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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 1934For the fiscal year ended December 31, 2004
oro

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 registeredCommon Stock, par value $1.00 per share
7.875% Quarterly Interest Bonds,
due March 1, 2032
Premium Income Equity Securities, due September 15, 2007

New York Stock Exchange
New York Stock Exchange
New York Stock Exchange


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

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

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

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

The aggregate market value of the voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on
June 30, 2004 as reported on the New York Stock Exchange, was approximately $654,409,600. 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 7, 2005Common Stock, par value $1.00 per share

241,771,033Documents Incorporated by Reference:
Proxy Statement for 2005
Annual Shareholders Meeting

Where Incorporated:
Part 3


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INDEX

|                  |         |     |                                                                                                              | Page
|----------------- | ------- | --- | ------------------------------------------------------------------------------------------------------------ | ----
|Part I            |         |     |                                                                                                              |     
|                  | Item 1  |     | Business                                                                                                     |     
|                  | Item 2  |     | Properties                                                                                                   |     
|                  | Item 3  |     | Legal Proceedings                                                                                            |     
|                  | Item 4  |     | Submission of Matters to a Vote of Security Holders                                                          |     
|Part II           |         |     |                                                                                                              |     
|                  | Item 5  |     | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |     
|                  | 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                                                                                      |     
|                  | Item 9B |     | Other Information                                                                                            |     
|Part III          |         |     |                                                                                                              |     
|                  | Item 10 |     | Directors and Executive Officers of the Company                                                              |     
|                  | Item 11 |     | Executive Compensation                                                                                       |     
|                  | Item 12 |     | Security Ownership of Certain Beneficial Owners and Management                                               |     
|                  | Item 13 |     | Certain Relationships and Related Transactions                                                               |     
|                  | Item 14 |     | Principal Accountant Fees and Services                                                                       |     
|Part IV           |         |     |                                                                                                              |     
|                  | Item 15 |     | Exhibits, Financial Statement Schedules                                                                      |     
|Index to Exhibits |         | 152
|Signatures        |         | 154

2

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Glossary of Terms and Abbreviations

APBAccounting
Principles Board.

Aquila
MerchantAquila Merchant Services, Inc., our merchant energy subsidiary.

BtuBritish
Thermal Unit, which is a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

CERCLA
(Superfund)Comprehensive Environmental Response Compensation Liability Act of 1980, which is federal environmental legislation that addresses remediation of contaminated sites.

CFTCCommodity
Futures Trading Commission.

CO2Carbon
Dioxide.

Cooling
Degree-DaysThe summation of positive differences between the mean daily temperatures and the 65o Fahrenheit base. This statistic is useful as an
indicator of demand for electricity for summer space cooling for residential and commercial customers.

EITFEmerging
Issues Task Force, an organization that is designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial
issues within the framework of existing authoritative literature.

Energy
ActEnergy Policy Act of 1992.

EPAEnvironmental
Protection Agency, a governmental agency of the United States of America.

ERISAEmployee
Retirement Income Security Act of 1974, as amended.

EWGExempt
Wholesale Generator, an independent power project certified by the FERC.

Exchange
ActSecurities Exchange Act of 1934, as amended.

FASBFinancial
Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States of America.

FERCFederal
Energy Regulatory Commission, a governmental agency of the United States of America that, among other things, regulates interstate transmission and wholesale sales of
electricity and gas and related matters.

FINFASB
Interpretation intended to clarify accounting pronouncements previously issued by the FASB.

FitchFitch
Ratings, a leading global rating agency.

FPAFederal
Power Act.

GAAPGenerally
Accepted Accounting Principles in the United States of America.

3

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GWhGigawatt-hour.

Heat
RateThe measure of efficiency of converting fuel to electricity, expressed as British thermal units (Btu) of fuel per kilowatt-hour. The lower the heat rate, the more
efficient the plant.

Heating
Degree-DaysThe summation of negative differences between the mean daily temperature and the 65o Fahrenheit base. This statistic is useful as an indicator
of demand for electricity and natural gas for winter space heating for residential and commercial customers.

kWhKilowatt-hour.

LIBORLondon
Inter-Bank Offering Rate.

McfOne
thousand cubic feet.

MGPManufactured
Gas Plant.

MMBtuOne
million Btu's.

MMcfOne
million cubic feet.

Moody'sMoody's
Investors Service, Inc., a leading global rating agency.

MWMegawatt,
one thousand Kilowatts.

MwhMegawatt-hour.

NOxNitrogen
oxide.

NSRNew
Source Review programs under the federal Clean Air Act.

NYMEXNew
York Mercantile Exchange.

NYSENew
York Stock Exchange.

NYSEGNew
York State Electric and Gas Corp.

OCIOther
Comprehensive Income (Loss) as defined by GAAP.

PGAPurchased
Gas Adjustment tariffs, which impact our natural gas utility customers.

PIESPremium
Income Equity Securities, our series of 6.75% mandatorily convertible senior notes.

PUHCAPublic
Utility Holding Company Act of 1935, as amended.

RTORegional
Transmission Organization.

S&PStandard
and Poor's, a division of The McGraw-Hill Companies, Inc., a leading global rating agency.

SECSecurities
and Exchange Commission, a governmental agency of the United States of America.

SFASStatement
of Financial Accounting Standards, the accounting and financial reporting rules issued by FASB.

SO2Sulfur
dioxide.

4

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Part I

Item 1.    Business

History and Organization

Aquila, Inc. (Aquila or the company, which may be referred to as "we," "us" or "our") is primarily an integrated electric and natural gas utility
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. As of December 31, 2004, we had 3,192 employees in the United States. Our business is organized into two groups: Domestic Utilities, which comprises our regulated
utility operations, and Merchant Services, which comprises our unregulated energy activities. All other operations are included in Corporate and Other, including costs that are not allocated to our
operating businesses; our controlling investment in a broadband company operating in Kansas City, Everest Connections; and our former investments in Australia, New Zealand and the United Kingdom.
Substantially all of our revenues are generated by the Domestic Utilities group.

Our
electric utilities include 2,075 MW of generation and 20,888 pole miles of electric transmission and distribution lines. Our gas utilities include 721 miles of intrastate gas
transmission pipelines and 19,356 miles of gas distribution mains and service lines. The Domestic Utilities group generated revenues of $1.8 billion in the year ended December 31, 2004
and had total assets of $3.2 billion at December 31, 2004.

Until
recently, our operations also included significant international utility investments and Merchant Services was a much larger component of our business. In 2002, we began to
reposition our business to concentrate on our Domestic Utilities and reduce our financial obligations. As part of that repositioning, we sold all of our international investments and a substantial
portion of our Merchant Services assets. Additionally, we wound down most of our Merchant Services energy trading portfolio. Our remaining Merchant Services group principally owns, operates, and
contractually controls non-regulated power generation assets in the United States. See Management's Discussion and Analysis for further discussion of our strategic and financial
repositioning.

Access to Company Information and Officer Certifications

The reports we file with the SEC are available free of charge at our websitewww.aquila.comas soon as reasonably
practicable after they are filed. In addition, the charters of our Audit, Nominating and Corporate Governance, and Compensation and Benefits Committees are located on our website along with our Code
of Business Conduct, Code of Ethics for Senior Financial Officers and Corporate Governance Principles. The information contained on our website is not part of this document.

Our
Chief Executive Officer and Chief Financial Officer have filed with the SEC, as exhibits to our annual report on Form 10-K, the certifications required by Section 302
of the Sarbanes Oxley Act regarding the quality of our public disclosure. Our Chief Executive Officer certified to the NYSE following our 2004 annual shareholder meeting that he was not aware of
violations by us of the NYSE corporate governance listing standards.

Each
of the foregoing documents is available in print to any of our shareholders upon request by writing to Aquila, Inc., 20 West Ninth Street, Kansas City,
Missouri 64105: Attention: Investor Relations.

5

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Business Group Summary

Segment information for the three years ended December 31, 2004 is included in Note 20 to the Consolidated Financial Statements.

I.    Domestic Utilities

Domestic Utilities generates, transmits and distributes electricity to approximately 452,646 customers in Colorado, Kansas and Missouri. Our electric generating
facilities and purchase power contracts supply electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies. Approximately 65%
of our electric customers are located in Missouri. Domestic Utilities also distributes natural gas to approximately 910,116 customers in Colorado, Iowa, Kansas, Michigan, Minnesota, Missouri and
Nebraska. Approximately 46% of our utility operations, based on the book value of our regulated assets, are located in Missouri.

Electric Generating Facilities

As of December 31, 2004, our owned or leased interests in electric generation plants were as follows:

|Unit      |                      | Location |               | Year Installed |                  | Unit Capability
(MW) |     | Fuel 
|--------- | -------------------- | -------- | ------------- | -------------- | ---------------- | -------------------- | --- | -----
|         
|          |                      |          |               |                |                  |                      |     |      
|Missouri: |                      |          |               |                |                  |                      |     |      
|          | Sibley #1-3          |          | Sibley        |                | 1960, 1962, 1969 |                      | 502 |      
|          | Ralph Green #3       |          | Pleasant Hill |                | 1981             |                      | 69  |      
|          | Nevada               |          | Nevada        |                | 1974             |                      | 20  |      
|          | Greenwood #1-4       |          | Greenwood     |                | 1975-1979        |                      | 241 |      
|          | KCI #1-2             |          | Kansas City   |                | 1970             |                      | 31  |      
|          | Lake Road #1, 3      |          | St. Joseph    |                | 1951, 1962       |                      | 30  |      
|          | Lake Road #2, 4      |          | St. Joseph    |                | 1957, 1967       |                      | 122 |      
|          | Lake Road #5         |          | St. Joseph    |                | 1974             |                      | 62  |      
|          | Lake Road #6-7       |          | St. Joseph    |                | 1989, 1990       |                      | 40  |      
|          | Iatan                |          | Iatan         |                | 1980             |                      | 121 |      
|Kansas:   |                      |          |               |                |                  |                      |     |      
|          | Judson Large #4      |          | Dodge City    |                | 1969             |                      | 142 |      
|          | Arthur Mullergren #3 |          | Great Bend    |                | 1963             |                      | 96  |      
|          | Cimarron River #1-2  |          | Liberal       |                | 1963, 1967       |                      | 72  |      
|          | Clifton #1-2         |          | Clifton       |                | 1974             |                      | 71  |      
|          | Jeffrey #1-3         |          | St. Mary's    |                | 1978, 1980, 1983 |                      | 354 |      
|Colorado: |                      |          |               |                |                  |                      |     |      
|          | W.N. Clark #1-2      |          | Canon City    |                | 1955, 1959       |                      | 43  |      
|          | Pueblo #6            |          | Pueblo        |                | 1949             |                      | 20  |      
|          | Pueblo #5            |          | Pueblo        |                | 1941, 2001       |                      | 9   |      
|          | AIP Diesel           |          | Pueblo        |                | 2001             |                      | 10  |      
|          | Diesel #1-5          |          | Pueblo        |                | 1964             |                      | 10  |      
|          | Diesel #1-5          |          | Rocky Ford    |                | 1964             |                      | 10  |      
|         
|          |                      | Total    |               |                |                  |                      |     | 2,075
|         

6

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We
are constructing a 315-megawatt, natural gas-fired, combustion turbine generation plant near Peculiar, Missouri. We expect to complete this facility during the
summer of 2005.

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

|Fuel SourceIn Megawatts (MW) |                             | 2004  |       | 2003  |       | 2002 
|----------------------------- | --------------------------- | ----- | ----- | ----- | ----- | -----
|                             
|                              |                             |       |       |       |       |      
|Coal                          |                             | 1,020 |       | 1,020 |       | 1,020
|Gas                           |                             | 439   |       | 439   |       | 444  
|Oil                           |                             | 90    |       | 90    |       | 92   
|Coal and gas                  |                             | 122   |       | 122   |       | 122  
|Gas and oil                   |                             | 404   |       | 404   |       | 414  
|                             
|                              | Total generation capability |       | 2,075 |       | 2,075 |      
|                             

At
December 31, 2004, Domestic Utilities had 4,650 miles of electric transmission lines and 16,238 miles of electric distribution lines, 721 miles of intrastate gas transmission
pipelines and 19,356 miles of gas distribution mains and service lines.

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

|                                      |             | 2004 |        | 2003  |   | 2002   |      
|------------------------------------- | ----------- | ---- | ------ | ----- | - | ------ | -----
|                                      |            
|                                      |             |      |        |       |   |        |      
|Sales (in millions)                   |             |      |        |       |   |        |      
|                                      | Residential |      | $      | 305.3 |   | $      | 292.2
|                                      | Commercial  |      |        | 218.4 |   |        | 200.9
|                                      | Industrial  |      |        | 124.1 |   |        | 113.2
|                                      | Other       |      |        | 111.5 |   |        | 91.2 
|                                      |            
|Total                                 |             | $    | 759.3  |       | $ | 697.5  |      
|                                      |            
|Volumes Generated and Purchased (GWh) |             |      |        |      
|                                      | Coal        |      |        | 6,476 |   |        | 6,880
|                                      | Gas         |      |        | 420   |   |        | 519  
|                                      | Coal/Gas    |      |        | 689   |   |        | 646  
|                                      | Gas/Oil     |      |        | 20    |   |        | 98   
|                                      |            
|Total generated                       |             |      | 7,605  |       |   | 8,143  |      
|Purchased                             |             |      | 5,739  |       |   | 4,670  |      
|                                      |            
|Total generated and purchased         |             |      | 13,344 |       |   | 12,813 |      
|Company use                           |             |      | (19    | )     |   | (16    | )    
|Line loss                             |             |      | (962   | )     |   | (964   | )    
|                                      |            
|Total                                 |             |      | 12,363 |       |   | 11,833 |      
|                                      |            
|Volumes (GWh)                         |             |      |        |       |   |        |      
|                                      | Residential |      |        | 4,063 |   |        | 4,107
|                                      | Commercial  |      |        | 3,454 |   |        | 3,391
|                                      | Industrial  |      |        | 2,605 |   |        | 2,570
|                                      | Other       |      |        | 2,241 |   |        | 1,765
|                                      |            
|Total                                 |             |      | 12,363 |       |   | 11,833 |      
|                                      |            
|                                      |             |      |        |       |   |        |      

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|Customers at Year End                                |                     |   |         |         |   |         |         |   |         |        
|---------------------------------------------------- | ------------------- | - | ------- | ------- | - | ------- | ------- | - | ------- | -------
|                                                     | Residential         |   |         | 387,365 |   |         | 381,033 |   |         | 374,697
|                                                     | Commercial          |   |         | 61,016  |   |         | 60,531  |   |         | 59,087 
|                                                     | Industrial          |   |         | 456     |   |         | 457     |   |         | 467    
|                                                     | Other               |   |         | 3,809   |   |         | 3,869   |   |         | 3,714  
|                                                     |                    
|Total                                                |                     |   | 452,646 |         |   | 445,890 |         |   | 437,965 |        
|                                                     |                    
|Average annual volume per residential customer (kWh) |                     |   | 10,582  |         |   | 10,850  |         |   | 10,952  |        
|Average annual sales per residential customer        |                     | $ | 795     |         | $ | 772     |         | $ | 741     |        
|Average residential sales per kWh (cents)            |                     |   | 7.51    |         |   | 7.12    |         |   | 6.76    |        
|Units of Fuel Used in Generation                     |                     |   |         |         |   |         |         |   |         |        
|                                                     | Coalthousand tons  |   |         | 4,367   |   |         | 4,529   |   |         | 4,287  
|                                                     | Natural gasMmcf    |   |         | 6,142   |   |         | 8,070   |   |         | 10,631 
|Average Cost of Fuel                                 |                     |   |         |         |   |         |         |   |         |        
|                                                     | Coalper ton        |   | $       | 22.96   |   | $       | 21.04   |   | $       | 20.62  
|                                                     | Natural gasper Mcf |   |         | 5.96    |   |         | 5.02    |   |         | 3.06   
|                                                     |                    

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

|                      |                | 2004 |         | 2003    |   | 2002   
|--------------------- | -------------- | ---- | ------- | ------- | - | -------
|                     
|                      |                |      |         |         |   |        
|Sales (in millions)   |                |      |         |         |   |        
|                      | Residential    |      | $       | 655.2   |   | $      
|                      | Commercial     |      |         | 284.7   |   |        
|                      | Industrial     |      |         | 48.0    |   |        
|                      | Other          |      |         | 44.1    |   |        
|                     
|Total                 |                | $    | 1,032.0 |         | $ | 969.5  
|                     
|Volumes (Mcf)         |                |      |         |         |   |        
|                      | Residential    |      |         | 68,748  |   |        
|                      | Commercial     |      |         | 33,171  |   |        
|                      | Industrial     |      |         | 6,863   |   |        
|                      | Transportation |      |         | 105,929 |   |        
|                      | Other          |      |         | 265     |   |        
|                     
|Total                 |                |      | 214,976 |         |   | 227,995
|                     
|Customers at Year End |                |      |         |         |   |        
|                      | Residential    |      |         | 817,331 |   |        
|                      | Commercial     |      |         | 82,186  |   |        
|                      | Industrial     |      |         | 2,339   |   |        
|                      | Other          |      |         | 8,260   |   |        
|                     
|Total                 |                |      | 910,116 |         |   | 900,777
|                     

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Seasonal Variations of Business

Our 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 Utilities' 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 and Rates

State Regulation

Our 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 rates 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 regulated
utilities and our other businesses. On June 26, 2003, the Kansas Commission modified that order. The May 7, 2003 and June 26, 2003 orders are filed as exhibits to our 2003 Annual
Report on Form 10-K. Among other things, the orders provide that without the approval of the Kansas Commission, we may not:



9

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The
rates that we are allowed to charge for our services are determined by state public service or utility commissions. Decisions are influenced by many factors, including the cost of
providing
service, capital expenditures, the prudence of our costs, views about appropriate rates of return, the rates of other utilities, general economic conditions and the political environment.

The
following summarizes our recent rate case activity:

|(In millions) |  | Type of Service |  | Date Requested |  | Date Approved |  | Amount Requested |      | Amount Approved
|------------- |  | --------------- |  | -------------- |  | ------------- |  | ---------------- | ---- | ---------------
|             
|              |  |                 |  |                |  |               |  |                  |      |                
|Minnesota(1)  |  | Gas             |  | 8/2000         |  | 7/2003        |  | $                | 9.8  |                
|Iowa(2)       |  | Gas             |  | 6/2002         |  | 2/2003        |  |                  | 9.3  |                
|Michigan(3)   |  | Gas             |  | 8/2002         |  | 3/2003        |  |                  | 14.3 |                
|Colorado(4)   |  | Electric        |  | 10/2002        |  | 6/2003        |  |                  | 23.4 |                
|Nebraska(5)   |  | Gas             |  | 6/2003         |  | 1/2004        |  |                  | 9.9  |                
|Missouri(6)   |  | Electric        |  | 7/2003         |  | 4/2004        |  |                  | 80.9 |                
|Missouri(7)   |  | Gas             |  | 8/2003         |  | 4/2004        |  |                  | 6.4  |                
|Colorado(8)   |  | Electric        |  | 12/2003        |  | 8/2004        |  |                  | 11.4 |                
|Kansas(9)     |  | Electric        |  | 6/2004         |  | 1/2005        |  |                  | 19.2 |                
|Kansas(10)    |  | Gas             |  | 11/2004        |  | Pending       |  |                  | 6.2  |                
|             



10

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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 PGA provisions that allow them to pass the prudently-incurred cost of gas through 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. These adjustments are subject to periodic prudence reviews by the state utility
commissions.

In
our regulated electric business in 2004, we generated approximately 57% of the power that we sold and we purchased the remaining 43% through long-term contracts or in the
open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have an Energy Cost Adjustment and an Incentive Clause Adjustment, respectively, that serve
a purpose similar to the PGAs for our gas utilities. 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 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. As
described more fully above, the Missouri Commission approved a settlement agreement in April 2004 for our electric operations that establishes our right to recover costs up to $13.98/Mwh in our
St. Joseph Light & Power operations and $19.71/Mwh in our Missouri Public Service operations for a two-year period. If our actual costs are higher than those allowed costs, then we
cannot recover the excess costs through rates. If our actual costs are less than those allowed costs, then we must refund the difference to our customers, except to the extent actual costs are below
$12.64/Mwh for our St. Joseph Light & Power operations and $16.65/Mwh for our Missouri Public Service operations. Since the rate increase went into effect pursuant to the settlement agreement,
our actual costs have exceeded the allowed costs by approximately $1.8 million through December 31, 2004.

11

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Federal Regulation

Under the FPA, our wholesale transmission and sale of electricity in interstate commerce and our generation facilities are subject to the jurisdiction of the
FERC. That 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.

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 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. 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 became effective on June 1, 2004, and we have modified our operations 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 Clean Water Act controls water discharge and intake requirements and generally prohibits the discharge of any pollutants, including heat, into any body of
surface water, except in

12

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compliance
with a discharge permit issued by a state environmental regulatory agency or the EPA.

316(b) Fish Impingement Requirements

In July 2004, the EPA issued new rules requiring power plants with cooling water intake structures to undertake studies and implement technologies to
minimize fish kills resulting from water withdrawal. We have three power plants that may be affected by these rules and are in discussion with the EPA concerning the application of this rule to those
facilities. Aquila is currently working with state and federal agencies involved with the Missouri River regulations to determine compliance options and benefits to Missouri River fish populations.

Missouri River Levels

Recent attempts have been made to address items such as drought conditions, endangered species, navigation, and recreational interests along the course of the
Missouri River through litigation and the revision of plans that manage the level of water flow. The U.S. Army Corps of Engineers has proposed changes for the management of the Missouri River that
may, in coming years, lower water levels. Reduced river levels can impact the net capacity of generating facilities along the Missouri River, which may in turn have a material impact on utility
operations in the future.

Air Emissions

Our facilities are subject to the 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, SO2, NOx and particulate matter. In addition, CO2 is also included as a potential emission that may
be regulated. Fossil-fueled power generating facilities emit each of the foregoing pollutants and, accordingly, are subject to substantial regulation and enforcement oversight by various governmental
agencies.

Clean Air Act

Title IV of the Clean Air Act (CAA) created an SO2 allowance trading program as part of the federal acid rain program. Each allowance gives the owner
the right to emit one ton of SO2. At the end of each year, each emitting unit must have enough allowances to cover its emissions for that year. Allowances may be traded so that affected
units that expect to emit more SO2 than their allowances may purchase allowances from other affected units that expect to emit less than their allocated allowances. The allowance
allocation is based on historical operating data. Our facilities emit SO2 in excess of their allocated allowances. Therefore, we must purchase additional allowances to stay in compliance.
Allowance prices have more than tripled in price during 2004 and we are continuing to evaluate the cost of purchasing allowances versus adding pollution control equipment.

Multi-pollutant regulations

Approximately 55% of our generating capacity is coal-fired. The EPA has issued proposed regulations (Interstate Air Quality Rule) with respect to
SO2, NOx and mercury emissions from coal-fired power plants. These new rules, if adopted, would require significant reductions in these emissions from our power plants in
phases, beginning as early as 2008. The rules have been

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placed
on hold while the EPA awaits the possibility of obtaining similar reductions under legislation that has been introduced in 2005. The EPA has stated that if legislation is not approved in early
2005, they will proceed with finalizing the Interstate Air Quality Rule. Multi-pollutant legislation has been introduced in the 2005 Congressional session and is currently being reviewed, but
generally requires reductions similar to the EPA proposed rules. The proposed mercury regulations contain a number of options and the final control requirements are uncertain. We anticipate additional
capital costs to comply with the mercury rules.

New Source Review

The EPA has been conducting enforcement initiatives nationwide to determine whether certain activities conducted at electric generating facilities were subject to
its NSR requirements under the CAA. The EPA is interpreting the CAA 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 and are generally responsible for this portion of its operating costs and capital expenditures. The electric
generation plants we own or lease are described in the table at Item 1, page 6. 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. Aquila would potentially be responsible for 16% of those costs.

Global Climate

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of debate. The Kyoto Protocol, which includes, among other
things, targets for limiting CO2 emissions, was signed by the United States, but then rejected by the current administration. Additional pressure for regulating CO2 emissions
may come from other countries that have ratified the protocol. Several legislative representatives have stated the desire to include carbon dioxide caps as part of multi-pollutant legislation.
Coal-fired power plants are significant sources of CO2 emissions. Therefore, any mandated federal greenhouse gas reductions or caps on CO2 emissions could have a
material impact.

