                       | Cash payments during the period                          |                         |     
|                                                       |                                                         
|Accrued severance and retention costs at end of period |                                                          | $                       | .9  
|                                                       |                                                         
|Other Restructuring Costs:                             |                                                          |                         |     
|                                                       | Accrued other restructuring costs at beginning of period |                         | $   
|                                                       | Additional expense during the period                     |                         |     
|                                                       | Cash payments during the period                          |                         |     
|                                                       |                                                         
|Accrued other restructuring costs at end of period(a)  |                                                          | $                       | 16.0
|                                                       |                                                         



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

Impairment charges and net loss on sale of assets we recorded for the years ended December 31, 2003, 2002 and 2001 are shown below. After-tax
losses in the following paragraphs are reported after giving consideration to the effects of non-deductible goodwill or intangibles and capital loss 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                                 |                        
|                                                        | Other                                                   |                        
|                                                       
|Total Domestic Networks                                 |                                                         |                        
|                                                       
|International Networks:                                 |                                                         |                        
|                                                        | Midlands                                                |                        
|                                                        | Australia                                               |                        
|                                                        | Other                                                   |                        
|                                                       
|Total International Networks                            |                                                         |                        
|                                                       
|Capacity Services:                                      |                                                         |                        
|                                                        | Acadia tolling agreement                                |                        
|                                                        | Turbines                                                |                        
|                                                        | Independent power plants                                |                        
|                                                        | 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                                |                                                         |                        
|                                                       
|Total impairment charges and net loss on sale of assets |                                                         | $                      
|                                                       

During 2003 and 2002, we also incurred impairment charges and net loss on sale of assets of $47.5 million and $438.2 million, respectively, 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.

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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 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 Services 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 with 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 Services' 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 utility operations, we made a decision in the fourth quarter of 2002 to reduce the future funding for the
network build-out of Everest Connections to levels necessary to complete construction in progress, serve existing customers and limit growth to the addition of customers on our existing
network. We evaluated Everest Connections' strategic alternatives 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 Connections' 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 their long-term prospects.
Accordingly, in

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June 2002
we recorded a $23.1 million pretax impairment charge, or $13.9 million after-tax, relating to these investments.

Certain
shareholders of Everest Connections have the option (target-based put rights) to sell their share interests to us if Everest Connections 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 share 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 probability-weighted expense of $7.1 million. As of December 31, 2003, we have reserved $7.8 million for this obligation.

During
2001, we decided to limit Everest Connections' 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.

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 in 2002, 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. In 2003, we agreed to sell these assets to another utility. As a result, we recorded pretax charges of
$.9 million and $9.0 million, or $.6 million and $5.5 million after tax, in 2003 and 2002, respectively, related to this system.

Midlands

In October 2003, we and FirstEnergy Corp. agreed to sell 100% of the shares in Aquila Sterling Limited (ASL), the owner of Midlands Electricity plc to a
subsidiary of Powergen UK plc for approximately £36 million. As a result of this agreement and our analysis of fair value surrounding this investment, in the third quarter of 2003
we recorded a $4.0 million pretax and after-tax impairment charge to write this investment down to its estimated fair value. We completed the sale of ASL in January 2004 and
received proceeds before transaction costs of $55.5 million. We estimate we will pay approximately $7.6 million in transaction fees. We expect to record a pretax and after-tax gain from
this sale of approximately $3.0 million in the first quarter of 2004 due to changes in the British pound exchange rate.

In
2002, we recorded a pretax and after-tax impairment charge of $247.5 million to record an other-than-temporary decline in this investment.
We purchased this investment in May 2002. See

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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 were in negotiations with
prospective buyers. Our evaluation of those offers indicated that this investment was impaired. The impairment stemmed from our inability to hold the investment long-term and thus realize
the benefits anticipated in our original analysis. 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.

Australia

In 2003, we sold our interests in Multinet Gas, United Energy Limited and AlintaGas Limited to a consortium consisting of AlintaGas, AMP Henderson and their
affiliates. We received approximately $622 million in cash proceeds from this sale before transaction costs and taxes. We retired our $200.0 million, 364-day secured credit
facility with these proceeds. In 2003, we recorded a pretax loss of $1.8 million, or $1.3 million after tax, in connection with this sale.

In
2002, we recorded a pretax impairment charge of $127.2 million, or $93.0 million after tax, to record an other-than-temporary decline in our investments in Multinet and
AlintaGas in Australia. Approximately $109 million of this pretax charge related to the Multinet business and the remaining impairment charge was related to our investment in AlintaGas. Our
liquidity situation and change in strategic direction in 2002 caused us to change our intention to hold these investments for the long-term. As a result, we considered the current market
value of these businesses, which included an offer to purchase our interest in these businesses, as well as an impairment charge taken in the financial statements of the underlying businesses, to
assess the realizability of our investment.

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, a joint equity investment of 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.

Acadia Tolling Agreement

In May 2003, we terminated our 20-year tolling agreement for the Acadia power plant in Louisiana. After making a termination payment of
$105.5 million, we were released from the remaining aggregate payment obligation of $833.9 million, or approximately $43.5 million on an annual basis.

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

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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 second quarter of 2003, we completed the contract termination and sale of certain turbines which had been written down to an estimated realizable value at December 31,
2002. In connection with the disposition, we recorded a pretax gain of $5.1 million, or $3.2 million after tax.

Independent Power Plants

In the third quarter of 2003, we decided to proceed with the sale of our investments in independent power plants. In November 2003, we agreed to sell our
interests in 12 plants to Teton Power Funding LLC. Two of the power plants, Lake Cogen Ltd. (Lake Cogen) and Onondaga Cogen Ltd Partnership (Onondaga), are consolidated on our balance
sheet. Therefore, in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144), we have reported the results of operations and
assets of these two plants in discontinued operations. See Note 6 for further explanation.

The
remaining plants are equity method investments that do not qualify for reporting as discontinued operations under SFAS 144 and are therefore included in continuing operations.
In the third quarter of 2003, we evaluated the carrying value of these equity method investments based on the bids received and other internal valuations. The results of this assessment indicated that
these investments were impaired. Therefore, we recorded a pretax impairment charge of $87.9 million, or $69.9 million after tax, to reduce the carrying value of our investments to their
estimated fair value. This sale is expected to close in March 2004. We expect to receive adjusted proceeds of approximately $257.0 million.

Exit from Lodi Gas Storage Investment

In August 2001, Aquila Merchant and a partner acquired 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
Merchant'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.

Termination of Cogentrix Acquisition

In August 2002, we terminated 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 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.

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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 $2.6 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.

Note 6: Discontinued Operations

Consistent with our plan to sell non-core assets and return to operating primarily as a domestic utility, we have sold or are in the process of
selling the following assets, which are therefore considered discontinued operations in accordance with SFAS 144. After-tax losses discussed below are reported after giving
consideration to the effect of non-deductible goodwill or intangibles and capital loss carryback and carryforward limitations. As a result, the net tax effect may differ substantially from
our expected statutory tax rates.

Canada

In September 2003, we agreed to sell our Canadian utility businesses (which are included in our International Networks segment) to Fortis, Inc. for
approximately C$1,360 million (US$1,047 million at the December 31, 2003 exchange rate), including the repayment or assumption of C$174 million (US$134 million at
the December 31, 2003 exchange rate) or US$913 million in net proceeds to us before closing adjustments, transaction costs and taxes. In addition, we will be required to repay
US$215 million borrowed by our Canadian subsidiaries under a 364-day unsecured loan. We expect to use the remaining net proceeds from the sale to pay related taxes and transaction
fees, improve our liquidity, and reduce debt and other obligations. The transaction is subject to approval by the regulatory commissions in Alberta and British Columbia, among other regulatory bodies,
as well as other customary closing conditions, and is expected to close in the first half of 2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate.

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Independent Power Plants

In the third quarter of 2003, we decided to proceed with the sale of our investments in independent power plants. In November 2003, we agreed to sell our
interests in 12 plants to Teton Power Funding LLC. Two of the power plants, Lake Cogen and Onondaga, are consolidated on our balance sheet. We have reported the results of operations and assets of
these two plants in discontinued operations. In the third quarter of 2003, we evaluated the carrying value of these assets based on the bids received and other internal valuations. The results of this
assessment indicated these assets were impaired. We recorded a pretax impairment charge of $47.5 million, or $39.8 million after tax, to reduce the carrying value of these assets to
their estimated fair value less costs to sell. We expect to close the sale of these plants in March 2004.

Gas Storage Facility

In August 2002, we agreed 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 agreed 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 Terminal

During the fourth quarter of 2002, we decided to dispose of Aquila Dock, Inc., our coal terminal in West Virginia. 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, 2003 in the Consolidated
Statements of Income. The related assets and liabilities included in the sale of these businesses, as detailed below, have been

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reclassified
as current and non-current assets and liabilities of discontinued operations on the December 31, 2003 and 2002 Consolidated Balance Sheets as follows:

|                                                         |                                      | December 31,
|-------------------------------------------------------- | ------------------------------------ | ------------
|
|                                                        
|Current assets of discontinued operations:               |                                      |             
|                                                         | Cash and cash equivalents            |             
|                                                         | Funds on deposit                     |             
|                                                         | Accounts receivable, net             |             
|                                                         | Price risk management assets         |             
|                                                         | Other current assets                 |             
|                                                        
|Total current assets of discontinued operations          |                                      | $           
|                                                        
|Non-current assets of discontinued operations:           |                                      |             
|                                                         | Property, plant and equipment, net   |             
|                                                         | Price risk management assets         |             
|                                                         | Goodwill, net                        |             
|                                                         | Other non-current assets             |             
|                                                        
|Total non-current assets of discontinued operations      |                                      | $           
|                                                        
|Current liabilities of discontinued operations:          |                                      |             
|                                                         | Current maturities of long-term debt |             
|                                                         | Short-term debt                      |             
|                                                         | Accounts payable                     |             
|                                                         | Other current liabilities            |             
|                                                        
|Total current liabilities of discontinued operations     |                                      | $           
|                                                        
|Non-current liabilities of discontinued operations:      |                                      |             
|                                                         | Long-term debt, net                  |             
|                                                         | Deferred credits                     |             
|                                                        
|Total non-current liabilities of discontinued operations |                                      | $           
|                                                        

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Operating results of discontinued operations are as follows:

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

Short-Term DebtCanadian Denominated Credit Facilities

On July 31, 2003, we closed on a $215.0 million, 364-day unsecured loan. The borrowers are Aquila Networks Canada Corp. (ANCC) and
Aquila Networks Canada (Alberta) Ltd. (ANCA), each of which is an indirect wholly-owned subsidiary. At closing, ANCC borrowed $115.0 million and ANCA borrowed $100.0 million. The
interest rate on this financing is the London Inter Bank Offering Rate (LIBOR) (with 2.50% floor) plus 4.25%. Proceeds were used by ANCA to repay and terminate its existing 364-day credit
agreement that matured on July 31, 2003 and a letter of credit facility. ANCC will use its proceeds to finance the capital expenditure and working capital requirements of its regulated utility
subsidiaries, as well as repay certain bank debt of its Canadian subsidiaries. The facilities will be repaid with the proceeds received in connection with the sale of our Canadian utility businesses.
We paid up-front arrangement fees of $4.3 million in connection with this borrowing.

