UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, 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, 2007
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 registered
|--------------------------------------- |  | -----------------------------------------
|Common Stock, par value $1.00 per share |  | New York Stock Exchange                  

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

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Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No ý

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 III of this Form 10-K or any amendment to
this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o No ý

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, 2007 as reported on the New York Stock Exchange, was approximately $956,230,218. 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 February 22, 2008
|----------------------------------------------------------------------------------------- |  | --------------------------------
|Common Stock, par value $1.00 per share                                                   |  | 375,944,512                     
|Documents Incorporated by Reference:
Proxy Statement for 2008
Annual Shareholders Meeting |  | Where Incorporated:
Part III    



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INDEX

|                  |         |     |                                                                                                              | Page
|----------------- | ------- | --- | ------------------------------------------------------------------------------------------------------------ | ----
|Part I            |         |     |                                                                                                              |     
|                  | Item 1  |     | Business                                                                                                     |     
|                  | Item 1A |     | Risk Factors                                                                                                 |     
|                  | Item 1B |     | Unresolved Staff Comments                                                                                    |     
|                  | 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, Executive Officers and Corporate Governance                                                       |     
|                  | Item 11 |     | Executive Compensation                                                                                       |     
|                  | Item 12 |     | Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters               |     
|                  | Item 13 |     | Certain Relationships and Related Transactions, and Director Independence                                    |     
|                  | Item 14 |     | Principal Accountant Fees and Services                                                                       |     
|Part IV           |         |     |                                                                                                              |     
|                  | Item 15 |     | Exhibits, Financial Statement Schedules                                                                      |     
|Index to Exhibits |         | 129
|Signatures        |         | 132

2

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Glossary of Terms and Abbreviations

APBAccounting
Principles Board.

AFUDCAllowance
for Funds Used During Construction.

Aquila
MerchantAquila Merchant Services, Inc., our wholly-owned merchant energy subsidiary.

BARTBest
Available Retrofit Technology.

Black
HillsBlack Hills Corporation, a South Dakota corporation.

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.

CAIRClean
Air Interstate Rule.

CAMRClean
Air Mercury Rule.

CO2Carbon
dioxide.

Crossroads
plantthe Crossroads Energy Center, a 304 MW electric generation "peaking" facility located in Clarksdale, Mississippi that is contractually controlled by Aquila.

EBITDAEarnings
before interest, taxes, depreciation and amortization.

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 2005.

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

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

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.

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

Great
Plains EnergyGreat Plains Energy Incorporated, a Missouri corporation.

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.

IUBIowa
Utilities Board, a governmental agency of the State of Iowa that, among other things, regulates the tariffs and service quality standards of our regulated utility operations in
Iowa.

3

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Kansas
CommissionKansas Corporation Commission, a governmental agency of the State of Kansas that, among other things, regulates the tariffs and service quality standards of our regulated
utility operations in Kansas.

KCPLKansas
City Power & Light Company, an electric utility company with operations in Missouri and Kansas that is wholly owned by Great Plains Energy.

kWhKilowatt-hour.

McfOne
thousand cubic feet.

Mergerthe
merger of Gregory Acquisition Corp., a wholly-owned subsidiary of Great Plains Energy, with and into Aquila.

MGPManufactured
Gas Plant.

MISOMidwest
Independent System Operator, which is a FERC-approved RTO.

Missouri
CommissionMissouri Public Service Commission, a governmental agency of the State of Missouri that, among other things, regulates the tariffs and service quality standards of our
regulated electric utility operations in Missouri.

MMBtuOne
Million Btus.

MmcfOne
million cubic feet.

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

MWMegawatt,
which is one thousand kilowatts.

MWhMegawatt-hour.

NOxNitrogen
oxide.

NYMEXNew
York Mercantile Exchange.

NYSENew
York Stock Exchange.

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

PCBPolychlorinated
Biphenyl.

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.

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.

WestarWestar
Energy, Inc., a Kansas utility company.

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 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, 2007, we had 2,213 employees in the United States, 953 of which are represented by union locals. Our business is organized into three business segments:
Electric Utilities, Gas Utilities and Merchant Services. Electric Utilities comprises our regulated electric utility operations, Gas Utilities comprises our regulated gas utility operations, and
Merchant Services comprises our remaining unregulated energy activities, which have been substantially wound down. All other operations are included in Corporate and Other, including costs that are
not allocated to our operating businesses; and our former interest in Everest Connections, which was classified as "held for sale" prior to its sale on June 30, 2006 and reported in
discontinued operations. Substantially all of our revenues are generated by our Electric and Gas Utilities.

We
sold our Michigan, Minnesota, and Missouri gas utilities in 2006 and our Kansas electric utility in 2007, which resulted in these operations being reported as discontinued operations.
Our Electric Utilities include 1,849 MWs of generation and 15,190 pole miles of electric transmission and distribution lines, and our Gas Utilities include 604 miles of intrastate gas transmission
pipelines and 11,364 miles of gas distribution mains and service lines. Our Electric and Gas
Utilities generated revenues from continuing operations of $1,475.0 million in the year ended December 31, 2007, and had total assets of $2.7 billion at December 31, 2007.

Our
Merchant Services group consists of our contractual interest in the Crossroads Energy Center, a "peaking" power generation facility, and our Aquila Merchant subsidiary, whose assets
and liabilities are limited to its remaining wholesale energy trading portfolio of natural gas delivery and transportation contracts. In 2006, we sold two merchant power plants, which resulted in
these operations being reported as discontinued operations.

Pending Merger

On February 6, 2007, we entered into a merger agreement with Great Plains Energy, Gregory Acquisition Corp., a wholly-owned subsidiary of Great Plains
Energy, and Black Hills, which provides for the merger (the Merger) of Gregory Acquisition Corp. into us, with Aquila continuing as the surviving corporation. If the Merger is completed, we will
become a wholly-owned subsidiary of Great Plains Energy, and our shareholders will receive cash and shares of Great Plains Energy common stock in exchange for their shares of Aquila common stock. At
the effective time of the Merger, each share of Aquila common stock will convert into the right to receive 0.0856 shares of Great Plains Energy common stock and a cash payment of $1.80.

In
connection with the Merger, we also entered into agreements with Black Hills under which we have agreed to sell our Colorado electric utility and our Colorado, Iowa, Kansas and
Nebraska gas utilities to Black Hills for $940 million, subject to certain purchase price adjustments. These asset sales will occur immediately prior to consummation of the Merger. The Merger
and the asset sales are each contingent upon the closing of the other transaction, meaning that one transaction will not close unless the other transaction closes.

The
information disclosed by the Company in this Form 10-K regarding its strategy, risks and specific plans is subject to change if the Merger is completed. See
Note 19 to the Consolidated Financial Statements for additional information related to these transactions.

5

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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 Accounting 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 2007 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.

Business Group Summary

Segment information for the three years ended December 31, 2007 is included in Note 17 to the Consolidated Financial Statements.

I.     Electric and Gas Utilities

Electric Utilities generates, transmits and distributes electricity to 400,804 customers in Colorado and Missouri. Our electric generating facilities and
purchased power contracts supply electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies. Approximately 77% of our
electric customers are located in Missouri. Gas Utilities distributes natural gas to 519,624 customers in Colorado, Iowa, Kansas, and Nebraska. Approximately 68% of our utility operations, based on
the book value of our regulated assets, are located in Missouri.

6

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Electric Utilities

As of December 31, 2007, our owned interests in electric generation plants were as follows:

|Unit      |                   | Location |                    | Year Installed |                  | MW |       | Fuel
|--------- | ----------------- | -------- | ------------------ | -------------- | ---------------- | -- | ----- | ----
|         
|Missouri: |                   |          |                    |                |                  |    |       |     
|          | Sibley #1-3       |          | Sibley             |                | 1960, 1962, 1969 |    | 508   |     
|          | Ralph Green #3    |          | Pleasant Hill      |                | 1981             |    | 71    |     
|          | Nevada            |          | Nevada             |                | 1974             |    | 20    |     
|          | Greenwood #1-4    |          | Greenwood          |                | 1975-1979        |    | 238   |     
|          | KCI #1-2          |          | Kansas City        |                | 1970             |    | 34    |     
|          | Lake Road #1, 3   |          | St. Joseph         |                | 1951, 1962       |    | 33    |     
|          | Lake Road #2, 4   |          | St. Joseph         |                | 1957, 1967       |    | 125   |     
|          | Lake Road #5      |          | St. Joseph         |                | 1974             |    | 68    |     
|          | Lake Road #6-7    |          | St. Joseph         |                | 1989, 1990       |    | 43    |     
|          | Iatan 1           |          | Iatan              |                | 1980             |    | 118   |     
|          | Jeffrey #1-3      |          | St. Mary's, Kansas |                | 1978, 1980, 1983 |    | 175   |     
|          | South Harper #1-3 |          | Peculiar           |                | 2005             |    | 315   |     
|Colorado: |                   |          |                    |                |                  |    |       |     
|          | W.N. Clark #1-2   |          | Canon City         |                | 1955, 1959       |    | 42    |     
|          | 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 capability  |          |                    |                |                  |    | 1,849 |     
|         

The following table shows Electric Utilities' overall fuel mix and generation capability for 2007:

|Fuel Source (MW) |                             |    
|---------------- | --------------------------- | ---
|                
|Coal             |                             | 843
|Gas              |                             | 449
|Oil              |                             | 93 
|Coal and gas     |                             | 125
|Gas and oil      |                             | 339
|                
|                 | Total generation capability |    
|                

At December 31, 2007, Electric Utilities owned or leased the electric transmission and distribution lines shown below:

|Line Type In Miles    |  |       
|--------------------- |  | ------
|                     
|Electric transmission |  | 2,132 
|Electric distribution |  | 13,058
|                     

7

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The following table summarizes regulated sales, volumes and customers for our Electric Utilities business:

|                                                          |             | 2007 |        | 2006  |   | 2005   |      
|--------------------------------------------------------- | ----------- | ---- | ------ | ----- | - | ------ | -----
|                                                          |            
|Sales (in millions)                                       |             |      |        |       |   |        |      
|                                                          | Residential |      | $      | 371.0 |   | $      | 328.7
|                                                          | Commercial  |      |        | 231.1 |   |        | 206.9
|                                                          | Industrial  |      |        | 98.4  |   |        | 91.9 
|                                                          | Other       |      |        | 137.3 |   |        | 140.4
|                                                          |            
|Total continuing electric operations                      |             |      | 837.8  |       |   | 767.9  |      
|Total discontinued electric operations                    |             |      | 42.3   |       |   | 188.8  |      
|                                                          |            
|Total                                                     |             | $    | 880.1  |       | $ | 956.7  |      
|                                                          |            
|Volumes Generated and Purchased (GWh)                     |             |      |        |       |   |        |      
|                                                          | Coal        |      |        | 5,307 |   |        | 5,463
|                                                          | Gas         |      |        | 214   |   |        | 149  
|                                                          | Coal/Gas    |      |        | 706   |   |        | 521  
|                                                          | Gas/Oil     |      |        | 39    |   |        | 82   
|                                                          |            
|Total generated                                           |             |      | 6,266  |       |   | 6,215  |      
|Purchased                                                 |             |      | 5,723  |       |   | 5,547  |      
|                                                          |            
|Total generated and purchased                             |             |      | 11,989 |       |   | 11,762 |      
|Company use                                               |             |      | (16    | )     |   | (15    | )    
|Line loss                                                 |             |      | (677   | )     |   | (713   | )    
|                                                          |            
|Total continuing electric operations                      |             |      | 11,296 |       |   | 11,034 |      
|Total discontinued electric operations (net of line loss) |             |      | 550    |       |   | 2,304  |      
|                                                          |            
|Total                                                     |             |      | 11,846 |       |   | 13,338 |      
|                                                          |            
|Volumes Sold (GWh)                                        |             |      |        |       |   |        |      
|                                                          | Residential |      |        | 4,200 |   |        | 3,997
|                                                          | Commercial  |      |        | 3,404 |   |        | 3,244
|                                                          | Industrial  |      |        | 1,882 |   |        | 1,863
|                                                          | Other       |      |        | 1,810 |   |        | 1,930
|                                                          |            
|Total continuing electric operations                      |             |      | 11,296 |       |   | 11,034 |      
|Total discontinued electric operations                    |             |      | 550    |       |   | 2,304  |      
|                                                          |            
|Total                                                     |             |      | 11,846 |       |   | 13,338 |      
|                                                          |            

8

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|
|

|                                                     |                     | 2007 |         | 2006    |   | 2005   
|---------------------------------------------------- | ------------------- | ---- | ------- | ------- | - | -------
|                                                    
|Customers at Year End                                |                     |      |         |         |   |        
|                                                     | Residential         |      |         | 351,230 |   |        
|                                                     | Commercial          |      |         | 46,380  |   |        
|                                                     | Industrial          |      |         | 331     |   |        
|                                                     | Other               |      |         | 2,863   |   |        
|                                                    
|Total continuing electric operations                 |                     |      | 400,804 |         |   | 396,829
|Total discontinued electric operations               |                     |      |        |         |   | 68,972 
|                                                    
|Total                                                |                     |      | 400,804 |         |   | 465,801
|                                                    
|Continuing Operations Statistics                    |                     |      |         |         |   |        
|Average annual volume per residential customer (kWh) |                     |      | 11,958  |         |   | 11,508 
|Average annual sales per residential customer        |                     | $    | 1,056   |         | $ | 946    
|Average residential sales per kWh (cents)            |                     |      | 8.83    |         |   | 8.22   
|Units of Fuel Used in Generation                     |                     |      |         |         |   |        
|                                                     | Coalthousand tons  |      |         | 3,673   |   |        
|                                                     | Natural gasMmcf    |      |         | 4,362   |   |        
|Average Cost of Fuel                                 |                     |      |         |         |   |        
|                                                     | Coalper ton        |      | $       | 31.03   |   | $      
|                                                     | Natural gasper Mcf |      |         | 6.21    |   |        
|                                                    