Solid Waste

Various materials used at our facilities are subject to disposal regulations. Our coal facilities generate ash that is sent to a permitted landfill or is utilized
either in roofing material, road construction or as flowable fill. The useful life of the permitted landfill at our Sibley location is set to expire in 2006. Therefore, we have begun investigating
options for this waste disposal. Until an option is chosen the future cost increase cannot be determined, but is not believed to be material.

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Past Operations

Some federal and state laws authorize the EPA and other agencies to issue orders compelling 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 party at two disposal sites for 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 former MGP sites, which are subject to the supervision of the EPA and various state environmental
agencies.

As
of December 31, 2004, we estimate probable costs of future investigation and remediation on our identified MGP sites and retained liabilities to be $6.6 million. This is
our best estimate based upon a comprehensive review of the potential costs associated with conducting investigative and remedial actions at our identified sites, as well as the likelihood of whether
such actions will be necessary. There are also additional costs that we consider to be less likely but still "reasonably possible" to be incurred at these sites. Based upon the results of studies at
these sites and our knowledge and review of potential remedial actions, it is reasonably possible that these additional costs could exceed our best estimate by approximately $9.0 million. This
estimate could change materially once we have investigated further. It could also be affected by the actions of environmental agencies and the financial viability of other responsible parties.
Ultimate liability also may be affected significantly if we are held responsible for parties unable to contribute financially to the cleanup effort.

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

II.   Merchant Services

Merchant Services consists principally of our interests in gas-fired merchant power plants and our remaining wholesale energy trading business. Our
merchant power plants are exempt wholesale generators that do not have dedicated customers and are designed to operate only during periods of peak demand in the geographic area in which the plant is
located. Because we currently believe 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 for the foreseeable future we will have limited ability to generate power from these plants at a gross profit. Annual operating and maintenance costs of these plants are approximately
$9.0 million. In addition, we make annual capacity payments of approximately $37.3 million on our Elwood tolling contracts. We have sold capacity in three of these plants which will
partially offset these costs in 2005 and 2006.

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The
table below shows information about our Merchant Services power plants as of December 31, 2004:

|Plant & Location         |                     | Location    |       | Type of
Investment       |  | Capacity
(MW) |  | Heat
Rates |  | Date in
Service
|------------------------ | ------------------- | ----------- | ----- | ------------------------ |  | ------------- |  | ---------- |  | ---------------
|                        
|                         |                     |             |       |                          |  |               |  |            |  |                
|Batesville Unit No. 3(a) |                     | Mississippi |       | Toll Contract            |  | 281           |  | 7.7        |  | August 2000    
|Elwood Energy L.L.C.     |                     | Illinois    |       | Toll Contracts           |  | 609           |  | 10.7       |  | July 2001      
|Coahoma Power Plant      |                     | Mississippi |       | Contractually Controlled |  | 340           |  | 11.9       |  | September 2002 
|Clay County Power Plant  |                     | Illinois    |       | Owned                    |  | 340           |  | 11.9       |  | November 2002  
|Piatt County Power Plant |                     | Illinois    |       | Owned                    |  | 510           |  | 12.0       |  | June 2003      
|                        
|                         | Total Capacity (MW) |             | 2,080 |                          |  |               | 
|                        



Although we have exited the wholesale energy trading business, in the late 1990s and early 2000s, we were one of the largest marketers and traders
of wholesale natural gas, electricity and other commodities in North America and Western Europe. We stopped wholesale energy trading during the third quarter of 2002, and subsequent activity has
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. Many, but not all, of our positions have been hedged to limit our exposure to price movements, and these contracts will continue to be our assets and liabilities until the
contracts are settled or assigned.

Competition

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, including the capacity payments on our Elwood tolling contracts and continued operating and maintenance costs on our other merchant power plants.

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Regulation

Natural Gas Marketing Regulation

Our natural gas purchases and sales are generally not regulated by the FERC or other regulatory authorities. However, we depend on natural gas transportation and
storage services offered by companies that are regulated by the FERC and state regulatory authorities to transport natural gas we purchase or sell.

Power Marketing Regulation

The 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.

Power Generation Regulation

In 1992, Congress passed the Energy Act to promote further competition in the development of new wholesale power generation sources by encouraging the development
of independent power projects that are certified by the FERC as EWGs. Our owned and contractually controlled merchant power plants are certified by the FERC as 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 and
independent power projects with access to their transmission systems.

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. Independent power projects (including EWGs) must obtain FERC
acceptance of their rates under FPA Section 205. Our EWGs have been granted market-based rate authority and comply with the FPA requirements governing the approval of wholesale rates.

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Our Executive Team

|Name                         |  | Age |  | Position                                              
|---------------------------- |  | --- |  | ------------------------------------------------------
|                             |  |     |  |                                                       
|Richard C. Green (Rick)      |  | 50  |  | President, Chief Executive Officer and Chairman       
|Keith G. Stamm               |  | 44  |  | Senior Vice President and Chief Operating Officer     
|Rick J. Dobson               |  | 46  |  | Senior Vice President and Chief Financial Officer     
|Leo E. Morton                |  | 59  |  | Senior Vice President and Chief Administrative Officer
|Christopher M. Reitz (Chris) |  | 39  |  | Interim General Counsel and Corporate Secretary       
|Sally C. McElwreath          |  | 64  |  | Senior Vice President, Corporate Communications       
|Brock A. Shealy              |  | 43  |  | Senior Vice President, Corporate Compliance Officer   
|Jon R. Empson                |  | 59  |  | Senior Vice President, Regulated Operations           
|Robert L. Poehling (Bob)     |  | 41  |  | 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, Inc. 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 what is now
Aquila Merchant. In November 2001, he was appointed President and Chief Operating Officer of what is now Domestic Utilities. In October 2002, Keith became Chief Operating Officer of
Aquila, Inc.

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

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Christopher M. Reitz (B.S., Accounting and Business, University of Kansas; J.D., University of Kansas Law School)

Chris joined our company in July 2000 in our General Counsel's office, serving most recently as Assistant General Counsel. In February 2005, he was
appointed Interim General Counsel and Corporate Secretary of Aquila, Inc. Prior to joining our company, Chris held corporate counsel positions with Cerner Corporation, Sprint Corporation and
the law firm of Blackwell Sanders Peper Martin LLP.

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 what is now Aquila Merchant 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 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 a partner with the law firm of Blackwell Sanders Peper Martin LLP.

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.

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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 "Domestic Utilities" and "Merchant Services." Certain of these properties are encumbered by liens securing loans made to us. See Note 13 to the Consolidated Financial
Statements for a description of the liens.

Item 3.  Legal Proceedings

Litigation

AMS Shareholder Lawsuit

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. This lawsuit is scheduled for trial in May 2005. We believe we have strong defenses and will defend this
case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given
the nature of the
claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Price Reporting Litigation

On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, that allegedly
manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market. The suit does not specify alleged damages and was filed on behalf of
all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002. On September 24, 2004, the court denied Aquila's motion to dismiss along with similar motions filed
by most of the other defendants. We will defend this case vigorously as we believe we have strong defenses to the plaintiff's claims. We cannot predict with certainty whether we will incur any
liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse
effect on our financial condition, results of operations and cash flows.

On
June 7, 2004, the City of Tacoma filed suit against 56 companies, including Aquila, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in
violation of the Sherman Act. This case was dismissed in February 2005. It is not certain whether the plaintiff will appeal this ruling.

On
July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies, including Aquila, in the Superior Court
of San Diego alleging manipulation of the California natural gas market in 2000 through 2002. Since that date 13 other counties, cities and other parties have filed similar complaints making nearly

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identical
allegations. These lawsuits allege violations of the Cartwright Act, the Sherman Act, and the California Unfair Competition Law and unjust enrichment. The lawsuits have been designated In re Natural Gas Anti-Trust
Cases Vand assigned to a Coordination Motion Judge in the Superior Court of San Diego to determine whether
they are complex and should be coordinated. Aquila is also a defendant in theUtility Savings & Refund Services, LLP v. Reliant Energy
Services, Inc., et al.lawsuit filed November 30, 2004 in the U.S. District Court for the Eastern District of California alleging violations of the
Sherman Act, the Cartwright Act, and the California Unfair Competition Law. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be
incurred in connection with these lawsuits. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash
flows.

Enron Bankruptcy Litigation

On March 7, 2005, we reached an agreement with Enron Corp. and certain of its affiliates (Enron). Under this agreement, we will pay
$28 million to Enron to settle all outstanding claims between Enron and Aquila associated with the various bankruptcy filings of Enron in December 2001 and two lawsuits filed by Enron
Canada Corp. in January 2003. In 2001, we reserved for substantially all of our then outstanding receivables from Enron, which resulted in a charge of $66.8 million. This charge did not
reflect potential gains we would record in the event we were successful in netting certain obligations to Enron against these receivables. Approximately $33.5 million of liabilities remained on
our books related to contracts with Enron after the 2001 charge. The settlement is subject to final approval the bankruptcy court. As a result of the settlement, we reduced our net liability to Enron
by approximately $6 million, or $3.7 million after tax.

Lender Litigation

On October 5, 2004 and October 15, 2004, lawsuits were filed against us by our lenders alleging that we were obligated to pay a "make whole" amount
when we prepaid the $430 million three-year secured term loan in September 2004. We believe that our termination of the term loan required us to pay a prepayment penalty of
$8.7 million. The plaintiff lenders have sued us for breach of contract for their proportionate share of the difference between their prepayment calculation and the $8.7 million, which
in the aggregate is approximately $20.6 million. We believe we have strong defenses and will defend these cases vigorously. We cannot predict with certainty whether we will incur any liability,
nor can we estimate the damages, if any, that might be incurred in connection with these lawsuits. However, given the nature of the claims, an adverse outcome could have a material adverse effect on
our financial condition, results of operations and cash flows.

ERISA Litigation

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against us, the Board of Directors and certain
members of management alleging they violated the ERISA and are responsible for losses that participants in the Aquila 401(k) plan experienced as a result of the decline in the value of their Aquila
stock held in the Aquila 401(k) plan. A number of similar lawsuits alleging that the defendants breached their fiduciary duties to the plan participants in violation of ERISA by concealing information
and/or misleading employees who held Aquila stock through the Aquila 401(k) plan were subsequently filed against us. The suits also seek damages for the plan's losses resulting from the alleged
breaches of fiduciary duties. On January 26, 2005 the court ordered that each of these lawsuits

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must
all be consolidated into a single case captioned,In re Aquila ERISA Litigation,and gave the plaintiffs 45 days to file an amended
consolidated complaint. We believe we have strong defenses and will defend this case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages,
if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of
operations and cash flows.

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 2004.

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Part II

Item 5.  Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our
common stock (par $1) is listed on the NYSE under the symbol ILA. Through March 15, 2002, the symbol was UCU. At March 7, 2005, 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 7, 2005, the reported last sale price
of the common stock on the NYSE was $4.06 per share.

Market Price Per Share

|              |  | High |      | Low |   | Cash
Dividends
|------------- |  | ---- | ---- | --- | - | --------------
|
|              |  |      |      |     |   |               
|2004 Quarters |  |      |      |     |   |               
|Fourth        |  | $    | 3.80 |     | $ | 3.00          
|Third         |  |      | 3.87 |     |   | 2.25          
|Second        |  |      | 4.86 |     |   | 3.05          
|First         |  |      | 4.75 |     |   | 3.41          
|             
|2003 Quarters |  |      |      |     |   |               
|Fourth        |  | $    | 4.37 |     | $ | 3.17          
|Third         |  |      | 3.85 |     |   | 2.16          
|Second        |  |      | 3.22 |     |   | 1.63          
|First         |  |      | 2.50 |     |   | 1.07          
|             

As
part of our repositioning plan, our board of directors in the third quarter of 2002 suspended the payment of dividends on our common stock. Our board of directors regularly evaluates
our common stock dividend policy. The determination whether we will pay dividends is influenced by many factors, including, among other things, our overall financial condition and cash flows, legal
and contractual restrictions on the payment of dividends, and general economic and competitive conditions. We are bound by certain agreements and orders that limit our ability to pay dividends. For
example, our $220 million five-year unsecured term loan and five-year unsecured revolving credit facility prohibit us from paying dividends if our senior unsecured debt
is not rated at least Ba2 by Moody's and BB by S&P. In addition, an order of the Kansas Corporation Commission prohibits us from paying any dividends without its approval. We can make no determination
at this time as to whether, or when, we will begin to pay dividends in the future.

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Item 6.  Selected Financial Data

|In millions, except per share amounts         |                       | 2004 |         | 2003  |   | 2002    |       | 2001 |          | 2000   |  
|--------------------------------------------- | --------------------- | ---- | ------- | ----- | - | ------- | ----- | ---- | -------- | ------ | -
|                                              |                      
|Sales                                         |                       | $    | 1,711.0 |       | $ | 1,674.0 |       | $    | 2,041.1  |        | $
|Gross profit                                  |                       |      | 496.8   |       |   | 549.9   |       |      | 549.1    |        |  
|Earnings (loss) from continuing operations(a) |                       |      | (349.2  | )(b)  |   | (356.0  | )(c)  |      | (1,725.4 | )(d)   |  
|Basic earnings (loss) per common share       |                       |      |         |       |   |         |       |      |          |        |  
|                                              | Continuing operations |      |         | (1.35 | ) |         | (1.83 | )    |          | (10.67 | )
|Diluted earnings (loss) per common share     |                       |      |         |       |   |         |       |      |          |        |  
|                                              | Continuing operations |      |         | (1.35 | ) |         | (1.83 | )    |          | (10.67 | )
|Cash dividends per common share               |                       |      |        |       |   |        |       |      | .775     |        |  
|Total assets                                  |                       |      | 4,777.3 |       |   | 7,719.1 |       |      | 9,376.0  |        |  
|Short-term debt                               |                       |      |        |       |   |        |       |      | 287.8    |        |  
|Long-term debt (including current maturities) |                       |      | 2,371.9 |       |   | 2,706.0 |       |      | 2,626.5  |        |  
|Common shareholders' equity                   |                       |      | 1,130.5 |       |   | 1,359.3 |       |      | 1,607.9  |        |  
|                                              |                      

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 and $8.1 of goodwill amortization for the years ended December 31, 2001 and 2000, respectively.
Goodwill amortization was not recorded in the years ended December 31, 2004, 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 and $10.5, respectively, of
goodwill amortization.

(b)   Included
in earnings (loss) from continuing operations for the year ended December 31, 2004, is a $46.6 million loss on the transfer of our interest in the
Aries power project and termination of our 20-year tolling agreement with that project, a $156.2 million loss on the termination of four long-term gas contracts,
$63.9 million of losses related to derivatives cancelled and replacement gas purchased for these four contracts, and $19.5 million of other impairment charges; offset in part by
$34.0 million of gains including the sale of our interests in 12 equity method independent power plants, the sale of a power development project in the United Kingdom and a distribution from
our interest in the BAF power partnership that sold its cogeneration facility.

(c)   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.

(d)   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 $181.2 million write-down of
Merchant Services' goodwill; (f) other impairment charges and losses on sale of assets of $91.9 million, primarily as a result of our decision to sell non-core assets to
improve our

24

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liquidity
position; and (g) $210.2 million of restructuring charges from our exit from the wholesale energy trading business and the restructuring of our domestic utility business. We
also recorded a $130.5 million gain on the sale of our shares of UnitedNetworks.

(e)   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 Utilities; (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.

(f)    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 fiber-optic communications networks. We also recorded a $44.0 million gain on the sale
of a 34% interest in Uecomm Limited to the public.

25

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

See
Forward-Looking Information and Risk Factors beginning on page 65.

Strategic and Financial Repositioning Overview

Overview

Our repositioning plan is based on improving operational results of our integrated electric and gas utility operations and strengthening our credit profile. The
key elements of our plan are to:



This
repositioning plan was developed to focus on building and maintaining the generation, transmission and distribution infrastructure necessary to provide our utility customers with
safe and reliable service, while increasing the returns on invested capital in jurisdictions that lag behind those of our peers. We intend to focus on improving our returns through future rate
activities and our recently initiated six sigma process improvement program, which we believe will bring our returns closer to those of our peers by the end of 2007.

Asset Divestures and Strengthen Credit Profile

With a stronger credit profile we will have the opportunity to invest in power generation, transmission and distribution capacity, as well as undertake
environmental upgrades over the next decade. These normal course investments will not only improve the reliability and quality of our utility service, but also provides a platform for additional
growth in our earnings and enhanced shareholder value.

Following
an extensive review and discussion with outside advisors on our stand-alone regulated utility strategy, we have retained investment banking advisors to conduct a competitive
sale process for certain regulated utility assets. Due to regulatory and price uncertainties associated with the sale of regulated assets, we intend to concurrently conduct a competitive bidding
process for utility assets having an aggregate net plant book value of approximately $874 million. The utilities that will be included in the competitive bidding process are our gas operations
in Michigan, Minnesota and Missouri and our electric operations in Kansas, Colorado

26

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and
our St. Joseph, Missouri service territory. At the conclusion of this process, we expect to enter into one or more definitive sale agreements to sell a subset of the offered properties. We will
not determine which assets to sell until the conclusion of the competitive bidding process. Among other considerations, our decision will be based on the comparison of the value of the offers versus
the value we can build by continuing to own and operate these assets, execution risk through the regulatory approval process, and the opportunity to support the growth of our remaining operations.

We
expect to use the proceeds from the sale of regulated utility assets to retire debt and other liabilities. We currently have more than $700 million of debt obligations that
are, or are expected to be callable at par or at a reasonable fixed contractual fee. Having the ability to repurchase debt securities at fixed prices allows us to deploy the proceeds from utility
asset divestures efficiently in order to reduce debt and improve our credit profile.

We
will also be focused on the divesture of our non-regulated assets and contractual requirements. This includes the continued analysis of the timing of our divesture of the
remaining three peaking facilities and Everest Connections. Additionally, we will continue to pursue the exit of our Elwood tolling contract commitments. The proceeds from the sale of the peaking
facilities and Everest Connections will be applied towards the exit of our Elwood tolling contract or to retire debt.

Historical Review of Repositioning Efforts

In response to significant changes in the energy industry during the past few years, we undertook a strategic review of our business in the second quarter of 2002
and announced a change in our strategic direction. Our revised strategy features a concentrated focus on our domestic utility operations, which preceded our diversification into merchant and
international arenas in the 1990s.

As
part of this repositioning, we took the following actions in 2002:



Separately,
we restructured Domestic Utilities in 2002 to more closely align it with its regulatory service areas. Due to our ongoing restructuring efforts since March 2002, we
reduced staff by approximately 1,800 employees, including those transferred with the sale of various businesses. Of these, 496 were Corporate or Domestic Utilities employees.

27

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



In
2004, we continued to implement our restructuring plan through the following actions, among others:



28

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

LIQUIDITY AND CAPITAL RESOURCES

Working Capital Requirements

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 months of the winter heating season due to higher natural gas consumption, potential periods of high natural gas prices and our current requirement to prepay certain
gas commodity suppliers and pipeline transportation companies. Under a stressed weather and commodity price environment, we believe this working capital peak could be as high as $350 million.
We anticipate using the combination of our $110 million five-year unsecured revolving credit
facility, $150 million secured accounts receivable facility and cash on hand to meet the peak winter working capital requirements of our business.

Cash Flows

Cash Flows from Operating Activities

Our 2004 cash flows from operations were negative due to significant cash impacts resulting primarily from our 2004 operating net loss, the exiting of our
non-core businesses including the termination of four long-term gas contracts, and the continued wind-down of our Merchant Services business. Our negative 2004 cash
flows were driven by the following events and factors:



29

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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:



Our
Elwood tolling contracts will have a material negative impact on our operating cash flows for the foreseeable future. We are attempting to restructure or terminate the Elwood tolling
contracts. Any cash payment made to exit this obligation would have a negative impact on operating cash flows in the year the payment is made, but would 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 debt has substantially increased
our interest costs and will continue to negatively impact our operating cash flows. 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 sales through utility rates, retiring debt and completing the wind-down of our Merchant Services business.

Cash Flows from Investing Activities

Cash flows provided from investing activities increased in 2004 compared to 2003, primarily due to an increase in net proceeds received from the 2004 sales of our
Canadian utility businesses, independent power plants, and Midlands Electricity. In 2003, we received proceeds from the sale of our merchant loan portfolio, investments in Australia, Quanta Services,
and our gas gathering and pipeline assets. In addition, we had lower merchant capital expenditures and investments in unconsolidated merchant subsidiaries in 2004 compared to 2003, due to the
completion of construction of a merchant power plant in June 2003, and the sale of our Aries power project in March 2004. Our utility capital expenditures decreased in 2004 due to the
sale of our Canadian utility businesses in May 2004.

30

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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, in
December 2002 we sold our merchant loan portfolio which 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 Flows from Financing Activities

Cash flows from financing activities decreased in 2004 compared to 2003. Our 2004 net cash used for financing activities consisted primarily of cash we paid to
retire our short and long-term debt obligations and to terminate four of our long-term gas contracts, offset in part by the issuance of our common stock, mandatorily
convertible PIES and our five-year unsecured term loan. In 2004, we retired the Midlands Electricity acquisition note, our three-year secured term loan, our 7.0% and 6.875%
senior notes, and debt related to our Canadian utility operations. In 2003, we retired the debt associated with our investment in Australia and the construction of our merchant power plants.
Additionally, we paid $556.7 million for the termination of our obligations under four long-term gas contracts in 2004. The funds used to retire debt and terminate our
long-term gas contracts were provided by investing activities, and the proceeds from our issuance of 46.0 million shares of common stock, our mandatorily convertible PIES and our
$220 million five-year unsecured term loan.

Cash
flows from financing activities decreased in 2003 compared to 2002. Our 2003 net cash used for financing activities reflects 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 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 receivable sale programs that were terminated in 2002 and to retire debt and company-obligated preferred securities.

Current Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and vendor payment terms, including collateral
and prepayment requirements. 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, 2004, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency  |  | Rating |  | Commentary      
|------- |  | ------ |  | ----------------
|
|        |  |        |  |                 
|Moody's |  | B2     |  | Stable Outlook  
|S&P     |  | B-     |  | Negative Outlook
|Fitch   |  | B-     |  | Stable Outlook  
|       

31

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Debt
ratings by the various rating agencies reflect each agency's opinion of the ability of the issuers to repay debt obligations as they come due. In general, lower ratings result in
higher borrowing costs and/or impaired ability to borrow. A security rating is not a recommendation to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the
assigning rating organization.

Any
rating below BBB, for S&P and Fitch, or Baa, for Moody's, is considered to be non-investment grade and indicates that the security is speculative in nature. A BB rating, for
S&P and Fitch, or a Ba rating, for Moody's, indicates that the issuer currently has the capacity to meet its financial commitment on the obligation; however, it faces major ongoing
uncertainties or exposure to adverse business, financial or economic conditions, which could lead to the obligor's inadequate capacity to meet its financial commitment on the obligation. An obligation
rated B is more vulnerable to nonpayment than obligations rated BB or Ba, but the obligor currently has capacity to meet its financial commitment on the obligation. Adverse business,
financial, or economic conditions will likely impair the obligor's capacity or willingness to meet its financial commitment on the obligation. The plus and minus symbols, for S&P and Fitch, and the
"1,2,3" modifiers, for Moody's, show relative standing within the major categories, 1 being the highest, or best, modifier in terms of credit quality.

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 additional 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. If our credit ratings improve to certain levels, the interest
rates on $970 million of our long-term debt obligations will be lowered.

Collateral Positions

As of December 31, 2004, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:

|In millions                          |  |  
|------------------------------------ |  | -
|
|                                     |  |  
|Trading positions                    |  | $
|Utility cash collateral requirements |  |  
|Elwood tolling contract              |  |  
|Insurance and other                  |  |  
|                                    
|Total Funds on Deposit               |  | $
|                                    

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

We
are required to post collateral with certain 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 the strengthening of our credit profile.

We
have been required to post collateral related to our Elwood tolling contract until we either successfully restructure the contract or obtain investment-grade credit ratings from
certain

32

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major
rating agencies. We will not be required to post any additional collateral related to this contract.