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Long-Term Debt

The following table summarizes the long-term debt balances included in current and non-current liabilities of discontinued operations at
December 31, 2003.

|In millions                                                         |  | December 31,
2003
|------------------------------------------------------------------- |  | -----------------
|                                                                   
|Canadian Asset Securitization, 3.458% due monthly to March 15, 2004 |  | $                
|Canadian Secured Debentures, 8.145%*, due 2003-2023(a)              |  |                  
|Canadian Denominated Credit Facilities, due May 2005(a)             |  |                  
|Other Canadian Obligations(a)                                       |  |                  
|                                                                   
|Total debt of discontinued operations                               |  | $                
|                                                                   



Canadian Asset Securitization

In 2002, ANCA 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, 2003 was US$21.9 million, which bears interest at a fixed rate of 3.458%. This securitization will be paid off in March 2004.

Canadian Secured Debentures

At December 31, 2003, our British Columbia utility business had debentures and a mortgage loan totaling $119.4 million (C$154.9 million) that
are secured by the assets of that subsidiary. We have guaranteed the debentures. We are working with the note holders to secure the release from our guaranty at the close of the sale of our Canadian
utility businesses. If we are unable to secure the release, we may continue as guarantor of these obligations for the remaining terms of the debentures. As our British Columbia utility business has an
investment grade credit rating and is subject to regulation requiring it to maintain an adequate level of capitalization, it is unlikely that we would be required to perform under these guaranties.

Canadian Denominated Credit Facilities

Our British Columbia utility business 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, 2003, US$15.4 million was outstanding at a rate of 3.76%.

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Commitments and Contingencies

|In millions                            |  | 2004 |      | 2005 |   | 2006 |  | 2007 |      | 2008 |   | Thereafter |  | Total
|-------------------------------------- |  | ---- | ---- | ---- | - | ---- |  | ---- | ---- | ---- | - | ---------- |  | -----
|                                      
|Aquila Networks Canada leases          |  | $    | 6.1  |      | $ | 5.7  |  | $    | 5.4  |      | $ | 5.2        |  | $    
|Aquila Networks Canada power purchases |  |      | 31.2 |      |   | 28.9 |  |      | 29.3 |      |   | 29.8       |  |      
|Lake Cogen leases                      |  |      | 16.2 |      |   | 16.9 |  |      | 18.7 |      |   | 19.5       |  |      
|                                      
|Total                                  |  | $    | 53.5 |      | $ | 51.5 |  | $    | 53.4 |      | $ | 54.5       |  | $    
|                                      

Aquila Networks Canada leases.Our Canadian subsidiaries' leases primarily relate to operating leases of vehicles and office
space over terms of up to 20 years.

Aquila Networks Canada power purchases.Our electric utility in British Columbia generates 47% of the power delivered to its
customers. It owns hydroelectric dams to generate much of this power. This business also purchases power to meet customer demands under short-term and long-term power purchase
contracts.

Lake Cogen leases.Lake Cogen, one of our consolidated independent power plants, has leases for the power plant and land that
it uses to generate power. The facility and land leases have terms of 16 and 20 years, respectively.

Canadian Pension Obligations

We maintain defined benefit pension plans in Canada. The actuarial assumptions used to calculate the benefit obligation and periodic pension costs for Canadian
plans are essentially the same as those used for the U.S. plans as discussed in Note 19. 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 Canadian plans are summarized below:

|In millions                                               |  | 2003 |      
|--------------------------------------------------------- |  | ---- | -----
|                                                          | 
|Projected Benefit Obligations in Excess of Plan Assets:   |  |      |      
|Fair value of plan assets                                 |  | $    | 50.8 
|Projected benefit obligation                              |  |      | 67.0 
|                                                          | 
|Funded status                                             |  | $    | (16.2
|                                                          | 
|Accumulated Benefit Obligations in Excess of Plan Assets: |  |      |      
|Fair value of plan assets                                 |  | $    | 50.8 
|Accumulated benefit obligation                            |  |      | 59.3 
|                                                          | 
|Funded status                                             |  | $    | (8.5 
|                                                          | 

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Note 7: Restricted Cash

Our restricted cash on the Consolidated Balance Sheets was comprised of the following:

|                                                   |  | December 31,
|-------------------------------------------------- |  | ------------
|
|                                                  
|Restricted customer funds on deposit               |  | $           
|Cash proceeds from sale of merchant loan portfolio |  |             
|Cash collateral on construction financing          |  |             
|Other                                              |  |             
|                                                  
|Total                                              |  | $           
|                                                  

During
2002, a large counterparty began to require 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 is not available for day-to-day operations. The amount of these deposits at December 31, 2003 and 2002 was $248.7 million and
$158.7 million, respectively.

In
2002, we were required to place $239.9 million of funds received from the sale of our merchant loan portfolio in a temporary escrow account until final resolution of sale
contingencies. In January 2003, these funds were released to us.

In
2002, 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 set aside cash collateral
related to the construction financing. As of December 31, 2002, we had set aside 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 as follows:

|                                      |  | December 31, |      
|------------------------------------- |  | ------------ | -----
|
|                                      | 
|Merchant Services accounts receivable |  | $            | 369.4
|Regulated utility accounts receivable |  |              | 137.0
|Other accounts receivable             |  |              | 6.4  
|Allowance for doubtful accounts       |  |              | (36.7
|Unbilled utility revenue              |  |              | 122.3
|                                      | 
|Total                                 |  | $            | 598.4
|                                      | 

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,

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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 sold trade receivables to bankruptcy-remote special-purpose entities (SPEs). The SPEs were related to the financial institutions and not 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 $.6 million and $2.9 million in 2002, and
2001, respectively. Collections on these receivables were reinvested on behalf of the buyers in newly created receivables. We had gross sales of accounts receivable of $1.4 billion and
$4.1 billion during 2002 and 2001, respectively. Our Consolidated Statements of Income include the loss on the sale of receivables of $2.5 million and $15.6 million in 2002 and
2001, respectively.

In
October 2003, we pledged receivables from certain of our merchant gas customers as collateral support for a margining agreement with one of our significant gas suppliers. The
total of these pledged receivables was $26.1 million at December 31, 2003.

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.

Note 9: Property, Plant and Equipment

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

|                                                       |                                          | December 31, |         
|------------------------------------------------------ | ---------------------------------------- | ------------ | --------
|
|
|Electric utility                                       |                                          | $            | 2,185.4 
|Gas utility                                            |                                          |              | 1,222.0 
|Non-regulated electric power generation                |                                          |              | 494.9   
|Communications                                         |                                          |              | 60.2    
|Corporate and other                                    |                                          |              | 364.4   
|Electric and gas utility plantconstruction in process |                                          |              | 44.1    
|                                                       |                                         
|                                                       |                                          |              | 4,371.0 
|Lessaccumulated depreciation and amortization         |                                          |              | (1,618.3
|                                                       |                                         
|                                                       | Total property, plant and equipment, net |              | $       
|                                                       |                                         

|                                        |  | Composite
Depreciation Rates
|--------------------------------------- |  | ----------------------------
|
|
|Electric utility                        |  | 3.1%                        
|Gas utility                             |  | 3.0%                        
|Non-regulated electric power generation |  | 2.8%                        
|Communications                          |  | 8.5%                        
|Corporate and other                     |  | 11.7%                       
|                                       

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Jointly Owned Electric Utility Plant

We own an 8% interest and lease another 8% interest in a coal-fired plant (Jeffrey Energy Center) with generating capacity of approximately 2,200
megawatts, that is operated by Westar Energy, Inc. We also own an 18% interest in a 670-megawatt coal-fired plant (Iatan) that is operated by a different utility. At
December 31, 2003, our investments in the Jeffrey Energy Center and Iatan electric utility plants totalled $190.1 million and related accumulated depreciation was $116.0 million.
Our pro rata share of Jeffrey Energy Center's and Iatan's operating costs are included in our Consolidated Statements of Income.

Note 10: Investments in Unconsolidated Subsidiaries

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

|                                     |       |         |  |                |  | Investment at
December 31, |       | Equity EarningsYear Ended
December 31, |  
|------------------------------------ | ----- | ------- |  | -------------- |  | -------------------------- | ----- | --------------------------------------- | -
|
|
|                                     |      
|Independent power plant partnerships |       | 20%-50% |  | U.S. & Jamaica |  | $                          | 200.6 |                                         | $
|Midlands Electricity plc *           |       | 79.9%   |  | United Kingdom |  |                            | 75.1  |                                         |  
|United Energy Limited                |       | Sold    |  | Australia      |  |                            |      |                                         |  
|Multinet Gas *                       |       | Sold    |  | Australia      |  |                            |      |                                         |  
|AlintaGas Limited*                   |       | Sold    |  | Australia      |  |                            |      |                                         |  
|UnitedNetworks Limited               |       | Sold    |  | New Zealand    |  |                            |      |                                         |  
|Quanta Services, Inc. *              |       | Sold    |  | United States  |  |                            |      |                                         |  
|Other                                |       | Various |  | United States  |  |                            | 37.2  |                                         |  
|                                     |      
|                                     | Total |         |  |                |  |                            | $     | 312.9                                   |  
|                                     |      



Independent Power Plant Partnerships

As of December 31, 2003, we owned interests in 12 independent power plants 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. In 2003, we decided to proceed
with the sale of our remaining investments in independent power plants. In January 2004, we sold our interest in one of these plants. In March 2004, we expect to close the sale of our
interests in 12 plants to Teton Power Funding LLC for approximately $257.0 million before transaction costs and taxes. Two of the power plants, Lake Cogen Ltd. (Lake Cogen) and Onondaga
Cogen Ltd Partnership (Onondaga), are consolidated on our balance sheet. The remaining 10 plants are equity method investments that do not qualify for reporting as discontinued
operations under SFAS 144 and are therefore included in continuing operations and in the investment table above. In the third quarter of 2003, we evaluated the carrying value of these equity
method investments based on the bids received and other internal valuations. The results of this assessment indicated that these

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investments
were impaired. Therefore, we recorded a pretax impairment charge of $87.9 million, or $69.9 million after tax, to reduce the carrying value of our investments to their
estimated fair value.