Gas Utilities

At December 31, 2007, Gas Utilities owned the gas transmission and distribution lines shown below:

|Line TypeIn Miles                       |  |       
|---------------------------------------- |  | ------
|                                        
|Intrastate gas transmission pipelines    |  | 604   
|Gas distribution mains and service lines |  | 11,364
|                                        

9

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The following table summarizes regulated sales, volumes and customers for our Gas Utilities business:

|                                  |                          | 2007 |         | 2006   |   | 2005   
|--------------------------------- | ------------------------ | ---- | ------- | ------ | - | -------
|                                 
|Sales (in millions)               |                          |      |         |        |   |        
|                                  | Residential              |      | $       | 409.1  |   | $      
|                                  | Commercial               |      |         | 150.2  |   |        
|                                  | Industrial               |      |         | 26.6   |   |        
|                                  | Transportation and other |      |         | 20.2   |   |        
|                                 
|Total continuing gas operations   |                          |      | 606.1   |        |   | 581.4  
|Total discontinued gas operations |                          |      | 3.4     |        |   | 294.6  
|                                 
|Total                             |                          | $    | 609.5   |        | $ | 876.0  
|                                 
|Volumes Sold (Mmcf)               |                          |      |         |        |   |        
|                                  | Residential              |      |         | 36,004 |   |        
|                                  | Commercial               |      |         | 15,227 |   |        
|                                  | Industrial               |      |         | 3,679  |   |        
|                                  | Transportation and other |      |         | 48,252 |   |        
|                                 
|Total continuing gas operations   |                          |      | 103,162 |        |   | 96,189 
|Total discontinued gas operations |                          |      |        |        |   | 52,659 
|                                 
|Total                             |                          |      | 103,162 |        |   | 148,848
|                                 

|
|

|                                  |                          | 2007    |         | 2006    |         | 2005   
|--------------------------------- | ------------------------ | ------- | ------- | ------- | ------- | -------
|                                 
|Customers at Year End             |                          |         |         |         |         |        
|                                  | Residential              |         | 468,410 |         | 464,825 |        
|                                  | Commercial               |         | 43,183  |         | 42,825  |        
|                                  | Industrial               |         | 1,596   |         | 1,529   |        
|                                  | Transportation and other |         | 6,435   |         | 6,581   |        
|                                 
|Total continuing gas operations   |                          | 519,624 |         | 515,760 |         | 508,543
|Total discontinued gas operations |                          |        |         |        |         | 414,556
|                                 
|Total                             |                          | 519,624 |         | 515,760 |         | 923,099
|                                 

Seasonal Variations of Business

Our electric and gas utility businesses are weather-sensitive. We have both summer- and winter-peaking utility businesses to reduce dependence on a single peak
season. The table below shows normal utility peak seasons.

Operations

PeakGas Utilities

November through MarchElectric Utilities

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, none have been implemented. Although we face competition from independent marketers for the sale of natural gas to our
industrial and

10

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commercial
customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a distribution charge.

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.

Our
regulated businesses produce, purchase and distribute power in two states and purchase and distribute natural gas in four states. All of our Gas Utilities have purchased gas
adjustment (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. The Kansas and Nebraska Commissions also allow us to recover the gas cost portion of uncollectible accounts through the PGA. The Kansas Commission has also established a weather
normalization tariff which provides a pass-through mechanism for weather margin variability from the level used to establish base rates to be paid by the customer.

In
our continuing regulated electric business in 2007, we generated approximately 52% of the power that we sold and we purchased the remaining 48% through long-term contracts
or in the open market. The regulatory provisions for recovering power costs vary by state. In Colorado, we have an Energy Cost Adjustment (ECA) clause which serves a purpose similar to the PGAs for
our gas utilities. To the extent that our fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference is passed through to the customer. In
Missouri, we also have the ability to adjust the rates we charge for electric service to offset 95% of the increases or decreases in prices we pay for purchased power and natural gas, coal or other
fuel we use in generating electricity (i.e., a fuel adjustment mechanism).

In
2003, the Kansas Commission issued orders in connection with its investigation into the affiliated transactions between our regulated utilities and our other businesses that require
us to obtain the approval of the Kansas Commission before taking the following actions: (i) pledge for the benefit of our lenders any regulated utility assets presently devoted to serving
Kansas retail customers; (ii) incur any new or modify any existing indebtedness other than routine, short-term borrowings incurred in the ordinary course of business for working
capital needs; (iii) pay any dividends; or (iv) enter into contracts that alienate, convey or create an interest in our assets (e.g., through issuing stock or debt or arranging
other securitization), or relate to products or services not required for the provision of continuing utility operations.

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.

11

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The
following summarizes our recent rate case activity:

|In millions  |  | Type of
Service |  | Date
Requested |  | Date
Effective |  | Amount
Requested |       | Amount
Approved
|------------ |  | --------------- |  | -------------- |  | -------------- |  | ---------------- | ----- | ---------------
|            
|Iowa(1)      |  | Gas             |  | 5/2005         |  | 3/2006         |  | $                | 4.1   |                
|Missouri(2)  |  | Electric        |  | 5/2005         |  | 3/2006         |  |                  | 78.6  |                
|Missouri(2)  |  | Steam           |  | 5/2005         |  | 3/2006         |  |                  | 5.0   |                
|Missouri(3)  |  | Electric        |  | 7/2006         |  | 6/2007         |  |                  | 118.9 |                
|Kansas (4)   |  | Gas             |  | 11/2006        |  | 6/2007         |  |                  | 7.2   |                
|Nebraska (5) |  | Gas             |  | 11/2006        |  | 9/2007         |  |                  | 16.3  |                
|            



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Federal Regulation

With Order 2000, FERC encouraged investor-owned utilities to join an RTO approved by the FERC. RTO characteristics include independence, scope and configuration,
operational authority, and short-term reliability. An RTO has the responsibility to provide tariff administration, regional planning, and scheduling functions, as well as monitor and
coordinate the regional grid. We have FERC jurisdictional transmission facilities in Colorado and Missouri.

In
Colorado, our only RTO option (WestConnect) has not yet been approved by the FERC. The members of that RTO include utilities in Arizona, New Mexico, Nevada and Colorado. We will
continue to monitor the status of WestConnect.

In
Missouri, in 2001 we submitted an application to the FERC and to the Missouri Commission to join MISO. At that time, MISO was the only FERC-approved RTO in the Midwest.
The FERC application was approved, but the application to the Missouri Commission was dismissed in 2002 when the MISO footprint was modified and AmerenUE was no longer a participant. We were relying
upon AmerenUE interconnections to provide electric connectivity from our transmission system to the MISO footprint. Upon further evolution of the MISO footprint, in 2003 we submitted another
application to the Missouri Commission to join and transfer operational control to MISO. In response to that application, the Missouri Commission
asked for additional cost-benefit information from us and MISO, and dismissed the application pending completion of the additional cost-benefit studies.

During
2006, two Missouri electric utilities, KCPL and Empire District Electric, were granted approval by the Missouri Commission to become members of the Southwest Power Pool (SPP). In
2007, we completed a cost/benefit study that identified benefits to joining MISO or SPP as compared to joining neither. We subsequently filed an application with the Missouri Commission requesting
authority to join MISO. That application is currently pending. AmerenUE filed an application with the Missouri Commission last year requesting authority to remain a member of MISO and that application
is also pending. We do not expect a significant impact to our financial statements upon participation in an RTO.

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Environmental Matters

General

We are subject to a number of federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel
and the public. These laws and regulations affect a broad range of our activities, and generally require:



Water Issues

The Clean Water Act protects water quality and generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in
compliance with a discharge permit issued by a state environmental regulatory agency or the 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 own two plants that are affected by these rules. We completed the required studies. Due to a recent court decision, these rules were remanded back to the
EPA for revision. At this time, we do not know what the revised rules will require or what impact they might have on our compliance options.

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 have a material impact on utility operations in
the future.

Air Emissions

Our facilities are subject to many federal, 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, mercury and particulate matter. In addition, CO2 is also included
as a potential emission that may be regulated. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, accordingly, are subject to substantial regulation and
enforcement oversight by various governmental agencies.

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Clean Air Act

Title IV of the Clean Air Act 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. Certain facilities are allocated allowances based on their historical operating data. 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 affected units that expect to emit more SO2 than their allocated allowances may purchase allowances in the open market.
Our facilities emit SO2 in excess of their allocated allowances. Currently, we purchase additional allowances to stay in compliance. We are continuing to evaluate the cost of purchasing
allowances as compared to the cost of adding pollution control equipment.

Multi-pollutant regulations

Approximately 53% of our Electric Utilities generating capacity is coal-fired. The EPA has issued the Clean Air Interstate Rule (CAIR) and the Clean
Air Mercury Rule (CAMR) regulations with respect to SO2, NOx and mercury emissions from certain power plants which burn fossil fuels. These new rules would require significant reductions
in these emissions from our power plants, especially coal-fired plants, in phases beginning as early as 2009. Missouri regulations implementing CAIR and CAMR have been finalized and
approved by EPA with allowances allocated to Aquila. For compliance with the SO2 reduction requirements, we plan to continue purchasing allowances. To comply with NOx reductions, we are
installing Selective Catalyzed Reduction (SCR) on Sibley #3 with an expected completion date of December 31, 2008. Selective Non-Catalytic Reduction (SNCR) controls are also being
placed on Sibley units 1 & 2 in 2008. A mercury monitor has been purchased and installed at Sibley, which will help determine if additional controls are needed for mercury removal to comply
with CAMR. CAIR and CAMR rules are being challenged in the courts and we are monitoring these cases to determine how our requirements may change.

Federal
multi-pollutant legislation is also being considered that would require reductions similar to the EPA rules and some that could add greenhouse gas emission requirements.

New Source Review

The EPA has been conducting enforcement initiatives nationwide to determine whether certain activities conducted at electric generating facilities are subject to
the EPA's New Source Review requirements under the Clean Air Act. The EPA is interpreting the Clean Air Act 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 New Source Review requirements. We review these cases and settlements to determine if the changes in requirements would have a material impact on our
operations.

In
January 2004, Westar received a notification from the EPA that it had violated New Source Review 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 92% owned by Westar and operated
exclusively by Westar. We have an 8% interest in the Jeffrey Energy Center and are generally responsible for this portion of its operating costs and capital expenditures. At this time, no settlement
has been reached with the EPA; however, it is possible that Westar could be subject to an enforcement action by the EPA and be required to make significant capital expenditures to install additional
pollution controls at the Jeffrey Energy Center. Irrespective of the NSR case, the recent high cost of SO2 allowances may make it economical to install SO2 technology. Westar

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is
upgrading its environmental controls on Jeffrey with completion scheduled in the spring of 2009.

On
January 31, 2006, KCPL was issued an air permit for Iatan 2 that included additional air pollution control equipment for Iatan 1. As an 18% owner of
Iatan 1, we are responsible for 18% of the costs of the additional air pollution control equipment for Iatan 1. Construction of the Iatan 1 additional air pollution control
equipment is expected to be completed in 2008.

Our
capital expenditure forecasts include $144.7 million over the next three years for these types of environmental improvements. These estimates are subject to change based upon
the timing and extent of the upgrades.

Global Climate Change

We utilize a diversified energy portfolio that includes a fuel mix of coal, natural gas, biomass, wind and nuclear sources. Of these fuel mixes,
coal-fired power plants are the most significant sources of CO2 emissions. We believe that it is possible that greenhouse gases may be regulated within the next five years.
There are no specifics on how greenhouse gases will be regulated, but any federally mandated greenhouse gas reductions or limits on CO2 emissions could have a material impact on our
financial position or results of operations.

In
2007, we had a team perform a comprehensive review of all our greenhouse gas impacts. Our February 2007 integrated resource plan for Missouri incorporates the current proposed federal
legislation for a "cap and trade" program for CO2 emissions, similar to that in place for SO2 emissions, on our future generation mix. We will continue to review greenhouse gas
impacts as legislation or regulation develops.

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 has expired and we are currently in the process of permitting a new
expansion of the landfill and expect to incur approximately $.5 million of capital expenditure in 2008 to open the new landfill.

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, and we retain some environmental liability
for several operations and investments that we no longer own. In addition, 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, 2007, we estimate probable costs of future investigation and remediation on our identified MGP sites, PCB sites and retained liabilities to be
$3.6 million. This estimate was based upon our 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 estimate by approximately $5.1 million.
This estimate could change

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materially
after further investigation. It could also be affected by the actions of environmental agencies and the financial viability of other responsible parties.

We
have received rate orders that enable us to recover environmental cleanup costs in certain jurisdictions. In other jurisdictions, there are 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 interest in the Crossroads plant and our remaining wholesale energy trading portfolio. The Crossroads plant does not
have dedicated customers and is designed to operate only during periods of peak demand. The table below shows information about the Crossroads plant as of December 31, 2007:

|Plant & Location         |  | Location    |  | Type of Investment       |  | MW  |  | Heat Rate |  | Date in Service
|------------------------ |  | ----------- |  | ------------------------ |  | --- |  | --------- |  | ---------------
|                        
|Crossroads Energy Center |  | Mississippi |  | Contractually Controlled |  | 304 |  | 11.9      |  | September 2002 
|                        

We stopped wholesale energy trading during 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 under economically feasible terms. Most, 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 Crossroads plant competes with non-regulated generators, regulated utilities, and other energy service companies. There is strong price
competition in the wholesale energy market and our marginal cost of producing power often exceeds market prices. Our Crossroads plant, which is a peaking plant, is generally dependent on volatility in
the wholesale energy market created by other plant outages and transmission constraints. Those events, if they occur, can create short-term opportunities for the Crossroads plant to
produce and sell power at 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 losses related to this plant, including continued operating and maintenance costs.