Contractual Obligations

Our contractual cash obligations include maturities of long-term debt, cash payments for our two remaining long-term gas contracts,
minimum payments on operating leases and regulated power, gas and coal purchase contracts, as well as the Elwood tolling contracts and merchant 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                             |  | 2005 |       | 2006 |   | 2007  |  | 2008 |       | 2009 |   | Thereafter |  | Total
|--------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------- |  | -----
|
|                                        |  |      |       |      |   |       |  |      |       |      |   |            |  |      
|Long-term debt obligations(a)           |  | $    | 42.0  |      | $ | 89.3  |  | $    | 43.3  |      | $ | 2.6        |  | $    
|Long-term gas contracts                 |  |      | 22.1  |      |   | 23.4  |  |      | 23.9  |      |   | 2.0        |  |      
|Lease and maintenance obligations       |  |      | 29.3  |      |   | 24.1  |  |      | 22.3  |      |   | 23.6       |  |      
|Elwood tolling contracts                |  |      | 37.3  |      |   | 37.3  |  |      | 37.3  |      |   | 37.4       |  |      
|Merchant gas transportation obligations |  |      | 9.2   |      |   | 8.5   |  |      | 5.4   |      |   | 5.4        |  |      
|Regulated purchase obligations          |  |      | 330.9 |      |   | 280.3 |  |      | 249.3 |      |   | 205.4      |  |      
|                                       
|Total                                   |  | $    | 470.8 |      | $ | 462.9 |  | $    | 381.5 |      | $ | 276.4      |  | $    
|                                       



Long-Term Gas Contracts

We accounted for the advance cash payments we received under these contracts as liabilities. We reduce 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 $69.6 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 versus a present value method applied under the default provisions of the contractual agreements. We do not intend to terminate
these remaining contracts.

Elwood Tolling Contracts

Because it is generally expected that the fuel and start-up costs of operating the Elwood power plant will exceed the revenues that would be generated
from the power sales, during the foreseeable future, we believe that our capacity to generate power from the Elwood power plant will largely be unutilized. Before including existing forward sales
contracts, we expect to incur pretax losses and negative operating cash flows of approximately $37.3 million in 2005 related to these contracts. We are attempting to terminate or restructure
this obligation.

33

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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, 2004, 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. These are discussed below.

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 substantially all of 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. In 2004, we paid $6.0 million to the buyer of the portfolio out of $10.7 million of swap proceeds collected. As of December 31,
2004, we have collected $28.0 million related to the remaining swaps, of which we have reserved $5.0 million to cover this obligation. The value of the unsettled portion of these swaps,
which expire by December 2006, was $28.5 million at December 31, 2004.

Equity Put Rights

Certain minority owners of Everest Connections had the option to sell their ownership units to us if Everest Connections did not meet certain financial and
operational performance measures as of December 31, 2004 (target-based put rights). If the target-based put rights were exercised, we would have been obligated to purchase up to
4.0 million and 4.75 million ownership units at a price of $1.00 and $1.10 per unit, 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. In 2004, we achieved the operating
targets related to 4.0 million and 1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million of this reserve. We did
not achieve the targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their options and were paid
$3.6 million for their ownership units in February 2005. As of December 31, 2004, we had fully reserved for this obligation. The minority owners of 9.5 million ownership
units also have the option to sell their ownership units to us at fair market value (market-based put rights). The market-based put rights expire on December 31, 2005. We have not provided for
this potential obligation as the exercise would represent an equity transaction at fair value. We do not believe based on current estimates of fair value that these market-based put rights are a
material contingent obligation.

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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  |                            | $      | 146.6 |                                   
|Canadian utilities  |                            |        | 72.8  |                                   
|Everest Connections |                            |        | 14.0  |                                   
|Corporate and Other |                            |        | 8.5   |                                   
|                   
|                    | Total capital expenditures |        | $     | 241.9                             
|                   

Our
estimated Domestic Utilities capital expenditures increase significantly in 2005 from 2004, primarily because of approximately $64.3 million of additional capital expenditures
on our South Harper Peaking Facility and related transmission system upgrades. In addition, 2006 and 2007 capital expenditures include the anticipated cost of additional emissions control equipment at
our generating facilities.

Iatan 2

Our 2005 power supply plan indicates the need for additional base-load capacity after 2009. There is generally a five- to
seven-year lead time required between the decision to proceed with a coal-fired generating project and the completion of development, permitting, construction and performance
testing of such a project. Kansas City Power & Light Company has presented their plan for the construction of up to 800 MW of coal-fired generating capacity at the existing Iatan
site in Weston, Missouri, through a series of workshops to the Missouri Public Service Commission (MPSC) and other interested parties. The additional 800 MW generating capacity is planned for
commercial operation prior to summer 2010. On March 2, 2005, we filed an experimental regulatory plan with the MPSC outlining certain regulatory principles needed in order to facilitate our
equity participation in 150 MW of the proposed new Iatan facility. The table presented above does not include the additional capital expenditures that would be associated with this participation.

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 FERC, Kansas Commission and Colorado Commission to issue up to $238 million of securities in the form of any combination
of common stock and long-term debt that is mandatorily convertible into our common stock. We do not have approvals to incur additional long-term debt.

We
are also required to obtain the prior approval of the FERC to issue short-term debt. We have obtained their approval to have outstanding up to $350 million of
additional secured or unsecured short-term debt. We must obtain the prior approval of the Kansas Corporation Commission to issue short-term debt except as required to meet our
working capital requirements.

35

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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.

Restriction on Ability to Issue Common Stock

Our certificate of incorporation authorizes us to issue up to 400 million shares of common stock, 20 million shares of Class A Common Stock
and 20 million shares of preferred stock. Of the 400 million shares of common stock authorized to be issued, approximately 391.6 million shares have either been issued or reserved
for issuance in connection with the conversion of our PIES or pursuant to employee compensation plans. Accordingly, unless our certificate of incorporation is amended with the approval of our
shareholders, our ability to raise capital through the sale of common stock is severely restricted.

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 GAAP.
In addition, our use of EBIT may not be comparable to similarly titled measures used by other entities.

36

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See
page 65 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 Utilities                                       |                                        | $                       | 159.1 
|Merchant Services                                        |                                        |                         | (438.7
|Corporate and Other                                      |                                        |                         | (24.5 
|                                                         |                                       
|Total EBIT                                               |                                        |                         | (304.1
|                                                         |                                       
|Interest expense                                         |                                        |                         | 258.4 
|Income tax benefit                                       |                                        |                         | (213.3
|                                                         |                                       
|Loss from continuing operations                          |                                        |                         | (349.2
|Earnings (loss) from discontinued operations, net of tax |                                        |                         | 56.7  
|Cumulative effect of accounting change, net of tax       |                                        |                         |      
|                                                         |                                       
|Net loss                                                 |                                        | $                       | (292.5
|                                                         |                                       
|Diluted earnings (loss) per share:                       |                                        |                         |       
|                                                         | Continuing operations                  |                         | $     
|                                                         | Discontinued operations                |                         |       
|                                                         | Cumulative effect of accounting change |                         |       
|                                                         |                                       
|                                                         | Net loss                               |                         | $     
|                                                         |                                       

Key Factors Impacting Continuing Operating Results

Our total loss before interest and taxes increased significantly in 2004 compared to 2003. Key factors affecting 2004 results were as follows:



Cumulative Effect of Accounting Change

In October 2002, the 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
SFAS No. 133, "Accounting for Derivative Instruments and Hedging

37

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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.

Restructuring Charges

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

|                                    |                                                    | Year Ended December 31,
|----------------------------------- | -------------------------------------------------- | -----------------------
|
|
|                                    |                                                    |                        
|Domestic Utilities:                 |                                                    |                        
|                                    | Severance costs                                    |                        
|                                    | Disposition of corporate aircraft                  |                        
|                                   
|Total Domestic Utilities            |                                                    |                        
|                                   
|Merchant Services:                  |                                                    |                        
|                                    | Interest rate swap reductions                      |                        
|                                    | 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 Merchant Services             |                                                    |                        
|                                   
|Corporate and Other severance costs |                                                    |                        
|                                   
|Total restructuring charges         |                                                    | $                      
|                                   

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Net Loss on Sale of Assets and Other Charges

As further discussed in Note 5 to the Consolidated Financial Statements, we recorded the following net loss (gain) on sale of assets and other charges:

|                                                   |                                                         | Year Ended December 31, |      
|-------------------------------------------------- | ------------------------------------------------------- | ----------------------- | -----
|
|
|                                                   |                                                         |                         |      
|Domestic Utilities:                                |                                                         |                         |      
|                                                   | Gas distribution system                                 |                         | $    
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Domestic Utilities                           |                                                         |                         |     
|                                                   |                                                        
|Merchant Services:                                 |                                                         |                         |      
|                                                   | Aries power project and tolling agreement               |                         |      
|                                                   | Termination of long-term gas contracts                  |                         |      
|                                                   | Red Lake gas storage development project                |                         |      
|                                                   | Acadia tolling agreement                                |                         |      
|                                                   | Turbine contracts                                       |                         |      
|                                                   | Independent power plants                                |                         |      
|                                                   | Investment in BAF Energy                                |                         |      
|                                                   | Enron bankruptcy                                        |                         |      
|                                                   | Marchwood development project                           |                         |      
|                                                   | Merchant Services goodwill                              |                         |      
|                                                   | Exit from Lodi gas storage investment                   |                         |      
|                                                   | Termination of Cogentrix acquisition                    |                         |      
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Merchant Services                            |                                                         |                         | 185.5
|                                                   |                                                        
|Corporate and Other:                               |                                                         |                         |      
|                                                   | Quanta Services                                         |                         |      
|                                                   | Everest Connections and other communication investments |                         |      
|                                                   | Midlands                                                |                         |      
|                                                   | Australia                                               |                         |      
|                                                   | Turbines impairment                                     |                         |      
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Corporate and Other                          |                                                         |                         | 2.8  
|                                                   |                                                        
|Total net loss on sale of assets and other charges |                                                         | $                       | 188.3
|                                                   |                                                        

During
2004, 2003 and 2002, we also incurred net (gains) losses on asset sales and other charges of $(74.0) million, $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: (i) 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

39

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our
merchant loan portfolio that were all sold in 2002 and early 2003, and (ii) our Canadian network businesses that we sold in May 2004 and our consolidated independent power plants,
Lake Cogen and Onondaga, that we sold in March 2004.

Operating
results of discontinued operations are as follows:

|                                             |                                                     | Year Ended December 31, |      
|-------------------------------------------- | --------------------------------------------------- | ----------------------- | -----
|
|
|                                             |                                                     |                         |      
|Sales                                        |                                                     | $                       | 130.9
|Cost of sales                                |                                                     |                         | 25.1 
|                                             |                                                    
|Gross profit                                 |                                                     |                         | 105.8
|                                             |                                                    
|Operating expenses:                          |                                                     |                         |      
|                                             | Operating expense                                   |                         |      
|                                             | Net loss (gain) on sale of assets and other charges |                         |      
|                                             | Depreciation and amortization expense               |                         |      
|                                             |                                                    
|Total operating expenses                     |                                                     |                         | (17.3
|                                             |                                                    
|Other income (expense):                      |                                                     |                         |      
|                                             | Equity in earnings of investments                   |                         |      
|                                             | Other income (expense)                              |                         |      
|                                             |                                                    
|Total other income (expense)                 |                                                     |                         | 2.7  
|                                             |                                                    
|Earnings (loss) before interest and taxes    |                                                     |                         | 125.8
|Interest expense                             |                                                     |                         | 14.7 
|                                             |                                                    
|Earnings (loss) before income taxes          |                                                     |                         | 111.1
|Income tax expense (benefit)                 |                                                     |                         | 54.4 
|                                             |                                                    
|Earnings (loss) from discontinued operations |                                                     | $                       | 56.7 
|                                             |                                                    

2004 versus 2003

Sales, Cost of Sales and Gross Profit

Sales and cost of sales decreased $191.5 million and $38.9 million, respectively, resulting in a gross profit decrease of $152.6 million in
2004 compared to 2003. Sales, cost of sales and gross profit for our Canadian network business decreased $126.0 million, $21.2 million and $104.8 million, respectively, primarily
due to the sale of these businesses in May 2004. Canadian utility sales, cost of sales and gross profit in June 2003 through December 2003 were $170.4 million,
$23.3 million and $147.1 million, respectively. These decreases were partially offset by the March 2003 decision by the Alberta Energy Utilities Board (AEUB) to reduce our 2002
and 2003 customer billing rates. The AEUB decision resulted in an adjustment that reduced our first quarter 2003 sales and gross profit by approximately $33.7 million. Sales, cost of sales and
gross profit for Lake Cogen and Onondaga were lower in 2004 by $65.2 million, $17.8 million and $47.4 million, respectively, due to the sale of these businesses in early
March 2004 and a price dispute settlement that increased Lake Cogen's 2003 sales by $5.7 million.

40

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Operating Expense

Operating expense decreased $85.2 million in 2004 compared to 2003 primarily due to the sale of our consolidated independent power plants in
March 2004 and our Canadian utility businesses in May 2004.

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

In 2004, net gain on sale of assets and other charges of $74.0 million consisted of a $65.6 million gain related to the sale of our Canadian utility
businesses in May 2004, and an $8.4 million gain related to the sale of our consolidated independent power plants, Lake Cogen and Onondaga, in March 2004. In 2003, the
$47.5 million net loss and other charges was related to the impairment charge taken on our consolidated independent power plants. In the third quarter of 2003, we decided to proceed with their
sale and therefore wrote them down to their estimated fair value less costs to sell, which was less than their carrying value.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $8.6 million in 2004 compared to 2003. The elimination of depreciation from our Canadian utility
businesses, due to their classification as held for sale in accordance with SFAS 144, decreased depreciation expense $21.4 million. SFAS 144 requires that depreciation expense no
longer be recorded for those assets classified for accounting purposes as held for sale. The decrease was offset by the $15.2 million adjustment in the first quarter of 2003 related to the
decision by the AEUB to reduce the depreciation rates on most of our distribution assets in Alberta.

Other Income (Expense)

Other income increased $18.7 million in 2004 compared to 2003, primarily due to 2003 costs including 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 Expense

Income tax expense increased $53.5 million in 2004 compared to 2003. The 2004 income tax expense on pretax income from discontinued operations was
primarily the result of taxes associated with the gain on the sale of our Canadian utility businesses. The effective tax rate on the pretax gain on sale of our Canadian utility businesses is
substantially higher than the statutory federal tax rate due to the following factors. The U.S. taxes reflect the partial deduction of Canadian taxes, including withholding taxes, from the U.S.
taxable income instead of the full utilization of foreign tax credits. Taxes on the sale also reflect our inability to fully utilize the tax loss on the sale of the Alberta business against the tax
gain on the sale of the British Columbia business. Offsetting the 2004 income tax expense was the reversal of $11.1 million of valuation allowances provided in 2003 related to the impairment of
our investments in independent power plants. This valuation allowance was reversed in 2004 when the final sale structure was determined and an updated estimate of expected capital losses was
completed. In addition, our former Alberta utility recognized income taxes using the flow-through method. As a result, the elimination of depreciation in 2004 and the adjustment of
depreciable lives due to the 2003 regulatory decision increased pretax income but had no impact on income tax expense.

41

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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 $56.0 million in 2003 compared to 2002 primarily due to the sale of our gas gathering and pipeline assets, merchant loan
portfolio and coal terminal in 2002 and early 2003.

Net Loss on Sale of Assets and Other Charges

Net loss on sale of assets and other charges 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 them down to estimated fair value less costs to sell, which was less than their carrying value. The
2002 net loss on sales of assets and other charges included 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 $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 AEUB's
decision 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 $73.5 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 $45.5 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

42

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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 $5.8 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 could no longer represent that cash from this business would be permanently reinvested. Therefore, additional
deferred tax was recorded to account for taxes associated with bringing 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 was expected to be a capital loss for which we provided additional valuation allowances.

43

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Three-Year ReviewDomestic Utilities

Domestic Utilities is made up of our electric and gas regulated utility businesses, which operate as Aquila in Colorado, Iowa, Kansas, Michigan, Minnesota,
Missouri and Nebraska.

|                                                |                                                     | 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                               |                        
|                                                | Net loss (gain) on sale of assets and other charges |                        
|                                                | Depreciation and amortization expense               |                        
|                                               
|Total operating expenses                        |                                                     |                        
|                                               
|Other income (expense):                         |                                                     |                        
|                                                | Other income                                        |                        
|                                               
|Earnings before interest and taxes              |                                                     | $                      
|                                               
|Electric sales and transportation volumes (GWh) |                                                     |                        
|Gas sales and transportation volumes (Mcf)      |                                                     |                        
|Electric customers                              |                                                     |                        
|Gas customers                                   |                                                     |                        
|                                               

2004 versus 2003

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Utilities businesses increased $113.8 million and $117.6 million, respectively, resulting in a gross profit
decrease of $3.8 million in 2004 compared to 2003. These changes were primarily due to the following factors:



44

---





Operating Expense

Operating expense increased $16.1 million in 2004 compared to 2003, as a result of a number of cost increases. The most significant of these was outside
services and materials costs, which increased $6.1 million, and labor and other compensation costs, which increased $5.3 million due to additional customer service representatives,
apprentice linemen, increased pension costs and compliance costs in 2004 compared to 2003.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $2.8 million in 2004 compared to 2003, primarily due to the adjustments to depreciation rates resulting
from recent rate cases.

2003 versus 2002

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Utilities businesses decreased $91.0 million and $98.1 million, respectively, resulting in a gross profit
increase of $7.1 million in 2003 compared to 2002. These changes were primarily due to the following factors:



45

---





Operating Expense

Operating expense decreased $17.1 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.

Restructuring Charges

Restructuring charges decreased $21.0 million in 2003 compared to 2002. As a result of the restructuring of our Domestic Utilities business to more closely
align it with our state service areas, we incurred $21.0 million in restructuring costs in 2002, primarily in the form of severance for terminated employees and the disposition of our corporate
aircraft operation.

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

As further discussed in Note 5 to the Consolidated Financial Statements, Domestic Utilities incurred a $9.0 million asset impairment charge related
to a local natural gas distribution system deemed unrecoverable in one of our regulatory jurisdictions in 2002, compared to a net $1.3 million gain in 2003 on several minor asset dispositions
and impairments.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $4.6 million in 2003 compared to 2002, primarily due to the adjustment of depreciation rates in one
jurisdiction in December 2002.

Earnings Trend

The recent settlement of our electric and gas rate cases in Missouri is expected to increase annual sales approximately $37.5 million and
$3.4 million, respectively. However, our costs of

46

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natural
gas used for fuel and purchased power have exceeded the level of costs recovered under the IEC discussed on page 10. If these costs remain above the IEC base cost for the
two-year period, we will not recover the excess. A portion of the rate increase is to cover increased costs in the 12-month test period such as additional staffing to improve
customer service. To the extent that operating costs increase or decrease subsequent to the test period, the impact of the change will affect our operating results.

Our
power supply agreement with Aries, which provides up to 500 MW of power, expires in June 2005. We plan to replace this power with the construction of the South Harper Peaking
Facility, a 315-megawatt combustion turbine generation plant near Peculiar, Missouri, and by entering into power purchase agreements. The construction of South Harper is expected to
require additional capital expenditures of approximately $44.8 million. In addition, transmission system upgrades of $19.5 million will be required. To the extent the cost of this
replacement power exceeds the cost of power recovered in rates under the Aries agreement, and until such cost is recovered in a subsequent rate case, our earnings could be adversely affected.

On
December 22, 2003, one of our coal suppliers declared a partial force majeure event due to a labor strike at the mine and gave us formal notice they would be unable to fully
perform their contract obligations for the then following 60 to 90 days. This force majeure condition continued throughout 2004 with Aquila receiving approximately 30% of its contracted
low-sulfur, high-Btu volumes. Although force majeure conditions are expected to improve in 2005, we continue to plan for and have secured substantial quantities of alternate
supply through spot purchases, despite a general decrease in availability of comparable coal on the spot market. These substitute supplies of coal are typically of higher sulfur content and therefore
require the purchase of additional SO2 emission allowances at a time when the cost of such allowances is substantially higher than historical levels. In the event we continue to replace
our original contracted coal supply with the substitute coal supply during 2005, our operating results could be adversely affected.

Merchant Services

We conduct our Merchant Services business through Aquila Merchant Services, Inc. (Aquila Merchant), which primarily owns, operates and contractually
controls our non-regulated power generation assets. Merchant Services includes our former North American and European energy trading businesses.

47

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Three-Year ReviewMerchant Services

|                                          |                                              | Year Ended December 31, |       
|----------------------------------------- | -------------------------------------------- | ----------------------- | ------
|
|
|                                          |                                              |                         |       
|Sales                                     |                                              | $                       | (152.9
|Cost of sales                             |                                              |                         | 57.1  
|                                          |                                             
|Gross loss                                |                                              |                         | (210.0
|                                          |                                             
|Operating expenses:                       |                                              |                         |       
|                                          | Operating expense                            |                         |       
|                                          | Restructuring charges                        |                         |       
|                                          | Net loss on sale of assets and other charges |                         |       
|                                          | Depreciation and amortization expense        |                         |       
|                                          |                                             
|Total operating expenses                  |                                              |                         | 235.8 
|                                          |                                             
|Other income:                             |                                              |                         |       
|                                          | Equity in earnings of investments            |                         |       
|                                          | Other income                                 |                         |       
|                                          |                                             
|Earnings (loss) before interest and taxes |                                              | $                       | (438.7
|                                          |                                             

Due
to EITF 02-3, we must now show our gains and losses from energy trading contracts on a net basis. To the extent losses exceeded gains, sales are shown as a negative
number.

2004 versus 2003

Sales, Cost of Sales and Gross Loss

Gross loss for our Merchant Services operations for 2004 was $210.0 million, primarily due to the following factors:



48

---





Gross
loss for our Merchant Services operations for 2003 was $157.3 million, primarily due to the following factors:



49

---





Operating Expense

Operating expense decreased $61.8 million primarily due to $26.5 million of expense accrued in 2003 related to our January 2004 settlement
with the CFTC, and lower labor and other costs related to continued reductions in staff as part of the wind-down of our Merchant operations.

Restructuring Charges

Restructuring charges decreased $24.0 million in 2004 compared to 2003. This decrease stemmed primarily from restructuring charges of $23.1 million
during 2003 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. As a result, we reduced our swap position and realized the loss associated with the cancelled portion of the
swaps.

Net Loss on Sale of Assets and Other Charges

During 2004, net loss on sale of assets and other charges consisted of a $156.2 million loss on the termination of four long-term gas
contracts, a $46.6 million loss on the transfer of our equity interest in the Aries power project and termination of our tolling obligation and an $8.9 million impairment charge on our
investment in the Red Lake gas storage project, offset by a $6.1 million gain related to the sale of our equity method investments in independent power plants, a $5.0 million gain on the
sale of our Marchwood development project in the United Kingdom, a $9.1 million gain related to a distribution from BAF Energy and a $6.0 million reduction of our reserve for the
anticipated settlement of our outstanding liabilities to Enron.

During
2003, we recorded $189.1 million of net loss on sale of assets and other charges. 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. Also included was a $105.5 million payment for the termination of 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 previously written down to estimated fair value.

50

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Depreciation and Amortization Expense

Depreciation and amortization expense decreased $14.4 million in 2004 compared to 2003, primarily due to the elimination of the amortization of premiums
associated with our equity method investments in independent power plants, resulting from the impairment of our investments in these plants in September 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $51.8 million due to the sale of our independent power plant investments in the first quarter of 2004.

Other Income (Expense)

Other income decreased $22.5 million in 2004 primarily due to two items recorded in 2003 that did not recur in 2004. 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 in 2003 that would have been payable had the Internal Revenue Service prevailed in the
dispute. We also realized foreign currency translation gains of $12.5 million on the wind-down of our European merchant operations in 2003.

2003 versus 2002

Sales, Cost of Sales and Gross Loss

The significant factors causing the gross loss of $157.3 million in 2003 are discussed above.

Gross
loss for our Merchant Services operations for 2002 was $137.4 million. The following describes the major components of the 2002 gross loss:



51

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Operating Expense

Operating expense decreased $52.2 million primarily due to labor and benefit savings, lower corporate costs resulting from the restructuring of this
business in 2002 and related operating cost reductions resulting from the exit from our wholesale energy trading operations in 2002, partially offset by $26.5 million of expense accrued in 2003
related to our January 2004 settlement with the CFTC and a $9.8 million write-down of our remaining merchant note receivable in 2003.