Midlands Electricity plc

In May 2002, we purchased from FirstEnergy Corp. a 79.9% economic interest in Aquila Sterling Limited (ASL), the holding company for Midlands Electricity,
a United Kingdom electricity network. FirstEnergy retained the remaining 20.1% of ASL. 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.

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. Pursuant to an operating services agreement, we provided 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 had 50% voting power and an
equal number of representatives on the ASL board of directors. Although we had the majority economic interest, FirstEnergy's participation in day-to-day business decisions
was significant, including approval of executive compensation, additional capital contributions, budgets, and the dissolution of the company. We were therefore required to account for this acquisition
using the equity method of accounting.

Downgrades
in credit ratings assigned to the public debt in the Midlands ownership chain 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), required pre-approval of cash payments to the owners in the form of management fees or
dividends. Accordingly, in 2003, we did not record equity earnings as no cash was received.

In
August 2002, Aquila and FirstEnergy initiated a bid process for the sale of Midlands. We received offers in early December and were in negotiations with prospective buyers at
December 31, 2002. As a result of those 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. See Note 5 for further discussion.

In
October 2003, we and FirstEnergy Corp. agreed to sell 100% of the shares in ASL, the owner of Midlands Electricity plc to a subsidiary of Powergen UK plc for approximately
£36 million. As a result of this agreement and our analysis of fair value surrounding this investment, in the third quarter of 2003 we recorded a $4.0 million pretax and
after-tax impairment charge to write this investment down to its estimated fair value. We completed the sale of ASL in January 2004 and received proceeds before transaction costs of
$55.5 million. We estimate we will pay approximately $7.6 million in transaction fees. Including the reclassification of $30.5 million of cumulative foreign currency translation
gains from OCI to income, we expect to record a pretax and after-tax gain from this sale of approximately $3.0 million in the first quarter of 2004 due to changes in the British pound exchange
rate in the fourth quarter of 2003 and early 2004.

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Following is the summarized financial information for Midlands Electricity plc:

|                             |                         | 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)  |                    | $                      
|                  

United Energy Limited, Multinet Gas and AlintaGas Limited

We acquired our initial investment in Australia in 1995. Our ownership interest in United Energy Limited (UEL), a publicly owned electric distribution company in
Melbourne, Australia, was 33.8%. UEL owned a 66% interest in Uecomm Limited, a communications business, and a 22.5% interest in AlintaGas Limited, a gas utility in Western Australia.

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. 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
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 was reflected as an equity
investment with the remaining 22.5% reflected as part of our interest in UEL.

In
2001, we 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%

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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 of 2002 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.

In
2003, we sold our interests in Multinet Gas, United Energy Limited and AlintaGas Limited to a consortium consisting of AlintaGas, AMP Henderson and their affiliates. We received
approximately $622 million in cash proceeds before transaction costs and taxes from this sale. We retired our $200.0 million, 364-day secured credit facility with these
proceeds. We recorded a pretax loss of $1.8 million, or $1.3 million after tax, in 2003 in connection with this sale.

Following
is the summarized financial information for UEL. The balance sheet as of December 31, 2003 is not included because we sold our investment in 2003:

|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 |                         | $                
|                            

|                   |                    | Seven Months Ended
July 31, |      | Year Ended December 31,
|------------------ | ------------------ | --------------------------- | ---- | -----------------------
|
|                  
|                   |                    |                             |      |                        
|Operating Results: |                    |                             |      |                        
|                   | Sales              |                             | $    | 157.3                  
|                   | Costs and expenses |                             |      | 126.4                  
|                  
|Net income         |                    | $                           | 30.9 |                        
|                  

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.

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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 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 US$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 sheets as of December 31, 2003 and 2002 and the income statement for the 2003 period are not included
because we sold our investment in 2002:

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

Quanta Services, Inc.

Between 1999 and 2001, we acquired voting convertible preferred and common stock of Quanta Services, Inc. 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,

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2002.
We sold our remaining 11.6 million shares of Quanta Services in February 2003 at a net price of $2.90 per share.

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 $24.8 million and $35.9 million in 2002 and 2001, respectively.

Following
is the summarized financial information for Quanta Services. The balance sheet as of December 31, 2003 and the income statement for the 2003 period are not included
because we sold our remaining investment in February 2003:

|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 |                         | $                
|                            

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

Aries Power Project

MEP Pleasant Hill, LLC, our 50%-owned joint venture that owns and operates the Aries Power Project in Pleasant Hill, Missouri, did not refinance or repay
$270.0 million of construction loans prior to their June 26, 2003 maturity. In response to the default, the lenders have drawn on $75.0 million of letters of credit that we and
our partner equally pledged to support the loans, reducing the loan balances to $195.0 million. Although the project is current on its interest payments and other operating expenses, the loans
remain in default. The loans are non-recourse to us and the default has no direct impact on our other credit arrangements or utility operations. We are currently working with our partner
and lenders to cure the default. As of December 31, 2003, our investment balance in the Aries Power Project was $33.4 million.

We
are currently in discussions with our joint venture partner regarding the transfer of our 50% interest in the Aries Power Project and other consideration to our partner in exchange
for

115

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the
release from our remaining capacity tolling obligation. If such a transaction were consummated, we would incur a loss.

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. As mentioned above, we sold our interests in Multinet and AlintaGas in 2003. Therefore they are not included in the 2003
balance sheets and their results of operations for 2003 are only included for the periods in which we owned them.

|                             |                         | 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. We primarily show these as deferred charges and other assets and deferred credits on our Consolidated Balance Sheets.

|                                    |                              | December 31,
|----------------------------------- | ---------------------------- | ------------
|
|                                   
|                                    |                              |             
|Regulatory Assets:                  |                              |             
|                                    | Under-recovered gas costs    |             
|                                    | Income taxes                 |             
|                                    | Environmental                |             
|                                    | Regulatory accounting orders |             
|                                    | Other                        |             
|                                   
|                                    | Total regulatory assets      |             
|                                   
|Regulatory Liabilities:             |                              |             
|                                    | Cost of removal              |             
|                                    | Income taxes                 |             
|                                    | Revenue subject to refund    |             
|                                    | Over-recovered gas costs     |             
|                                   
|                                    | Total regulatory liabilities |             
|                                   
|Net regulatory (liabilities) assets |                              | $           
|                                   

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



Regulatory
liabilities represent items we expect to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers.
These liabilities include:



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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                           |       |              | 
|                                           |      
|                                           | Total |              | $
|                                           |      
|Weighted average interest rate at year end |       |              | 
|                                           |      

Revolving Credit Facility

In April 2002, we entered into a revolving credit facility totaling $650.0 million. The credit facility consisted of two $325.0 million
credit agreements, one with a maturity of 364 days, and the other with a maturity of three years. In 2002, affected lenders granted us waivers of the requirement to comply with an interest
coverage covenant and a capitalization ratio covenant specified in the revolving credit facility until April 12, 2003. We were required to pay fees of approximately $3.6 million to the
lenders in connection with these waivers. We were also required to use 50% of the net cash proceeds from asset sales to reduce our obligations to the affected lenders on a pro rata basis. In
April 2003, the 364-day credit facility was repaid in full and the unused portion of the three-year credit facility was terminated. During the second quarter of 2003, we
terminated the remainder of the three-year facility and replaced the letters of credit issued under it with new letters of credit issued under our letter of credit facility discussed
below.

Letter of Credit Facility

In April 2003, we executed a 364-day letter of credit agreement with a commercial bank. Under terms of the agreement, the bank committed to
issue letters of credit under the facility subject to a limit of $200.0 million outstanding at any one time. All letters of credit issued are fully secured by cash deposits with the bank. The
committed amount automatically decreased to

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$150.0 million
at December 31, 2003. At December 31, 2003, $83.2 million of letters of credit were outstanding under this facility.

Turbine Facility

In May 2001, we entered into a five-year operating lease through a special-purpose entity (SPE) for 10 electric power plant turbines plus
related equipment. Under this agreement, we could lease up to $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 of 2002 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. 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
SPE's equity, this SPE 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. We also had posted
$28.0 million of cash collateral in support of these notes. The notes were scheduled to mature in 2005, but we repaid them in full in April 2003. We therefore classified the notes as
short-term debt at December 31, 2002.

364-Day Senior Secured Credit Facility

In April 2003, we closed on a $200.0 million, 364-day secured loan. The borrower was UtiliCorp Australia, Inc., a wholly-owned
subsidiary. At closing, we borrowed $100.0 million of the available $200.0 million. The interest rate on this financing was initially the LIBOR (with a 3% floor) plus 4.0% for the first
90 days. After the first 90 days, the interest rate increased an additional 2% and would have increased an additional 2% every subsequent 90 days with a
maximum rate at maturity of LIBOR (with a 3% floor) plus 10%. We paid up-front arrangement fees of $4.1 million in connection with this borrowing. Proceeds from this borrowing were
used to retire debt.

In
May 2003, we exercised our option under the 364-day financing to borrow the remaining $100.0 million available under the facility. The proceeds were used to
terminate our Acadia tolling agreement as discussed in Note 5. We paid additional arrangement fees of $4.1 million for this borrowing. We retired $90.7 million of this borrowing
in June 2003 with proceeds from the sale of our interest in AlintaGas. The remaining balance of $109.3 million was retired in July 2003 with proceeds from the sale of our
interests in United Energy and Multinet Gas.