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 Generation and Marketing Regulation

The Federal Power Act and other FERC rules regulate the generation and 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 Federal Power Act and the FERC.

The
Federal Power Act grants the FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. It also provides the FERC with ongoing as
well as initial jurisdiction, enabling the FERC to modify previously approved rates. Such rates may be

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based
on a cost-of-service approach or through competitive bidding or negotiation on a market basis. Independent power projects must obtain FERC acceptance of their rates under
Section 205 of the Federal Power Act. The Crossroads plant has been granted market-based rate authority and complies with the requirements governing the approval of wholesale rates.

Item 1A.    Risk Factors

Operating Risks

We may continue to incur losses in our Merchant Services business.

We may incur a material impairment charge if we decide to sell our interest in Crossroads power plant or liquidate our remaining wholesale energy trading
contracts in an inefficient or untimely manner. In addition, we expect to continue to incur operating losses from our remaining Merchant Services business.

Our non-investment grade credit ratings have an adverse effect on our liquidity and borrowing costs.

Our long-term senior unsecured debt is presently rated "Ba3" (Ratings Under Review for Possible Upgrade) by Moody's, and "B+" (Credit Watch Positive)
by S&P. Our non-investment grade ratings have increased our borrowing costs. These increases in our borrowing costs are not recoverable in our utility rates. In addition, our
non-investment grade ratings generally require us to prepay our commodity purchases or post collateral to obtain trade credit. As of December 31, 2007, we had posted
$229.6 million of collateral (in the form of cash or letters of credit) with counterparties.

Our ability to refinance debt or raise new capital could be restricted by the terms of our finance agreements and our regulatory orders.

The terms of our credit facilities and regulatory orders limit the amount of additional indebtedness that we can incur. For example, our ability to incur
indebtedness is restricted unless the additional indebtedness satisfies certain conditions (including use of proceeds restrictions), and prior to issuing long-term debt securities we must
obtain the approval of the FERC and certain state commissions. Even if we were to repay our credit facilities, we would still be required to seek regulatory approvals to issue long-term
debt. Thus, our ability to raise capital quickly (if at all) on favorable market terms could be limited.

Regulatory commissions may refuse to approve some or all of the utility rate increases we may request in the future.

Our regulated electricity and natural gas operations are subject to cost-of-service regulation and earnings oversight. This regulatory
treatment does not provide any assurance as to achievement of earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities
based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested
capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the
state public utility commissions will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce
a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

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Our operating results can be adversely affected by milder weather.

Our utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is typically
greater in the summer and winter months associated with cooling and heating, and demand for natural gas is extremely sensitive to winter weather effects on space heating requirements. Because natural
gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas
revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our operations have historically generated less revenues and income when weather conditions are
cooler in the summer and warmer in the winter. We expect that unusually mild summers and winters would have an adverse effect on our financial condition and results of operations.

Our utility business is subject to complex government regulations and changes in these regulations or in their implementation may affect the costs of
operating our businesses, which may negatively impact our results of operations.

Our natural gas and electric utilities operate in a highly regulated environment. Retail operations, including the prices charged, are regulated by the state
public utility commissions for our service areas. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on our performance by, for example, increasing
competition or costs, threatening investment recovery or impacting rate structure.

In
addition, our operations are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. To comply with these legal
requirements, we must spend significant sums on environmental monitoring, pollution control and emission fees.

New
environmental laws and regulations affecting our operations, and new interpretations of existing laws and regulations, may be adopted or become applicable to us. For example, the
laws governing air emissions from coal-burning plants have recently been revised by federal and state authorities. These changes will result in the imposition of substantially more
stringent limitations on these emissions than those currently in effect.

We
may not be able to obtain or maintain all environmental regulatory approvals necessary to our business. If there is a delay in obtaining any required environmental regulatory approval
or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted or subjected to additional costs.

The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on our financial condition.

We are a party to various material litigation matters and regulatory matters arising out of our business operations. The ultimate outcome of these matters cannot
presently be determined, nor can the liability that could potentially result from a negative outcome in each case presently be reasonably estimated. The liability we may ultimately incur with respect
to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters and, as a result, these matters may have a
material adverse effect on our consolidated financial position.

As
further discussed in Note 18 to the Consolidated Financial Statements, Cass County is seeking to require us to remove the South Harper power peaking facility. In May 2006, the
Missouri Commission issued an order specifically authorizing our construction and operation of the power plant and substation. In June 2006, the trial court further stayed its injunction and

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authorized
us to operate the plant and substation while Cass County appealed the Missouri Commission's order. Cass County filed an appeal with the Circuit Court of Cass County, challenging the
lawfulness and reasonableness of the Missouri Commission's order. In October 2006, the Circuit Court ruled that the Missouri Commission's order was unlawful and unreasonable. The Missouri Commission
and Aquila appealed the court's decision, and in May 2007, oral arguments were heard by the Missouri Court of Appeals for the Western District of Missouri. We expect a decision from the appellate
court in the first half of 2008. If we exhaust all of our legal options and are ordered to remove the plant and substation, we estimate the cost to dismantle these facilities to be up to
$20 million. We estimate the incremental cost of relocating and reconstructing the plant and substation on a site that is being developed to meet future generation needs to be approximately
$75 million based on recent engineering studies. Additional costs may be incurred to store the equipment before relocating it, and to secure replacement power until the plant and substation can
be reconstructed. We cannot reasonably estimate with certainty the total amount of these and other incremental costs that could be incurred, or the potential impairment of the carrying value of our
investment in the plant we could suffer to the extent the ultimate costs incurred exceed the amount allowed for recovery in rates.

Risks Relating to the Merger

The Merger may not be completed, which could adversely affect our business operations.

We will not be able to complete the Merger until we obtain regulatory approvals from the Missouri and the Kansas utility commissions. If these approvals are not
received, or they are not received on terms that satisfy the conditions in the transaction agreements, then the parties will not be obligated to complete the transactions. In addition, the Merger is
subject to other customary conditions. For example, the transactions may not be completed if either the operations being sold to Black Hills or our remaining businesses suffer a material adverse
effect. Furthermore, the Merger and the asset sales are contingent upon the closing of the other transaction, meaning that one transaction will not close unless the other transaction closes.

We are subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect our business.

Uncertainty about the effect of the Merger on employees and customers may have an adverse effect on us, regardless of whether it is completed. Although we have
taken steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed or is terminated, and for a
period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships with the parties.

Employee
retention and recruitment may be particularly challenging during the pendency of the Merger, as employees and prospective employees may experience uncertainty about their future
roles. The departure of existing key employees or the failure of potential key employees to accept employment with us, despite our retention and recruiting efforts, could have a material adverse
impact on our business, financial condition and operating results, regardless of whether the transactions are eventually completed.

In
addition, the transaction agreements restrict us from taking certain actions until the transactions are completed or the agreements are terminated. These restrictions may prevent us
from pursuing otherwise attractive business opportunities and making other changes to our businesses prior to completion of the transactions or termination of the agreements.

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We will incur significant costs in connection with the Merger.

We expect to incur significant costs (primarily investment banking, legal and employee retention costs) in connection with the Merger, regardless of whether it is
completed. We will expense these costs as they are incurred. We incurred approximately $2.3 million and $16.6 million of costs (primarily investment banking and legal costs) related to
the Merger in 2006 and 2007, respectively. On January 31, 2008, we paid $8.8 million to numerous non-executive employees pursuant to agreements entered into last year to
mitigate employee attrition prior to the closing of the Merger. We cannot at this time estimate the total costs to be incurred by the Company prior to consummation of the Merger.

Item 1B.    Unresolved Staff Comments

None.

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 electricity generation assets.

Our
principal owned and leased assets, and the location of those assets, are generally described in Item 1 under "Electric and Gas Utilities" and "Merchant Services." The utility
assets of our Missouri Public Service and our St. Joseph Light & Power operations in Missouri have been pledged as collateral for certain of our long-term debt obligations.
See Note 11 for more information.

Item 3.    Legal Proceedings

See Note 18 to the Consolidated Financial Statements.

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

The following matters were, at a special meeting of stockholders held on October 9, 2007, submitted to a vote of security holders in the fourth quarter of
2007:

1.     Proposal
to adopt the merger agreement with Great Plains Energy dated as of February 6, 2007:

Votes For

Votes Against

Votes Abstain226,258,156

25,832,507

3,292,516


2.     Proposal
to adjourn the special meeting of stockholders, if necessary, to permit further solicitation of proxies in the event there are not sufficient votes at the time
of the special meeting to adopt the merger agreement:

Votes For

Votes Against

Votes Abstain220,037,685

34,451,700

893,794


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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. At February 22, 2008, we had approximately 23,900 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 February 22, 2008, the reported last sale price of the common stock
on the NYSE was $3.30 per share.

Market Price Per Share

|              |  | High |      | Low |   | Cash Dividends
|------------- |  | ---- | ---- | --- | - | --------------
|
|2007 Quarters |  |      |      |     |   |               
|Fourth        |  | $    | 4.19 |     | $ | 3.68          
|Third         |  |      | 4.16 |     |   | 3.45          
|Second        |  |      | 4.39 |     |   | 4.00          
|First         |  |      | 4.81 |     |   | 3.94          
|2006 Quarters |  |      |      |     |   |               
|Fourth        |  | $    | 4.85 |     | $ | 4.29          
|Third         |  |      | 4.77 |     |   | 4.12          
|Second        |  |      | 4.50 |     |   | 3.91          
|First         |  |      | 4.06 |     |   | 3.45          
|

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The graph below compares the cumulative total shareholder return on our common stock for the last five fiscal years with the cumulative total return of the
S&P 500 Index, an index of utility companies in our peer group and the Edison Electric Institute Combination Gas and Electric Utility Index.

The
graph assumes that the value of the investment in our stock and each index was $100 on December 31, 2002, and that all dividends were reinvested.

GRAPHIC

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Item 6.    Selected Financial Data

|In millions, except per share amounts         |                       | 2007 |         | 2006 |   | 2005    |      | 2004 |         | 2003 |  
|--------------------------------------------- | --------------------- | ---- | ------- | ---- | - | ------- | ---- | ---- | ------- | ---- | -
|
|Sales                                         |                       | $    | 1,466.6 |      | $ | 1,369.6 |      | $    | 1,314.1 |      | $
|Gross profit                                  |                       |      | 565.7   |      |   | 488.0   |      |      | 450.4   |      |  
|Loss from continuing operations               |                       |      | (18.1)  | (a)  |   | (282.0) | (b)  |      | (158.0) | (c)  |  
|Basic and diluted loss per common share      |                       |      |         |      |   |         |      |      |         |      |  
|                                              | Continuing operations |      |         | (.05 | ) |         | (.75 | )    |         | (.40 | )
|Cash dividends per common share               |                       |      |        |      |   |        |      |      |        |      |  
|Total assets                                  |                       |      | 2,993.6 |      |   | 3,472.4 |      |      | 4,630.7 |      |  
|Short-term debt                               |                       |      | 25.0    |      |   |        |      |      | 12.0    |      |  
|Long-term debt (including current maturities) |                       |      | 1,037.8 |      |   | 1,405.6 |      |      | 1,979.5 |      |  
|Common shareholders' equity                   |                       |      | 1,355.7 |      |   | 1,306.1 |      |      | 1,309.9 |      |  
|

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

(a)   Included
in loss from continuing operations for the year ended December 31, 2007 is a $1.3 million loss on the early retirement of debt and
$24.5 million of merger-related expenses in 2007.

(b)   Included
in loss from continuing operations for the year ended December 31, 2006 is a $218.0 million loss on the exit of the Elwood tolling contract in
June 2006 and $28.2 million of losses on early retirement of debt in 2006.

(c)   Included
in loss from continuing operations for the year ended December 31, 2005 is a $82.3 million loss on the early termination of the PIES; offset in
part by $31.3 million of net gains primarily related to the termination of our power sales contract and assignment of our rights under the Batesville tolling contract and the sale of our
interests in the IntercontinentalExchange, Inc. (ICE) and the Red Lake gas storage development project.

(d)   Included
in 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 a power partnership that sold its cogeneration facility.

(e)   Included
in loss from continuing operations for the year ended December 31, 2003 are (i) a $105.5 million termination payment regarding our
20-year tolling agreement for the Acadia power plant; (ii) an $87.9 million impairment charge on our equity method investments in 12 independent power plants; and
(iii) $26.1 million of restructuring charges from exiting interest rate swaps related to our Raccoon Creek and Goose Creek construction financing arrangements and additional severance
and retention payments related to the wind-down of our trading operations.

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

See Forward-Looking Information beginning on page 53 and Risk Factors beginning on page 18.

Strategic and Financial Repositioning Overview

Pending Merger

We have entered into a merger agreement with Great Plains Energy, which is discussed in Note 19 to the Consolidated Financial Statements.

Operating Strategy

Our remaining repositioning initiatives are focused on improving operational results of our integrated electric and gas utility operations and strengthening our
credit profile in order to efficiently execute our utility growth strategy. We will continue 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 will also focus on improving
our returns through future rate activities and process improvements.