Restructuring Charges

Restructuring charges decreased $155.3 million in 2003 compared to 2002. This decrease stemmed primarily from significant charges taken in 2002. 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 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.

Partially
offsetting the decrease were restructuring charges of $23.1 million and $6.2 million during 2003 and 2002, 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,
the notional amount
of our swaps exceeded our outstanding debt. We therefore reduced our position and realized the loss associated with the cancelled portion of the swaps.

Net Loss on Sale of Assets and Other Charges

During 2003, we recorded $189.1 million of net loss on sale of assets and other charges. 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 of 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 previously written down to estimated fair value.

For
2002, net loss on sale of assets and other charges consisted primarily of an impairment charge of $181.2 million related to goodwill associated with Merchant Services that
became unrealizable due to our exit from this business, $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 our proposed Cogentrix acquisition, and $9.7 million of other impairments.

52

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Depreciation and Amortization Expense

Depreciation and amortization expense increased $16.3 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. These increases were partially offset by decreased depreciation related to excess
leasehold improvements and equipment that were expensed when we vacated the related leased properties.

Other Income (Expense)

Other income increased $12.2 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 in 2003 that would have been payable had the Internal Revenue Service prevailed in the dispute. We also realized foreign currency
translation gains of $12.5 million on the wind-down of our European merchant operations.

Current Operating Developments

ICE Sale

In February 2005, we sold our 4.5% interest in IntercontinentalExchange, Inc. (ICE), which owns a web-based commodity exchange platform,
to other shareholders in ICE for approximately $13.8 million. This transaction resulted in a pretax gain of approximately $9.3 million.

Batesville Tolling Contract

In February 2005, we terminated our power sales contract and assigned our rights and obligations under the toll contract in exchange for approximately
$16.3 million. This transaction resulted in a pretax gain of approximately $16.3 million.

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 tolling agreements with Elwood and expect to incur pretax losses and negative operating cash flows of approximately
$37.3 million in 2005 related to this arrangement. We are attempting to terminate or restructure this obligation. We have sold capacity in three of these plants which will partially offset
these costs in 2005 and 2006. As a result of the above factors and our change in strategy, we do not expect Merchant Services to be profitable in the next two to three years.

53

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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.

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. 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 Merchant 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 $22.2 million of total volatility (potential earnings or losses) related to this contract.

Corporate Matters

Corporate and Other EBIT

The table below summarizes EBIT for Corporate and Other, which contains the retained costs of the company that are not allocated to our operating businesses, and
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 year ended December 31, 2002 includes our ownership interest in Quanta Services, Inc., a provider of field services to
electric utilities, telecommunications and cable television companies, and governmental entities. We began decreasing our ownership interest in Quanta Services in July 2002 and sold our
remaining shares in February 2003.

Also
included are our former equity method investments in Australia, New Zealand and the United Kingdom, each of which has been sold. 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 year ended December 31, 2002, includes the earnings from our investment in UnitedNetworks Limited, a New Zealand gas and electric distribution company
that we sold in October 2002.

54

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We
sold our former Canadian utility businesses in May 2004 and the results of these operations have been reclassified as discontinued operations and are not included below (see
Note 6 to the Consolidated Financial Statements).

|                                          |                                              | Year Ended December 31, |      
|----------------------------------------- | -------------------------------------------- | ----------------------- | -----
|
|
|                                          |                                              |                         |      
|Sales                                     |                                              | $                       | 38.3 
|Cost of sales                             |                                              |                         | 12.3 
|                                          |                                             
|Gross profit                              |                                              |                         | 26.0 
|                                          |                                             
|Operating expenses:                       |                                              |                         |      
|                                          | Operating expense                            |                         |      
|                                          | Restructuring charges                        |                         |      
|                                          | Net loss on sale of assets and other charges |                         |      
|                                          | Depreciation and amortization expense        |                         |      
|                                          |                                             
|Total operating expenses                  |                                              |                         | 61.7 
|                                          |                                             
|Other income (expense):                   |                                              |                         |      
|                                          | Equity in earnings of investments            |                         |      
|                                          | Gain on sale of subsidiary stock             |                         |      
|                                          | Minority interest in loss of subsidiaries    |                         |      
|                                          | Other income (expense)                       |                         |      
|                                          |                                             
|Earnings (loss) before interest and taxes |                                              | $                       | (24.5
|                                          |                                             

2004 versus 2003

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit increased $6.1 million, $2.7 million and $3.4 million, respectively, in 2004 compared to 2003,
primarily due to an increase in customers and higher average sales to residential and business customers at Everest Connections.

Operating Expense

Operating expense decreased $20.4 million in 2004 compared to 2003, due to a $14.2 million decrease in insurance and other costs associated with
having non-investment grade credit ratings. Consulting fees decreased $8.2 million in 2004 due to the completion of our restructuring efforts in 2003. In addition, the sale of our
international investments in Australia and the United Kingdom decreased operating expenses $12.5 million. These decreases were partially offset by an $8.8 million increase in costs
associated with the settlement of the appraisal rights shareholder lawsuit in 2004 and $4.9 million of additional costs related to the exit of our international networks investment in 2004.

Restructuring Charges

Restructuring charges decreased $3.3 million in 2004 compared to 2003. This was primarily due to $2.1 million of severance and other related costs
that were paid in 2003 in connection with the restructuring of Everest Connections, and $.9 million of executive severance that was paid in 2003.

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

The 2004 net loss on sale of assets and other charges of $2.8 million is mainly due to the $10.6 million impairment on three natural gas combustion
turbines that were held for future construction by one of our non-regulated subsidiaries and have now been transferred to our Missouri electric operations at their current fair value. The
impairment was partially offset by the reversal of our Everest Connections target-based put rights liability of $4.5 million due to the meeting of certain financial and operational performance
measures, and the $3.3 million gain we recorded in connection with the sale of our interest in Midlands Electricity in January 2004. The Midlands Electricity investment was written down
to its estimated fair value in 2002 and again in September 2003. However, due to strengthening of the British pound exchange rate in the fourth quarter of 2003 and in early 2004, we realized a
gain on the closing of the sale. The 2003 loss on sale of assets of $6.9 million was related to the impairment charge taken on our investment in Midlands Electricity in September 2003
and the net loss on the sale of our interests in AlintaGas, United Energy and Multinet Gas in Australia in May and July 2003.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $2.8 million primarily due to customer equipment additions resulting from Everest Connections customer
growth and network expansion.

Equity in Earnings of Investments

Equity in earnings of investments decreased $15.7 million in 2004 compared to 2003 due to the sale of our investments in Australia in May and
July 2003.

Other Income (Expense)

Other income decreased $49.6 million, mainly due to $42.1 million of foreign currency gains recognized in 2003 related to favorable movements in the
Australian and New Zealand dollar against the U.S. dollar, and $12.3 million of foreign currency gains recognized in the second quarter of 2003 due to the strengthening of the Canadian dollar
on U.S. dollar obligations at a former Canadian finance subsidiary not included in discontinued operations. We had an $11.9 million gain on foreign currency related to the wind-down
of our Canadian merchant subsidiaries in 2004. Additionally in 2004, we realized a $1.9 million gain on the early redemption of the note payable issued in connection with our acquisition of
Midlands, which was offset by $1.8 million in fees paid to lenders in connection with the waiver and amendment of financial covenants under our retired secured term loan. These gains in 2004
were partially offset by $8.7 million of prepayment penalties and fees we paid in association with the retirement of the secured term loan.

2003 versus 2002

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit increased $19.3 million, $5.7 million and $13.6 million, respectively, in 2003 compared to 2002,
primarily due to an increase in customers at Everest Connections.

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Operating Expense

Operating expense increased $9.0 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 and $6.5 million of cost savings in Everest Connections associated with the restructuring of its
operations in 2003. In addition, our losses on investments associated with the cash surrender value of certain life insurance policies were greater in 2002 than 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 $5.7 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, partially offset by the restructuring of the operations of Everest
Connections in the first half of 2003. This resulted in the termination of approximately 160 employees and $2.1 million of severance and related restructuring costs.

Net Loss on Sale of Assets and Other Charges

Net loss on sale of assets and other charges 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. The 2002 impairments also included 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. See Note 5 to the Consolidated Financial
Statements for further explanation.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $12.0 million primarily due to the reduced depreciable asset base at Everest Connections resulting from the
impairment charge recorded in the fourth quarter of 2002.

Equity in Earnings of Investments

Equity in earnings of investments decreased $98.2 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 2003 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 management fees from Midlands, 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.

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Gain on Sale of Subsidiary Stock

In October 2002, we sold our shares in our New Zealand utility business in a public tender offer and realized a gain of $130.5 million.

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

Other Income (Expense)

Other income increased $71.3 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. This increase was also due
to $12.3 million of foreign currency gains recognized in the second quarter of 2003 due to the strengthening of the Canadian dollar on U.S. dollar obligations of a former Canadian finance
subsidiary not included in discontinued operations.

Interest Expense and Income Tax Benefit

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

|                   |  | Year Ended December 31, |       
|------------------ |  | ----------------------- | ------
|
|
|                   |  |                         |       
|Interest expense   |  | $                       | 258.4 
|                   | 
|Income tax benefit |  | $                       | (213.3
|                   | 

2004 versus 2003

Interest Expense

Interest expense decreased $14.7 million in 2004 compared to 2003. The decrease was primarily the result of the following:



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These
decreases were partially offset by the following increase in interest expense:



Income Tax Benefit

The income tax benefit increased $68.2 million in 2004 compared to 2003, primarily due to increased pretax losses, the decrease in net valuation allowances
provided on capital losses and the accrual of non-deductible fines and penalties in 2003.

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.

Income Tax Benefit

The income tax benefit decreased $47.7 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.

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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. These activities require that management make certain judgments regarding the election of the normal purchases
and sales exceptions.

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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, 2004 were $138.1 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 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
2004, we evaluated the carrying value of three power peaking plants we own. As of December 31, 2004, the carrying value of these plants was $467.7 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, 2004. 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.

Goodwill and Other Intangible Assets

On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142 we no longer amortize
goodwill, but instead test it for impairment

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each
year on November 30, and if impaired, write it off against earnings at that time. 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, 2004 was $111.0 million.

Regulatory Accounting Implications

We currently record the economic effects of regulation in accordance with the provisions of SFAS No. 71 "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71). Accordingly, our balance sheet reflects certain costs as regulatory assets. We are required to periodically assess the probable recovery of our 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, 2004 were $126.8 million and $88.3 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
using a "more likely than not" assessment of realization. This assessment takes into consideration tax planning strategies within our control, including assumptions regarding the availability and
character of future taxable income. As of December 31, 2004, we have recorded $304.7 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 or state taxable income to enable us to realize the related tax assets.

As
of December 31, 2004, we had approximately $460.7 million of federal net operating loss carryforwards originating in 2003 and $418.4 million of estimated federal
net operating losses originating in 2004. The 2003 federal net operating loss carryforward expires in 2023 and can be carried back to 2001 to offset potential IRS audit adjustments. The 2004 federal
net operating loss carryforward expires in 2024 and cannot be carried back due to losses in the carryback years. We did not record valuation allowances against the deferred tax assets related to
federal net operating losses. This determination was based on our assessment that it is more likely than not

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that
we will realize these deferred assets during the carryforward period. This assessment considered the forecasted reversal of existing temporary differences and taxable income expected to be
generated in the carryforward period and potential IRS audit adjustments in 2001.

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, 2004, 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, 2004, and our estimated annual
pension cost (APC) on the income statement for 2005 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                              | % |                           | -     |                           |  
|                              | 

Significant Balance Sheet Movements

Total assets decreased by $2,941.8 million since December 31, 2003. This decrease is primarily due to the following:



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Total
liabilities decreased by $2,713.0 million and common shareholders' equity decreased by $228.8 million since December 31, 2003. These changes are primarily
attributable to the following:



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New Accounting Standards

In 2004, the FASB issued a revised Interpretation No. 46, "Consolidation of Variable Interest Entities," a new SFAS and a FASB Staff Position that had
potential impacts on our financial results: SFAS No. 123R, "Share-Based Payments," and FASB Staff Position No. 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003." 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). See Notes 1, 2 and 19 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. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual
results to differ materially from those anticipated. The forward-looking statements contained in this report include:



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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market RiskUtility Operations

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 PGA provisions that allow them to pass the prudently-incurred cost of gas through 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. These adjustments are subject to periodic prudence reviews
by the state utility commissions.

In
our regulated electric business in 2004, we generated approximately 57% of the power that we sold and we purchased the remaining 43% through long-term contracts or in the
open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have an Energy Cost Adjustment and an Incentive Clause Adjustment, respectively, that serve
a purpose similar to the PGAs for our gas utilities. 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 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 exposure to commodity price changes is concentrated in the Missouri electric operations resulting in
greater earnings volatility from year to year there than in our other electric rate jurisdictions.

We
have taken several measures to mitigate the commodity price risk exposure in our Missouri electric operations. One of these measures is contracting for a diverse supply of coal to
meet 94% of our native load fuel requirements of coal-fired generation in 2005 and 87% in 2006 through 2007, respectively. We are currently receiving reduced volumes on one of these coal
contracts because of a declared partial force majeure that occurred in 2004. The price risk associated with our natural gas and on-peak spot market purchased power
requirements is also mitigated through a dollar-cost averaging hedging plan using NYMEX futures contracts and options. This is a multi-year hedging plan. As of
December 31, 2004, we had financial contracts in place to price hedge approximately 66% of our on-peak natural gas and natural gas equivalent purchased power price exposure for
2005.

Additional
factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of
fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and scheduled outages at our facilities that use
fossil fuels. Our customers' electricity usage could also vary from year to year based on the weather or other factors.

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 primarily 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,

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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 (VaR) for all commodities during 2004 was $2.4 million. Our Board of Directors sets our VaR limit. We are currently limited to
$3.0 million for the remaining commodity trading portfolio and a $5.0 million target for the aggregate book that includes the first 18 months of Merchant Services asset positions.
In addition to VaR, 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. Additionally, we have one remaining highly customized actuarial-based contract, which expires in September 2006, with life-of-contract VaR of approximately
$22.2 million at December 31, 2004.

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.

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

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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 2004 are summarized below:

|In millions                             |  | Total |       
|--------------------------------------- |  | ----- | ------
|                                        | 
|                                        |  |       |       
|Fair value at December 31, 2003         |  | $     | 130.0 
|Reduction in fair value during the year |  |       | (154.0
|Contracts realized or cash settled      |  |       | 45.4  
|                                        | 
|Fair value at December 31, 2004         |  | $     | 21.4  
|                                        | 

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

|In millions                                        |  | 2005 |       | 2006 |   | 2007 |   | 2008 |      | Thereafter |   | Total
|-------------------------------------------------- |  | ---- | ----- | ---- | - | ---- | - | ---- | ---- | ---------- | - | -----
|                                                  
|                                                   |  |      |       |      |   |      |   |      |      |            |   |      
|Prices actively quoted                             |  | $    | (12.4 | )    | $ | 13.8 |   | $    |     |            | $ |     
|Prices provided by other external sources          |  |      |      |      |   |     |   |      | 18.4 |            |   |     
|Priced based on models and other valuation methods |  |      |      |      |   | (5.4 | ) |      |     |            |   | 1.9  
|                                                  
|Net price risk management assets (liabilities)     |  | $    | (12.4 | )    | $ | 8.4  |   | $    | 18.4 |            | $ | 1.9  
|                                                  

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, 2004, associated with our forward positions within our trading portfolio and our billed receivables (excluding
residential

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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   |       | $                | 37.3  |                      | $ | 138.1
|Financial institutions    |       |                  | 113.2 |                      |   |     
|Oil and gas producers     |       |                  | .1    |                      |   |     
|Commercial and industrial |       |                  |      |                      |   | 3.2  
|                         
|                          | Total |                  | $     | 150.6                |   | $    
|                         

In
our Domestic Utilities business, approximately 54% of our sales are to residential customers. Therefore, our credit risk associated with these sales is relatively low. See
pages 7 and 8 under Properties for a breakout of our customers by type.

Currency Rate Exposure

We have substantially wound down our United Kingdom and Canadian merchant trading businesses, which are included in our Merchant Services segment, and have sold
our international utility businesses in Canada, Australia, New Zealand and the United Kingdom. Our remaining currency rate exposure relates only to approximately $58.5 million of cash held in
foreign countries, a limited trading portfolio in Canada and the resolution of outstanding tax obligations and receivables.

Interest Rate Exposure

We have approximately $275.1 million in unhedged variable rate financial obligations. A 100-basis-point change in the variable rate financial
instruments would affect net income by approximately $1.7 million.

72

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Item 8. Financial Statements and Supplementary Data

|                                                                                                   |                                               |       |     | Page No.
|-------------------------------------------------------------------------------------------------- | --------------------------------------------- | ----- | --- | --------
|
|Consolidated Statements of Income for the three years ended December 31, 2004                      |                                               | 74   
|Consolidated Balance Sheets at December 31, 2004 and 2003                                          |                                               | 75   
|Consolidated Statements of Common Shareholders' Equity for the three years ended December 31, 2004 |                                               | 76   
|Consolidated Statements of Comprehensive Income for the three years ended December 31, 2004        |                                               | 77   
|Consolidated Statements of Cash Flows for the three years ended December 31, 2004                  |                                               | 78-79
|Notes to Consolidated Financial Statements:                                                        |                                               | 80   
|                                                                                                   | Summary of Significant Accounting Policies    |       | 80 
|                                                                                                   | New Accounting Standards                      |       | 86 
|                                                                                                   | Risk Management                               |       | 87 
|                                                                                                   | Restructuring Charges                         |       | 90 
|                                                                                                   | Net Loss on Sale of Assets and Other Charges  |       | 93 
|                                                                                                   | Discontinued Operations                       |       | 99 
|                                                                                                   | Restricted Cash                               |       | 103
|                                                                                                   | Accounts Receivable                           |       | 104
|                                                                                                   | Property, Plant and Equipment                 |       | 104
|                                                                                                   | Investments in Unconsolidated Subsidiaries    |       | 106
|                                                                                                   | Regulatory Assets                             |       | 112
|                                                                                                   | Short-Term Debt                               |       | 114
|                                                                                                   | Long-Term Debt                                |       | 115
|                                                                                                   | Long-Term Gas Contracts                       |       | 119
|                                                                                                   | Capital Stock and Stock Compensation          |       | 120
|                                                                                                   | Accumulated Other Comprehensive Income (Loss) |       | 125
|                                                                                                   | Earnings (Loss) Per Share                     |       | 125
|                                                                                                   | Income Taxes                                  |       | 126
|                                                                                                   | Employee Benefits                             |       | 131
|                                                                                                   | Segment Information                           |       | 136
|                                                                                                   | Commitments and Contingencies                 |       | 139
|                                                                                                   | Quarterly Financial Data (Unaudited)          |       | 144
|Report of Independent Registered Public Accounting Firm                                            |                                               | 145  
|Report of Independent Registered Public Accounting Firm                                            |                                               | 146  

73

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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                                              |                                              |                          | 1,711.0
|                                                         |                                             
|Cost of sales:                                           |                                              |                          |        
|                                                         | Electricityregulated                        |                          |        
|                                                         | Natural gasregulated                        |                          |        
|                                                         | Electricitynon-regulated                    |                          |        
|                                                         | Natural gasnon-regulated                    |                          |        
|                                                         | Othernon-regulated                          |                          |        
|                                                         |                                             
|Total cost of sales                                      |                                              |                          | 1,214.2
|                                                         |                                             
|Gross profit                                             |                                              |                          | 496.8  
|                                                         |                                             
|Operating expenses:                                      |                                              |                          |        
|                                                         | Operating expense                            |                          |        
|                                                         | Restructuring charges                        |                          |        
|                                                         | Net loss on sale of assets and other charges |                          |        
|                                                         | Depreciation and amortization expense        |                          |        
|                                                         |                                             
|                                                         |                                              | Total operating expenses |        
|                                                         |                                             
|Other income (expense):                                  |                                              |                          |        
|                                                         | Equity in earnings of investments            |                          |        
|                                                         | Minority interest in loss of subsidiaries    |                          |        
|                                                         | Gain on sale of subsidiary stock             |                          |        
|                                                         | Other income                                 |                          |        
|                                                         |                                             
|                                                         |                                              | Total other income       |        
|                                                         |                                             
|Interest expense                                         |                                              |                          | 258.4  
|                                                         |                                             
|Loss from continuing operations before income taxes      |                                              |                          | (562.5 
|Income tax benefit                                       |                                              |                          | (213.3 
|                                                         |                                             
|Loss from continuing operations                          |                                              |                          | (349.2 
|Earnings (loss) from discontinued operations, net of tax |                                              |                          | 56.7   
|Cumulative effect of accounting change, net of tax       |                                              |                          |       
|                                                         |                                             
|Net Loss                                                 |                                              | $                        | (292.5 
|                                                         |                                             
|Basic and diluted earnings (loss) per common share:      |                                              |                          |        
|                                                         | Continuing operations                        |                          | $      
|                                                         | Discontinued operations                      |                          |        
|                                                         | Cumulative effect of accounting change       |                          |        
|                                                         |                                             
|                                                         | Net loss                                     |                          | $      
|                                                         |                                             

See accompanying notes to consolidated financial statements.

74

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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                       |             
|                                           | Prepaid pension                                    |             
|                                           | Other current assets                               |             
|                                           | 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               |             
|                                           | Accounts payable                                   |             
|                                           | Accrued interest                                   |             
|                                           | Other 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                            |             
|                                           | 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.

75

---





Aquila, Inc.  Consolidated Statements of Common Shareholders' Equity

|                                                                                                                                                                                                                                                                                                                   |                                                                             | Year Ended December 31, |         
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | --------------------------------------------------------------------------- | ----------------------- | --------
|
|
|                                                                                                                                                                                                                                                                                                                   |                                                                             |                         |         
|Common stock:authorized 400,000,000 at December 31, 2004, 2003 and 2002, par value $1 per share, 241,739,573 shares issued at December 31, 2004 (195,252,630 at December 31, 2003
and 193,782,782 at December 31, 2002); 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                                                                                                                                                                                                                                                                                                |                                                                             |                         | 241.7   
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|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 shares under compensation arrangements                          |                         |         
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|Balance end of year                                                                                                                                                                                                                                                                                                |                                                                             |                         | 3,228.6 
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|Retained earnings (deficit):                                                                                                                                                                                                                                                                                       |                                                                             |                         |         
|                                                                                                                                                                                                                                                                                                                   | Balance beginning of year                                                   |                         |         
|                                                                                                                                                                                                                                                                                                                   | Net loss                                                                    |                         |         
|                                                                                                                                                                                                                                                                                                                   | Other                                                                       |                         |         
|                                                                                                                                                                                                                                                                                                                   | Dividends on common stock, ($.775 per share in 2002)                        |                         |         
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|Balance end of year                                                                                                                                                                                                                                                                                                |                                                                             |                         | (2,340.6
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|Treasury stock, at cost, 251 shares at December 31, 2004 (129 shares at December 31, 2003 and 7,443 shares at December 31, 2002)                                                                                                                                                                                   |                                                                             |                         |        
|Accumulated other comprehensive income (loss)                                                                                                                                                                                                                                                                      |                                                                             |                         | .8      
|                                                                                                                                                                                                                                                                                                                   |                                                                            
|Total Common Shareholders' Equity                                                                                                                                                                                                                                                                                  |                                                                             | $                       | 1,130.5 
|                                                                                                                                                                                                                                                                                                                   |                                                                            

See
accompanying notes to consolidated financial statements.