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Note 13: Long-Term Debt

This
table summarizes our long-term debt:

|                                                              |                                                                                       | December 31,
|------------------------------------------------------------- | ------------------------------------------------------------------------------------- | ------------
|
|                                                             
|                                                              |                                                                                       |             
|First Mortgage Bonds:                                         |                                                                                       |             
|                                                              | Various, 9.44%, due annually through 2021(a)                                          |             
|Secured Credit Facility:                                      |                                                                                       |             
|                                                              | LIBOR plus 5.00%, due April 11, 2006(a)                                               |             
|Senior Notes:                                                 |                                                                                       |             
|                                                              | 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                                                    |             
|                                                              | 7.75% Series, due June 15, 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 164,837 common shares at $15.79 per share) |             
|Other:                                                        |                                                                                       |             
|                                                              | Note Payable, 8.15%, due annually through 2008                                        |             
|                                                              | Clay County Project Notes                                                             |             
|                                                              | Piatt County Project Notes                                                            |             
|                                                              | Australian Medium Term Notes                                                          |             
|                                                              | Australian Denominated Credit Facilities                                              |             
|                                                              | Other notes and obligations(a)                                                        |             
|                                                             
|Total Long-Term Debt                                          |                                                                                       |             
|Less current maturities                                       |                                                                                       |             
|                                                             
|Long-term debt, net                                           |                                                                                       | $           
|                                                             
|Fair value of long-term debt, including current maturities(b) |                                                                                       | $           
|                                                             



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

In millions

Maturing Amounts2004

$
414.82005


54.82006


532.82007


55.12008


19.5Thereafter


1,629.0Total

$
2,706.0


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

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

The
three-year facility is secured by (i) $430.0 million of first mortgage bonds issued under a new indenture that constitutes a lien on our existing and future
Michigan, Nebraska, Iowa and Colorado utility network assets, (ii) a pledge of the equity of two wholly-owned subsidiaries that indirectly hold our Canadian utility businesses, and
(iii) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our interests in independent power plants. If we default on this loan, the lenders would be entitled to be fully
repaid from the sale proceeds of this collateral before other creditors could assert their claims against the pledged assets.

We
have also committed to use reasonable efforts to obtain approvals that would provide these lenders additional domestic utility assets as collateral for their loans. If, as a result of
the

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addition
of any such collateral, the value of the domestic regulated utility asset collateral securing the indenture exceeds 167% of the loan secured by the indenture, the pledge of the Canadian and
independent power projects equity interest may be released and the interest rate would be reduced to LIBOR (which has a 3% floor) plus 5.00%. In April 2003, we filed applications with the state
regulatory bodies in Kansas, Minnesota and Missouri requesting authority to pledge our utility assets located in their respective states. In October 2003, the Minnesota Public Utility
Commission voted to deny our request to pledge Minnesota utility assets. We re-filed the application to address the concerns raised by the Minnesota Commission. The Minnesota Commission
issued an order in January 2004 again denying our request. In February 2004, the Kansas Corporation Commission and the Missouri Public Service Commission denied our request to pledge our Kansas
and Missouri utility assets.

After
our Iowa utility assets were pledged, our interest rate was reduced as described above, and we have pledged utility assets in Michigan, Nebraska, Iowa and Colorado sufficient to
fully collateralize the loan. We are not required by the credit facility to maintain collateral for the loan beyond the utility assets pledged. However, it is our intention that borrowings under the
credit facility that are not needed to support our utility operations be collateralized by non-utility assets.

The
$430.0 million 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 our $250.0 million, 7% senior note series due July 15, 2004 and our $150.0 million, 6.875% senior note series due October 1, 2004, at least two weeks prior
to their respective maturity dates. We would also have to pay our lenders an early termination fee of 2% of the amount repaid pursuant to this provision. Among other restrictions, the
three-year secured facility contains the following financial covenants with which we were in compliance as of December 31, 2003:

The
three-year facility also contains covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on
acquisitions, sale transactions, and the amount that we can fund our unregulated merchant businesses and our Everest Connections communications 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 Standard & Poor's, or if such a payment would cause a default under
the 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
re-borrowed. To the extent we default on any of our loan covenants, our interest rate will increase an additional 2% during the default period.

Note Payable

In connection with the acquisition of our interest in Midlands Electricity from FirstEnergy Corp., 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%. In 2003, FirstEnergy sold this note to two unrelated third parties and removed the
requirement that we repay the note on an undiscounted basis if we sold our interest in Midlands.

In
February 2004, we extinguished the entire note payable. We paid $78.6 million to extinguish this note payable and accrued interest, resulting in other income related to
this transaction of approximately $2.0 million.

Clay County and Piatt County Construction Financing

In November 2000, we entered into a $145.0 million lease through a special-purpose entity (SPE) to finance the 340-megawatt Clay County
power plant. This plant was completed in 2002. In February 2002, we entered into an agreement to lease from a SPE a $235 million, 510-megawatt power plant in Piatt County,
Illinois. This plant was 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. 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, 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


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

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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, an additional $21.0 million of debt was repaid in early 2003. As discussed in Note 7, we had 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 classified both facilities as current maturities of
long-term debt as of December 31, 2002.

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.

As
of December 31, 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 from BBB to BB, a non-investment grade rating with a negative outlook, and Fitch downgraded us to from BBB- to BB 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 increased and we were required to repay certain notes.

In
2003 and 2002, we retired $78.6 million and $91.7 million, respectively, of our Australian denominated notes that were put to us as a result of the credit downgrades. We
do not expect any additional repayments of debt due to further credit downgrades.

Secured Financing

In each state in which we have utility operations not pledged as collateral, we are required to obtain the approval of their public service commission before
pledging utility assets located in the 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 the 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. Our authority to issue short-term debt expires in March 2004. We have submitted an
application to the FERC and the Kansas Corporation Commission for authority to have outstanding up to $500 million of short-term debt which could be secured or unsecured. The FERC
recently issued an order in which it announced that any

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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

We believe we have sufficient liquidity to cover our operational needs through December 2004. Our next significant need for outside capital relates to our
need to retire senior notes maturing in July and October 2004. We anticipate retiring these notes with proceeds from 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.

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.

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(a) |       | Long-Term
Gas Contract
Margin
Loss(b) |   | Total Long-Term
Gas Contract
Cash
Payments(c)
|----------- | ----- | ------------------------------------ | ----- | ------------------------------------- | - | ---------------------------------------------
|           
|            |       |                                      |       |                                       |   |                                              
|2004        |       | $                                    | 84.8  |                                       | $ | 48.1                                         
|2005        |       |                                      | 87.6  |                                       |   | 49.8                                         
|2006        |       |                                      | 90.9  |                                       |   | 52.2                                         
|2007        |       |                                      | 91.9  |                                       |   | 53.0                                         
|2008        |       |                                      | 79.1  |                                       |   | 46.6                                         
|Thereafter  |       |                                      | 236.8 |                                       |   | 150.0                                        
|           
|            | Total |                                      | $     | 671.1                                 |   | $                                            
|           



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

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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 would be required to pay the issuers of the surety bonds
or the counterparties on these arrangements approximately $860.0 million. This amount is greater than the long-term gas contract balance on our Consolidated Balance Sheet due to our
use of the units of revenue method of relieving the long-term obligation versus a present value method applied under default provisions based on contractual agreements.

Note 15: 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 we 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 in a tax-free exchange for each outstanding share of Aquila Merchant
Class A common stock. Aquila Merchant shareholders holding approximately 1.7 million shares of Aquila Merchant Class A shares exercised dissenters' rights to request an appraisal
of the fair value of their shares 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 exceeded our proportionate interest in
the fair value of the net assets of Aquila Merchant 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 ($29.7 million of which was allocated to our natural gas gathering and pipeline assets and our gas storage facility which were
included in discontinued operations) based on future expected cash flows. We wrote off all of this goodwill in 2002. See Note 1 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. These proceeds 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, raising

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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.

Premium Equity Participating Security Units

In November 2002, we issued approximately 11.7 million shares of our common stock to settle substantially all of our purchase contracts related to our
premium equity participating security units (PEPS). Each PEPS unit had an issue price of $25 and consisted of a contract to purchase shares of our common stock on, or prior to, November 16,
2002 and a preferred security of UtiliCorp Capital Trust I. Each purchase contract yielded 2.40% per year, paid quarterly, on the $25 stated amount of the PEPS unit. Each trust
preferred security yielded 7.35% per year, paid quarterly on the $25 stated amount of the PEPS Unit, until November 16, 2002. These trust preferred securities were cancelled upon
the issuance of common stock to settle the purchase contracts.

Suspension of Dividend

In November 2002, the Board of Directors suspended the annual dividend on common stock for an undetermined period. This decision follows 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. Currently one of our loan agreements and a regulatory order prohibit our paying any dividends. We can make no determination
as to whether or when we will pay dividends in the future.

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, 2003, 2002 and 2001, 608,074, 2,188,427 and 843,201 shares were issued, respectively,
under the Stock Plan. As of December 31, 2003, direct purchase and dividend reinvestment has been suspended under this plan until we obtain authorization of additional shares.

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

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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, 2003, 2002 and 2001, 665,254,
281,394 and 260,046 shares were purchased, respectively, under the Employee Stock Purchase Plan. As of December 31, 2003, purchases have been suspended under this plan until we obtain
authorization of additional shares.

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 were made in cash and invested as directed by the employee. Company contributions were $8.1 million, $11.5 million and $11.2 million during the years ended
December 31, 2003, 2002 and 2001, 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 2003, 2002 and 2001, compensation expense (in millions) of $4.9, $5.9 and
$5.0, 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 company common stock and their elections. Total compensation expense for the years ended December 31, 2003 and 2001, was $.4 million and
$19.6 million, respectively. Due to the company's 2002 performance, no awards were earned for the year ended December 31, 2002, and no new awards were granted in 2002.

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 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

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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 options for 1,278,713 shares were
granted to employees. The exercise price of these options is $24.02. 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. The terms associated with stock options awarded under the Plan can vary with each grant, but 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. In
February 2003, options for 408,300 shares were granted to executives under this plan. These options vest ratably over three years and are exercisable for seven years.