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

Historical Review of Repositioning Efforts

In 2002, we announced a change in our strategic direction. Our revised strategy featured a concentrated focus on our utility operations, which preceded our
diversification into merchant and international arenas in the 1990s. As part of this repositioning, we have sold or wound-down a number of operations to generate cash, reduce debt, and
eliminate other long-term obligations. Significant repositioning efforts include:



Proceeds
from these transactions were used to pay down debt, eliminate other long-term obligations, fund restructuring charges and support our continuing operations. Our
total long-term and short-term debt has been reduced from $3.6 billion at September 30, 2002 to $1.1 billion at December 31, 2007.

As
a result of these repositioning efforts, we have reduced our total staffing from 5,989 at the end of 2001 to 2,213 at the end of 2007, through the sale of operations, attrition and
involuntary separations.

We
have also sought to improve the earnings of our core remaining utility states through rate relief totaling $196 million, including $141 million in our Missouri electric
operations, since 2002.

25

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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, during potential periods of high natural gas prices and due to our current requirement to
prepay certain gas commodity suppliers and pipeline transportation companies. Under a stressed weather and commodity price environment, such as the spike in commodity prices in late 2005 following an
active hurricane season, we estimate our working capital needs for our utility operations could increase up to $200 million over base requirements. We anticipate using the combination of
revolving credit and letter of credit facilities listed below and cash on hand to meet our peak winter working capital requirements.

|Credit Facility                                                       |  | Expiration         |   | Maximum
Capacity |       | Borrowings or Letters
of Credit Issued at
December 31, 2007
|--------------------------------------------------------------------- |  | ------------------ | - | ---------------- | ----- | -----------------------------------------------------------
|
|
|Four-Year Secured Revolving Credit Facility                           |  | April 22, 2009(1   | ) | $                | 150.0 |                                                            
|Five-Year Unsecured Revolving Credit Facility                         |  | September 19, 2009 |   |                  | 110.0 |                                                            
|$180 Million Unsecured Revolving Credit and Letter of Credit Facility |  | April 13, 2010(1   | ) |                  | 180.0 |                                                            
|$50 Million Unsecured Revolving Credit and Letter of Credit Facility  |  | December 17, 2008  |   |                  | 50.0  |                                                            
|                                                                     



Cash Flows

Our Statement of Cash Flows for the three years ended December 31, 2007 includes the cash flows related to our discontinued operations. Included in our
cash provided from operating activities in 2007 is approximately $12.1 million of cash flows associated with our discontinued operations. Our cash from investing activities in 2007 includes
$289 million of cash received on the sale of our assets offset by $15.2 million of additions to utility plant.

The
disposition of our discontinued operations and the use of the proceeds from these sales to retire outstanding long-term debt and other obligations has reduced our
financing costs and working capital requirements and has strengthened our liquidity position.

Cash Flows from Operating Activities

Our positive 2007 operating cash flows were the result of $105.0 million in pretax, pre-depreciation earnings from continuing and discontinued
operations and $66.7 million related to the return of funds on deposit due to the continued
wind-down of our merchant trading portfolio and the change in our utility derivative positions.

Our
positive 2006 operating cash flows were the result of $190 million in pretax earnings from our continuing and discontinued operations before the loss on our Elwood tolling
agreement, the continued wind-down of our merchant trading portfolio which triggered the

26

---



return
of $118.3 million of funds on deposit and a $23.9 million decrease in other current assets. Additionally, we received $38.7 million of funds on deposit returns due to the
replacement of cash deposits and cash-collateralized letters of credit with unsecured letters of credit supporting the Elwood tolling contracts, and utilized $27.8 million of gas
and other inventory held in storage. The increases were offset by the $218 million payment to exit the Elwood tolling agreement in the second quarter of 2006, the return of $58.4 million
of counterparty collateral resulting from lower natural gas prices since December 2005, and a $25.4 million payment to Calpine in connection with the netting of amounts owed under various
contracts at the time of Calpine's bankruptcy filing.

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 to cover these interest costs as well as to fund our capital investment plan. We are attempting to
do this by improving the efficiency of our remaining businesses, increasing sales through utility rates and completing the wind-down of our Merchant Services business.

Cash Flows from Investing Activities

The decrease in cash provided from investing activities in 2007 from 2006 was primarily the result of lower cash proceeds received on the sale of assets. In
addition, utility capital expenditures increased compared to 2006 primarily due to the construction of the Iatan 2 facility and environmental upgrades.

The
increase in cash provided from investing activities in 2006 from 2005 is primarily the result of cash proceeds received in 2006 on the sale of our Michigan, Minnesota and Missouri
gas operations, our Illinois peaking plants and Everest Connections.

Cash Flows from Financing Activities

Cash used for financing activities decreased in 2007 compared to 2006 primarily as the result of a lower level of long-term debt retirements.

Cash
used for financing activities increased in 2006 compared to 2005 primarily as the result of our $350 million debt tender offer in June 2006 and the prepayment of our
$220 million unsecured term loan in 2006.

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, 2007, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency  |  | Rating |  | Commentary                               
|------- |  | ------ |  | -----------------------------------------
|
|Moody's |  | Ba3    |  | Ratings Under
Review for Possible Upgrade
|S&P     |  | B+     |  | Credit Watch Positive                    
|Fitch   |  | BB-    |  | Ratings Watch Positive                   
|       

27

---



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 Baa3, 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 (i.e., 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 $637.3 million of our long-term debt obligations, as well as advance rates on our Iatan Facility, Five-Year Unsecured Revolving Credit Facility and
Four-Year Secured Revolving Credit Facility, will be lowered.

Collateral Positions

As of December 31, 2007, we had posted cash collateral for the following:

|In millions                          |  |  
|------------------------------------ |  | -
|
|Trading positions                    |  | $
|Utility cash collateral requirements |  |  
|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 will vary
depending on the magnitude of the price movement and the current position of our trading portfolio. As these trading positions settle in the future, the collateral will be returned.

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.

Contractual Obligations

Our contractual cash obligations include principal maturities and interest on long-term debt, minimum payments on operating leases and regulated
power, gas and coal purchase contracts, as well as merchant gas transportation obligations. See Notes 10, 11 and 18 to the Consolidated Financial Statements for further discussion of these
obligations.

28

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

|In millions                                                 |  | 2008 |       | 2009 |   | 2010  |  | 2011 |       | 2012 |   | Thereafter |  | Total
|----------------------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------- |  | -----
|
|Short-term and long-term debt obligations                   |  | $    | 27.4  |      | $ | 70.8  |  | $    | 1.1   |      | $ | 335.5      |  | $    
|Interest on long-term debt(a)                               |  |      | 118.6 |      |   | 117.8 |  |      | 113.1 |      |   | 92.1       |  |      
|Lease and other obligations                                 |  |      | 12.3  |      |   | 9.6   |  |      | 7.7   |      |   | 6.5        |  |      
|Merchant gas transportation obligations                     |  |      | 5.5   |      |   | 5.5   |  |      | 5.5   |      |   | 5.0        |  |      
|Non-qualified pension and other post-retirement benefits(b) |  |      | 5.8   |      |   | 6.3   |  |      | 6.7   |      |   | 6.8        |  |      
|Unrecognized tax benefits(c)                                |  |      | 7.7   |      |   | 1.8   |  |      |      |      |   |           |  |      
|Regulated purchase obligations                              |  |      | 274.7 |      |   | 235.2 |  |      | 233.3 |      |   | 184.3      |  |      
|                                                           
|Total                                                       |  | $    | 452.0 |      | $ | 447.0 |  | $    | 367.4 |      | $ | 630.2      |  | $    
|                                                           



Regulated business purchase obligations

In 2007, our electric utility operations generated 52% of the power delivered to their customers. Our electric utility operations purchase coal and natural gas,
including transportation capacity, under long-term contracts with the longest extending through 2020. We also purchase power and gas to meet customer needs under short-term and
long-term purchase contracts.

Pending Merger

If the Merger is completed, we will incur and expense significant costs, primarily consisting of investment banking, legal, employee retention,
change-in-control, and other severance costs. In 2006 and 2007, we incurred approximately $2.3 million and $16.6 million, respectively, of costs (primarily
investment banking and legal costs) relating the Merger. We paid $6.2 million to our investment bankers upon announcement of the Merger in February 2007, and we paid $4.5 million to them
in October 2007 upon receipt of shareholder
approval. On January 31, 2008, we made payments totaling $8.8 million to numerous non-executive employees to help retain their services while approvals were being obtained
for the Merger. See Note 19 to the Consolidated Financial Statements.

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

29

---



December 31,
2007, 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.

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
|--------------------------- | -------------------------- | ------ | ----- | ----------------------------------
|
|
|
|Electric Utilities          |                            | $      | 234.7 |                                   
|Gas Utilities               |                            |        | 40.8  |                                   
|Corporate and Other         |                            |        | 7.9   |                                   
|                           
|Total Continuing Operations |                            |        | 283.4 |                                   
|Discontinued Operations     |                            |        | 15.2  |                                   
|                           
|                            | Total capital expenditures |        | $     | 298.6                             
|                           

Iatan 2

Our Missouri power supply plan indicates the need for base-load capacity after 2009. KCPL is constructing Iatan 2, an 850 MW
coal-fired electric generating facility that will be adjacent to the Iatan 1 electric generation station located in Platte County, Missouri. Iatan 2 is planned for commercial
operation in 2010. We have entered into an ownership agreement with KCPL and other utilities under which we acquired an 18% undivided interest in Iatan 2, which will be operated by KCPL. We
have and will reimburse KCPL for our pro rata share of the construction, operating and maintenance costs and will be entitled to the energy from our pro rata share of Iatan 2's generating
capacity. The capital requirements included in the table above for this participation based on information provided by KCPL, including AFUDC, are estimated as follows: 2008 -
$116.1 million, 2009 - $83.9 million, and 2010 - $72.8 million.

The
construction environment for the Iatan 1 and Iatan 2 projects is challenging, particularly the tight market conditions for skilled labor and lengthening lead times for
delivery of materials, resulting in upward cost pressure. KCPL is conducting a thorough assessment of the impact of
the current environment on the projects' cost and completion schedule. The results of the assessment are expected to be available in the second quarter of 2008.

Environmental Capital Expenditures

The EPA finalized several Clean Air Act regulations such as CAIR, BART and the CAMR regulations in 2005 that would affect our coal-fired power plants
by requiring reductions in emissions of SO2, NOX and mercury. We completed engineering studies that evaluated costs and likely controls for compliance with CAIR, BART and CAMR.
For our Missouri operations, we estimate that probable capital expenditures through 2010 will be approximately $144.7 million based on current engineering bids. Costs have been increasing due
to a number of factors including higher material prices and a shortage of labor in the power sector. At this point we are not able to reasonably estimate if additional costs may be incurred.

30

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Combustion Turbine Plant

We filed an Integrated Resource Plan with the Missouri Commission in February 2007 that included the construction of a combustion turbine plant between 2008 and
2010. The capital expenditures table above includes approximately $186 million to complete this project. We are exploring transmission options for delivery of capacity and energy from the
Crossroads plant in Mississippi to our utility customers in Missouri. If cost effective for our customers, we intend to add the Crossroads plant to our Missouri rate base in lieu of constructing the
new combustion turbine plant. This would eliminate most if not all of the $186 million in capital expenditures that is in the current 2008-2010 forecast for the new combustion
turbine project.

Regulatory Approvals Required for Financing

We are required to obtain the prior approval of the FERC, Kansas Commission and Colorado Commission prior to issuing long-term debt or stock. We have
not requested 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 from time to time up to
$500 million of additional secured or unsecured short-term debt. Our FERC authority to issue short-term debt expires in April 2008, and on January 22, 2008, we
filed an application with the FERC requesting authority to issue up to $500 million of short-term debt securities from time to time over the next two years. We must also obtain the
prior approval of the Kansas Commission to issue short-term debt except as required to meet our working capital requirements.

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 10 million shares of preference stock. Of the 400 million shares of common stock authorized to be issued, 384 million shares have either been issued or reserved for issuance
in connection with 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, taxes, depreciation and amortization (EBITDA). We use EBITDA 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, EBITDA 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 EBITDA, while financing and
income taxes are separately discussed at the corporate level.

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 former Kansas electric utility operations and our former Michigan, Minnesota, and Missouri gas utility operations, (ii) our former peaking
power plants in Illinois, and (iii) our former communications business, Everest Connections. Therefore, the operating

31

---



results
of these assets are discussed separately from the reporting segments to which they relate under the caption "Discontinued Operations."

As
described in Note 6 to the Consolidated Financial Statements, only direct operating costs associated with the utility divisions currently held for sale have been reclassified
to discontinued operations. The costs related to corporate and centralized services that were allocated to these divisions in 2005 remain in continuing operations. Effective January 1, 2006, we
ceased allocating costs to our held-for-sale utilities. We have eliminated the majority of these costs previously incurred to support the sold utility divisions. Fixed costs
that could not be eliminated such as depreciation of shared corporate assets and corporate governance costs have been reallocated to the remaining utility divisions.