76

---



Aquila, Inc.  Consolidated Statements of Comprehensive Income

|                                                                                                                                                           |                                                                                                                                                                                                                | Year Ended December 31,            |       
|---------------------------------------------------------------------------------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------- | ------
|
|
|                                                                                                                                                           |                                                                                                                                                                                                                |                                    |       
|Net loss                                                                                                                                                   |                                                                                                                                                                                                                | $                                  | (292.5
|Other comprehensive income (loss), net of related tax:                                                                                                     |                                                                                                                                                                                                                |                                    |       
|Foreign currency adjustments:                                                                                                                              |                                                                                                                                                                                                                |                                    |       
|                                                                                                                                                           | Foreign currency translation adjustments, net of deferred tax expense (benefit) of $(14.5) million and $50.3 million for 2004 and 2003, respectively                                                           |                                    |       
|                                                                                                                                                           | Reclassification of foreign currency (gains) losses to income due to sale of businesses and other, net of deferred tax (expense) benefit of $(26.2) million and $(9.5) million for 2004 and 2003,
respectively |                                    |       
|                                                                                                                                                           |                                                                                                                                                                                                               
|                                                                                                                                                           |                                                                                                                                                                                                                | Total foreign currency adjustments |       
|                                                                                                                                                           |                                                                                                                                                                                                               
|Cash flow hedges:                                                                                                                                          |                                                                                                                                                                                                                |                                    |       
|                                                                                                                                                           | Unrealized gains (losses) on hedging instruments during the period, net of deferred tax expense (benefit) of $(1.0) million, $(.4) million and $(10.9) million for 2004, 2003 and 2002, respectively           |                                    |       
|                                                                                                                                                           | Unrealized gains (losses) on hedging instruments of equity method investments, net of deferred tax expense (benefit) of $(5.6) million and $(1.7) million for 2003 and 2002, respectively                      |                                    |       
|                                                                                                                                                           | Reclassification of net losses (gains) on hedging instruments to net income, net of deferred tax benefit (expense) of $.8 million, $9.1 million and $2.4 million for 2004, 2003 and 2002,
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 $5.5 million and $1.8 million for 2004 and 2003,
respectively  |                                    |       
|                                                                                                                                                           |                                                                                                                                                                                                               
|                                                                                                                                                           |                                                                                                                                                                                                                | 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) expense of $2.7 million and $(2.7) million for 2004 and 2003, respectively |                                                                                                                                                                                                                |                                    | 4.4   
|                                                                                                                                                           |                                                                                                                                                                                                               
|Other comprehensive income (loss)                                                                                                                          |                                                                                                                                                                                                                |                                    | (49.8 
|                                                                                                                                                           |                                                                                                                                                                                                               
|Total Comprehensive Loss                                                                                                                                   |                                                                                                                                                                                                                | $                                  | (342.3
|                                                                                                                                                           |                                                                                                                                                                                                               

See
accompanying notes to consolidated financial statements.

77

---





Aquila, Inc.  Consolidated Statements of Cash Flows

|                                        |                                                                              | Year Ended December 31, |                                                                                            
|--------------------------------------- | ---------------------------------------------------------------------------- | ----------------------- | -------------------------------------------------------------------------------------------
|
|                                        |                                                                             
|                                        |                                                                              |                         |                                                                                            
|Cash Flows From Operating Activities:   |                                                                              |                         |                                                                                            
|                                        | Net loss                                                                     |                         | $                                                                                          
|                                        | Adjustments to reconcile net loss to net cash used for operating activities: |                         |                                                                                            
|                                        |                                                                              |                         | Depreciation and amortization expense                                                      
|                                        |                                                                              |                         | Gain on sale of subsidiary stock                                                           
|                                        |                                                                              |                         | Restructuring charges                                                                      
|                                        |                                                                              |                         | Cash paid for restructuring and other charges                                              
|                                        |                                                                              |                         | Net loss on sale of assets and other charges                                               
|                                        |                                                                              |                         | 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 of subsidiaries                                                 
|                                        |                                                                              |                         | Changes in certain assets and liabilities, net of effects of acquisitions and divestitures:
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                              |                         |                                                                                            
|                                        |                                                                             
|Cash used for operating activities      |                                                                              |                         | (341.5                                                                                     
|                                        |                                                                             
|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 investing activities |                                                                              |                         | 1,026.3                                                                                    
|                                        |                                                                             

78

---



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

|                                                                                                                                                                                                            |                                                      | Year Ended December 31, |         
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------- | ----------------------- | --------
|
|                                                                                                                                                                                                            |                                                     
|                                                                                                                                                                                                            |                                                      |                         |         
|Cash Flows From Financing Activities:                                                                                                                                                                       |                                                      |                         |         
|                                                                                                                                                                                                            | Issuance of 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                                                                                                                                                          |                                                      |                         | (1,117.2
|                                                                                                                                                                                                            |                                                     
|Increase (decrease) in cash and cash equivalents                                                                                                                                                            |                                                      |                         | (432.4  
|Cash and cash equivalents at beginning of year (includes $55.8 million, $55.6 million and $45.0 million of cash included in current assets of discontinued operations in 2004, 2003 and 2002, respectively) |                                                      |                         | 657.5   
|                                                                                                                                                                                                            |                                                     
|Cash and Cash Equivalents at End of Year (includes $55.8 million and $55.6 million of cash included in current assets of discontinued operations in 2003 and 2002, respectively)                            |                                                      | $                       | 225.1   
|                                                                                                                                                                                                            |                                                     
|Supplemental cash flow information:                                                                                                                                                                         |                                                      |                         |         
|                                                                                                                                                                                                            | Interest paid, net of amount capitalized             |                         | $       
|                                                                                                                                                                                                            | Income taxes paid (refunded), net                    |                         |         
|                                                                                                                                                                                                            |                                                     

See
accompanying notes to consolidated financial statements.

79

---





Aquila, Inc.  Notes to Consolidated Financial Statements

Note 1: Summary of Significant Accounting Policies

Description of Business

Aquila, Inc. (Aquila) is an energy provider headquartered in Kansas City, Missouri. We operate in two business segments, Domestic Utilities and Merchant
Services.

Domestic
Utilities operates primarily as Aquila in the distribution and transmission of electricity and natural gas to retail and wholesale customers in seven states. Our electric
generation facilities and purchase power contracts 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.

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. 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. Aquila Merchant currently owns or contractually controls non-regulated
merchant power plants. Our former investments in 13 independent power plants were sold in the first quarter of 2004. Two of these plants that were consolidated are reported in discontinued operations.
Merchant 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.

Corporate
and Other includes the costs of the company that are not allocated to our operating businesses. Corporate and Other 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. 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.

We
also owned and operated electric utilities in two Canadian provinces, which were sold in May 2004 and are reported in discontinued operations.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States required that we make certain
estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of December 31, 2004 and 2003, and the reported
amounts of sales and expenses during the three years ended December 31, 2004. Significant items subject to such estimates and assumptions include the carrying value of property, plant and
equipment; the valuation of

80

---



derivative
instruments; valuation allowances for receivables and deferred income taxes; and assets and liabilities related to employee benefits. Actual results could differ materially 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
evaluated the carrying value of our equity method investments periodically or when there were 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 considered 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 SEC 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 SFAS 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, 2004, we had goodwill in continuing operations of $113.6 million, less accumulated
amortization of $2.6 million.

81

---



Our goodwill was allocated to each segment as follows:

|In millions                |                                         | Domestic
Utilities |       | Merchant
Services |   | Corporate and Other |        | Total Continuing Operations |      | Total Discontinued Operations |  
|-------------------------- | --------------------------------------- | ------------------ | ----- | ----------------- | - | ------------------- | ------ | --------------------------- | ---- | ----------------------------- | -
|
|Balance, December 31, 2001 |                                         | $                  | 109.0 |                   | $ | 6.2                 |        | $                           | 26.6 |                               | $
|                           | Repurchase of Aquila Merchant shares(a) |                    |       |                  |   |                     | 189.0  |                             |      |                              |  
|                           | Merchant Services impairment(b)         |                    |       |                  |   |                     | (181.2 | )                           |      |                              |  
|                           | Everest Connections impairment(b)       |                    |       |                  |   |                     |       |                             |      | (21.6                         | )
|                           | Sales of businesses(c)                  |                    |       |                  |   |                     | (14.0  | )                           |      | (5.0                          | )
|                           | Exchange rate change and other          |                    |       | 2.0               |   |                     |       |                             |      |                              |  
|                           |                                        
|Balance, December 31, 2002 |                                         |                    | 111.0 |                   |   |                    |        |                             |     |                               |  
|                           | Exchange rate change and other          |                    |       |                  |   |                     |       |                             |      |                              |  
|                           |                                        
|Balance, December 31, 2003 |                                         |                    | 111.0 |                   |   |                    |        |                             |     |                               |  
|                           | Sales of businesses(c)                  |                    |       |                  |   |                     |       |                             |      |                              |  
|                           | Exchange rate change                    |                    |       |                  |   |                     |       |                             |      |                              |  
|                           |                                        
|Balance, December 31, 2004 |                                         | $                  | 111.0 |                   | $ |                    |        | $                           |     |                               | $
|                           |                                        



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
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

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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 do so. 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 contracted threshold cooling or heating degree-days in the period multiplied by the
contract price.

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.

Inventories

Our inventories consist primarily of natural gas in storage, coal, materials and supplies that are valued at weighted average cost.

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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 reduction 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 forecasted volumes of gas to be delivered. See Note 14 for further discussion.

Income Taxes

We use the liability method to reflect income taxes on our financial statements. We recognize deferred tax assets and liabilities by applying enacted tax rates
and regulations to the differences between the carrying value of existing assets and liabilities and their respective tax basis and capital loss and tax credit carryforwards. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in the period that the change 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. If it is probable that we will receive regulatory recovery, we record these costs in a regulatory asset.

Stock Based Compensation

We issue stock options to employees from time to time and account for these options under APB 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.

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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 |                                                                                                        | 2004 |   | 2003   |   | 2002 |       
|------------------------------------- | ------------------------------------------------------------------------------------------------------ | ---- | - | ------ | - | ---- | ------
|
|Net loss:                             |                                                                                                        |      |   |        |   |      |       
|                                      | As reported                                                                                            |      | $ | (292.5 | ) | $    | (336.4
|                                      | Premium Income Equity Securities (PIES) adjustment (Note 13)                                           |      |   | 9.4    |   |      |      
|                                      |                                                                                                       
|                                      | Loss available for common shares                                                                       |      |   | (283.1 | ) |      | (336.4
|                                      | Total stock-based employee compensation expense determined under fair value method, net of related tax |      |   | (9.3   | ) |      | (5.4  
|                                      |                                                                                                       
|                                      | Pro forma net loss                                                                                     |      | $ | (292.4 | ) | $    | (341.8
|                                      |                                                                                                       
|Basic and diluted loss per share:     |                                                                                                        |      |   |        |   |      |       
|                                      | As reported                                                                                            |      | $ | (1.13  | ) | $    | (1.73 
|                                      | Pro forma                                                                                              |      |   | (1.16  | ) |      | (1.76 
|                                      |                                                                                                       

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:

|                                      |  | 2004 |           | 2003 |   | 2002   
|------------------------------------- |  | ---- | --------- | ---- | - | -------
|
|Weighted average fair value per share |  | $    | 2.25      |      | $ | ..85   
|Expected volatility                   |  |      | 83%       |      |   | 55%    
|Risk-free interest rate               |  |      | 3.40%     |      |   | 3.53%  
|Expected lives                        |  |      | 3.7 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
December 2004, the FASB issued SFAS No. 123R, "Share-Based Payments," that would require all companies to expense the value of employee stock options in periods
beginning after June 15, 2005. Based on the small number of options that are expected to be unvested at that date, we do not expect the impact of this standard to have a material effect on our
financial statements.

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, 2004 and 2003, our cash held in
foreign countries was $58.5 million and $104.6 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

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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 2004 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 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. The adoption of this interpretation did not have a material effect on our financial statements.

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 required 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 that 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.

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Note 3: Risk Management

Overview

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

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 commitments to purchase or sell financial instruments or commodities at fixed prices at future dates. The contractual
amounts and terms of these financial instruments at December 31, 2004 are below:

|                    |                             | December 31, 2004
|------------------- | --------------------------- | -----------------
|
|
|
|Energy Commodities: |                             |                  
|                    | Natural gas(trillion Btu's) |                  
|                    | Electricity(megawatt-hours) |                  
|                    | Crude oil(barrels)          |                  
|Financial Products: |                             |                  
|                    | Interest rate instruments   |                  
|                   

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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.

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, 2004, 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, 2004, and the average value for the year ended December 31, 2004:

|            |  | Price Risk Management Assets |       | Price Risk Management Liabilities
|----------- |  | ---------------------------- | ----- | ---------------------------------
|
|
|            |  |                              |       |                                  
|Natural gas |  | $                            | 615.2 |                                  
|Electricity |  |                              | 48.3  |                                  
|Coal        |  |                              | 11.2  |                                  
|Other       |  |                              | 9.5   |                                  
|           
|Total       |  | $                            | 684.2 |                                  
|           

Our
price risk management assets are concentrated with ten counterparties representing 76% of the total asset value of the portfolio. This concentration of customers may impact our
overall exposure to credit risk, either positively or negatively, as 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

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assess,
both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or
cash flows of the related underlying exposures. Any ineffective portion of a financial instrument's change in fair value is recognized in other income (expense) 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, is 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 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 $8.8 million decrease in OCI related to cash flow hedges in 2004, net of both taxes and reclassifications to earnings.

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 utility businesses produce, purchase and distribute power in three states and purchase and distribute gas in seven states. All of our gas distribution
utilities have PGA provisions that allow them to pass the prudently-incurred 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. These adjustments are subject to periodic prudence reviews by the state utility
commissions. In addition, as allowed by state regulatory commissions, we have entered into certain financial instruments to reduce our customers' underlying exposure to fluctuations in gas prices.
These instruments are collectible under the provisions of the PGA upon settlement.

In
2004, our regulated electric business generated approximately 57% of the power that we sold and purchased the remaining 43% through long-term contracts or in the open
market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have

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an
Energy Cost Adjustment and an Incentive Clause Adjustment, respectively, that serve a purpose similar to that of the PGAs for the gas utilities. 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 Missouri, there is no provision to pass through changes in costs except through a
rate case filing. We are, however, currently operating under a two-year settlement agreement that allows us to recover such costs up to a specified amount per Mwh specific to each of our
Missouri service territories. The settlement rate per unit sold is $13.98/Mwh for our St. Joseph Light & Power operations and $19.71/Mwh for our Missouri Public Service operations. Our actual
costs since the rate increase went into effect pursuant to the settlement agreement on April 22, 2004 have exceeded the amount allowed under the settlement by approximately $1.8 million
through December 31, 2004. If the amounts collected under the settlement agreement exceed our cost incurred for the two-year period, we will be required to refund the excess with
interest to our customers. We will not recover the excess of the actual costs over the settlement rate. 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.

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 Merchant Services and the restructuring of our Domestic Utilities, we have recorded the following restructuring
charges:

|                                    |                                                    | Year Ended December 31,
|----------------------------------- | -------------------------------------------------- | -----------------------
|
|
|                                    |                                                    |                        
|Domestic Utilities:                 |                                                    |                        
|                                    | Severance costs                                    |                        
|                                    | Disposition of corporate aircraft                  |                        
|                                   
|Total Domestic Utilities            |                                                    |                        
|                                   
|Merchant Services:                  |                                                    |                        
|                                    | Interest rate swap reductions                      |                        
|                                    | 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 Merchant 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 $.9 million in 2004 related to the continued exit from our Merchant Services business and the sale of our
investments in international networks.

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 Corporate and Other. This resulted from the termination of approximately 160 employees. We also incurred $2.2 million of retention payments in 2003 related to
trhe continued wind-down of our domestic and international energy trading operations in Merchant Services, and $1.4 million of Corporate and Other severance costs related to our
continued exit from Merchant Services and the restructuring of Domestic Utilities.

We
incurred $55.7 million of total severance costs in 2002 related to the restructuring of Domestic Utilities in order to more closely align it with its regulatory service areas
and the decision to exit our energy trading business in Merchant Services. These actions resulted in the termination of approximately 1,205 energy trading employees, 500 Domestic Utilities 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 from 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, the notional amount of our interest rate swaps exceeded the outstanding debt. As a
result, we reduced our swap position and realized the loss associated with the cancelled portion of the 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 and retention costs at beginning of period |                         | $  
|                                                       | Additional expense during the period                         |                         |    
|                                                       | Cash payments during the period                              |                         |    
|                                                       |                                                             
|Accrued severance and retention costs at end of period |                                                              | $                       | .8 
|                                                       |                                                             
|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)  |                                                              | $                       | 7.0
|                                                       |                                                             



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

Pretax net loss (gain) on sale of assets and other charges we recorded for the years ended December 31, 2004, 2003 and 2002 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. The after-tax losses (gains) discussed below are based on current
estimates of the tax treatment of these transactions and may be adjusted after detailed allocation of the purchase price for tax purposes and the filing of tax returns including these sales.

|                                                   |                                                         | Year Ended December 31, |      
|-------------------------------------------------- | ------------------------------------------------------- | ----------------------- | -----
|
|
|                                                   |                                                         |                         |      
|Domestic Utilities:                                |                                                         |                         |      
|                                                   | Gas distribution system                                 |                         | $    
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Domestic Utilities                           |                                                         |                         |     
|                                                   |                                                        
|Merchant Services:                                 |                                                         |                         |      
|                                                   | Aries power project and tolling agreement               |                         |      
|                                                   | Termination of long-term gas contracts                  |                         |      
|                                                   | Red Lake gas storage development project                |                         |      
|                                                   | Acadia tolling agreement                                |                         |      
|                                                   | Turbine contracts                                       |                         |      
|                                                   | Independent power plants                                |                         |      
|                                                   | Investment in BAF Energy                                |                         |      
|                                                   | Enron bankruptcy                                        |                         |      
|                                                   | Marchwood development project                           |                         |      
|                                                   | Merchant Services goodwill                              |                         |      
|                                                   | Exit from Lodi gas storage investment                   |                         |      
|                                                   | Termination of Cogentrix acquisition                    |                         |      
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Merchant Services                            |                                                         |                         | 185.5
|                                                   |                                                        
|Corporate and Other:                               |                                                         |                         |      
|                                                   | Quanta Services                                         |                         |      
|                                                   | Everest Connections and other communication investments |                         |      
|                                                   | Midlands                                                |                         |      
|                                                   | Australia                                               |                         |      
|                                                   | Turbines impairment                                     |                         |      
|                                                   | Other                                                   |                         |      
|                                                   |                                                        
|Total Corporate and Other                          |                                                         |                         | 2.8  
|                                                   |                                                        
|Total net loss on sale of assets and other charges |                                                         | $                       | 188.3
|                                                   |                                                        

During
2004, 2003 and 2002, we also incurred net loss (gain) on sale of assets and other charges of $(74.0) million, $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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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.

Aries Power Project and Tolling Agreement

In March 2004, we transferred to Calpine Corp., our joint venture partner in the Aries power project, our 50% ownership interest in this project,
$5.0 million cash and certain transmission and ancillary contract rights in exchange for the termination of our remaining aggregate undiscounted payment obligation of approximately
$397.3 million under our 20-year tolling agreement with the Aries facility. At the same time, Calpine returned approximately $12.5 million of collateral we had posted in
support of ongoing energy trading contracts. We recorded a pretax loss of $46.6 million, or $35.4 million after tax, in connection with this transaction.

Termination of Long-Term Gas Contracts

As discussed in more detail in Note 14, we terminated four of our long-term gas supply contracts resulting in payments of $712.9 million
and pretax losses of $156.2 million, or $97.6 million after tax in 2004.

Red Lake Storage Development Project

In January 2002, we acquired the Red Lake property for development of two salt cavern natural gas storage facilities with a combined working capacity of 12
Bcf. In December 2004, we decided to proceed with the potential sale of this property and signed a letter of intent with a third party for less than the carrying value of our investment. As a
result, we recorded a pretax impairment charge of $8.9 million, or $5.6 million after tax. We are in the process of conducting due diligence with the prospective buyer. The value of this
asset may be adjusted further based on the outcome of the potential sale or future regulatory actions by the FERC.

Acadia Tolling Agreement

In May 2003, we terminated our 20-year tolling agreement for the Acadia power plant located in Louisiana. After making a termination payment of
$105.5 million, resulting in a $63.8 million after-tax loss, we were released from the remaining aggregate payment obligation of $833.9 million, or approximately
$43.5 million on an annual basis.

Turbine Contracts

As discussed in Note 12, we had a contract to acquire four General Electric turbines. Our intent was to place these turbines into future power plant
development projects. However, due to the restructuring of our business and change in our business strategy, we made the decision in the fourth quarter of 2002 to cease these development projects and
to sell these turbines or

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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 November 2003, we agreed to sell our interests in 12 independent power plants. Two of the power plants were 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 were equity method investments that did not qualify for reporting as discontinued operations under SFAS 144 and were 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 closed in March 2004. We received adjusted proceeds of approximately $256.9 million and paid approximately $4.1 million in
transaction fees. As the actual proceeds were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $6.1 million, or $22.6 million after tax in
2004. The after-tax gain was greater than the pretax gain because an income tax benefit of $16.2 million was recognized for the reversal of a valuation allowance provided in 2003.
The 2003 valuation allowance was provided as it was expected that a substantial portion of the loss would be treated as a capital loss, the benefit from which more likely than not would not be
realized. However, the form of the final sale and detailed allocation of the purchase price for tax purposes based on an independent appraisal resulted in a portion of these losses being realized as
ordinary losses. The related valuation allowance was therefore reversed in 2004.

Investment in BAF Energy

We own a 23.11% non-voting limited partnership interest in BAF Energy, a California limited partnership that formerly owned a 120 MW natural
gas-fired combined cycle cogeneration facility in King City, California. In May 2004, Calpine King City Cogen, LLC purchased 100% of the King City cogeneration facility from BAF
Energy. Our share of the proceeds, approximately $24.3 million, was received as a distribution from the partnership in June 2004. As a result of the distribution, we recorded a pretax
gain of $9.1 million, or $5.7 million after tax, in the second quarter of 2004.

Enron Bankruptcy

On March 7, 2005, we reached an agreement with Enron Corp. and certain of its affiliates (Enron). Under this agreement, we will pay $28 million to
Enron to settle all outstanding claims between Enron and Aquila associated with the various bankruptcy filings of Enron in December 2001 and two lawsuits filed by Enron Canada Corp. in
January 2003. In 2001, we

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reserved
for substantially all of our then outstanding receivables from Enron, which resulted in a charge of $66.8 million. This charge did not reflect potential gains we would record in the
event we were successful in netting certain obligations to Enron against these receivables. Approximately $33.5 million of liabilities remained on our books related to contracts with Enron
after the 2001 charge. The settlement is subject to final approval the bankruptcy court. As a result of the settlement, we reduced our net liability to Enron by approximately $6 million, or
$3.7 million after tax.

Marchwood Development Project

In January 2004, we sold undeveloped land and site licenses for a proposed merchant power plant development project in the United Kingdom for approximately
$5.0 million. As a final decision to proceed with construction of this project had not been made, all project development costs had been expensed as incurred. As a result, the pretax gain on
the sale was equal to the net proceeds of $5.0 million, or $3.1 million after tax.

Merchant 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 Merchant
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 $181.2 million of unamortized goodwill in 2002.

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 pretax loss on this transaction of $21.9 million pretax or $21.6 million after-tax.

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 best 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.

Merchant ServicesOther

Included in other impairments for Merchant Services are three additional impairments or losses. In December 2002, we recorded a $4.2 million
impairment charge on one of our equity

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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.

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

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

Certain
minority owners of Everest Connections had the option to sell their ownership units to us if Everest Connections did not meet certain financial and operational performance
measures as of December 31, 2004 (target-based put rights). If the put rights were exercised, we would have been obligated to purchase up to 4.0 million and 4.75 million ownership
units at a price of $1.00 and $1.10 per unit, 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. In 2004, we achieved the operating targets related to 4.0 million and
1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million pretax and after tax of this reserve. We did not achieve the
targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their option and were paid $3.6 million for their
ownership units in February 2005. We had fully reserved for this payment as of December 31, 2004.

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,
received proceeds of $55.5 million and paid approximately $7.6 million in transaction fees. We recorded a pretax and
after-tax gain from this sale of approximately $3.3 million in 2004 due to strengthening in the British pound exchange rate in the fourth quarter of 2003 and early 2004.

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,
which we purchased in May 2002. See Note 10 for further discussion. The purchase price was based on our ability to hold the investment long-term, which would allow us to use
this investment as a base to extract synergies in future acquisitions and to continue to develop certain of its non-regulated businesses. However, our liquidity situation in 2002 caused us
to revise our strategic view of this investment. As a result, in August 2002, we initiated a bid process for the sale of our interest in Midlands Electricity. We received offers in early
December and 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 was consistent with a corresponding impairment charge taken in the financial statements of the underlying business.