Summary of Stock Options

This table summarizes all stock options:

|Shares:                      |  | 2003      |   | 2002       |   | 2001       |  
|---------------------------- |  | --------- | - | ---------- | - | ---------- | -
|
|                             |  |           |   |            |   |            |  
|Beginning balance            |  | 8,908,508 |   | 6,118,123  |   | 7,156,600  |  
|Granted                      |  | 408,300   |   | 1,789,152  |   | 825,069    |  
|Converted from Merchant plan |  |          |   | 2,641,369  |   |           |  
|Exercised                    |  | (85,577   | ) | (270,028   | ) | (1,779,548 | )
|Cancelled                    |  | (819,433  | ) | (1,370,108 | ) | (83,998    | )
|                             | 
|Ending balance               |  | 8,411,798 |   | 8,908,508  |   | 6,118,123  |  
|                             | 
|Weighted average prices:     |  |           |   |            |   |            |  
|Beginning balance            |  | $20.75    |   | $22.37     |   | $21.39     |  
|Granted price                |  | 1.44      |   | 1.83       |   | 28.75      |  
|Converted price              |  |          |   | 34.82      |   |           |  
|Exercised price              |  | 3.04      |   | 24.14      |   | 21.42      |  
|Cancelled price              |  | 18.21     |   | 29.49      |   | 21.69      |  
|                             | 
|Ending balance               |  | $20.16    |   | $20.75     |   | $22.37     |  
|                             | 

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This table summarizes all outstanding and exercisable stock options as of December 31, 2003:

|             |       | Outstanding Options |           | Exercisable Options
|------------ | ----- | ------------------- | --------- | -------------------
|
|            
|             |       |                     |           |                    
|$1.44-1.83   |       | 1,914,714           |           | 6.00               
|$18.17-23.56 |       | 3,839,568           |           | 4.37               
|$24.02-29.78 |       | 927,171             |           | 5.75               
|$34.80-42.34 |       | 1,730,345           |           | 6.50               
|            
|             | Total |                     | 8,411,798 |                    
|            

No
restricted stock awards were granted during 2003. As of December 31, 2003, we had 526,000 restricted stock awards outstanding.

Note 16: Accumulated Other Comprehensive Income (Loss)

The table below reflects the activity for accumulated other comprehensive income (loss) for 2001, 2002 and 2003:

|In millions               |  | Foreign
Currency
Adjustments |       | Cash
Flow
Hedges |   | Held for Sale
Securities |   | Minimum
Pension
Liability |      | Accumulated
Other
Comprehensive
Income (Loss) |  
|------------------------- |  | ---------------------------- | ----- | ---------------- | - | ------------------------ | - | ------------------------- | ---- | --------------------------------------------- | -
|                          | 
|Balance December 31, 2000 |  | $                            | (40.2 | )                | $ |                         |   | $                         |     |                                               | $
|2001 change               |  |                              | (51.3 | )                |   | .9                       |   |                           |     |                                               |  
|                          | 
|Balance December 31, 2001 |  |                              | (91.5 | )                |   | .9                       |   |                           |     |                                               |  
|2002 change               |  |                              | 74.0  |                  |   | (18.9                    | ) |                           | 7.3  |                                               |  
|                          | 
|Balance December 31, 2002 |  |                              | (17.5 | )                |   | (18.0                    | ) |                           | 7.3  |                                               |  
|2003 change               |  |                              | 81.3  |                  |   | 9.2                      |   |                           | (7.3 | )                                             |  
|                          | 
|Balance December 31, 2003 |  | $                            | 63.8  |                  | $ | (8.8                     | ) | $                         |     |                                               | $
|                          | 

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Note 17: Earnings (Loss) Per Share

The table below shows how we calculated diluted earnings (loss) per share and diluted shares outstanding. Basic earnings (loss) per share and basic weighted
average shares are the starting point in calculating the dilutive measures. To calculate basic earnings (loss) per share, divide earnings (loss) available for common shares by weighted average shares
outstanding without adjusting for dilutive items. Diluted earnings (loss) per share are calculated by dividing earnings (loss) 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 losses in 2003 and 2002, the potential issuances of common stock were
anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.

|                                                                                                                       |                                              | Year Ended December 31,
|---------------------------------------------------------------------------------------------------------------------- | -------------------------------------------- | -----------------------
|
|                                                                                                                      
|                                                                                                                       |                                              |                        
|Earnings (loss) available for common shares from continuing operations                                                 |                                              | $                      
|Interest on convertible bonds                                                                                          |                                              |                        
|                                                                                                                      
|Earnings (loss) available for common shares from continuing operations after assumed conversion of dilutive securities |                                              |                        
|Earnings (loss) from discontinued operations                                                                           |                                              |                        
|Cumulative effect of accounting change                                                                                 |                                              |                        
|                                                                                                                      
|Earnings (loss) available for common shares after assumed conversion of dilutive securities                            |                                              | $                      
|                                                                                                                      
|Basic earnings (loss) per share:                                                                                       |                                              |                        
|                                                                                                                       | Earnings (loss) from continuing operations   |                        
|                                                                                                                       | Earnings (loss) from discontinued operations |                        
|                                                                                                                       | Cumulative effect of accounting change       |                        
|                                                                                                                      
|                                                                                                                       | Net income (loss)                            |                        
|                                                                                                                      
|Diluted earnings (loss) per share:                                                                                     |                                              |                        
|                                                                                                                       | Earnings (loss) from continuing operations   |                        
|                                                                                                                       | Earnings (loss) from discontinued operations |                        
|                                                                                                                       | Cumulative effect of accounting change       |                        
|                                                                                                                      
|                                                                                                                       | Net income (loss)                            |                        
|                                                                                                                      
|Weighted average number of common shares used in basic earnings (loss) per share                                       |                                              |                        
|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 (loss) per share           |                                              |                        
|                                                                                                                      

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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                                                 |                                    |                         | (141.7
|                                                                                                        |                                   
|Income tax expense (benefit) from discontinued operations:                                              |                                    |                         |       
|Current                                                                                                 |                                    |                         | 17.2  
|Deferred (net of valuation allowance of $11.1 million and $75.4 million in 2003 and 2002, respectively) |                                    |                         | (19.7 
|                                                                                                        |                                   
|Income tax expense (benefit) from discontinued operations                                               |                                    |                         | (2.5  
|Income tax benefit on cumulative effect of accounting change                                            |                                    |                         |      
|                                                                                                        |                                   
|                                                                                                        |                                    | Total                   |       
|                                                                                                        |                                   

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

|                                           |                                                            | December 31,  |      
|------------------------------------------ | ---------------------------------------------------------- | ------------- | -----
|
|                                           |                                                           
|                                           |                                                            |               |      
|Deferred Tax Assets:                       |                                                            |               |      
|                                           | Alternative minimum tax credit carryforward                |               | $    
|                                           | Net operating loss carryforward                            |               |      
|                                           | Mark-to-market losses                                      |               |      
|                                           | Accrued bonuses and deferred compensation                  |               |      
|                                           | Allowance for doubtful accounts                            |               |      
|                                           | Asset impairments                                          |               |      
|                                           | Realized capital loss carryforward for income tax purposes |               |      
|                                           | Unrealized capital losses                                  |               |      
|                                           | Other                                                      |               |      
|                                           | Less: valuation allowance                                  |               |      
|                                           |                                                           
|Total deferred tax assets                  |                                                            |               | 309.2
|                                           |                                                           
|Deferred Tax Liabilities and Credits:      |                                                            |               |      
|                                           | Accelerated depreciation and other plant differences:      |               |      
|                                           |                                                            | Regulated     |      
|                                           |                                                            | Non-regulated |      
|                                           | Reserve for contingent tax liabilities                     |               |      
|                                           | Basis difference in international investments              |               |      
|                                           | Currency translation adjustment                            |               |      
|                                           | Pension costs                                              |               |      
|                                           | Regulatory asset                                           |               |      
|                                           |                                                           
|Total deferred tax liabilities and credits |                                                            |               | 685.4
|                                           |                                                           
|Deferred income taxes and credits, net     |                                                            | $             | 376.2
|                                           |                                                           

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    |              | (3.5 
|                                  | Revocation of permanent foreign reinvestments |              |     
|                                  | Change in valuation allowance                 |              | (10.3
|                                  | Reserve for contingent tax liabilities        |              | 17.4 
|                                  | Minority interest                             |              |     
|                                  | Goodwill                                      |              |     
|                                  | Other                                         |              | 2.6  
|                                  |                                              
|Effective Income Tax Rate         |                                               | (28.8        | )%   
|                                  |                                              

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At December 31, 2003 and 2002, we had alternative minimum tax credit carryforwards of $110.3 million and $56.9 million, respectively. 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. 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. When we filed our 2002 tax return in September 2003, we revised the amount of capital
losses claimed from the amounts estimated at December 31, 2002. As a result, we reduced the valuation allowances provided in 2002 by approximately $84.9 million. In 2003, we also
provided approximately $45.0 million of additional valuation allowances for the estimated capital losses primarily associated with the sale of our investments in independent power plants and
the determination that certain state net operating loss carryforwards would more likely than not expire unutilized. At December 31, 2003, we had approximately $487.8 million of net
realized capital loss carryforwards available for federal income tax purposes that expire in 2007 and 2008 and recognized impairment charges of $363.6 million that we expect to realize (for
income tax purposes) as capital losses when the assets are sold.

Net Operating Loss Carryforwards

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. When we filed
our 2002 tax return in September 2003, the net operating loss increased to $681.9 million primarily as a result of the treatment of a loss as an ordinary loss instead of a capital loss.
This 2002 net operating loss was carried back in our federal income tax return for 2002 to offset taxable income in 1997 through 2001. As a result of these capital and net 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. As a result of the
increase in the net operating loss on the 2002 tax return filed in September 2003, an additional refund of $26.7 million was received in September 2003.