The
use of EBITDA 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 EBITDA may not be comparable to similarly titled measures used by other entities.

|                                                                       |                         | Year Ended December 31, |      
|---------------------------------------------------------------------- | ----------------------- | ----------------------- | -----
|
|
|Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization: |                         |                         |      
|Electric Utilities                                                     |                         | $                       | 195.5
|Gas Utilities                                                          |                         |                         | 65.0 
|                                                                       |                        
|Total Utilities                                                        |                         |                         | 260.5
|                                                                       |                        
|Merchant Services                                                      |                         |                         | (5.6 
|Corporate and Other                                                    |                         |                         | (15.9
|                                                                       |                        
|Total EBITDA                                                           |                         |                         | 239.0
|                                                                       |                        
|Depreciation and amortization expense                                  |                         |                         | 108.3
|Interest expense                                                       |                         |                         | 142.8
|Income tax expense (benefit)                                           |                         |                         | 6.0  
|                                                                       |                        
|Loss from continuing operations                                        |                         |                         | (18.1
|Earnings (loss) from discontinued operations, net of tax               |                         |                         | 12.7 
|                                                                       |                        
|Net income (loss)                                                      |                         | $                       | (5.4 
|                                                                       |                        
|Diluted earnings (loss) per share:                                     |                         |                         |      
|                                                                       | Continuing operations   |                         | $    
|                                                                       | Discontinued operations |                         |      
|                                                                       |                        
|                                                                       | Net income (loss)       |                         | $    
|                                                                       |                        

Key Factors Impacting Continuing Operating Results

Our total EBITDA increased significantly in 2007 compared to 2006. Key factors affecting 2007 results were as follows:



32

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Three-Year ReviewElectric Utilities

The table below summarizes the operations of our Missouri and Colorado Electric Utilities, which represent substantially all of our continuing electric
operations:

|                                                        |                                       | Year Ended December 31,
|------------------------------------------------------- | ------------------------------------- | -----------------------
|
|
|Sales:                                                  |                                       |                        
|                                                        | Electricityregulated                 |                        
|                                                        | Othernon-regulated                   |                        
|                                                       
|Total sales                                             |                                       |                        
|                                                       
|Cost of sales:                                          |                                       |                        
|                                                        | Electricityregulated                 |                        
|                                                        | Othernon-regulated                   |                        
|                                                       
|Total cost of sales                                     |                                       |                        
|                                                       
|Gross profit                                            |                                       |                        
|                                                       
|Operation and maintenance expense                       |                                       |                        
|Taxes other than income taxes                           |                                       |                        
|Other income (expense)                                  |                                       |                        
|                                                       
|EBITDA                                                  |                                       | $                      
|                                                       
|Reconciliation of EBITDA to Income Before Income Taxes: |                                       |                        
|                                                        | EBITDA                                |                        
|                                                        | Depreciation and amortization expense |                        
|                                                        | Interest expense                      |                        
|                                                       
|Income before income taxes                              |                                       | $                      
|                                                       
|Electric sales and transmission volumes (GWh)           |                                       |                        
|Electric customers                                      |                                       |                        
|                                                       

2007 versus 2006

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Electric Utilities business increased $70.1 million and $29.3 million, respectively, resulting in a gross profit
increase of $40.8 million in 2007 compared to 2006. These changes were primarily due to the following factors:



33

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Operation and Maintenance Expenses

Operation and maintenance expenses consisted of the following:

|                                                     |  | Year Ended December 31,
|---------------------------------------------------- |  | -----------------------
|
|
|Operating expenses of Colorado and Missouri electric |  | $                      
|Allocated expenses of Kansas electric                |  |                        
|                                                    
|Total operating expenses                             |  | $                      
|                                                    

Taxes Other Than Income Taxes Expense

Taxes other than income taxes expense decreased $2.6 million in 2007 compared to 2006. The primary cause of this decrease was an unfavorable settlement of
a property tax dispute in the second quarter of 2006 that did not recur in 2007.

Other Income (Expense)

Other income increased $10.1 million primarily due to the receipt in 2007 of $3.2 million in breakup fees related to the unsuccessful attempt to
purchase the Aries power plant for which we had been named the stalking horse bidder in an auction process run on behalf of creditors of Calpine Corporation. AFUDC primarily related to the
construction of Iatan 2 of $5.0 million also contributed to the overall increase. AFUDC represents the cost of both debt and equity funds

34

---



used
to finance utility plant additions during the construction period. AFUDC is capitalized as a part of the cost of utility plant and is credited to other income.

2006 versus 2005

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Electric Utilities business increased $84.0 million, $65.1 million and $18.9 million,
respectively, in 2006 compared to 2005. These increases were primarily due to the following factors:



Operation and Maintenance Expenses

Operation and maintenance expense increased $16.9 million in 2006 compared to 2005. A primary factor contributing to this increase was a change in the
allocation of corporate and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities. This change resulted in an
increased allocation of these costs to our Electric Utilities of approximately $10.1 million and a corresponding decreased allocation to our Gas Utilities for the year. Also contributing to the
year-over-year increase was a $6.5 million increase in labor and benefit costs.

Other Income (Expense)

Other income decreased $5.0 million primarily due to decreased AFUDC associated with the construction of our South Harper peaking facility in 2005.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $6.5 million due to the additional depreciation of our South Harper peaking facility, which was placed in
service in the third quarter of 2005, and additional depreciation related to corporate shared assets such as our billing system and call centers. The change in the allocation of central services costs
mentioned above resulted in an increased allocation of centralized asset depreciation to our Electric Utilities and a corresponding decreased allocation to our Gas Utilities.

35

---



Earnings Trend

Our Missouri electric assets comprise a majority of our utility assets, and the earnings generated by our Missouri operations account for a majority of our total
utility earnings and revenue. We expect this trend to continue, and for our financial condition to become increasingly dependent on the revenue and earnings generated by our Missouri operations. We
are making significant investments in our Missouri electric operations which will require us to file multiple rate cases between now and 2010. As we increase rates, we expect the earnings generated by
our Missouri operations to improve.

Three Year ReviewGas Utilities

The table below summarizes the operations of our Colorado, Iowa, Kansas and Nebraska Gas Utilities, which represent our continuing gas operations:

|                                                               |                                       | Year Ended December 31, |        
|-------------------------------------------------------------- | ------------------------------------- | ----------------------- | -------
|
|
|Sales:                                                         |                                       |                         |        
|                                                               | Natural gasregulated                 |                         | $      
|                                                               | Othernon-regulated                   |                         |        
|                                                               |                                      
|Total sales                                                    |                                       |                         | 636.3  
|                                                               |                                      
|Cost of sales:                                                 |                                       |                         |        
|                                                               | Natural gasregulated                 |                         |        
|                                                               | Othernon-regulated                   |                         |        
|                                                               |                                      
|Total cost of sales                                            |                                       |                         | 448.1  
|                                                               |                                      
|Gross profit                                                   |                                       |                         | 188.2  
|                                                               |                                      
|Operation and maintenance expense                              |                                       |                         | 109.6  
|Taxes other than income taxes                                  |                                       |                         | 11.9   
|Other income (expense)                                         |                                       |                         | (1.7   
|                                                               |                                      
|EBITDA                                                         |                                       | $                       | 65.0   
|                                                               |                                      
|Reconciliation of EBITDA to Income (Loss) Before Income Taxes: |                                       |                         |        
|                                                               | EBITDA                                |                         | $      
|                                                               | Depreciation and amortization expense |                         |        
|                                                               | Interest expense                      |                         |        
|                                                               |                                      
|Income (loss) before income taxes                              |                                       | $                       | 21.5   
|                                                               |                                      
|Gas sales and transportation volumes (Mmcf)                    |                                       |                         | 103,162
|Gas customers                                                  |                                       |                         | 519,624
|                                                               |                                      

2007 versus 2006

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Gas Utilities business increased $25.7 million and $5.6 million, respectively, for a gross profit increase of
$20.1 million in 2007 compared to 2006. These changes were primarily due to the following factors:



36

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Operation and Maintenance Expenses

Operation and maintenance expenses consisted of the following:

|                                                              |  | Year Ended December 31,
|------------------------------------------------------------- |  | -----------------------
|
|
|Operating expenses of Colorado, Iowa, Kansas and Nebraska gas |  | $                      
|Allocated expenses of Michigan, Minnesota and Missouri gas    |  |                        
|                                                             
|Total operating expenses                                      |  | $                      
|                                                             

Operation and maintenance expense decreased $3.2 million in 2007 compared to 2006. The decrease was primarily due to lower bad debt and office expenses.

2006 versus 2005

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Gas Utilities business decreased $20.5 million and $24.3 million, respectively, which resulted in a gross profit
increase of $3.8 million in 2006 compared to 2005. These changes were primarily due to the following factors:



37

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Operation and Maintenance Expenses

Operation and maintenance expenses decreased $9.0 million in 2006 compared to 2005. The primary cause of the decrease was a change in the allocation of
corporate and central services costs effective January 1, 2006 to no longer allocate these costs to our held-for-sale utilities. This change resulted in an increased
allocation of these costs to our Electric Utilities of approximately $10.1 million and a corresponding decreased allocation to our Gas Utilities. Partially offsetting the decreased allocation
was an increase in employee benefit costs.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $5.4 million in 2006 compared to 2005, primarily as the result of a decrease in allocated depreciation
related to central services assets and a reduction in the composite depreciation rate for Iowa gas utility plant. The change in the allocation of central services costs discussed above resulted in an
increased allocation of depreciation expense to our Electric Utilities and corresponding decreased allocation to our Gas Utilities.

Three-Year ReviewMerchant Services

Our Merchant Services business consists of our contractual interest in the Crossroads plant and our Aquila Merchant subsidiary, whose assets and liabilities are
limited to its wholesale trading portfolio.

|                                                                      |                                                     | Year Ended December 31, |      
|--------------------------------------------------------------------- | --------------------------------------------------- | ----------------------- | -----
|
|
|Sales                                                                 |                                                     | $                       | (8.4 
|Cost of sales                                                         |                                                     |                         | 2.7  
|                                                                      |                                                    
|Gross loss                                                            |                                                     |                         | (11.1
|                                                                      |                                                    
|Operating expenses:                                                   |                                                     |                         |      
|                                                                      | Operation and maintenance expense                   |                         |      
|                                                                      | Taxes other than income taxes                       |                         |      
|                                                                      | Restructuring charges                               |                         |      
|                                                                      | Net loss (gain) on sale of assets and other charges |                         |      
|                                                                      |                                                    
|Total operating expenses                                              |                                                     |                         | (2.3 
|                                                                      |                                                    
|Other income:                                                         |                                                     |                         |      
|                                                                      | Other income                                        |                         |      
|                                                                      |                                                    
|Earnings (loss) before interest, taxes, depreciation and amortization |                                                     | $                       | (5.6 
|                                                                      |                                                    
|Reconciliation of EBITDA to Loss Before Income Taxes:                 |                                                     |                         |      
|                                                                      | EBITDA                                              |                         | $    
|                                                                      | Depreciation and amortization expense               |                         |      
|                                                                      | Interest expense                                    |                         |      
|                                                                      |                                                    
|Loss before income taxes                                              |                                                     | $                       | (34.8
|                                                                      |                                                    

38

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Due to the application of Emerging Issues Task Force (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", we report 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.

2007 versus 2006

Sales, Cost of Sales and Gross Loss

Gross loss for our Merchant Services operations for 2007 was $11.1 million, primarily due to the following factors:



Gross
loss for our Merchant Services operations for 2006 was $28.0 million, primarily due to the following factors:



Operation and Maintenance Expense, net

Operation and maintenance expense decreased $9.3 million in 2007 from 2006 primarily due to a $15.8 million decrease in the provision for price
reporting litigation offset by the 2006 reversal of $6.6 million of allowances for bad debts provided in prior years as our receivable balance declined with the roll-off of the
legacy trading portfolio.

Net Loss on Sale of Assets and Other Charges

In 2006, we recorded a pretax loss of $218.0 million on the assignment of our rights and obligations under the Elwood tolling agreement.

Other Income

Other income decreased $3.9 million in 2007 compared to 2006 due to less interest income on funds on deposit.

2006 versus 2005

The significant factors causing our $28.0 million gross loss for 2006 are described above.

39

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Gross
loss for our Merchant Services operations for 2005 was $42.8 million, primarily due to the following factors:



Operation and Maintenance Expense

Operation and maintenance expense decreased $6.9 million from 2005 primarily due to $4.5 million of reduced costs for staffing needed to manage our
remaining trading positions and non-regulated power generation assets and $2.8 million lower outside services expenses related to litigation and the wind-down of the
merchant business.

Taxes Other Than Income Taxes

Refunds of taxes other than income taxes decreased $1.4 million from 2005 primarily due to the difference between the $7.2 million refund of value
added taxes we received in 2005 and the $5.0 million refund of Canadian goods and services taxes we received in 2006.

Restructuring Charges

Restructuring charges decreased $6.6 million in 2006 compared to 2005, primarily due to the 2005 termination of the majority of the remaining leases
associated with our former Merchant Services headquarters.

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

In 2006, we recorded a pretax loss of $218.0 million on the assignment of our rights and obligations under the Elwood tolling agreement. In 2005, we had
pretax gains of $16.3 million on the assignment of our rights and obligations under the Batesville tolling agreement and related forward sale contract and $9.3 million on the sale of our
stock investment in ICE and $6.2 million on the sale of our Red Lake gas storage development project.

40

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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. We have assessed the
realizability of our investment in the Crossroads plant and do not believe an impairment has occurred. We will continue to have operating and maintenance costs associated with this plant, whether it
is being utilized to generate power or is idle. As of December 31, 2007, the carrying value of this plant was $112.2 million. We are exploring transmission options for delivery of
capacity and energy from the Crossroads plant in Mississippi to our utility customers in Missouri. If cost effective for our customers, we intend to add the Crossroads plant to our Missouri rate base.
Additionally, we
continue to wind down and terminate our remaining trading positions with various counterparties. However, it will take a number of years to complete the wind-down. Because most of our
remaining 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, and
the termination or liquidation of additional trading contracts. As a result of the above factors, we do not expect Merchant Services to be profitable in the next two to three years.