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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 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.

Turbines Impairment

In December 2004, we determined that the carrying value of three Westinghouse Siemens natural gas combustion turbines held for future construction by one
of our non-regulated subsidiaries was impaired. These turbines were transferred from the non-regulated subsidiary to our Missouri regulated electric division for the
construction of a 315-megawatt, natural gas peaking generation plant near Peculiar, Missouri. Missouri affiliate transaction rules require that such transfers be made at the lower of fair
market value or fully distributed cost. We obtained an appraisal of the fair value of the turbines, which was less than the carrying value of the turbines and related costs. As a result, we recorded a
pretax impairment charge of approximately $10.6 million, or $6.5 million after tax. This transfer is subject to the final determination of the Missouri Public Service Commission which is
expected in 2005.

Note 6: Discontinued Operations

We have sold the assets discussed below, which are considered discontinued operations in accordance with SFAS 144. The only remaining asset that had been
classified as held for sale in 2003 was a merchant note receivable which was not sold with our merchant loan business in 2002. Due to our unsuccessful efforts to sell this note in 2004, we determined
that the asset and its associated results from operations should be reclassified as held for use under the provisions of SFAS 144. As a result, we reclassified $10.4 million of assets to
deferred charges and other assets as of December 31, 2003. Additionally, we reclassified pretax losses (income) of $8.8 million and $(1.5) million, or $5.4 million and $(.9)
million after tax, to continuing operations for the years ended December 31, 2003 and 2002, respectively.

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

On May 31, 2004, we completed the sale of our Canadian utility operations in Alberta and British Columbia to two wholly-owned subsidiaries of
Fortis Inc., a Canadian energy company, for

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approximately
$1.08 billion (CDN$1.476 billion), including the assumption of debt of $113 million (CDN$155 million) by the purchasers. The closing proceeds include
$85 million (CDN$116 million) of adjustments for working capital and capital expenditures as provided under the sales agreements. We recorded a pretax gain from this sale of
$65.6 million, or $9.1 million after tax, including final working capital and capital expenditure adjustments.

The
effective tax rate on the pretax gain on sale of our Canadian utility businesses is substantially higher than the statutory federal tax rate due to the following factors. The U.S.
taxes reflect the partial deduction of Canadian taxes, including withholding taxes, from the U.S. taxable income instead of the full utilization of foreign tax credits. Taxes on the sale also reflect
our inability to fully utilize the tax loss on the sale of the Alberta business against the tax gain on the sale of the British Columbia business.

Prior
to the closing of the sale, we retired debt related to our Canadian utility operations including $215 million under a 364-day credit facility and
$15 million (CDN$20 million) under a revolving bank credit facility. In addition, we were released at the closing of the sale from our guarantor obligations with respect to our former
British Columbia utility's debentures and second mortgage loan totaling $113.0 million (CDN$155.0 million).

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 independent power plants. Two of the power plants were 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 closed the sale of these plants in March 2004. Because the actual proceeds realized were
greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $8.4 million, or $16.2 million after tax, in the first quarter of 2004. The
after-tax gain was greater than the pretax gain because an income tax benefit of $11.1 million was recognized for the partial reversal of a valuation allowance provided in 2003. The
2003 valuation allowance was provided as it was
expected that a substantial portion of the loss would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale and a
detailed allocation of the purchase price for tax purposes based on an independent appraisal resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance
was therefore reversed in 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 $152.0 million after tax.

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Merchant Loan Portfolio

Historically, we provided capital to energy-related businesses seeking financing for energy projects. After we made the decision to exit the wholesale energy
trading business, we decided to sell our loan portfolio because this business was no longer 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.

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, 2004 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 Consolidated Balance Sheets as follows:

|In millions                                              |                                      | December 31,
2003
|-------------------------------------------------------- | ------------------------------------ | -----------------
|
|                                                         |                                      |                  
|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                                        |                                                          | $                       | 130.9
|Cost of sales                                |                                                          |                         | 25.1 
|                                             |                                                         
|                                             | Gross profit                                             |                         |      
|                                             |                                                         
|Operating expenses:                          |                                                          |                         |      
|                                             | Operating expense                                        |                         |      
|                                             | Impairment charges and net loss (gain) on sale of assets |                         |      
|                                             | Depreciation and amortization expense                    |                         |      
|                                             |                                                         
|Total operating expense                      |                                                          |                         | (17.3
|                                             |                                                         
|Other income (expense):                      |                                                          |                         |      
|                                             | Equity in earnings of investments                        |                         |      
|                                             | Other income (expense)                                   |                         |      
|                                             |                                                         
|Total other income (expense)                 |                                                          |                         | 2.7  
|                                             |                                                         
|Interest expense                             |                                                          |                         | 14.7 
|                                             |                                                         
|Earnings (loss) before taxes                 |                                                          |                         | 111.1
|Income tax expense (benefit)                 |                                                          |                         | 54.4 
|                                             |                                                         
|Earnings (loss) from discontinued operations |                                                          | $                       | 56.7 
|                                             |                                                         

Note 7: Restricted Cash

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

|                                      |  | December 31,
|------------------------------------- |  | ------------
|
|
|                                      |  |             
|Restricted customer funds on deposit  |  | $           
|Escrow for prepayment penalty dispute |  |             
|Other                                 |  |             
|                                     
|Total                                 |  | $           
|                                     

A
large counterparty required us to segregate the customer funds on deposit that it had advanced to us from our daily cash accounts. This amount was considered "restricted cash" and was
not available for day-to-day operations. In September 2004, the underlying contracts with this counterparty were settled and we returned the funds it had deposited with
us from our restricted cash.

Certain
lenders have contested our retirement of the $430 million three-year secured term loan and are seeking additional prepayment penalties of approximately
$20.6 million. As a result, we have deposited $20.6 million with the term loan facility agent and classified the amount as restricted cash. See Note 21 for further discussion.

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Note 8: Accounts Receivable

Our accounts receivable on the Consolidated Balance Sheets are as follows:

|                                       |  | December 31, |      
|-------------------------------------- |  | ------------ | -----
|
|
|                                       |  |              |      
|Merchant Services accounts receivable  |  | $            | 193.1
|Domestic Utilities accounts receivable |  |              | 157.6
|Other accounts receivable              |  |              | 5.3  
|Allowance for doubtful accounts        |  |              | (30.7
|Unbilled utility revenue               |  |              | 138.1
|                                       | 
|Total                                  |  | $            | 463.4
|                                       | 

In
2004, we entered into a $150 million six-month secured revolving credit facility. Borrowings under this facility are secured by the accounts receivable generated by
our regulated utility operations in Colorado, Kansas, Michigan, Missouri and Nebraska. There were no borrowings under this facility at December 31, 2004. See Note 12 for further
discussion.

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 $33.2 million at December 31, 2004.

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                                       |                                          | $            | 2,264.4 
|Gas utility                                            |                                          |              | 1,249.7 
|Non-regulated electric power generation                |                                          |              | 494.9   
|Communications                                         |                                          |              | 77.4    
|Corporate and other                                    |                                          |              | 286.4   
|Electric and gas utility plantconstruction in process |                                          |              | 132.3   
|                                                       |                                         
|                                                       |                                          |              | 4,505.1 
|Lessaccumulated depreciation and amortization         |                                          |              | (1,727.7
|                                                       |                                         
|                                                       | Total property, plant and equipment, net |              | $       
|                                                       |                                         

Our
property, plant and equipment includes acquisition-related adjustments that are being amortized over useful lives not exceeding 40 years. Net amounts included in electric
utility and

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gas
utility that are not included in our rate base were $59.3 million and $64.0 million at December 31, 2004 and 2003, respectively.

|                                        |  | Composite Depreciation Rates |  
|--------------------------------------- |  | ---------------------------- | -
|
|
|                                        |  |                              |  
|Electric utility                        |  | 2.8                          | %
|Gas utility                             |  | 2.9                          | %
|Non-regulated electric power generation |  | 2.8                          | %
|Communications                          |  | 9.0                          | %
|Corporate and other                     |  | 11.6                         | %
|                                        | 

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, operated by Westar Energy, Inc. We also own an 18% interest in a 670-megawatt coal-fired plant (Iatan) operated by Kansas City Power & Light Company.
At December 31, 2004, our investments in the Jeffrey and Iatan plants totaled $194.9 million and related accumulated depreciation was $119.5 million. Our pro rata share of Jeffrey
Energy Center's and Iatan's operating costs are included in our Consolidated Statements of Income.

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 accreted 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.

SFAS 143
requires 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, and removal
and disposal of storage tanks and transformers containing PCB's. 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 borrowing rates depending on the anticipated settlement date.

In
connection with the adoption of SFAS 143 in January 2003, our regulated business recorded an asset retirement obligation of $.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.

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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 $1.1 million as of December 31, 2004.

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.

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 |       | Sold    |  | U.S. & Jamaica |  | $                          |    |                                         
|Midlands Electricity plc *           |       | Sold    |  | United Kingdom |  |                            |    |                                         
|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  |  |                            | 1.5 |                                         
|                                    
|                                     | Total |         |  |                |  |                            | $   | 1.5                                     
|                                    



Independent Power Plant Partnerships

As of December 31, 2003, we owned interests in 14 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 and evaluated the carrying value of these equity method investments based on the bids received and other internal valuations. The
results of this

106

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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. In January 2004, we sold our interest in one of these plants. In March 2004, we closed the sale of our interests in 12 plants for
approximately $256.9 million and paid approximately $4.1 million in transaction costs. As the actual proceeds realized were greater than estimated when we recorded the 2003 impairment
charges, we recorded a pretax gain of $6.1 million, or $22.6 million after tax, in 2004. Two of the power plants, Lake Cogen Ltd. (Lake Cogen) and Onondaga Cogen Ltd.
Partnership (Onondaga), were consolidated on our balance sheet. The remaining 10 plants were equity method investments that did not qualify for reporting as discontinued operations under
SFAS 144 and were therefore included in continuing operations and in the investment table above.

In
May 2004, BAF Energy, in which we own a 23.11% interest, sold the cogeneration facility it owned and distributed to us our share of the proceeds, approximately
$24.3 million. As a result of the distribution, we recorded a pretax gain of $9.1 million, or $5.7 million after tax, in 2004.

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. The gross purchase price 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 us management fees and dividends.
Additionally, the local regulatory body, the Office of Gas and Electricity Markets, 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
£

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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, received proceeds of $55.5 million and
paid approximately $7.6 million in transaction fees. We recorded a pretax and after-tax gain from this sale of approximately $3.3 million in the first quarter of 2004 due to
strengthening in the British pound exchange rate in the fourth quarter of 2003 and early 2004.

Following
is the summarized financial information for Midlands Electricity plc. The balance sheet as of December 31, 2004 and the income statement for the 2004 period are not
included because we sold our investment in January 2004:

|In millions                  |                         | December 31,
2003
|---------------------------- | ----------------------- | -----------------
|
|                             |                         |                  
|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)  |                    | $                       | 80.1
|                   |                   

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.

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In July 2002, UEL and Ikon sold their combined 50% interest in Pulse Energy, a retail electric and gas company. Through our 33.8% ownership in United Energy and our 25.5%
ownership in Ikon, we had an approximately 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, 2004 and 2003 and the income statement for the 2004 period are not included because
we sold our investment in 2003:

|In millions        |                    | Seven Months Ended
July 31,
2003 |      | Year Ended
December 31,
2002
|------------------ | ------------------ | -------------------------------- | ---- | ----------------------------
|                  
|                   |                    |                                  |      |                             
|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.

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; supermajority 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

109

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to
the public for net proceeds of approximately $41 million, reducing our effective interest in UNL to 55.5%.

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 we used 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 pretax gain of $130.5 million, or $28.0 million after tax,
in the fourth quarter of 2002 as a result of the sale of UNL shares.

Following
is the summarized financial information for UNL. The balance sheets as of December 31, 2004 and 2003 and the income statements for the 2004 and 2003 periods are not
included because we sold our investment in 2002:

|In millions        |                    | Nine Months Ended
September 30,
2002
|------------------ | ------------------ | ------------------------------------
|                  
|                   |                    |                                     
|Operating Results: |                    |                                     
|                   | Sales              |                                     
|                   | Costs and expenses |                                     
|                  
|Net income         |                    | $                                   
|                  

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, 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 in 2002.

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Following
is the summarized financial information for Quanta Services. The balance sheets as of December 31, 2004 and 2003 and the income statements for the 2004 and 2003 periods
are not included because we sold our remaining investment in February 2003:

|In millions        |                    | Year Ended
December 31,
2002 |       
|------------------ | ------------------ | ---------------------------- | ------
|                   |                   
|                   |                    |                              |       
|Operating Results: |                    |                              |       
|                   | Sales              |                              | $     
|                   | Costs and expenses |                              |       
|                   |                   
|Net loss           |                    | $                            | (619.6
|                   |                   

Aries Power Project

In March 2004, we transferred to Calpine Corp., our joint venture partner in the Aries power project, our 50% ownership interest in this project,
$5.0 million cash and certain transmission and ancillary contract rights in exchange for the termination of our remaining aggregate undiscounted payment obligation of approximately
$397.3 million under our 20-year tolling agreement with the Aries facility. At the same time, Calpine returned approximately $12.5 million of collateral we had posted in
support of ongoing energy trading contracts. We recorded a pretax loss of $46.6 million, or $35.4 million after tax, in connection with this transaction.

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 and our interest in independent power plants
and Aries in March 2004. Therefore, the balance sheet as of December 31, 2004 and the 2004 income statement are not included. The 2003 balance sheet includes only the independent power
plants and Aries and the results of operations for 2003 includes each investment only for the periods in which we owned them.

|In millions                  |                         | December 31,
2003
|---------------------------- | ----------------------- | -----------------
|                            
|                             |                         |                  
|Assets:                      |                         |                  
|                             | Current assets          |                  
|                             | Non-current assets      |                  
|                            
|Total assets                 |                         | $                
|                            
|                             | Current liabilities     |                  
|                             | Non-current liabilities |                  
|                             | Equity                  |                  
|                            
|Total liabilities and equity |                         | $                
|                            

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|                   |                    | Year Ended
December 31, |      
|------------------ | ------------------ | ----------------------- | -----
|
|                   |                   
|                   |                    |                         |      
|Operating Results: |                    |                         |      
|                   | Sales              |                         | $    
|                   | Costs and expenses |                         |      
|                   |                   
|Net income (loss)  |                    | $                       | 162.4
|                   |                   

Note 11: Regulatory Assets

Federal, state 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.

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     |              |     
|                                    | Pensions                     |              |     
|                                    | Other                        |              |     
|                                    |                             
|                                    | Total regulatory liabilities |              |     
|                                    |                             
|Net regulatory (liabilities) assets |                              | $            | 38.5
|                                    |                             

Regulatory
assets are either currently being collected in rates or are expected to be collected through rates in a future period, as described below:



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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, as
described below:



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.

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Note 12: Short-Term Debt

We had no short-term borrowings outstanding on December 31, 2004 or 2003.

Letter of Credit Facility

In April 2004, we extended a 364-day letter of credit agreement with a commercial bank for an additional 364 days. Under terms of the
agreement, the bank committed to issue letters of credit under the facility subject to a limit of $100.0 million outstanding at any one time. All letters of credit issued are fully secured by
cash deposits with the bank. At December 31, 2004, $71.1 million of letters of credit were outstanding under this facility. Additionally, we have other letters of credit outstanding of
approximately $6.6 million as of December 31, 2004.

Six-Month Secured Revolving Credit Facility

On October 22, 2004, we completed a $125 million secured revolving credit facility (the AR Facility). On December 1, 2004, we amended this
facility to increase the maximum borrowing limit to $150 million. Proceeds may be used for working capital and other general corporate purposes. The facility is secured by the accounts
receivable generated by our regulated utility operations in Colorado, Kansas, Michigan, Missouri and Nebraska. The six-month facility expires April 22, 2005. We expect to extend or
replace this facility prior to its maturity. Borrowings under the AR Facility bear interest at the LIBOR plus 2.50%. Among other restrictions, we are required under the AR Facility to maintain the
same debt-to-total capital and EBITDA-to-interest expense ratios as those contained in the five-year unsecured term loan and revolving
credit facilities discussed in Note 13. There were no borrowings under this AR Facility at December 31, 2004.

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Note 13: Long-Term Debt

This
table summarizes our long-term debt:

|                                                              |                                                                                                                                                                   | December 31,
|------------------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------
|
|                                                             
|                                                              |                                                                                                                                                                   |             
|First Mortgage Bonds:                                         |                                                                                                                                                                   |             
|                                                              | 9.44% Series, due annually through 2021(a)                                                                                                                        |             
|Secured Term Loan:                                            |                                                                                                                                                                   |             
|                                                              | LIBOR plus 5.00%, due April 11, 2006 (retired September 2004)                                                                                                     |             
|Unsecured Term Loan:                                          |                                                                                                                                                                   |             
|                                                              | LIBOR plus 5.75% (8.26% at December 31, 2004), due September 19, 2009                                                                                             |             
|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                                                                                                                                    |             
|Mandatorily Convertible Notes:                                |                                                                                                                                                                   |             
|                                                              | 6.75% Series, mandatorily convertible on September 15, 2007 into common shares at a conversion rate of 8.0386 to 9.8039 shares per $25 par value convertible note |             
|Convertible Subordinated Debentures:                          |                                                                                                                                                                   |             
|                                                              | 6.625%, due July 1, 2011 (convertible into 149,556 common shares at $15.79 per share)                                                                             |             
|Other:                                                        |                                                                                                                                                                   |             
|                                                              | Note Payable, 8.15%, due annually through 2008 (retired February 2004)                                                                                            |             
|                                                              | Other notes and obligations 4.63%*, due 2005-2028(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 Amounts2005

$
42.02006


89.32007(a)


388.32008


2.62009


421.5Thereafter


1,428.2Total

$
2,371.9




Mandatorily Convertible Senior Notes

In August 2004, we issued 13.8 million Premium Income Equity Securities (PIES) at $25 per PIES unit, including an over-allotment of
1.8 million PIES, representing $345.0 million of mandatorily convertible senior notes. These notes are unsecured and bear interest at 6.75% through September 15, 2007. Unless
converted earlier by the holder into our common stock, on
September 15, 2007, these securities will automatically convert into shares of our common stock at a conversion rate ranging from 8.0386 to 9.8039 shares of common stock per PIES, based on the
average closing price of our common stock for the 20-day trading period prior to the mandatory conversion date. Our net proceeds on the issuance of the PIES were $334.3 million,
after underwriting discounts, commissions and other costs. We used the proceeds to retire long-term debt and other long-term liabilities.

If
the mandatory conversion had occurred on December 31, 2004, the average closing price of our common stock for the 20-day trading period used to determine the
conversion rate would have been $3.50. Using that rate, we would have converted each security into 8.0386 shares of our common stock. The fair value of those shares would have been
$409.3 million as of December 31, 2004.

Senior Notes Rating Triggers

In July 2002, we issued $500.0 million of 11.875% senior notes due in July 2012. Because Moody's and S&P 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. Because Moody's and S&P have downgraded our credit ratings, the interest rate on these notes
has been adjusted to a maximum rate of 9.95%.

If
our credit ratings improve to certain levels, the interest rates on these notes and our Five-Year Facilities (discussed below) will be lowered.

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Three-Year Secured Term Loan

In April 2003, we closed on a $430.0 million, three-year secured loan. The initial interest rate on the facility was LIBOR (with a 3% floor)
plus 5.75%. This rate was reduced to LIBOR (with a 3% floor) plus 5.00% when additional regulated utility collateral was pledged. 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 was 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 held our Canadian utility businesses, and
(iii) a pledge of the equity of a wholly-owned subsidiary that indirectly held our interests in independent power plants.

The
$430.0 million secured term loan became immediately due and payable in September 2004 when we did not complete an exchange offer, tender offer, refinancing or other
retirement transaction with regard to 80% of our $150.0 million, 6.875% senior note series due October 1, 2004, at least two weeks prior to its maturity date. We paid our lenders an
early termination fee of 2%, or $8.7 million, pursuant to this provision. We also wrote off $10.3 million of unamortized debt issue costs. Certain lenders participating in the term loan
are contesting the terms of the prepayment and seeking to require us to pay additional prepayment penalties of approximately $20.6 million. We have deposited $20.6 million with the term
loan facility agent pending resolution of this dispute. The liens against our regulated utility assets in Michigan, Nebraska, Iowa and Colorado that were pledged as collateral on the term loan have
been released. See Note 21 for discussion of litigation relating to this dispute.

Five-Year Unsecured Term Loan and Revolving Credit Facility

In September 2004, we completed a $220 million 364-day unsecured term loan and a $110 million 364-day unsecured revolving
credit facility. The facilities automatically extended to September 2009 when we received extension approval from the FERC and various state public utility commissions (Five-Year
Facilities). We borrowed the full amount of the term loan and received $211.3 million of net proceeds after upfront fees and expenses on the two facilities. We had not drawn on the revolving
credit facility as of December 31, 2004. The Five-Year Facilities bear interest at the LIBOR plus 5.75%, subject to reduction if our credit rating improves. Among other
restrictions, the Five-Year Facilities contain the following financial covenants with which we were in compliance as of December 31, 2004:

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The
Five-Year Facilities also contain covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on
acquisitions, sale transactions and investments. In addition, we are prohibited from paying dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by
Moody's and BB by S&P, or if such a payment would cause a default under the facility.

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 required 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 paid $78.6 million to extinguish this note payable and accrued interest, resulting in other income related to this transaction of approximately
$1.9 million.

Credit Ratings

Our non-investment grade 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, 2004, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency  |  | Rating |  | Outlook         
|------- |  | ------ |  | ----------------
|       
|        |  |        |  |                 
|Moody's |  | B2     |  | Stable Outlook  
|S&P     |  | B-     |  | Negative Outlook
|Fitch   |  | B-     |  | Stable Outlook  
|       

We
do not have any debt with repayment provisions linked to our credit ratings.

Secured Financing

We generally are required to obtain the approval of the relevant state public service commission before pledging utility assets located in the state as
collateral. We currently do not have approval to pledge those utility operations as collateral.

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In
addition, we are required to obtain prior approval from the FERC before we can issue long-term or short-term debt. We currently have authority from the FERC to
have up to $350 million of additional short-term, unsecured debt outstanding. Our authority to issue short-term debt expires in March 2006. The FERC recently
issued an order in which it announced that any future debt authorization orders would prohibit companies subject to its jurisdiction from using their utility properties as collateral for loans unless
the loan proceeds will be used to support their utility operations.

Except
in limited circumstances, holders of our senior notes and bonds, which represent the majority of our unsecured obligations, do not have the right to restrict our use of collateral
or to be equally or ratably secured if we provide collateral to other creditors. Our five-year facilities prohibit us from pledging our assets as collateral except in certain
circumstances.

Note 14: Long-Term Gas Contracts

In 1997 through 2000, we were paid in advance on six contracts to deliver gas to municipal utilities over the subsequent 10 to 12 years. These contracts
were settled monthly through the physical delivery of gas. We hedged our exposure to changes in gas prices related to these contracts.

In
2004, we terminated four long-term gas contracts, which included the APEA contracts for which Chubb provided surety bonds (APEA III and APEA IV), and our APEA (APEA
II) and MGAM contracts, for which St. Paul/Travelers provided surety bonds. As a result, we were required to pay APEA, Chubb, St. Paul/Travelers and MGAM approximately $712.9 million
under the liquidated damages and other provisions of the gas supply contracts and termination agreements. We recorded a pretax charge of $156.2 million, or $97.6 million after tax, on
the termination of these four contracts.

In
addition, the realization of the price risk management assets and liabilities associated with the terminated long-term gas contracts, and the related commodity hedges that
were terminated, resulted in non-cash, mark-to-market losses of $40.3 million primarily related to the discounting of our trading portfolio,
$16.5 million for margin recorded on these contracts and $7.1 million of net replacement gas payments under the termination provisions of these contracts.