Primarily
as the result of losses incurred as we continue to exit the wholesale energy trading business and sell non-core assets, we incurred estimated net operating losses
of $235.6 million in 2003. We expect to carry back $122.6 million of the 2003 federal net operating losses to offset taxable income in 2000 and 2001. The carryback of the 2003 federal
net operating loss is not expected to generate a cash refund. Rather, our alternative minimum tax credit carryforward increased to $110.3 million. The remaining estimated federal net operating
loss of $113.0 million can be carried forward to offset taxable income through 2023. At December 2003, we also have deferred tax benefits of $41.9 million related to state net
operating losses. We did not record valuation allowances against the deferred tax assets related to the federal net operating losses as management believes it is more likely than not that sufficient
taxable income will be generated

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from
continuing operations during the carryforward period to utilize these losses. However, we recorded a valuation allowance of $13.8 million against the state net operating loss benefits.
This determination was based on our assessment that it is more likely than not that we will not realize these deferred assets during the state carryforward periods. This assessment considered the
forecast reversal of existing temporary differences and taxable income we expect to generate in the state carryforward periods.

Reserve for Contingent Tax Liabilities

As of December 31, 2003 and 2002, we had recorded $208.7 million and $93.2 million, respectively, of cumulative tax provisions for tax
deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is reasonably likely that these deductions or income positions will
be challenged when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of
these audits is uncertain. If the positions taken on the tax returns are ultimately sustained we will reverse these tax provisions to income. If the positions taken on the tax returns are not
ultimately sustained, we may be required to make cash payments plus interest and/or utilize our net operating loss or alternative minimum tax credit carryforwards.

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 investments in 2002 and our Australian investments in 2003 and we are in the process of closing the sale of our Canadian investments. As a result, we can no longer
represent that cash from our international investments will be permanently invested outside the United States. Therefore, additional deferred tax of $148.3 million was recorded in 2002 to
account for the estimated taxes that will arise when we bring asset sale proceeds back to the United States.

Goodwill

Included in 2002 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 was not deductible for income tax purposes and therefore does not result in the recognition of a tax benefit.

Note 19: Employee Benefits

We provide defined benefit pension plans for our employees in the United States and Canada. Since we are in the process of selling our Canadian business, it is
reported in discontinued operations. Summarized benefit plan information for Canada can be found in Note 6. Benefits under the U.S. 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 net periodic post-retirement benefit costs to the extent that they are tax-deductible. For measurement purposes, projected benefit obligations and the fair value of
plan assets were determined as of September 30, 2003 and 2002.

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Effective
September 30, 2003, we changed our actuarial assumptions for the average expected rate of return on plan assets from 9.50% to 8.50% 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 6.75% to 6.00% to reflect a decrease in rates of return on high-quality, fixed-income investments currently available and expected to be available
during the period to maturity of the pension benefits.

On
December 8, 2003, legislation took effect that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate
that the benefits we pay after 2006 will be lower as a result of the new Medicare provisions; however, the retiree medical obligations and costs reported do not reflect the impact of this legislation.
FASB Staff Position 106-1 permits deferring the recognition of the new Medicare provisions' impact due to open questions about some of the new Medicare provisions and a lack of
authoritative guidance about certain matters. The final accounting guidance could require changes to previously reported information.

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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                    |  | $                | 301.7 |                                | $
|Service cost                                           |  |                  | 8.0   |                                |  
|Interest cost                                          |  |                  | 19.2  |                                |  
|Plan participants' contribution                        |  |                  |      |                                |  
|Prior service costs                                    |  |                  |      |                                |  
|Actuarial (gain) loss                                  |  |                  | 17.7  |                                |  
|Curtailment loss                                       |  |                  |      |                                |  
|Benefits paid                                          |  |                  | (16.2 | )                              |  
|                                                       | 
|Projected benefit obligation at end of year            |  | $                | 330.4 |                                | $
|                                                       | 
|Change in Plan Assets:                                 |  |                  |       |                                |  
|Fair value of plan assets at start of year             |  | $                | 248.4 |                                | $
|Actual return on plan assets                           |  |                  | 52.4  |                                |  
|Employer contribution                                  |  |                  | 3.8   |                                |  
|Plan participants' contribution                        |  |                  |      |                                |  
|Benefits paid                                          |  |                  | (16.2 | )                              |  
|                                                       | 
|Fair value of plan assets at end of year               |  | $                | 288.4 |                                | $
|                                                       | 
|Funded status:                                         |  |                  |       |                                |  
|Funded status                                          |  | $                | (42.0 | )                              | $
|Unrecognized transition amount                         |  |                  | (2.6  | )                              |  
|Unrecognized net actuarial loss                        |  |                  | 119.4 |                                |  
|Unrecognized prior service cost                        |  |                  | 23.9  |                                |  
|                                                       | 
|Net amount recognized                                  |  | $                | 98.7  |                                | $
|                                                       | 
|Amounts Recognized in the Consolidated Balance Sheets: |  |                  |       |                                |  
|Prepaid benefit cost                                   |  | $                | 108.0 |                                | $
|Accrued benefit liability                              |  |                  | (17.2 | )                              |  
|Intangible asset                                       |  |                  | 7.9   |                                |  
|                                                       | 
|Net amount recognized                                  |  | $                | 98.7  |                                | $
|                                                       | 
|Reconciliation of Net Amount Recognized:               |  |                  |       |                                |  
|Net amount recognized at start of year                 |  | $                | 106.2 |                                | $
|Net periodic benefit cost                              |  |                  | (14.5 | )                              |  
|Curtailment (gain) loss                                |  |                  | (.3   | )                              |  
|Contributions                                          |  |                  | 3.8   |                                |  
|Expense adjustment                                     |  |                  | 3.5   |                                |  
|                                                       | 
|Net amount recognized at end of year                   |  | $                | 98.7  |                                | $
|                                                       | 
|Weighted Average Assumptions as of September 30:       |  |                  |       |                                |  
|Discount rate for expense                              |  |                  | 6.75  | %                              |  
|Discount rate for disclosure                           |  |                  | 6.00  | %                              |  
|Expected return on plan assets for expense             |  |                  | 9.50  | %                              |  
|Rate of compensation increase                          |  |                  | 4.15  | %                              |  
|                                                       | 

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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 10% in 2004 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                             |  | $                | 8.0   |                                | $
|Interest cost                            |  |                  | 19.2  |                                |  
|Expected return on plan assets           |  |                  | (22.9 | )                              |  
|Amortization of transition amount        |  |                  | (1.2  | )                              |  
|Amortization of prior service cost       |  |                  | 1.1   |                                |  
|Recognized net actuarial (gain) loss     |  |                  | 10.3  |                                |  
|Curtailment (gain) loss                  |  |                  | .3    |                                |  
|Regulatory adjustment                    |  |                  | (3.5  | )                              |  
|                                         | 
|Net Periodic Benefit Cost                |  | $                | 11.3  |                                | $
|                                         | 

The non-qualified Supplemental Executive Retirement Plan (SERP) was amended in 2001 to include certain participants' annual incentive compensation in the
calculation of plan benefits.

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 plans are summarized below:

|In millions                                               |  | 2003 |       | 2002 |  
|--------------------------------------------------------- |  | ---- | ----- | ---- | -
|
|Projected Benefit Obligations in Excess of Plan Assets:   |  |      |       |      |  
|Fair value of plan assets at end of year                  |  | $    | 288.4 |      | $
|Projected benefit obligation at end of year               |  |      | 330.4 |      |  
|                                                          | 
|Funded status                                             |  | $    | (42.0 | )    | $
|                                                          | 
|Accumulated Benefit Obligations in Excess of Plan Assets: |  |      |       |      |  
|Fair value of plan assets at end of year                  |  | $    |      |      | $
|Accumulated benefit obligation at end of year             |  |      | 17.2  |      |  
|                                                          | 
|Funded status(a)                                          |  | $    | (17.2 | )    | $
|                                                          | 



The accumulated benefit obligation for all our U.S. defined benefit pension plans was $300.4 million and $261.7 million at September 30,
2003, and 2002, respectively.

We
engaged benefit plan consultants to assist in the development of a statement of pension plan investment objectives and to perform a study modeling expectations of future returns of
numerous portfolios using historic rates of return. The rate of return assumption we used was a

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result
of selecting the model portfolio from the study that best fit our pension plan investment objectives.

Pension Plan Investment Objectives

Our
U.S. qualified pension plan weighted-average asset allocations at September 30, 2003, and 2002, by asset category, along with the long-term targets and target
ranges, are as follows:

|                          |       | Plan Assets at September 30 |       | Plan Asset Allocation Targets |      
|------------------------- | ----- | --------------------------- | ----- | ----------------------------- | -----
|
|
|
|Asset Category:           |       |                             |       |                               |      
|Core fixed income         |       | 14.9                        | %     | 9.7                           | %    
|High yield bonds          |       | 8.0                         |       | 5.2                           |      
|Large cap equities        |       | 31.5                        |       | 30.0                          |      
|Mid cap equities          |       | 5.8                         |       |                              |      
|Small cap equities        |       | 13.9                        |       | 15.1                          |      
|International equities    |       | 12.6                        |       | 14.3                          |      
|Emerging markets equities |       | 2.7                         |       | 2.1                           |      
|Real estate               |       | 7.6                         |       | 4.4                           |      
|Private equity            |       | 1.1                         |       | .3                            |      
|Cash                      |       | 1.9                         |       | 14.0                          |      
|Other                     |       |                            |       | 4.9                           |      
|                          |      
|                          | Total |                             | 100.0 | %                             | 100.0
|                          |      

Our U.S. other post-retirement benefit plan assets at December 31, 2003 and 2002, were 100% invested in cash and cash equivalents.

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 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

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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 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, 2003, and our estimated annual
pension cost (APC) on the income statement for 2004 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 AssumptionIncr.(decr.) |   | Impact on PBOIncr.(decr.) |       | Impact on APCIncr.(decr.) |  
|----------------------------- |  | -------------------------------- | - | ------------------------- | ----- | ------------------------- | -
|
|Discount rate                 |  | ..25                             | % | $                         | (10.9 | )                         | $
|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 2004.

|                                                        |  | 1 Percentage-Point |    
|------------------------------------------------------- |  | ------------------ | ---
|
|
|
|Effect on total of service and interest cost components |  | $                  | ..7
|Effect on post-retirement benefit obligation            |  |                    | 8.0

We expect to contribute $.8 million and $6.5 million to our U.S. defined benefit pension plans and other post-retirement benefit plans,
respectively, in 2004. No discretionary contributions are planned in 2004.