Corporate Matters

Three-Year ReviewCorporate and Other

The table below summarizes EBITDA for Corporate and Other, which includes the retained costs of the Company that are not allocated to our operating businesses.

We
sold our former 97% owned subsidiary, Everest Connections, a communications provider, in June 2006. The results of Everest Connections have been reclassified as discontinued
operations and are not included below (see Note 6 to the Consolidated Financial Statements).

|                                                                         |                                              | Year Ended December 31, |      
|------------------------------------------------------------------------ | -------------------------------------------- | ----------------------- | -----
|
|
|Sales                                                                    |                                              | $                       |     
|Cost of sales                                                            |                                              |                         |     
|                                                                         |                                             
|Gross profit                                                             |                                              |                         |     
|                                                                         |                                             
|Operating expenses:                                                      |                                              |                         |      
|                                                                         | Operation and maintenance expense            |                         |      
|                                                                         | Taxes other than income taxes                |                         |      
|                                                                         | Restructuring charges                        |                         |      
|                                                                         | Net loss on sale of assets and other charges |                         |      
|                                                                         |                                             
|Total operating expenses                                                 |                                              |                         | 29.7 
|                                                                         |                                             
|Other income:                                                            |                                              |                         |      
|                                                                         | Other income                                 |                         |      
|                                                                         |                                             
|Earnings (loss) before interest and taxes, depreciation and amortization |                                              | $                       | (15.9
|                                                                         |                                             
|Reconciliation of EBITDA to Loss Before Income Taxes:                    |                                              |                         |      
|                                                                         | EBITDA                                       |                         | $    
|                                                                         | Depreciation and amortization expense        |                         |      
|                                                                         | Interest expense                             |                         |      
|                                                                         |                                             
|Loss before income taxes                                                 |                                              | $                       | (63.2
|                                                                         |                                             

41

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2007 versus 2006

Operation and Maintenance Expense

Operation and maintenance expense increased $9.8 million primarily due to approximately $24.5 million of advisor fees, employee retention costs and
legal costs related to the pending merger offset in part by costs associated with asset sales in 2006.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $3.8 million in 2007 compared to 2006 as a result of a $3.1 million settlement of a withholding tax audit in
2006.

Restructuring Charges

We recorded $1.5 million of one-time termination benefits in 2007 related to the departure of our Chief Operating Officer. In 2006, we accrued
approximately $5.7 million of one-time termination benefits related to the plan to reduce executive management and central services costs in connection with the sale of our Kansas
electric and Michigan, Minnesota and Missouri gas operations.

Net Loss on Sale of Assets and Other Charges

In 2007, we recorded a pretax loss of $1.3 million related to the early retirement of $344 million of outstanding senior notes. In 2006, we recorded
pretax losses of $28.2 million upon the completion of a cash tender offer that resulted in the early retirement of approximately $350 million of outstanding senior notes and the
prepayment of our five-year term loan.

Other Income

Other income decreased $13.3 million in 2007 compared to 2006 primarily due to $11.0 million of lower interest on invested cash and
$9.9 million of interest on IRS refunds in 2006 offset in part by $3.6 million of net gains on the sale of excess land and office space in 2007 and a $2.2 million release of
Canadian withholding tax reserves in 2007.

2006 versus 2005

Operation and Maintenance Expense

Operation and maintenance expense decreased $4.0 million in 2006 as a result of lower legal fees related to litigation and a reduction in consulting fees
and other costs associated with the process of selling certain of our Gas and Electric Utilities in 2005, offset in part by merger related costs in 2006 of $2.3 million, primarily legal and
investment banking fees. See Note 19 to the Consolidated Financial Statements.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.8 million in 2006 compared to 2005 primarily due to a $3.1 million settlement of a withholding tax audit.

Restructuring Charges

In connection with the sale of our Kansas electric and Michigan, Minnesota and Missouri gas operations, management adopted and communicated to employees a plan to
reduce corporate and central services costs, which included the elimination of 83 employee positions through involuntary terminations. Approximately $5.7 million of one-time
termination benefits were accrued in 2006.

42

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Net Loss on Sale of Assets and Other Charges

In 2006, we recorded a pretax loss of $28.2 million upon the completion of a cash tender offer that resulted in the early retirement of approximately
$350 million of outstanding senior notes and the prepayment of our five-year term loan. In 2005, we recorded a loss of $82.3 million related to the early conversion of the
PIES. In addition, we recognized a $4.4 million loss in 2005 on three natural gas combustion turbines that were held by one of our non-regulated subsidiaries and were transferred to
our Missouri electric operations at their current fair value.

Other Income

Other income increased $22.5 million in 2006 compared to 2005 primarily due to increased interest income on available cash balances and interest income on
tax refunds partially offset by additional letter of credit fees under our $180 million Revolving Credit and Letter of Credit Facility.

Interest Expense and Income Tax Benefit

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

|                             |  | Year Ended December 31, |      
|---------------------------- |  | ----------------------- | -----
|
|
|                             |  |                         |      
|Interest expense             |  | $                       | 142.8
|                             | 
|Income tax expense (benefit) |  | $                       | 6.0  
|                             | 

2007 versus 2006

Interest Expense

Interest expense decreased $16.4 million in 2007 compared to 2006 due to $29.7 million of interest savings on the retirement of $350 million
of debt in 2006 and $368 million of debt in 2007 and $17.1 million of savings related to the prepayment of the five-year term loan in September 2006. These decreases were
offset in part by $30.5 million of decreased allocations of interest to discontinued operations due to the completion of the sale of certain assets in 2006 and 2007.

Income Tax Expense (Benefit)

Income tax expense (benefit) decreased $73.3 million in 2007 compared to 2006. The effective tax rate in 2007 was (48.8)% compared to 19.3% in 2006. The
effective tax rate for 2007 differed from the combined statutory rate as a result of approximately $31.2 million of valuation allowance provided on deferred tax assets and $8.6 million
of tax provisions resulting from Canadian tax audit adjustments received in the second quarter, offset in part by $26.9 million of reductions in unrecognized tax benefits. The effective tax
rate for 2006 differed from the combined statutory
rate as a result of $84.6 million of unrecognized tax benefits provided in 2006 in connection with the $218 million loss on the assignment of our obligations under the Elwood tolling
agreement.

43

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2006 versus 2005

Interest Expense

Interest expense increased $9.0 million in 2006 compared to 2005 primarily due to $36.4 million of decreased allocations of interest to discontinued
operations due to the completion of the sale of certain assets. This increase in expense for continuing operations reflects the delay between the receipt of cash proceeds and the use of that cash to
reduce debt. In addition, to the extent that cash proceeds are used to reduce obligations other than debt this interest expense will remain in continuing obligations. The increase also includes the
write-off of $3.5 million of deferred debt costs related to the prepayment of our five-year term loan in September 2006. These increases were offset in part by
$18.2 million of lower interest costs resulting from the retirement of $350 million of senior notes in a debt tender in June 2006 and the prepayment of the five-year term
loan in September 2006. Interest expense also decreased in 2006 compared to 2005 by approximately $10.6 million related to the early conversion of the PIES issued in August 2004.

Income Tax Benefit

Income tax benefit increased $24.2 million in 2006 compared to 2005 primarily as a result of greater pretax losses in 2006. The effective tax rate in 2006
was 19.3% primarily as a result of the $84.6 million reserve for uncertain tax positions provided in 2006 in connection with the $218 million loss on the assignment of our obligations
under the Elwood tolling agreement. The effective tax rate in 2005 was 21.4% primarily as a result of a non-deductible loss related to the PIES exchange.

Discontinued Operations

Operating results of discontinued operations are as follows:

|                                             |                                                     | Year Ended December 31, |     
|-------------------------------------------- | --------------------------------------------------- | ----------------------- | ----
|
|
|                                             |                                                     |                         |     
|Sales                                        |                                                     | $                       | 45.8
|Cost of sales                                |                                                     |                         | 23.4
|                                             |                                                    
|Gross profit                                 |                                                     |                         | 22.4
|                                             |                                                    
|Operating expenses:                          |                                                     |                         |     
|                                             | Operation and maintenance expense                   |                         |     
|                                             | Taxes other than income taxes                       |                         |     
|                                             | Restructuring charges                               |                         |     
|                                             | Net loss (gain) on sale of assets and other charges |                         |     
|                                             |                                                    
|Total operating expenses (income)            |                                                     |                         | 9.7 
|                                             |                                                    
|Other income (expense):                      |                                                     |                         |     
|                                             | Other income                                        |                         |     
|                                             |                                                    
|EBITDA                                       |                                                     |                         | 12.9
|                                             | Depreciation and amortization expense               |                         |     
|                                             | Interest expense                                    |                         |     
|                                             |                                                    
|Earnings (loss) before income taxes          |                                                     |                         | 8.8 
|Income tax expense (benefit)                 |                                                     |                         | (3.9
|                                             |                                                    
|Earnings (loss) from discontinued operations |                                                     | $                       | 12.7
|                                             |                                                    

44

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2007 versus 2006

Sales, Cost of Sales and Gross Profit

Electric
Utilities

Sales
and cost of sales for our Kansas electric utility decreased $146.6 million and $72.3 million, respectively, resulting in a gross profit decrease of
$74.3 million in 2007 compared to 2006 primarily due to the sale of these operations on April 1, 2007.

Gas
Utilities

Sales
and cost of sales for our Michigan, Minnesota, and Missouri gas utilities decreased $296.7 million and $238.6 million, respectively, resulting in a gross profit
decrease of $58.1 million due to the sale of these operations in 2006.

Corporate
and Other

Sales,
cost of sales and gross profit decreased $25.1 million, $8.2 million, and $16.9 million, respectively, in 2007 compared to 2006 due to the sale of our Everest
Connections subsidiary in June 2006 and our Illinois merchant peaking facilities in March 2006.

Operation and Maintenance and Taxes Other Than Income Taxes Expense

Operation and maintenance and taxes other than income taxes expense decreased $60.1 million and $8.9 million, respectively, in 2007 compared to 2006
primarily as a result of the sale of our former Michigan, Missouri, and Minnesota gas operations and our Everest Connections subsidiary in 2006 and our Kansas electric operations on April 1,
2007.

Net (Gain) on Sale of Assets and Other Charges

In 2006, we sold our Michigan, Missouri and Minnesota gas operations and Everest Connections and recognized gains of $92.2 million, $30.7 million,
$120.5 million and $25.5 million, respectively. In 2007, we sold our Kansas electric operations and recognized a gain of $1.8 million and recorded final adjustments of
$1.8 million related to peaking plants and gas operations which were sold in 2006.

Interest Expense

Interest expense decreased $30.5 million in 2007 compared to 2006 as the allocations to our Michigan, Missouri and Minnesota gas operations, our two
Illinois merchant peaking facilities and our Everest Connections subsidiary ended when they were sold.

Income Tax Expense (Benefit)

Income tax expense decreased $19.3 million in 2007 compared to 2006 primarily due to taxes provided on higher pretax earnings in 2006 resulting from gains
on the sale of Michigan and Missouri gas operations and Everest Connections. The effective income tax rate for 2007 was (44.3)% compared to 4.8% for 2006. The 2007 tax rate was affected by the release
of $7.2 million of valuation allowance due to additional capital gains on the sale of operations recognized on our 2006 income tax return. The 2006 effective income tax rate was impacted by the
release of $112.6 million of valuation allowances resulting from estimated capital gains on the sale of our Michigan, Missouri and Minnesota gas operations, partially offset by the effect of
the write-off of non-deductible acquisition premiums in the pretax gain on the sale of our Michigan gas operations.

45

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2006 versus 2005

Sales, Cost of Sales and Gross Profit

Electric
Utilities

Sales
for our Kansas electric utility decreased $2.0 million, while cost of sales decreased $9.1 million, resulting in a $7.1 million increase in gross profit in
2006 compared to 2005. Sales and gross profit increased by $2.2 million due to a rate increase in Kansas effective in April 2005 and by $1.5 million due to increased transmission and
other revenues. Lower demand charges and transmission costs combined with the positive impact of emission allowance cost recovery in the ECA resulted in a net $3.2 million increase in gross
profit.

Gas
Utilities

Sales
and cost of sales for our Michigan, Minnesota, and Missouri gas utilities decreased $325.7 million and $240.1 million, respectively, resulting in a gross profit
decrease of $85.6 million. The sale of our Michigan, Missouri and Minnesota gas operations decreased sales, cost of sales and gross profit by $323.5 million, $248.5 million and
$75.0 million, respectively. Sales and cost of sales increased approximately $50.8 million due to a 32.8% increase in gas costs primarily in the first quarter of 2006 which were passed
through to our customers with no impact on gross profit. Unseasonably mild winter weather decreased gas volumes sold and reduced sales, cost of sales and gross profit, primarily in Michigan and
Minnesota, by $52.0 million, $44.2 million and $7.8 million, respectively, in the first half of 2006.

Other

Other
sales, cost of sales and gross profit decreased $35.7 million, $15.5 million and $20.2 million, respectively in 2006 compared to 2005. These decreases were due
to the sale of our Illinois peaking power plants on March 31, 2006 and Everest Connections on June 30, 2006.

Operation and Maintenance Expense

Operation and maintenance expense decreased $33.3 million in 2006 compared to 2005 primarily as a result of the sale of our Michigan and Missouri gas
operations and our Everest Connections subsidiary in the second quarter of 2006 and the sale of our Minnesota gas operations at the beginning of the third quarter of 2006.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.5 million in 2006 compared to 2005, primarily due to a Minnesota property tax settlement in 2005 regarding
protested property valuations in prior tax years.