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We
do not intend to terminate our two remaining long-term gas contracts with the Municipal Gas Authority of Georgia (MGAG) and APEA (APEA I), which have a total obligation
and total remaining cash payments as outlined below:

|In millions |       | Long-Term
Gas Contract
Settlement(a) |      | Long-Term
Gas Contract
Margin
Loss(b) |   | Total Long-Term
Gas Contract
Cash
Payments(c)
|----------- | ----- | ------------------------------------ | ---- | ------------------------------------- | - | ---------------------------------------------
|           
|            |       |                                      |      |                                       |   |                                              
|2005        |       | $                                    | 15.0 |                                       | $ | 7.1                                          
|2006        |       |                                      | 15.7 |                                       |   | 7.7                                          
|2007        |       |                                      | 15.8 |                                       |   | 8.1                                          
|2008        |       |                                      | 1.4  |                                       |   | .6                                           
|           
|            | Total |                                      | $    | 47.9                                  |   | $                                            
|           



We accounted for the cash payments in advance related to these contracts as long-term obligations. We reduce our obligation on these
long-term gas contracts as gas is delivered to the customer under the units of revenue method. If we were to default on the two remaining contracts, 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 $69.6 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 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 we
sold 5,750,000 previously issued shares. Upon completion of the offering, we owned approximately 80% of Aquila Merchant's outstanding shares.

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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. In June 2004, we paid approximately $38 million, including interest from 2002, to settle this litigation. This resulted in the
recognition of additional expense of $8.8 million including litigation costs in 2004.

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, which was classified as
goodwill. We wrote off all of this goodwill in 2002 in connection with the sale of assets or through impairment charges. 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 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. In August 2004, we sold 46.0 million shares of our common stock to the public, including an over-allotment option
of 6.0 million shares, which raised $112.3 million in net proceeds. We used the proceeds of this offering to retire long-term debt and reduce other long-term
liabilities.

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 indefinite period. This decision followed 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. Currently one of our loan agreements and a
regulatory order prohibit us from paying any dividends. We can make no determination as to whether or when we will pay dividends in the future.

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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 Common Stock Purchase Plan

Our Dividend Reinvestment and Common Stock Purchase Plan (the Stock Plan) has been suspended until we obtain authorization of additional shares. Previously we
offered current and potential shareholders the option to participate in the Stock Plan. The Stock Plan allowed 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 allowed members to reinvest dividends into additional common shares at a 5% discount. For the years ended
December 31, 2003 and 2002, 608,074 and 2,188,427 shares were issued, respectively, under the Stock Plan.

Employee Stock Purchase Plan

Purchases have been suspended under our Employee Stock Purchase Plan until we obtain authorization of additional shares. Participants in this plan had the
opportunity to buy shares of common stock at a reduced price through regular payroll deductions and/or lump sum deposits of up to 20% of the employee's base salary, but not more than $25,000 annually.
Contributions were credited to the participant's account throughout an option period. At the end of the option period, the participant's total account balance was applied to the purchase of common
stock. The shares were purchased at 85% of the lower of the market price on the first day or the last day of the option period. Participants must have been 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 and 2002, 665,254 and 281,394 shares were purchased, respectively, under the Employee Stock
Purchase Plan.

Retirement Investment Plan

A defined contribution plan, the Retirement Investment Plan (Savings Plan), covers all of our full-time and eligible part-time employees.
Participants may generally elect to contribute up to 50% of their annual pay on a before- or after-tax basis subject to certain limitations. The company generally matches contributions up
to 6% of pay. Participants may direct their contributions into various investment options. Through 2002, all matching contributions made by the company were in Aquila stock. Effective in 2003, our
matching contributions were made in cash and invested as directed by the employee. Company contributions were $8.4 million, $8.1 million and $11.5 million during the years ended
December 31, 2004, 2003 and 2002, 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 are 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 2004, 2003 and 2002, compensation expense (in millions) of $4.3, $4.9 and
$5.9, respectively,

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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. No new grants have been provided to senior executive officers since the performance cycle beginning in 2002.
We currently have only one outstanding grant to junior executives for the 2003 through 2005 performance cycle. Total compensation expense for the years ended December 31, 2004 and 2003, was
$.7 million and $.4 million, respectively.

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. All equity-based awards are issued under this plan. Stock options under this plan and preceding plans have generally been granted at
market prices with one to three year vesting terms and have been exercisable for seven to 10 years from the date of grant. In December 2004, we granted fully vested stock options for
approximately 1.9 million shares to all employees other than senior executive officers of the company. These options are exercisable for seven years from the date of grant. As of
December 31, 2004, we have approximately 4.9 million shares of common stock available for issuance under this plan and preceding plans.

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Summary of Stock Options

This table summarizes all stock option activity:

|                             |  | 2004      |   | 2003      |   | 2002       |  
|---------------------------- |  | --------- | - | --------- | - | ---------- | -
|
|                             |  |           |   |           |   |            |  
|Shares:                      |  |           |   |           |   |            |  
|Beginning balance            |  | 8,558,048 |   | 8,908,508 |   | 6,118,123  |  
|Granted                      |  | 1,900,760 |   | 408,300   |   | 1,789,152  |  
|Converted from Merchant plan |  |          |   |          |   | 2,641,369  |  
|Exercised                    |  | (472,591  | ) | (85,577   | ) | (270,028   | )
|Cancelled                    |  | (348,118  | ) | (673,183  | ) | (1,370,108 | )
|                             | 
|Ending balance               |  | 9,638,099 |   | 8,558,048 |   | 8,908,508  |  
|                             | 
|Weighted average prices:     |  |           |   |           |   |            |  
|Beginning balance            |  | $20.22    |   | $20.75    |   | $22.37     |  
|Granted price                |  | 3.75      |   | 1.44      |   | 1.83       |  
|Converted price              |  |          |   |          |   | 34.82      |  
|Exercised price              |  | 4.06      |   | 3.04      |   | 24.14      |  
|Cancelled price              |  | 21.57     |   | 17.15     |   | 29.49      |  
|                             | 
|Ending balance               |  | $17.73    |   | $20.22    |   | $20.75     |  
|                             | 

This
table summarizes all outstanding and exercisable stock options as of December 31, 2004:

|             |       | Outstanding Options |           | Exercisable Options
|------------ | ----- | ------------------- | --------- | -------------------
|
|            
|             |       |                     |           |                    
|$1.44-1.83   |       | 1,409,266           |           | 4.99               
|$3.75        |       | 1,899,210           |           | 6.99               
|$18.16-24.90 |       | 4,257,182           |           | 3.46               
|$28.13-39.52 |       | 2,072,441           |           | 5.59               
|            
|             | Total |                     | 9,638,099 |                    
|            

No
restricted stock awards were granted during 2004 or 2003. As of December 31, 2004, we had 453,326 restricted stock awards outstanding.

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Note 16: Accumulated Other Comprehensive Income (Loss)

The table below reflects the activity for accumulated other comprehensive income (loss) for 2002, 2003 and 2004:

|In millions               |  | Foreign
Currency
Adjustments |       | Cash
Flow
Hedges |   | Held for Sale
Securities |   | Minimum
Pension
Liability |      | Accumulated
Other
Comprehensive
Income (Loss) |  
|------------------------- |  | ---------------------------- | ----- | ---------------- | - | ------------------------ | - | ------------------------- | ---- | --------------------------------------------- | -
|                          | 
|                          |  |                              |       |                  |   |                          |   |                           |      |                                               |  
|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                     | ) |                           |     |                                               |  
|2004 change               |  |                              | (63.0 | )                |   | 8.8                      |   |                           |     |                                               |  
|                          | 
|Balance December 31, 2004 |  | $                            | .8    |                  | $ |                         |   | $                         |     |                                               | $
|                          | 

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. Weighted average shares used in basic earnings per share includes 110.9 million shares issuable on the conversion of the mandatorily
convertible Premium Income Equity Securities (PIES) from August 24, 2004, the date of issuance of the PIES. See Note 13 for further discussion. 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

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2004,
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, |       
|-------------------------------------------------------------------------------------------- | ----------------------------------------------------------- | ----------------------- | ------
|
|                                                                                             |                                                            
|                                                                                             |                                                             |                         |       
|Loss from continuing operations                                                              |                                                             | $                       | (349.2
|Interest and debt amortization costs associated with the PIES                                |                                                             |                         | 9.4   
|                                                                                             |                                                            
|Loss available for common shares from continuing operations                                  |                                                             |                         | (339.8
|Interest on convertible bonds                                                                |                                                             |                         |      
|                                                                                             |                                                            
|Loss available for common shares from continuing operations                                  |                                                             |                         | (339.8
|Earnings (loss) from discontinued operations                                                 |                                                             |                         | 56.7  
|Cumulative effect of accounting change                                                       |                                                             |                         |      
|                                                                                             |                                                            
|Loss available for common shares                                                             |                                                             | $                       | (283.1
|                                                                                             |                                                            
|Basic and diluted earnings (loss) per share:                                                 |                                                             |                         |       
|                                                                                             | Loss available for common shares from continuing operations |                         | $     
|                                                                                             | Earnings (loss) from discontinued operations                |                         |       
|                                                                                             | Cumulative effect of accounting change                      |                         |       
|                                                                                             |                                                            
|                                                                                             | Net loss available for common shares                        |                         | $     
|                                                                                             |                                                            
|Weighted average number of common shares used in basic and diluted earnings (loss) per share |                                                             |                         | 251.35
|                                                                                             |                                                            

Note 18: Income Taxes

Loss from continuing operations before income taxes consisted of:

|         |       | Year Ended December 31, |       
|-------- | ----- | ----------------------- | ------
|
|         |      
|         |       |                         |       
|Domestic |       | $                       | (560.8
|Foreign  |       |                         | (1.7  
|         |      
|         | Total |                         | $     
|         |      

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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 benefit from continuing operations                                                                                  |                                    |                         | (213.3
|                                                                                                                               |                                   
|Income tax expense (benefit) from discontinued operations:                                                                     |                                    |                         |       
|Current                                                                                                                        |                                    |                         | 36.3  
|Deferred (net of valuation allowance of $(11.1) million, $11.1 million and $75.4 million in 2004, 2003 and 2002, respectively) |                                    |                         | 18.1  
|                                                                                                                               |                                   
|Income tax expense (benefit) from discontinued operations                                                                      |                                    |                         | 54.4  
|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                  |                                                            |               | 523.8
|                                           |                                                           
|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 |                                                            |               | 671.8
|                                           |                                                           
|Deferred income taxes and credits, net     |                                                            | $             | 148.0
|                                           |                                                           

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    |              | (3.8
|                                  | Revocation of permanent foreign reinvestments |              |    
|                                  | Change in valuation allowance                 |              | (1.5
|                                  | Reserve for contingent tax liabilities        |              | (.9 
|                                  | Goodwill                                      |              |    
|                                  | Other                                         |              | 3.3 
|                                  |                                              
|Effective Income Tax Rate         |                                               | (37.9        | )%  
|                                  |                                              

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Tax Credits

At December 31, 2004 and 2003, we had alternative minimum tax credit carryforwards of $103.6 million. These credits do not expire and can be used to
decrease future cash tax payments. In addition, at December 31, 2004 and 2003, we had general business tax credit carryforwards of $6.7 million. The substantial majority of the general
business credits expire in 2018, after which time they become a deduction against taxable income instead of a credit against tax. We did not record valuation allowances against the deferred tax asset
related to the general business credits as we believe that more likely than not they will be utilized.

Capital Loss Carryforwards

As of December 31, 2004, we had approximately $716.3 million of net realized capital loss carryforwards available for federal income tax purposes
that expire in 2007 through 2009 and recognized impairment charges of $45.1 million that we expect to realize (for income tax purposes) as capital losses when the assets are sold. The tax
benefit of these carryforwards and impairments is reflected on our balance sheet as a deferred tax asset of $292.7 million. 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 have established a full valuation allowance of $292.7 million against these tax benefits.

Net Operating Loss Carryforwards

As of December 31, 2004, we had approximately $460.7 million of federal net operating loss carryforwards originating in 2003 and
$418.4 million of estimated federal net operating losses
originating in 2004. The 2003 federal net operating loss carryforward expires in 2023 and can be carried back to 2001 to offset potential IRS audit adjustments. The 2004 federal net operating loss
carryforward expires in 2024 and cannot be carried back due to losses in the carryback years. At December 2004 and 2003, we had recorded deferred tax benefits of $359.7 million and
$81.4 million, respectively, related to our cumulative net operating loss carryforwards. Included in these amounts are deferred tax benefits of $52.0 million and $41.9 million,
respectively, related to state net operating losses. The state net operating loss carryforwards expire in various years.

We
did not record valuation allowances against the deferred tax assets related to the federal net operating losses as we believe it is more likely than not that sufficient taxable income
to utilize these losses during the carryforward period will be generated from continuing operations, including the reversal of deferred tax liabilities on our regulated business plus income from the
sale of assets. However, we recorded a valuation allowance of $13.8 million in 2003 and an additional valuation allowance of $15.9 million in 2004 against the state net operating loss
benefits. Also, in 2004, $17.8 million of state net operating loss benefits and related valuation allowance was written off because we no longer operate in certain states. At
December 2004, our valuation allowance related to state net operating losses was $11.9 million. This valuation allowance is necessary because we believe that it is more likely than not
that we will not realize the deferred tax assets related to these state net operating losses during the applicable carryforward periods. This assessment considered the decline in future business
activity in certain states and the taxable income we expect to generate in the applicable state carryforward periods.

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As
a result of the PIES offering and concurrent common stock offering, which closed on August 24, 2004, we may be limited in our ability to utilize certain of our net operating
losses and general business credit carryforwards to offset future taxable income and tax liability, respectively. The Internal Revenue Code imposes an annual limitation on the use of a corporation's
tax attributes if a corporation undergoes an ownership change for tax purposes during a three-year test period. The PIES and common stock offerings, in conjunction with additional
transactions in our company stock during the testing period, may constitute an ownership change for this purpose.

If
an ownership change is determined to have occurred, our ability to use the general business credits, the net operating loss carryforward from 2003, and the net operating loss
generated through August 24, 2004, would be subject to an annual limitation. In such case, the amount of net operating loss subject to the limitation would not be determined until the 2004 tax
return is filed and such determination would be subject to audit by the IRS. Based on our current estimate of the total net operating losses at August 24, 2004, and our current estimate of the
annual limitation, we do not expect that the annual limitation would cause any of our net operating losses or general business credits to expire unutilized. Thus, we have not established a valuation
allowance against the tax benefits of the net operating losses or general business credits existing at August 24, 2004.

We
also have significant capital loss and minimum tax credit carryforwards that would be subject to the annual limitation described above. However, a full valuation allowance has already
been provided against the tax benefits from the capital loss carryforwards and the minimum tax credit carryforwards do not expire. Therefore, no additional valuation allowance is required due to the
potential ownership change annual usage limitation.

Reserve for Contingent Tax Liabilities

As of December 31, 2004 and 2003, we had recorded in deferred tax liabilities $244.0 million and $208.7 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 reserve
is included in deferred tax liabilities because the timing of the resolution of these audits is uncertain and 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 carryforwards, alternative minimum tax credit carryforwards, and/or general business 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, our Australian investments in 2003 and our Canadian investments in 2004. As a result, we could no longer represent that cash from our
international investments would 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 arose when we brought asset sale proceeds back to the United States.

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Goodwill

Included in 2002 impairment charges and net loss on sales of assets was $200.5 million of Merchant Services goodwill 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. Benefits under the plans reflect the employees' compensation, years of service and age at retirement.
We satisfy the minimum funding requirements under ERISA. In addition to pension benefits, we provide post-retirement health care and life insurance benefits for certain 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, 2004 and 2003.

On
December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective. The Act expands Medicare, primarily by offering a
prescription drug benefit to Medicare-eligible retirees starting in 2006, as well as a federal subsidy to sponsors of retiree healthcare plans that provide a benefit that is at least actuarially
equivalent to Medicare Part D. Our actuaries have determined that the benefits provided under our other post-retirement benefit plans are actuarially equivalent to the Medicare
Part D benefits under the Act for current retirees. Therefore, we will qualify for the 28% federal subsidy. We have recognized the effect of the Act on our other post-retirement
benefit obligations and costs in our financial statements, beginning July 1, 2004 in accordance with FASB Staff Position No. 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." Based on a remeasurement of the plans at April 1, 2004, the effect of the Act on the accumulated
post-retirement benefit obligation was a decrease of $10.1 million, which we expect to amortize to reduce net periodic benefit costs in future periods. The effect of the Act on net
periodic benefit cost was a decrease of $.7 million for 2004.

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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                                              |  | $                | 330.4 |                                | $
|Service cost                                                                     |  |                  | 7.8   |                                |  
|Interest cost                                                                    |  |                  | 19.4  |                                |  
|Plan participants' contribution                                                  |  |                  |      |                                |  
|Actuarial (gain) loss                                                            |  |                  | (4.7  | )                              |  
|Curtailment loss                                                                 |  |                  |      |                                |  
|Benefits paid                                                                    |  |                  | (15.3 | )                              |  
|                                                                                 | 
|Projected benefit obligation at end of year                                      |  | $                | 337.6 |                                | $
|                                                                                 | 
|Change in Plan Assets:                                                           |  |                  |       |                                |  
|Fair value of plan assets at start of year                                       |  | $                | 288.4 |                                | $
|Actual return on plan assets                                                     |  |                  | 39.7  |                                |  
|Employer contribution                                                            |  |                  | 0.8   |                                |  
|Plan participants' contribution                                                  |  |                  |      |                                |  
|Benefits paid                                                                    |  |                  | (15.3 | )                              |  
|                                                                                 | 
|Fair value of plan assets at end of year                                         |  | $                | 313.6 |                                | $
|                                                                                 | 
|Funded status:                                                                   |  |                  |       |                                |  
|Funded status                                                                    |  | $                | (24.0 | )                              | $
|Unrecognized transition amount                                                   |  |                  | (1.5  | )                              |  
|Unrecognized net actuarial loss                                                  |  |                  | 90.9  |                                |  
|Unrecognized prior service cost                                                  |  |                  | 12.0  |                                |  
|Accumulated regulatory gain/loss adjustment                                      |  |                  | 10.6  |                                |  
|                                                                                 | 
|Net amount recognized before SFAS 71 regulatory liability                        |  |                  | 88.0  |                                |  
|SFAS 71 regulatory liability                                                     |  |                  | (6.6  | )                              |  
|                                                                                 | 
|Net amount recognized                                                            |  | $                | 81.4  |                                | $
|                                                                                 | 
|Amounts Recognized in the Consolidated Balance Sheets:                           |  |                  |       |                                |  
|Prepaid benefit cost                                                             |  | $                | 98.7  |                                | $
|Accrued benefit liability                                                        |  |                  | (18.1 | )                              |  
|SFAS 71 regulatory liability                                                     |  |                  | (6.6  | )                              |  
|Intangible asset                                                                 |  |                  | 7.4   |                                |  
|                                                                                 | 
|Net amount recognized                                                            |  | $                | 81.4  |                                | $
|                                                                                 | 
|Reconciliation of Net Amount Recognized:                                         |  |                  |       |                                |  
|Net amount recognized at start of year                                           |  | $                | 96.4  |                                | $
|Net periodic benefit cost before curtailments and regulatory expense adjustments |  |                  | (11.3 | )                              |  
|Curtailment (gain) loss                                                          |  |                  |      |                                |  
|Contributions                                                                    |  |                  | .8    |                                |  
|Regulatory gain/loss adjustment                                                  |  |                  | (.2   | )                              |  
|SFAS 71 regulatory adjustment                                                    |  |                  | (4.3  | )                              |  
|                                                                                 | 
|Net amount recognized at end of year                                             |  | $                | 81.4  |                                | $
|                                                                                 | 
|Weighted Average Assumptions as of September 30:                                 |  |                  |       |                                |  
|Discount rate for expense                                                        |  |                  | 6.00  | %                              |  
|Discount rate for disclosure                                                     |  |                  | 6.00  | %                              |  
|Expected return on plan assets for expense                                       |  |                  | 8.50  | %                              |  
|Expected return on plan assets for disclosure                                    |  |                  | 8.50  | %                              |  
|Rate of compensation increase                                                    |  |                  | 4.40  | %                              |  
|                                                                                 | 

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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 for non-prescription drug medical costs starting at 9% in 2005 and decreasing 1% annually until the rate levels out at 5% for years 2009 and thereafter. For
prescription drug costs, we used a graded rate starting at 13% in 2005 and decreasing 1% annually until the rate levels out at 5% for years 2013 and thereafter.

|                                                                                 |  | Pension Benefits |       | Other
Post-retirement
Benefits |  
|-------------------------------------------------------------------------------- |  | ---------------- | ----- | ------------------------------ | -
|
|
|
|                                                                                 |  |                  |       |                                |  
|Components of Net Periodic Benefit Cost:                                         |  |                  |       |                                |  
|Service cost                                                                     |  | $                | 7.8   |                                | $
|Interest cost                                                                    |  |                  | 19.4  |                                |  
|Expected return on plan assets                                                   |  |                  | (23.9 | )                              |  
|Amortization of transition amount                                                |  |                  | (1.2  | )                              |  
|Amortization of prior service cost                                               |  |                  | 1.1   |                                |  
|Recognized net actuarial (gain) loss                                             |  |                  | 8.1   |                                |  
|                                                                                 | 
|Net periodic benefit cost before curtailments and regulatory expense adjustments |  |                  | 11.3  |                                |  
|Curtailment (gain) loss                                                          |  |                  |      |                                |  
|Regulatory gain/loss adjustment                                                  |  |                  | .2    |                                |  
|SFAS 71 regulatory adjustment                                                    |  |                  | 4.3   |                                |  
|                                                                                 | 
|Net periodic benefit cost after curtailments and regulatory expense adjustments  |  | $                | 15.8  |                                | $
|                                                                                 | 

In
our most recent settlement with the Missouri Public Service Commission (the Commission), we agreed to recover our Missouri-related pension funding at an agreed-upon annual
amount for ratemaking purposes. This settlement determines the annual amount we will recover and recognize as pension expense beginning in the second quarter of 2004. As ordered by the Commission, the
difference between the agreed-upon expense for ratemaking purposes and the amount determined under SFAS No. 87, "Employers' Accounting for Pensions," will be recognized as a
regulatory asset or liability in accordance with SFAS 71. The impact of this settlement on net periodic benefit cost was an increase of $4.3 million for 2004.

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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 plans are
summarized below:

|In millions                                               |  | 2004 |       | 2003 |  
|--------------------------------------------------------- |  | ---- | ----- | ---- | -
|
|                                                          |  |      |       |      |  
|Projected Benefit Obligations in Excess of Plan Assets:   |  |      |       |      |  
|Fair value of plan assets at end of year                  |  | $    | 313.6 |      | $
|Projected benefit obligation at end of year               |  |      | 337.6 |      |  
|                                                          | 
|Funded status                                             |  | $    | (24.0 | )    | $
|                                                          | 
|Accumulated Benefit Obligations in Excess of Plan Assets: |  |      |       |      |  
|Fair value of plan assets at end of year                  |  | $    |      |      | $
|Accumulated benefit obligation at end of year             |  |      | 18.1  |      |  
|                                                          | 
|Funded status(a)                                          |  | $    | (18.1 | )    | $
|                                                          | 



The
accumulated benefit obligation for all our defined benefit pension plans was $311.2 million and $300.4 million at September 30, 2004, and 2003, 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 result of selecting the model portfolio from the study that best fit our pension plan
long-term investment objectives. As a result of a related asset allocation study, in November 2004 we changed our portfolio of qualified pension plan assets from a mix of 77% equity
and 23% fixed income securities to a mix of 69% equity and 31% fixed income securities to be achieved over a three month period ending February 1, 2005. At the same time, we shifted certain
equity assets from passive to more active management to enhance the long-term investment performance.