Following
are estimated future benefit payments, which reflect expected future service, as appropriate:

|In millions                        |  | Pension Benefits |       | Other Post-retirement Benefits
|---------------------------------- |  | ---------------- | ----- | ------------------------------
|
|Estimated Future Benefit Payments: |  |                  |       |                               
|2004                               |  | $                | 14.8  |                               
|2005                               |  |                  | 14.9  |                               
|2006                               |  |                  | 15.2  |                               
|2007                               |  |                  | 15.7  |                               
|2008                               |  |                  | 16.7  |                               
|2009-2013                          |  |                  | 108.8 |                               
|                                  

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Note 20: 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.

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 (EBIT):*                    |                           |                         |       
|Global Networks Group                                         |                           |                         |       
|                                                               | Domestic Networks         |                         | $     
|                                                               | International Networks ** |                         |       
|                                                               |                          
|Total Global Networks Group                                    |                           |                         | 181.1 
|                                                               |                          
|Merchant Services**                                           |                           |                         |       
|                                                               | Capacity Services         |                         |       
|                                                               | Wholesale Services        |                         |       
|                                                               | Minority interest         |                         |       
|                                                               |                          
|Total Merchant Services                                        |                           |                         | (406.7
|Corporate and other                                            |                           |                         | 6.4   
|                                                               |                          
|Total EBIT                                                     |                           |                         | (219.2
|Interest expense                                               |                           |                         | 273.1 
|                                                               |                          
|Earnings (loss) from continuing operations before income taxes |                           | $                       | (492.3
|                                                               |                          



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|                                        |                        | Year Ended December 31, |      
|--------------------------------------- | ---------------------- | ----------------------- | -----
|
|
|
|Depreciation and Amortization Expense:* |                        |                         |      
|Global Networks Group                  |                        |                         |      
|                                        | Domestic Networks      |                         | $    
|                                        | International Networks |                         |      
|                                        |                       
|Total Global Networks Group             |                        |                         | 134.2
|                                        |                       
|Merchant Services                      |                        |                         |      
|                                        | Capacity Services      |                         |      
|                                        | Wholesale Services     |                         |      
|                                        |                       
|Total Merchant Services                 |                        |                         | 31.8 
|Corporate and other                     |                        |                         | (1.3 
|                                        |                       
|                                        | 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                   |                        
|                           



Geographical Information

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



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Note 21: Commitments and Contingencies

Commitments

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

|In millions                                      |                             | 2004 |      | 2005  |   | 2006 |      | 2007 |      | 2008 |   | Thereafter |      | Total
|------------------------------------------------ | --------------------------- | ---- | ---- | ----- | - | ---- | ---- | ---- | ---- | ---- | - | ---------- | ---- | -----
|
|Future minimum paymentsfacilities and equipment |                             | $    | 27.4 |       | $ | 20.1 |      | $    | 14.7 |      | $ | 13.4       |      | $    
|Merchant tolling obligations                     |                             |      | 57.7 |       |   | 68.9 |      |      | 76.7 |      |   | 76.7       |      |      
|Merchant gas transportation obligations          |                             |      | 8.8  |       |   | 8.8  |      |      | 8.3  |      |   | 5.8        |      |      
|Regulated business purchase obligations:         |                             |      |      |       |   |      |      |      |      |      |   |            |      |      
|                                                 | Purchased power obligations |      |      | 102.0 |   |      | 78.8 |      |      | 62.7 |   |            | 66.3 |      
|                                                 | Purchased gas obligations   |      |      | 95.8  |   |      | 88.6 |      |      | 77.9 |   |            | 65.3 |      
|                                                 | Coal contracts              |      |      | 73.8  |   |      | 72.2 |      |      | 72.1 |   |            | 52.3 |      
|                                                

Future minimum payments

Future minimum 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 2003, 2002 and 2001 was (in millions), $22.4, $25.4 and $22.5, respectively.

Merchant tolling 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 domestic electric utility operations generate 60% of the power delivered to their customers. Our domestic utility operations purchase coal and natural gas as
fuel for its generating power plants under long-term contracts. These operations also purchase power and gas to meet customer needs under short-term and long-term
purchase contracts.

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Contingent Obligations

Merchant Loan Portfolio

In connection with our former portfolio of merchant loans to energy-related businesses, we 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 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. As of December 31, 2003 we have collected $27.3 million related to these swaps, of which we have reserved $10.5 million to cover this obligation. The value
of the unsettled portion of these swaps was $26.5 million at December 31, 2003.

Guarantees

We have 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.

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, 2003, we had $83.2 million of letters of credit outstanding with expiration dates ranging from one month to 12 months.

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.

We
have guaranteed the performance of certain gas aggregators in connection with loans that were made by our 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. We have terminated all of these agreements as of
December 31, 2003. Our exposure is limited to the outstanding payable balances of the aggregators as of the termination dates of these agreements. Our guarantees for these agreements at
December 31, 2003 totaled $9.2 million.

Equity Put Rights

Certain shareholders of Everest Connections have the option to sell their share interests to us if Everest Connections does not meet certain financial and
operational performance measures (target-based put rights) as of December 31, 2004. If the target-based put rights were exercised, we would be obligated to purchase up to 4.0 million and
4.75 million share 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 probability-weighted expense of $7.1 million. As of December 31, 2003, we have reserved $7.8 million
for this obligation. Such shareholders also have the option to sell their share interests to us at fair market value (market-based put rights) if they have not exercised their target-based put rights.
The market-based put rights expire on December 31, 2005 for 9.5 million shares and do not expire for the remaining 3.25 million shares. We have not provided for this potential
obligation as the exercise would represent an equity transaction at fair value.

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Legal

On February 19, 2002, we filed a suit which is currently pending in the U.S. District Court for the Western District of Missouri 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
$513.0 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 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 federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange
offer completed in January 2002. The suit raised 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. On December 9, 2003, the court denied our motion to dismiss this lawsuit. Persons holding certificates formerly representing
approximately 1.7 million shares of Aquila Merchant common stock are also pursuing their appraisal rights in connection with the recombination. The dissenters' rights action is scheduled
for trial in May 2004. We do not believe that either of these actions will have an outcome materially adverse to us.

On
August 18, 2003, EPCOR filed a lawsuit against Aquila, Inc., Aquila Networks Canada Limited, and Aquila Networks Canada (Alberta) Ltd. in the Court of Queen's Bench of
Alberta. EPCOR alleges Aquila breached its agreements with EPCOR in which our Alberta utility is to provide EPCOR customer and billing information in connection with EPCOR's provision of retail
service to southern and central Alberta customers. EPCOR claims C$77 million for breach of the agreements and for negligence, including damage to its reputation, and C$6 million in
aggravated and punitive damages. In response to preliminary motions, EPCOR has provided particulars of its claims and we filed a Statement of Defense in late February 2004. This litigation will
be assumed by the purchaser of our Canadian operations upon the closing of the sale transaction and an affiliate of the purchaser has agreed to indemnify us against any damages or liabilities arising
from this litigation after completion of the sale.

In
August and November 2003, two class action lawsuits brought on behalf of entities that bought and sold natural gas futures and options contracts on the New York Mercantile
Exchange during the years 2000 through 2002 were filed in the U.S. District Court for the Southern District of New York against numerous defendants, including the company's subsidiary, Aquila
Merchant, seeking damages for alleged violations of the Commodity Exchange Act and for allegedly aiding and abetting such violations. Plaintiffs claim that, during the referenced time period, the
defendants reported false and misleading trading information, including inflated volume and price information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek
class action certification, actual damages in unspecified amounts, costs, attorneys' fees and other appropriate relief.

147

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We
are 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.

The
EPA proposed two regulations in December 2003 that would affect our coal-fired power plants by requiring reductions in emissions of sulfur dioxide, nitrogen oxide
and mercury. The rules are in proposed form only and are subject to change. If adopted as proposed, we estimate that we could be required to make capital expenditures of $40 million to
$150 million to comply with the regulations. These expenditures would be incurred, at the earliest, in the 2007-2009 time frame. These costs would likely be recoverable in rate
cases.

Other Matters

In January 2004, Aquila Merchant and the Commodity Futures Trading Commission (CFTC) trial staff reached a settlement regarding reporting of natural gas
trading information to publications that compile and report index prices. The period of data reporting covered by the settlement was from at least January 1999 through May 2002. In
January 2004, the CFTC filed and simultaneously approved an order settling an administrative action against Aquila Merchant. The CFTC order states several of Aquila Merchant's trading desks
knowingly submitted reports containing non-existent trades, as well as certain actual trades in which the price and/or volume was altered. Aquila Merchant agreed to pay a civil penalty of
$26.5 million without admitting or denying the commission's findings.

On
April 30, 2003 the FERC issued an order requiring Aquila Merchant and 10 other companies to make written demonstrations regarding index price reporting practices. The order
required Aquila Merchant to state the disciplinary actions taken, identify its code of conduct for price submissions, show that its submission practices lack financial conflicts of interest, and show
that it is cooperating with related government investigations. The FERC announced on July 23, 2003 that it "accepted" Aquila Merchant's account of internal remedies for reporting natural gas
trading data and stated that Aquila Merchant met the order's requirements.

On
June 25, 2003, the FERC issued two orders to show cause concerning Enron-type gaming behavior in the western power markets during the region's 2000-2001
energy crisis. The FERC order encouraged parties to consider settlement of these issues through discussions with the FERC trial staff and on August 29, 2003, FERC trial staff and Aquila
Merchant entered into an agreement in which we agreed to pay $76,000 to bring full and final resolution of all issues related to Aquila Merchant in the orders to show cause. The agreement was approved
by the FERC in March 2004.