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

During 2006 we closed on the sale of our Michigan, Minnesota and Missouri gas operations and Everest Connections and recognized gains of $92.2 million,
$120.5 million, $30.7 million and $25.5 million, respectively. The 2005 net loss on sales of assets and other charges of $159.5 million was the result of an impairment of
our former Illinois peaking power plants.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $41.6 million in 2006 compared to 2005 as a result of the elimination of depreciation from our Kansas
electric and Michigan, Minnesota and Missouri gas utility businesses, Goose Creek and Raccoon Creek peaking plants and Everest

46

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Connections
in 2006, due to their classification as held for sale in 2005 in accordance with SFAS 144.

Interest Expense

Interest expense decreased $36.6 million in 2006 compared to 2005 as the allocations to our Michigan, Minnesota, and Missouri gas operations, our two
Illinois peaking plants and our Everest Connections subsidiary ended when they were sold. In addition, allocations to the Illinois peaking plants decreased in the first quarter of 2006 due to the
decrease in the proportion of these assets to total net assets resulting from the impairment charges recognized in the fourth quarter of 2005.

Income Tax Expense (Benefit)

Income tax expense increased $56.4 million in 2006 compared to 2005 due in part to the increased income before income taxes resulting from the gains on the
sales discussed above. The effective income tax rate for 2006 was 4.8% compared to 36.3% for 2005 primarily due to the reversal of $112.6 million of valuation allowances on capital losses
resulting from estimated capital gains realized on the sale of our Michigan, Missouri, and Minnesota gas operations, partially offset by the effect of the write-off of
non-deductible acquisition premiums in the pretax gain on the sale of our Michigan gas operations.

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 No. 133, "Accounting for Derivative and Hedging Activities" (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:



47

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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. 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 financial instruments are considered derivatives under SFAS 133 and are marked-to-market and recorded in our PGA accounts as they are collectible under the
provisions of the PGA upon settlement. We also have entered into a program for our electric utility operations in Missouri to mitigate our exposure to natural gas price volatility in the market. This
program extends multiple years and the mark-to-market liability position of the portfolio of $3.9 million related to contracts that will settle against actual purchases
of natural gas and purchased power in 2008 through 2010. In connection with the 2005 Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they
settle. A net regulatory asset has been recorded under SFAS 71 in the amount of $3.9 million to reflect the change in the timing of recognition authorized by the Missouri Commission.

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, 2007 were $86.4 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 144. 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

48

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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.

We
evaluated the carrying value of the Crossroads plant as of December 31, 2005. We performed this evaluation due to reduced spark spreads and an oversupply of generation at that
time. This situation has prevented the plant from producing significant margins and, in turn, has created losses for us. We separately tested the cash flows for the plant based on estimated margin
contributions and forecasted operating expenses over its remaining plant life. The peaking plant was placed into service in 2002 and we depreciate the facility 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 this asset, the undiscounted probability weighted cash flows for the plant significantly exceeded its then current book value. Therefore, under
SFAS 144 no impairment was required as of December 31, 2005. We have evaluated this asset as held and used. As of December 31, 2007, we reviewed market conditions and the
assumptions used in the 2005 assessment and determined that no significant adverse changes had occurred. Therefore, a full assessment was not required. As of December 31, 2007, the carrying
value of this plant was $112.2 million.

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 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
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, 2007 was $111.0 million.

Regulatory Accounting Implications

We currently record the economic effects of regulation in accordance with the provisions of 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

49

---



earnings.
Total regulatory assets and liabilities at December 31, 2007 were $183.6 million and $99.8 million, respectively. See Note 9 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 using a "more likely than not" assessment threshold. Our most significant deferred tax
assets relate to net operating loss carryforwards, capital loss carryforwards and alternative minimum tax credits. The assessment considered tax planning strategies within our control. The assessment,
however, did not take into consideration the expected taxable gains, both capital and ordinary, from the pending sales of our Colorado electric property and our Colorado, Kansas, Iowa and Nebraska gas
properties. In addition, the assessment did not take into consideration our pending merger with Great Plains Energy. See Note 15 to the Consolidated Financial Statements for discussion
regarding the valuation allowance against deferred tax assets.

Unrecognized Tax Benefits

As of December 31, 2007, we have unrecognized tax benefits of $205.2 million, $169.2 million of which would impact the effective rate if
recognized. We have also recorded $5.8 million of interest expense (net of tax benefit) related to these unrecognized tax benefits. The tax returns containing the tax deductions or income
positions that generated the unrecognized tax benefits are currently under audit or will likely be audited. We use significant judgment in the determination of whether tax benefits meet the "more
likely than not" threshold for recognition pursuant to FIN 48. See Note 15 to the Consolidated Financial Statements for further discussion.

Pension Plans

Our reported costs of providing non-contributory defined pension benefits (described in Note 16 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, 2007, our average assumed discount rate was 6.51% and our average expected return on plan assets was 8.25%.

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, 2007, and our estimated annual
pension cost (APC) on the income statement for 2008 by a similar amount in the opposite

50

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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                              | % | $                         | (10.4 | )                         | $
|Rate of return on plan assets |  | .25                              | % |                           |      |                           |  
|                              | 

Legal Contingencies

We are currently involved in various claims and legal proceedings. We periodically review the status of each significant matter and assess our potential financial
exposure. If the potential loss from any claim or legal proceeding is considered probable and the amount can be reasonably estimated, we accrue a liability for the estimated loss. We use significant
judgment in both the determination of probability and the determination as to whether an exposure is reasonably estimable. Because of uncertainties related to these matters, accruals are based only on
the best information at that time. As additional information becomes available, we reassess the potential liability related to our pending claims and litigation and may revise our estimates. Such
revisions in the estimates of potential liabilities could have a material impact on our financial position and results of operations. We expense legal fees as incurred.

Significant Balance Sheet Movements

Total assets decreased by $478.8 million since December 31, 2006. This decrease is primarily due to the following:



51

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Total
liabilities decreased by $528.4 million and common shareholders' equity increased by $49.6 million since December 31, 2006. These changes are primarily
attributable to the following:



New Accounting Standards

In 2006 and 2007, the Financial Accounting Standards Board (FASB) issued a number of interpretations, staff positions and new accounting standards that had
potential impacts on our financial results. In 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS 157), SFAS No. 158, "Employers' Accounting for Defined Benefit
Pension and Other Postretirement Plansan amendment of FASB Statements No. 87, 88, 106, and 132(R)" (SFAS 158), FIN No. 48, "Accounting for Uncertainty in Income
Taxes" (FIN 48), and FASB Staff Position (FSP) AUG AIR-1 "Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1). In 2006, the SEC issued Staff Accounting
Bulletin (SAB) No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements" (SAB 108). In 2007, the FASB issued SFAS
No. 160, "Noncontrolling Interests in Consolidated Financial Statements" (SFAS 160) and SFAS No. 141R,
"Business Combinations" (SFAS 141R). See Notes 2, 15 and 16 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.

52

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Forward-Looking Information

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:



53

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Market RiskUtility Operations

Our regulated businesses produce, purchase and distribute power in two states and purchase and distribute natural gas in four 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 continuing regulated electric business in 2007, we generated approximately 52% of the power that we sold and we purchased the remaining 48% through long-term contracts
or in the open market. The regulatory provisions for recovering power cost vary by state. In Colorado, we have an ECA that serves a purpose similar to the PGAs for our gas utilities. To the extent
that our fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, we have a fuel adjustment
mechanism that permits us to adjust rates based on 95% of the cost of increases or decreases in purchased power and fuel.

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 100% of our native load fuel requirements of coal-fired generation in 2008 and 46% in 2009, respectively. The price risk associated with our natural gas and on-peak spot
market purchased power requirements is also mitigated through a hedging plan using NYMEX futures contracts and options. This is a multi-year hedging plan. As of December 31, 2007,
we had financial contracts in place to hedge approximately 53% of our expected on-peak natural gas and natural gas equivalent purchased power price
exposure for 2008. The mark-to-market value of these contracts at December 31, 2007 was a liability of $3.9 million.

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 and interest 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 and interest rate contracts that are settled
by the delivery of the commodity or cash. These contracts take many forms, including futures, forwards, swaps and options. As we are winding down our trading portfolio, most of our positions have been
hedged to limit our exposure to the above risks.

We
measure the risk in our trading portfolio using a value-at-risk methodology assuming a 95% confidence level, a one day holding period to liquidate positions
and historical volatility and correlations which weight recent activity more heavily. The average value-at-risk for all commodities during 2007 was $.3 million. As
determined by our Board of Directors, our value-at-risk limit is currently $3.0 million for the remaining commodity trading portfolio and $5.0 million for the
aggregate book that includes the first 18 months of Merchant Services asset positions. In addition to value-at-risk, we also apply other risk control measures that
incorporate

54

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volumetric
limits by commodity, loss limits, durational limits and application of stress testing to our various risk portfolios.

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. Under SFAS 133, our energy commodity trading contracts, including physical
transactions (mainly gas) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of
counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market
prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. In addition, the market prices or fair values used in
determining the value of the portfolio are our best estimates utilizing information such as historical volatility, time value, counterparty credit and the potential impact on market prices of
liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When market prices are not readily available or determinable, certain contracts are
recorded at fair value using an alternative approach such as model pricing.

The
changes in fair value of our Utilities and Merchant Services derivative contracts for 2007 are summarized below:

|In millions                                       |  | Utilities |       | Merchant
Services |   | Total |  
|------------------------------------------------- |  | --------- | ----- | ----------------- | - | ----- | -
|                                                  | 
|                                                  |  |           |       |                   |   |       |  
|Fair value at December 31, 2006                   |  | $         | (19.1 | )                 | $ | 32.2  |  
|Increase (decrease) in fair value during the year |  |           | .6    |                   |   | (1.8  | )
|Contracts realized or cash settled                |  |           | 20.0  |                   |   | (18.5 | )
|                                                  | 
|Fair value at December 31, 2007                   |  | $         | 1.5   |                   | $ | 11.9  |  
|                                                  | 

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

|In millions                                        |  | 2008 |    | 2009 |   | 2010 |  | 2011 |     | Thereafter |   | Total
|-------------------------------------------------- |  | ---- | -- | ---- | - | ---- |  | ---- | --- | ---------- | - | -----
|                                                  
|                                                   |  |      |    |      |   |      |  |      |     |            |   |      
|Prices actively quoted                             |  | $    | .8 |      | $ | 4.7  |  | $    |    |            | $ |     
|Prices provided by other external sources          |  |      |   |      |   |     |  |      | 1.2 |            |   |     
|Priced based on models and other valuation methods |  |      |   |      |   |     |  |      |    |            |   | 1.0  
|                                                  
|Net price risk management assets                   |  | $    | .8 |      | $ | 4.7  |  | $    | 1.2 |            | $ | 1.0  
|                                                  

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,

55

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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, 2007, associated with our forward positions within our trading portfolio and our billed receivables (excluding
tariff 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 |       | $                | 55.5 |                      | $ | 33.5 
|Financial institutions  |       |                  | 16.6 |                      |   |     
|                       
|                        | Total |                  | $    | 72.1                 |   | $    
|                       

A
majority of the customers in our Electric and Gas Utilities businesses are billed under jurisdictional tariffs in the states in which we operate. We are obligated to provide service to
all of our electric and gas customers within their respective franchised territories. Credit risk is managed by credit and collection policies that are consistent with state regulatory requirements.
See pages 9 and 10 under Business for a breakout of our utility customers by type.

Currency Rate Exposure

We have wound down our Canadian merchant trading business, which was included in our Merchant Services segment, and have sold our utility businesses in Canada,
Australia, New Zealand and the United Kingdom. Our remaining currency rate exposure relates only to approximately $1.3 million of cash and restricted cash held in foreign countries.

Interest Rate Exposure

We do not have a material amount of unhedged variable rate financial obligations at December 31, 2007.