Pension Plan Investment Objectives

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Our
qualified pension plan weighted-average asset allocations by asset category at September 30, 2004 and 2003, 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         |       | 14.6                         | %     | 14.9                          | %    
|High yield bonds          |       | 8.2                          |       | 8.0                           |      
|Large cap equities        |       | 32.2                         |       | 31.5                          |      
|Mid cap equities          |       | 9.9                          |       | 5.8                           |      
|Small cap equities        |       | 10.2                         |       | 13.9                          |      
|International equities    |       | 13.0                         |       | 12.6                          |      
|Emerging markets equities |       | 2.7                          |       | 2.7                           |      
|Real estate               |       | 7.8                          |       | 7.6                           |      
|Private equity            |       | 1.3                          |       | 1.1                           |      
|Cash                      |       | .1                           |       | 1.9                           |      
|                          |      
|                          | Total |                              | 100.0 | %                             | 100.0
|                          |      

Our
other post-retirement benefit plan assets at December 31, 2004 and 2003 were 100% invested in short-term debt instruments 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 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, 2004, and our estimated annual
pension cost (APC) on the income statement for 2005 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                              | % |                           |      |                           |  
|                              | 

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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 2005.

|                                                        |  | 1 Percentage-Point |    
|------------------------------------------------------- |  | ------------------ | ---
|
|
|                                                        |  |                    |    
|Effect on total of service and interest cost components |  | $                  | .3 
|Effect on post-retirement benefit obligation            |  |                    | 5.4

Based
on actuarial projections, we expect to contribute $.8 million and $6.1 million to our defined benefit pension plans and other post-retirement benefit
plans, respectively, in 2005. No discretionary contributions are planned in 2005.

In
February 2005, we amended our pension and other post-retirement benefit plans to bring our benefits into line with our regulated utility peers. The effects of these
amendments on our projected (pension) benefit obligation and accumulated post-retirement benefit obligation were increases of $21.9 million and $24.9 million, respectively,
as of our most recent measurement date, September 30, 2004.

Following
are estimated future benefit payments, which reflect expected future service, as appropriate, as well as the plan amendments approved in February 2005. Other
post-retirement benefits are reflected gross without considering the estimated subsidy to be received under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, while
the estimated subsidy is shown separately.

|In millions                        |  | Pension Benefits |       | Other
Post-retirement
Benefits |   | Medicare
Drug
Subsidy | 
|---------------------------------- |  | ---------------- | ----- | ------------------------------ | - | --------------------- | 
|
|                                   |  |                  |       |                                |   |                       | 
|Estimated Future Benefit Payments: |  |                  |       |                                |   |                       | 
|2005                               |  | $                | 16.6  |                                | $ | 6.7                   | 
|2006                               |  |                  | 17.5  |                                |   | 7.5                   | 
|2007                               |  |                  | 18.7  |                                |   | 8.2                   | 
|2008                               |  |                  | 19.8  |                                |   | 8.6                   | 
|2009                               |  |                  | 21.4  |                                |   | 9.0                   | 
|2010-2014                          |  |                  | 130.3 |                                |   | 46.7                  | 
|                                   | 

Note 20: Segment Information

We have restated our financial reporting segments to reflect the significant changes in our business over the last two years, including the continuing
wind-down of our wholesale energy trading operations and the sale of our merchant loan portfolio, natural gas pipeline, gathering and storage assets, investments in international utility
networks and investment in Quanta Services, Inc. We now manage our business in two operating segments: Domestic Utilities and Merchant Services. Domestic Utilities consists of our regulated
electricity and natural gas utility

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operations
in seven states. Merchant Services includes our remaining investments in merchant power plants, our commitments under merchant capacity tolling obligations, our commitments under
long-term gas contracts and the remaining contracts from our wholesale energy trading operations. All other operations are included in Corporate and Other, including the costs of the
company that are not allocated to our operating businesses, our investment in Everest Connections, and our former investments in Quanta Services, Australia and the United Kingdom. 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. The current and
non-current assets of our consolidated independent power plants and our Canadian utility businesses are included in Merchant Services and Corporate and Other, respectively.

Business Lines

|                    |  | Year Ended December 31,
|------------------- |  | -----------------------
|
|
|                    |  |                        
|Sales:(a)           |  |                        
|Domestic Utilities  |  | $                      
|Merchant Services   |  |                        
|Corporate and Other |  |                        
|                   
|Total               |  | $                      
|                   



|                                                     |  | Year Ended December 31, |       
|---------------------------------------------------- |  | ----------------------- | ------
|
|
|                                                     |  |                         |       
|Earnings (Loss) Before Interest and Taxes (EBIT):(a) |  |                         |       
|Domestic Utilities                                   |  | $                       | 159.1 
|Merchant Services(b)                                 |  |                         | (438.7
|Corporate and Other(b)                               |  |                         | (24.5 
|                                                     | 
|Total EBIT                                           |  |                         | (304.1
|Interest expense                                     |  |                         | 258.4 
|                                                     | 
|Loss from continuing operations before income taxes  |  | $                       | (562.5
|                                                     | 



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|                                          |       | Year Ended December 31,
|----------------------------------------- | ----- | -----------------------
|
|
|                                          |       |                        
|Depreciation and Amortization Expense:(a) |       |                        
|Domestic Utilities                        |       | $                      
|Merchant Services                         |       |                        
|Corporate and Other                       |       |                        
|                                         
|                                          | Total |                        
|                                         



|                        |       | December 31,
|----------------------- | ----- | ------------
|
|
|                        |       |             
|Identifiable Assets:(a) |       |             
|Domestic Utilities      |       | $           
|Merchant Services(b)    |       |             
|Corporate and other(b)  |       |             
|                       
|                        | Total |             
|                       



|                         |       | Year Ended December 31,
|------------------------ | ----- | -----------------------
|
|
|                         |       |                        
|Capital Expenditures:(a) |       |                        
|Domestic Utilities       |       | $                      
|Merchant Services        |       |                        
|Corporate and other      |       |                        
|                        
|                         | Total |                        
|                        



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Geographical Information

|                    |  | Year Ended December 31, |        
|------------------- |  | ----------------------- | -------
|
|
|                    |  |                         |        
|Sales:(a)           |  |                         |        
|United States       |  | $                       | 1,711.0
|Canada              |  |                         | 1.3    
|Other international |  |                         | (1.3   
|                    | 
|Total               |  | $                       | 1,711.0
|                    | 



|                       |  | December 31,
|---------------------- |  | ------------
|
|
|                       |  |             
|Long-Lived Assets:(a)  |  |             
|United States          |  | $           
|Other international(b) |  |             
|                      
|Total                  |  | $           
|                      



Note 21: Commitments and Contingencies

Capital Expenditures

We have made certain construction commitments in connection with our 2005 capital expenditure plan. During 2005, we estimate that our total capital expenditures
will be approximately $237.7 million.

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Commitments

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

|In millions                                      |                             | 2005 |      | 2006  |   | 2007 |       | 2008 |      | 2009  |   | Thereafter |       | Total
|------------------------------------------------ | --------------------------- | ---- | ---- | ----- | - | ---- | ----- | ---- | ---- | ----- | - | ---------- | ----- | -----
|
|                                                 |                             |      |      |       |   |      |       |      |      |       |   |            |       |      
|Future minimum paymentsFacilities and equipment |                             | $    | 17.7 |       | $ | 13.5 |       | $    | 11.7 |       | $ | 11.5       |       | $    
|                                                 | Jeffrey Energy Center       |      |      | 11.6  |   |      | 10.6  |      |      | 10.6  |   |            | 12.1  |      
|Elwood tolling contracts                         |                             |      | 37.3 |       |   | 37.3 |       |      | 37.3 |       |   | 37.4       |       |      
|Merchant gas transportation obligations          |                             |      | 9.2  |       |   | 8.5  |       |      | 5.4  |       |   | 5.4        |       |      
|Regulated business purchase obligations:         |                             |      |      |       |   |      |       |      |      |       |   |            |       |      
|                                                 | Purchased power obligations |      |      | 128.5 |   |      | 110.4 |      |      | 116.5 |   |            | 118.9 |      
|                                                 | Purchased gas obligations   |      |      | 111.6 |   |      | 97.2  |      |      | 70.6  |   |            | 38.5  |      
|                                                 | Coal contracts              |      |      | 90.8  |   |      | 72.7  |      |      | 62.2  |   |            | 48.0  |      
|                                                

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 2004, 2003 and 2002 was (in millions), $16.2, $22.4 and $25.4, respectively.

We
have an operating lease of an 8% interest in the Jeffrey Energy Center through 2019. The lease contains certain fixed price and fair market value purchase and renewal options. The
lease payments vary by year but are recognized as lease expense on a straight-line basis of approximately $10.4 million annually.

Elwood tolling contracts

In connection with our merchant power generation business, we have entered into two power purchase agreements through 2017 for a portion of the total output of
the Elwood power plant owned by others. This agreement is treated as an operating lease for accounting purposes.

Merchant gas transportation obligations

We have long-term commitments through 2017 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

In 2004, our electric utility operations generated 57% of the power delivered to their customers. Our electric utility operations purchase coal and natural gas,
including transportation capacity, as fuel for its generating power plants under long-term contracts through 2020. These

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operations
also purchase power and gas to meet customer needs under short-term and long-term purchase contracts.

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. In 2004, we paid $6.0 million to the buyer of the portfolio out of $10.7 million of swap proceeds collected. As of December 31, 2004 we have collected
$28.0 million related to the remaining swaps, of which we have reserved $5.0 million to cover this obligation. The value of the
unsettled portion of these swaps, which expire by December 2006, was $28.5 million at December 31, 2004.

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, 2004, we had $77.7 million of letters of credit outstanding with expiration dates generally 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.

Equity Put Rights

Certain minority owners of Everest Connections had the option to sell their ownership units to us if Everest Connections did not meet certain financial and
operational performance measures as of December 31, 2004 (target-based put rights). If the target-based put rights were exercised, we would have been obligated to purchase up to
4.0 million and 4.75 million ownership units at a price of $1.00 and $1.10 per unit, 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. In 2004, we achieved the operating
targets related to 4.0 million and 1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million of this reserve. We did
not achieve the targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their options and were paid
$3.6 million for their ownership units in February 2005. As of December 31, 2004, we had fully reserved for this obligation. The minority owners of 9.5 million ownership
units also have the option to sell their ownership units to us at fair market value (market-based put rights.) The market-based put rights expire on December 31, 2005. We have not provided for
this potential obligation as the exercise would represent an equity transaction at fair value. We do not believe

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based
on current estimates of fair value that these market-based put rights are a material contingent obligation.

Legal

AMS Shareholder Lawsuit

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. This lawsuit is scheduled for trial in May 2005. We believe we have strong defenses and will defend this
case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given
the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Price Reporting Litigation

On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, that allegedly
manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market. The suit does not specify alleged damages and was filed on behalf of
all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002. On September 24, 2004, the court denied Aquila's motion to dismiss along with similar motions filed
by most of the other defendants. We will defend this case vigorously as we believe we have strong defenses to the plaintiff's claims. We cannot predict with certainty whether we will incur any
liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse
effect on our financial condition, results of operations and cash flows.

On
June 7, 2004, the City of Tacoma filed suit against 56 companies, including Aquila, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in
violation of the Sherman Act. This case was dismissed in February 2005. It is not certain whether the plaintiff will appeal this ruling.

On
July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies, including Aquila, in the Superior Court
of San Diego alleging manipulation of the California natural gas market in 2000 through 2002. Since that date 13 other counties, cities and other parties have filed similar complaints making nearly
identical allegations. These lawsuits allege violations of the Cartwright Act, the Sherman Act and the California Unfair Competition Law and unjust enrichment. The lawsuits have been designated In re Natural Gas Anti-Trust
Cases Vand assigned to a Coordination Motion Judge in the Superior Court of San Diego to determine whether they are
complex and should be coordinated. Aquila is also a defendant in theUtility Savings & Refund Services, LLP v. Reliant Energy Services, Inc.,
et al.lawsuit filed November 30, 2004 in the U.S. District Court for the Eastern District of California alleging violations of the Sherman Act, the
Cartwright Act, and the California Unfair Competition Law. We believe we have strong defenses and will defend these cases vigorously. We cannot predict with certainty whether we will incur any
liability, nor can we estimate the damages, if any, that might be incurred in connection with these lawsuits. However,

142

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given
the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Enron Bankruptcy Litigation

On March 7, 2005, we reached an agreement with Enron Corp. and certain of its affiliates (Enron). Under this agreement, we will pay $28 million to
Enron to settle all outstanding claims between Enron and Aquila associated with the various bankruptcy filings of Enron in December 2001 and two lawsuits filed by Enron Canada Corp. in
January 2003. In 2001, we reserved for substantially all of our then outstanding receivables from Enron, which resulted in a charge of $66.8 million. This charge did not reflect potential gains
we would record in the event we were successful in netting certain obligations to Enron against these receivables. Approximately $33.5 million of liabilities remained on our books related to contracts
with Enron after the 2001 charge. The settlement is subject to final approval the bankruptcy court. As a result of the settlement, we reduced our net liability to Enron by approximately
$6 million, or $3.7 million after tax.

Lender Litigation

On October 5, 2004 and October 15, 2004, lawsuits were filed against us by our lenders alleging that we were obligated to pay a "make whole" amount
when we prepaid the $430 million three-year secured term loan in September 2004. We believe that our termination of the term loan required us to pay a prepayment penalty of
$8.7 million. The plaintiff lenders have sued us for breach of contract for their proportionate share of the difference between their prepayment calculation and the $8.7 million, which
in the aggregate is approximately $20.6 million. We believe we have strong defenses and will defend these cases vigorously. We cannot predict with certainty whether we will incur any liability,
nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our
financial condition, results of operations and cash flows.

ERISA Litigation

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against us, the Board of Directors and certain
members of management alleging they violated the ERISA and are responsible for losses that participants in the Aquila 401(k) plan experienced as a result of the decline in the value of their Aquila
stock held in the Aquila 401(k) plan. A number of similar lawsuits alleging that the defendants breached their fiduciary duties to the plan participants in violation of ERISA by concealing information
and/or misleading employees who held Aquila stock through the Aquila 401(k) plan were subsequently filed against us. The suits also seek damages for the plan's losses resulting from the alleged
breaches of fiduciary duties. On January 26, 2005 the court ordered that each of these lawsuits must all be consolidated into a single case captioned,In re Aquila ERISA
Litigation,and gave the plaintiffs 45 days to file an amended consolidated complaint. We believe we have strong defenses and will defend these cases vigorously. We
cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the
claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

143

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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.

As
of December 31, 2004, we estimate probable costs of future investigation and remediation on our identified MGP sites and retained liabilities to be $6.6 million. This is
our best estimate based upon a comprehensive review of the potential costs associated with conducting investigative and remedial actions at our identified sites, as well as the likelihood of whether
such actions will be necessary. There are also additional costs that we consider to be less likely but still "reasonably possible" to be incurred at these sites. Based upon the results of studies at
these sites and our knowledge and review of potential remedial actions, it is reasonably possible that these additional costs could exceed our best estimate by approximately $9.0 million. This
estimate could change materially once we have investigated further. It could also be affected by the actions of environmental agencies and the financial viability of other responsible parties.
Ultimate liability also may be affected significantly if we are held responsible for parties unable to contribute financially to the cleanup effort.

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 $100 million to
$400 million to comply with the regulations. We estimate the costs for 2005 to be approximately $1 million. This estimate could change materially once the regulations are finalized and
we have investigated further. We believe these costs would likely be allowed for recovery in future rate cases.

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.

|                                                       |                              | 2004 Quarters |       | 2003 Quarters |  
|------------------------------------------------------ | ---------------------------- | ------------- | ----- | ------------- | -
|
|
|
|
|                                                       |                              |               |       |               |  
|Sales                                                  |                              | $             | 553.2 |               | $
|Gross profit                                           |                              |               | 121.3 |               |  
|Loss from continuing operations                        |                              |               | (84.6 | )             |  
|Earnings (loss) from discontinued operations           |                              |               | 32.8  |               |  
|                                                       |                             
|                                                       | Net loss                     |               | $     | (51.8         | )
|                                                       |                             
|Basic and diluted earnings (loss) per common share:(a) |                              |               |       |               |  
|                                                       | From continuing operations   |               | $     | (.43          | )
|                                                       | From discontinued operations |               |       | .17           |  
|                                                       |                             
|                                                       | Net income (loss)            |               | $     | (.26          | )
|                                                       |                             



144

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Report of Independent Registered Public Accounting Firm

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, 2004 and 2003, 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, 2004. In
connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule, "Schedule IIValuation and Qualifying Accounts," for each
of the years in the three-year period ended December 31, 2004. These consolidated financial statements and the financial statement schedule are the responsibility of the company's
management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aquila, Inc. and subsidiaries as of
December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004 in conformity with
United States generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken
as a whole, presents fairly, in all material respects, the information set forth therein.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Aquila, Inc.'s internal control over
financial reporting as of December 31, 2004 based on criteria established inInternal ControlIntegrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2005 expressed an unqualified opinion on management's assessment of, and the effective operation
of, internal control over financial reporting.

/s/
KPMG LLP
Kansas City, Missouri

March 11,
2005

145

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Report of Independent Registered Public Accounting Firm

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

We have audited management's assessment, included in the Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that
Aquila, Inc. (the Company) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal
ControlIntegrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Aquila, Inc.'s management is responsible
for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an
opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In
our opinion, management's assessment that Aquila, Inc. maintained effective internal control over financial reporting as of December 31, 2004 is fairly stated, in all
material respects, based on criteria established inInternal ControlIntegrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Also, in our opinion, Aquila, Inc. maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2004 based on criteria established inInternal ControlIntegrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).

146

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We
have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Aquila, Inc. and
subsidiaries as of December 31, 2004 and 2003, 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, 2004, and our report dated March 11, 2005 expressed an unqualified opinion on those consolidated financial statements.

/s/
KPMG LLP
Kansas City, Missouri

March
11, 2005

147

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

Not
Applicable.

Item 9A. Controls and Procedures

Disclosure 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.

Management's Report on Internal Control Over Financial Reporting

Our
management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal ControlIntegrated
Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal
ControlIntegrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.

Our
management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, has been audited by KPMG LLP, an independent
registered public accounting firm, as stated in their report which is included herein.

Item 9B. Other Information

Not
Applicable.

Part III

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

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

148

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Equity Compensation Plan Information

The following table provides information as of December 31, 2004 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     |       | 9,312,769                                                                                      |           | $                                                                              | 17.50 |                                                                                                                                               
|Equity compensation plans not approved by security holders |       | 325,330                                                                                        | (c)       | $                                                                              | 24.02 |                                                                                                                                               
|                                                          
|                                                           | Total |                                                                                                | 9,638,099 |                                                                                |       |                                                                                                                                               
|                                                          



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.

149

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Part IV

Item 15. Exhibits, Financial Statement Schedules

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 2004, 2003 and 2002 on page 151.

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

(a)(3) List of Exhibits*

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

|10(a)(7)  |  | Annual and Long-Term Incentive Plan.                                                                                                                                             
|--------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10(a)(8)  |  | First Amendment to Annual and Long-Term Incentive Plan.                                                                                                                          
|10(a)(9)  |  | Form of Severance Compensation Agreement (change in control agreement) of Certain Executives.                                                                                    
|10(a)(10) |  | Life Insurance Program for Officers.                                                                                                                                             
|10(a)(11) |  | Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001.                                                                                         
|10(a)(12) |  | Employment Agreement for Richard C. Green                                                                                                                                        
|10(a)(13) |  | Amended and Restated Capital Accumulation Plan.                                                                                                                                  
|10(a)(14) |  | First Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                                           
|10(a)(15) |  | Second Amendment to the Amended and Restated Capital Accumulation Plan.                                                                                                          
|10(a)(16) |  | 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)(17) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan.                                                                                                                           
|10(a)(18) |  | Executive Security Trust Amended and Restated as of April 4, 2002.                                                                                                               
|10(a)(19) |  | Supplemental Executive Retirement Agreement, by and between Aquila, Inc. (formerly UtiliCorp United Inc.) and John R. Baker, dated as of May 7, 1990.                            



(b) Exhibits

The Index to Exhibits follows on page 152.

150

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AQUILA, INC.  SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2004
(in millions)

|Column A                        |      | Column B |   | Column C |  | Column D |      | Column E
|------------------------------- | ---- | -------- | - | -------- |  | -------- | ---- | --------
|
|
|                               
|                                |      |          |   |          |  |          |      |         
|Allowance for Doubtful Accounts |      |          |   |          |  |          |      |         
|                                | 2004 |          | $ | 36.7     |  | $        | 12.6 |         
|                                | 2003 |          |   | 28.3     |  |          | 18.3 |         
|                                | 2002 |          |   | 58.8     |  |          | 13.5 |         
|Maintenance Reserves(a)         |      |          |   |          |  |          |      |         
|                                | 2004 |          | $ | 4.0      |  | $        | 3.5  |         
|                                | 2003 |          |   | 3.1      |  |          | 2.8  |         
|                                | 2002 |          |   | 3.2      |  |          | 2.6  |         
|Other Reserves(b)               |      |          |   |          |  |          |      |         
|                                | 2004 |          | $ | 26.3     |  | $        | 32.2 |         
|                                | 2003 |          |   | 18.5     |  |          | 45.1 |         
|                                | 2002 |          |   | 17.6     |  |          | 37.5 |         
|Restructuring Reserves(c)       |      |          |   |          |  |          |      |         
|                                | 2004 |          | $ | 16.9     |  | $        | .9   |         
|                                | 2003 |          |   | 49.2     |  |          | 28.2 |         
|                                | 2002 |          |   |         |  |          | 96.0 |         
|                               



151

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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)          |  | Amended and Restated By-laws of the company. (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.                                  
|*4(b)          |  | Form of Rights Agreement between the company and UMB Bank, N.A. (as successor to First Chicago Trust Company of New York), as Rights Agent. (Exhibit 4 to the company's Form 10-Q for the period ended
September 30, 1996.)               
|*4(c)          |  | Amendment to Rights Agreement. (Exhibit 4(d) to the company's Post Effective Amendment No. 1 to Registration Statement on Form S-3 No. 333-29657 filed March 15, 2002.)                                                                   
|*10(a)(1)      |  | Indenture, dated as of August 24, 2001, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee. (Exhibit 4(d) to the company's Registration Statement on Form S-3 (File No. 333-68400)
filed August 27, 2001.)                  
|*10(a)(2)      |  | First Supplemental Indenture to the August 24, 2001 Indenture, dated February 28, 2002, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee. (Exhibit 4 to the company's Current Report on
Form 8-K filed February 27, 2002.)
|*10(a)(3)      |  | Third Supplemental Indenture to the August 24, 2001 Indenture, between the Company and J.P. Morgan Trust Company (Exhibit 4 to the company's Current Report on Form 8-K filed August 20,
2004.)                                           
|*10(a)(4)      |  | $110 million Revolving Credit Agreement among the company, the lenders and Credit Suisse First Boston dated September 20, 2004. (Exhibit 10.1 to the company's Current Report on Form 8-K filed on
September 21, 2004.)                   
|*10(a)(5)      |  | $220 million Credit Agreement among the company, the lenders and Credit Suisse First Boston dated September 20, 2004. (Exhibit 10.2 to the company's Current Report on Form 8-K filed on
September 21, 2004.)                             
|*10(a)(6)      |  | Financing Agreement between the company and Union Bank of California dated October 22, 2004. (Exhibit 10.1 to the company's Current Report on Form 8-K filed on October 28, 2004.)                                                        
|*10(a)(7)      |  | 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)(8)      |  | 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)(9)      |  | 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.)    
|               |  |                                                                                                                                                                                                                                           

152

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|*10(a)(10) |  | 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)(11) |  | 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)(12) |  | 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)(13) |  | 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)(14) |  | First Amendment to the Amended and Restated Capital Accumulation Plan. (Exhibit 10(a)(2) to the company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001.)                                                                                                                                           
|*10(a)(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) |  | 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)(17) |  | 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)(18) |  | 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)(19)  |  | Supplemental Executive Retirement Agreement, by and between Aquila, Inc. (formerly UtiliCorp United, Inc.) and John R. Baker, dated as of May 7, 1990.                                                                                                                                                                  
|12         |  | Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                     
|14         |  | Code of Ethics.                                                                                                                                                                                                                                                                                                         
|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. (Exhibit 99.1 to the company's Annual Report on Form 10-K for the year ended
December 31, 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. (Exhibit 99.2 to the company's Annual Report on Form 10-K for the year ended
December 31, 2003.)                                                                                                   



153

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized as of March 11, 2005.

| |  | 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 11, 2005.

|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/PATRICK J. LYNCHPatrick J. Lynch                 |  | Director                                                                                               
|By: |  | /s/GERALD L. SHAHEENGerald L. Shaheen               |  | Director                                                                                               

154

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