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Note 22: 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.

|                                             |                                           | 2003 Quarters |       | 2002 Quarters |  
|-------------------------------------------- | ----------------------------------------- | ------------- | ----- | ------------- | -
|
|
|
|Sales                                        |                                           | $             | 522.8 |               | $
|Gross profit                                 |                                           |               | 109.6 |               |  
|Earnings (loss) from continuing operations   |                                           |               | (64.4 | )             |  
|Earnings (loss) from discontinued operations |                                           |               | 12.5  |               |  
|Cumulative effect of change in accounting    |                                           |               |      |               |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | (51.9         | )
|                                             |                                          
|Basic earnings per common share:(a)          |                                           |               |       |               |  
|                                             | From continuing operations                |               | $     | (.33          | )
|                                             | From discontinued operations              |               |       | .06           |  
|                                             | Cumulative effect of change in accounting |               |       |              |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | (.27          | )
|                                             |                                          
|Diluted earnings per common share:(a)        |                                           |               |       |               |  
|                                             | From continuing operations                |               | $     | (.33          | )
|                                             | From discontinued operations              |               |       | .06           |  
|                                             | Cumulative effect of change in accounting |               |       |              |  
|                                             |                                          
|                                             | Net income (loss)                         |               | $     | (.27          | )
|                                             |                                          



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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, 2003 and 2002 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, 2003. 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, 2003. 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% owned investee company at December 31, 2001. 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 million for the year ended December 31, 2001. The financial statements of Quanta Services, Inc. for the year
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, 2003 and 2002 and the consolidated results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2003 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 2, the company changed its method of accounting for asset retirement obligations.

/s/
KPMG, LLP
Kansas City, Missouri

March 9,
2004

150

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

Not
Applicable.

Item 9a. 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
as of the end of the period covered by this report 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 reports filed with the Securities and Exchange Commission. There has been no change in our internal
controls over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 Part 1, Item 1 of this Form 10-K.

151

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Equity Compensation Plan Information

The following table provides information as of December 31, 2003 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     |       | 8,034,243                                                                                       | (a)       | $                                                                               | 19.98 |                                                                                                                                                | 6,834,445
|Equity compensation plans
not approved by security
holders |       | 377,555                                                                                         | (c)       | $                                                                               | 24.02 |                                                                                                                                                |         
|                                                           |      
|                                                           | Total |                                                                                                 | 8,411,798 |                                                                                 |       |                                                                                                                                                |          
|                                                           |      



Item 14. Principal Accountant Fees and Services

Information
regarding this item appears in our proxy statement and is hereby incorporated by reference in this Annual Report on Form 10-K.

152

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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 2003, 2002 and 2001 on page 155.

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

(a)(3) List of Exhibits*

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

|10(a)(4)  |  | Annual and Long-Term Incentive Plan.                                                                                                                                             
|--------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10(a)(5)  |  | First Amendment to Annual and Long-Term Incentive Plan.                                                                                                                          
|10(a)(6)  |  | Form of Severance Compensation Agreement (change in control agreement) of Certain Executives.                                                                                    
|10(a)(7)  |  | Life Insurance Program for Officers.                                                                                                                                             
|10(a)(8)  |  | Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001.                                                                                         
|10(a)(9)  |  | Employment Agreement for Richard C. Green                                                                                                                                        
|10(a)(10) |  | Employment Agreement for Robert K. Green.                                                                                                                                        
|10(a)(11) |  | Amended and Restated Capital Accumulation Plan.                                                                                                                                  
|10(a)(12) |  | First Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                                           
|10(a)(13) |  | Severance Compensation Agreement (change in control agreement) dated as of March 16, 2001, by and between Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and Keith Stamm.
|10(a)(14) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan.                                                                                                                           
|10(a)(15) |  | Second Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                                          
|10(a)(16) |  | UtiliCorp United Inc. Executive Security Trust Amended and Restated as of April 4, 2002.                                                                                         
|10(a)(17) |  | Agreement dated October 1, 2002 by and between the company and Robert K. Green.                                                                                                  
|10(a)(18) |  | Retention Agreement dated as of July 1, 2002 by and between Aquila Merchant Services, Inc. and Edward K. Mills.                                                                  
|10(a)(19) |  | Retention Agreement dated as of August 13, 2002 by and between the company and Leslie J. Parrette, Jr.                                                                           
|          |  |                                                                                                                                                                                  

153

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|10(a)(20) |  | Severance Payment Agreement Release and Waiver of Claims dated October 17, 2002 by and between the company and Dan J. Streek.           
|--------- |  | ----------------------------------------------------------------------------------------------------------------------------------------
|10(a)(21) |  | Severance Payment Agreement Release and Waiver of Claims dated October 11, 2002 by and between the company and Edward K. Mills.         
|10(a)(22) |  | Severance Payment Agreement Release and Waiver of Claims dated as of July 10, 2003 by and between the company and Cadwallader Payne, Jr.



(b) Reports on Form 8-K

Reports on Form 8-K for the quarter ended December 31, 2003, were as follows:

A
Current Report on Form 8-K with respect to Item 7 and 12, dated November 6, 2003, was filed with the Securities and Exchange Commission by the
Registrant.

(c) Exhibits

The Index to Exhibits follows on page 156.

154

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AQUILA, INC.  SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2003
(in millions)

|Column A                         |      | Column B |   | Column C |  | Column D |      | Column E
|-------------------------------- | ---- | -------- | - | -------- |  | -------- | ---- | --------
|
|
|                                
|                                 |      |          |   |          |  |          |      |         
|Allowance for Doubtful Accounts |      |          |   |          |  |          |      |         
|                                 | 2003 |          | $ | 28.3     |  | $        | 18.3 |         
|                                 | 2002 |          |   | 58.8     |  |          | 13.5 |         
|                                 | 2001 |          |   | 44.9     |  |          | 80.4 |         
|Maintenance Reserves(a)         |      |          |   |          |  |          |      |         
|                                 | 2003 |          | $ | 3.1      |  | $        | 2.8  |         
|                                 | 2002 |          |   | 3.2      |  |          | 2.6  |         
|                                 | 2001 |          |   | 13.5     |  |          | .7   |         
|Other Reserves(b)               |      |          |   |          |  |          |      |         
|                                 | 2003 |          | $ | 18.5     |  | $        | 45.1 |         
|                                 | 2002 |          |   | 17.6     |  |          | 37.5 |         
|                                 | 2001 |          |   | 21.7     |  |          | 30.3 |         
|Restructuring Reserves(c)       |      |          |   |          |  |          |      |         
|                                 | 2003 |          | $ | 49.2     |  | $        | 28.2 |         
|                                 | 2002 |          |   |         |  |          | 96.0 |         
|                                



155

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AQUILA, INC.  INDEX TO EXHIBITS

|Exhibit Number |  | Description                                                                                                                                                                                                                           
|-------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|               |  |                                                                                                                                                                                                                                       
|*3(a)          |  | 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% 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. (Exhibit 10(a)(1) to the company's Annual Report on Form 10-K for the year ended
December 31, 2002.)                
|*10(a)(2)      |  | First Supplemental Indenture to the Indenture of Mortgage and Deed of Trust. (Exhibit 10(a)(2) to the company's Annual Report on Form 10-K for the year ended December 31, 2002.)                                                     
|*10(a)(3)      |  | $430 million Credit Agreement among the company, the lenders and Credit Suisse First Boston dated April 9, 2003. (Exhibit 10(a)(3) to the company's Annual Report on Form 10-K for the year ended
December 31, 2002.)                 
|*10(a)(4)      |  | 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)(5)      |  | 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)(6)      |  | Form of Severance Compensation Agreement (change in control 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)(7)      |  | 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)(8)      |  | 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)(9)      |  | Employment Agreement for Richard C. Green (Exhibit 10.1 to the company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.)                                                                                     
|*10(a)(10)     |  | 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.)                                                                                          
|*10(a)(11)     |  | 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)(12)     |  | 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.)                                                         
|               |  |                                                                                                                                                                                                                                       

156

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|*10(a)(13) |  | Severance Compensation Agreement (change in control 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)(14) |  | 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)(15) |  | 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)(16) |  | 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)(17) |  | 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)(18) |  | 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)(19) |  | Retention Agreement dated as of August 13, 2002 by and between the company and Leslie J. Parrette, Jr. (Exhibit 10(a)(26) to the company's Annual Report on Form 10-K for the year ended December 31,
2002.)                                                                                                            
|*10(a)(20) |  | Severance Payment Agreement Release and Waiver of Claims dated October 17, 2002 by and between the company and Dan J. Streek. (Exhibit 10(a)(27) to the company's Annual Report on Form 10-K for the year
ended December 31, 2002.)                                                                                     
|*10(a)(21) |  | Severance Payment Agreement Release and Waiver of Claims dated October 11, 2002 by and between the company and Edward K. Mills. (Exhibit 10(a)(28) to the company's Annual Report on Form 10-K for the
year ended December 31, 2002.)                                                                                   
|*10(a)(22) |  | Severance Payment Agreement Release and Waiver of Claims dated as of July 10, 2003 by and between the company and Cadwallader Payne, Jr. (Exhibit 10.1 to the company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2003.)                                                                             
|21         |  | Subsidiaries of the company.                                                                                                                                                                                                                                                                                            
|23         |  | Consent of KPMG, LLP.                                                                                                                                                                                                                                                                                                   
|31.1       |  | Certification of Chief Executive Officer under Section 302.                                                                                                                                                                                                                                                             
|31.2       |  | Certification of Chief Financial Officer under Section 302.                                                                                                                                                                                                                                                             
|32.1       |  | Certification of Chief Executive Officer under Section 906.                                                                                                                                                                                                                                                             
|32.2       |  | Certification of Chief Financial Officer under Section 906.                                                                                                                                                                                                                                                             
|99.1       |  | Order of the State Corporation Commission of the State of Kansas on Docket No. 02-UTCG-701-GIG, dated May 7, 2003.                                                                                                                                                                                                      
|99.2       |  | Order of the State Corporation Commission of the State of Kansas on Docket No. 02-UTCG-701-GIG, dated June 26, 2003.                                                                                                                                                                                                    
|99.3       |  | Report of Arthur Andersen LLP on the financial statements of Quanta Services, Inc.                                                                                                                                                                                                                                      



157

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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 March 9, 2004.

| |  | 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 March 9, 2004.

|By: |  | /s/ Richard C. GreenRichard C. Green                 |  | President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer)
|--- |  | ---------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------
|By: |  | /s/ Rick J. DobsonRick J. Dobson                     |  | Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)         
|By: |  | /s/ John R. BakerJohn R. Baker                       |  | Director                                                                                               
|By: |  | /s/ Herman CainHerman Cain                           |  | Director                                                                                               
|By: |  | /s/ Dr. Michael M. CrowDr. Michael M. Crow           |  | 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                                                                                               

158

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