56

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Item 8.    Financial Statements and Supplementary Data

|                                                                                                   |                                                             |     |     | Page
|-------------------------------------------------------------------------------------------------- | ----------------------------------------------------------- | --- | --- | ----
|
|Consolidated Statements of Income for the three years ended December 31, 2007                      |                                                             | 58 
|Consolidated Balance Sheets at December 31, 2007 and 2006                                          |                                                             | 59 
|Consolidated Statements of Common Shareholders' Equity for the three years ended December 31, 2007 |                                                             | 60 
|Consolidated Statements of Comprehensive Income for the three years ended December 31, 2007        |                                                             | 61 
|Consolidated Statements of Cash Flows for the three years ended December 31, 2007                  |                                                             | 62 
|Notes to Consolidated Financial Statements:                                                        |                                                             | 63 
|                                                                                                   | Note 1: Summary of Significant Accounting Policies          |     | 63 
|                                                                                                   | Note 2: New Accounting Standards                            |     | 67 
|                                                                                                   | Note 3: Risk Management                                     |     | 69 
|                                                                                                   | Note 4: Restructuring Charges                               |     | 71 
|                                                                                                   | Note 5: Net (Gain) Loss on Sale of Assets and Other Charges |     | 73 
|                                                                                                   | Note 6: Discontinued Operations                             |     | 75 
|                                                                                                   | Note 7: Accounts Receivable                                 |     | 78 
|                                                                                                   | Note 8: Utility and Non-Utility Plant                       |     | 79 
|                                                                                                   | Note 9: Regulatory Assets and Liabilities                   |     | 81 
|                                                                                                   | Note 10: Short-Term Debt                                    |     | 83 
|                                                                                                   | Note 11: Long-Term Debt                                     |     | 85 
|                                                                                                   | Note 12: Capital Stock and Stock Compensation               |     | 88 
|                                                                                                   | Note 13: Accumulated Other Comprehensive Income (Loss)      |     | 95 
|                                                                                                   | Note 14: Earnings (Loss) Per Share                          |     | 96 
|                                                                                                   | Note 15: Income Taxes                                       |     | 97 
|                                                                                                   | Note 16: Employee Benefits                                  |     | 104
|                                                                                                   | Note 17: Segment Information                                |     | 113
|                                                                                                   | Note 18: Commitments and Contingencies                      |     | 116
|                                                                                                   | Note 19: Pending Merger                                     |     | 120
|                                                                                                   | Note 20: Quarterly Financial Data (Unaudited)               |     | 122
|Report of Independent Registered Public Accounting Firm                                            |                                                             | 123

57

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Aquila, Inc.  Consolidated Statements of Income

|                                                         |                                              | Year Ended December 31, |        
|-------------------------------------------------------- | -------------------------------------------- | ----------------------- | -------
|
|                                                         |                                             
|Sales:                                                   |                                              |                         |        
|                                                         | Electricityregulated                        |                         | $      
|                                                         | Natural gasregulated                        |                         |        
|                                                         | Othernon-regulated                          |                         |        
|                                                         |                                             
|Total sales                                              |                                              |                         | 1,466.6
|                                                         |                                             
|Cost of sales:                                           |                                              |                         |        
|                                                         | Electricityregulated                        |                         |        
|                                                         | Natural gasregulated                        |                         |        
|                                                         | Othernon-regulated                          |                         |        
|                                                         |                                             
|Total cost of sales                                      |                                              |                         | 900.9  
|                                                         |                                             
|Gross profit                                             |                                              |                         | 565.7  
|                                                         |                                             
|Operating expenses:                                      |                                              |                         |        
|                                                         | Operation and maintenance expense            |                         |        
|                                                         | Taxes other than income taxes                |                         |        
|                                                         | Restructuring charges                        |                         |        
|                                                         | Net loss on sale of assets and other charges |                         |        
|                                                         | Depreciation and amortization expense        |                         |        
|                                                         |                                             
|Total operating expenses                                 |                                              |                         | 459.4  
|                                                         |                                             
|Operating income (loss)                                  |                                              |                         | 106.3  
|                                                         |                                             
|Other income, net                                        |                                              |                         | 24.4   
|Interest expense                                         |                                              |                         | 142.8  
|                                                         |                                             
|Loss from continuing operations before income taxes      |                                              |                         | (12.1  
|Income tax expense (benefit)                             |                                              |                         | 6.0    
|                                                         |                                             
|Loss from continuing operations                          |                                              |                         | (18.1  
|Earnings (loss) from discontinued operations, net of tax |                                              |                         | 12.7   
|                                                         |                                             
|Net income (loss)                                        |                                              | $                       | (5.4   
|                                                         |                                             
|Basic and diluted earnings (loss) per common share:      |                                              |                         |        
|                                                         | Continuing operations                        |                         | $      
|                                                         | Discontinued operations                      |                         |        
|                                                         |                                             
|                                                         | Net income (loss)                            |                         | $      
|                                                         |                                             

See
accompanying notes to consolidated financial statements.

58

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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                       |             
|                                           | Regulatory assets, current                         |             
|                                           | Other current assets                               |             
|                                           | Current assets of discontinued operations          |             
|                                          
|Total current assets                       |                                                    |             
|                                          
|                                           | Utility plant, net                                 |             
|                                           | Non-utility plant, net                             |             
|                                           | Price risk management assets                       |             
|                                           | Goodwill, net                                      |             
|                                           | Pension asset                                      |             
|                                           | Regulatory assets                                  |             
|                                           | Deferred charges and other assets                  |             
|                                           | Non-current assets of discontinued operations      |             
|                                          
|Total Assets                               |                                                    | $           
|                                          
|Liabilities and Shareholders' Equity       |                                                    |             
|Current liabilities:                       |                                                    |             
|                                           | Current maturities of long-term debt               |             
|                                           | Short-term debt                                    |             
|                                           | Accounts payable                                   |             
|                                           | Accrued interest                                   |             
|                                           | Regulatory liabilities, current                    |             
|                                           | Accrued compensation and benefits                  |             
|                                           | Pension and post-retirement benefits, current      |             
|                                           | Other accrued liabilities                          |             
|                                           | Price risk management liabilities                  |             
|                                           | 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                  |             
|                                           | Pension and post-retirement benefits               |             
|                                           | Regulatory liabilities                             |             
|                                           | 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.

59

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Aquila, Inc.  Consolidated Statements of Common Shareholders' Equity

|                                                                                                                                                                                                                                                                                                                         |                                                     | Year Ended December 31, |         
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | --------------------------------------------------- | ----------------------- | --------
|
|
|                                                                                                                                                                                                                                                                                                                         |                                                     |                         |         
|Common stock:authorized 400 million shares at December 31, 2007, 2006 and 2005, par value $1 per share, 375,959,157 shares issued at December 31, 2007, 374,611,194 at
December 31, 2006 and 373,603,277 at December 31, 2005; authorized 20 million shares of Class A common stock, par value $1 per share, none issued |                                                     |                         |         
|                                                                                                                                                                                                                                                                                                                         | Balance beginning of year                           |                         | $       
|                                                                                                                                                                                                                                                                                                                         | Issuance of shares through PIES exchange/conversion |                         |         
|                                                                                                                                                                                                                                                                                                                         | Issuance of shares under compensation arrangements  |                         |         
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Balance end of year                                                                                                                                                                                                                                                                                                      |                                                     |                         | 376.0   
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Premium on capital stock:                                                                                                                                                                                                                                                                                                |                                                     |                         |         
|                                                                                                                                                                                                                                                                                                                         | Balance beginning of year                           |                         |         
|                                                                                                                                                                                                                                                                                                                         | Issuance of shares through PIES exchange/conversion |                         |         
|                                                                                                                                                                                                                                                                                                                         | Issuance of shares under compensation arrangements  |                         |         
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Balance end of year                                                                                                                                                                                                                                                                                                      |                                                     |                         | 3,512.5 
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Accumulated deficit:                                                                                                                                                                                                                                                                                                     |                                                     |                         |         
|                                                                                                                                                                                                                                                                                                                         | Balance beginning of year                           |                         |         
|                                                                                                                                                                                                                                                                                                                         | Net income (loss)                                   |                         |         
|                                                                                                                                                                                                                                                                                                                         | Cumulative effect of accounting change              |                         |         
|                                                                                                                                                                                                                                                                                                                         | Other                                               |                         |         
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Balance end of year                                                                                                                                                                                                                                                                                                      |                                                     |                         | (2,533.1
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Treasury stock, at cost, 53,742 shares at December 31, 2007 (90,063 shares at December 31, 2006 and 7 shares at December 31, 2005)                                                                                                                                                                                       |                                                     |                         | (.2     
|Accumulated other comprehensive income (loss)                                                                                                                                                                                                                                                                            |                                                     |                         | .5      
|                                                                                                                                                                                                                                                                                                                         |                                                    
|Total Common Shareholders' Equity                                                                                                                                                                                                                                                                                        |                                                     | $                       | 1,355.7 
|                                                                                                                                                                                                                                                                                                                         |                                                    

See
accompanying notes to consolidated financial statements.

60

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Aquila, Inc.  Consolidated Statements of Comprehensive Income

|                                                                      |                                                                                                                                                                                                                                | Year Ended December 31, |     
|--------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | ----------------------- | ----
|
|
|Net income (loss)                                                     |                                                                                                                                                                                                                                | $                       | (5.4
|Other comprehensive income (loss), net of related tax:                |                                                                                                                                                                                                                                |                         |     
|Foreign currency adjustments:                                         |                                                                                                                                                                                                                                |                         |     
|                                                                      | Foreign currency translation adjustments, net of deferred tax expense (benefit) of $.6 million, $(.1) million and $(.2) million for 2007, 2006 and 2005, respectively                                                          |                         |     
|                                                                      | Reclassification of foreign currency (gains) losses to income due to sale of businesses and other, net of deferred tax (expense) benefit of $(.5) million, $.1 million and $(.4) million for 2007, 2006 and
2005, respectively |                         |     
|                                                                      |                                                                                                                                                                                                                               
|                                                                      | Total foreign currency adjustments                                                                                                                                                                                             |                         |     
|                                                                      |                                                                                                                                                                                                                               
|Pension and post-retirement benefits costs arising during the period: |                                                                                                                                                                                                                                |                         |     
|                                                                      | Net actuarial gain, net of deferred tax expense (benefit) of $ million after valuation allowance for 2007                                                                                                                     |                         |     
|Pension and post-retirement benefits costs amortized to income:       |                                                                                                                                                                                                                                |                         |     
|                                                                      | Prior service cost, net of deferred tax expense (benefit) of $ million after valuation allowance for 2007                                                                                                                     |                         |     
|                                                                      | Net actuarial loss, net of deferred tax expense (benefit) of $ million after valuation allowance for 2007                                                                                                                     |                         |     
|                                                                      | Accumulated regulatory loss adjustment, net of deferred tax expense (benefit) of $ million after valuation allowance for 2007                                                                                                 |                         |     
|                                                                      |                                                                                                                                                                                                                               
|                                                                      | Total pension and post-retirement benefit costs                                                                                                                                                                                |                         |     
|                                                                      |                                                                                                                                                                                                                               
|Other comprehensive income (loss)                                     |                                                                                                                                                                                                                                |                         | 31.1
|                                                                      |                                                                                                                                                                                                                               
|Total Comprehensive Income (Loss)                                     |                                                                                                                                                                                                                                | $                       | 25.7
|                                                                      |                                                                                                                                                                                                                               

See
accompanying notes to consolidated financial statements.

61

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Aquila, Inc.  Consolidated Statements of Cash Flows

|                                                                                                                                                                                    |                                                                                            | Year Ended December 31, |                                                                           
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------ | ----------------------- | --------------------------------------------------------------------------
|
|                                                                                                                                                                                    |                                                                                           
|Cash Flows From Operating Activities:                                                                                                                                               |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    | Net income (loss)                                                                          |                         | $                                                                         
|                                                                                                                                                                                    | Adjustments to reconcile net income (loss) to net cash provided from operating activities: |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         | Depreciation and amortization expense                                     
|                                                                                                                                                                                    |                                                                                            |                         | Restructuring charges                                                     
|                                                                                                                                                                                    |                                                                                            |                         | Cash paid for restructuring and other charges                             
|                                                                                                                                                                                    |                                                                                            |                         | Net (gain) loss on sale of assets and other charges                       
|                                                                                                                                                                                    |                                                                                            |                         | Net changes in price risk management assets and liabilities               
|                                                                                                                                                                                    |                                                                                            |                         | Deferred income taxes and investment tax credits                          
|                                                                                                                                                                                    |                                                                                            |                         | Changes in certain assets and liabilities, net of effects of divestitures:
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    |                                                                                           
|Cash provided from operating activities                                                                                                                                             |                                                                                            |                         | 159.1                                                                     
|                                                                                                                                                                                    |                                                                                           
|Cash Flows From Investing Activities:                                                                                                                                               |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    | Utilities capital expenditures                                                             |                         |                                                                           
|                                                                                                                                                                                    | Investments in communication services                                                      |                         |                                                                           
|                                                                                                                                                                                    | Cash proceeds received on sale of assets                                                   |                         |                                                                           
|                                                                                                                                                                                    | Other                                                                                      |                         |                                                                           
|                                                                                                                                                                                    |                                                                                           
|Cash provided from (used for) investing activities                                                                                                                                  |                                                                                            |                         | (2.2                                                                      
|                                                                                                                                                                                    |                                                                                           
|Cash Flows From Financing Activities:                                                                                                                                               |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    | Premium on the retirement of long-term debt                                                |                         |                                                                           
|                                                                                                                                                                                    | Issuance of long-term debt                                                                 |                         |                                                                           
|                                                                                                                                                                                    | Retirement of long-term debt                                                               |                         |                                                                           
|                                                                                                                                                                                    | Short-term borrowings (repayments), net                                                    |                         |                                                                           
|                                                                                                                                                                                    | Cash paid on long-term gas contracts                                                       |                         |                                                                           
|                                                                                                                                                                                    | Other                                                                                      |                         |                                                                           
|                                                                                                                                                                                    |                                                                                           
|Cash used for financing activities                                                                                                                                                  |                                                                                            |                         | (355.3                                                                    
|                                                                                                                                                                                    |                                                                                           
|Increase (decrease) in cash and cash equivalents                                                                                                                                    |                                                                                            |                         | (198.4                                                                    
|Cash and cash equivalents at beginning of year(includes $4.8 million and $6.6 million of cash included in current assets of discontinued operations in 2006 and 2005, respectively) |                                                                                            |                         | 232.8                                                                     
|                                                                                                                                                                                    |                                                                                           
|Cash and Cash Equivalents at End of Year(includes $4.8 million of cash included in current assets of discontinued operations in 2005)                                               |                                                                                            | $                       | 34.4                                                                      
|                                                                                                                                                                                    |                                                                                           
|Supplemental cash flow information:                                                                                                                                                 |                                                                                            |                         |                                                                           
|                                                                                                                                                                                    | Interest paid, net of amount capitalized                                                   |                         | $                                                                         
|                                                                                                                                                                                    | Income taxes paid (refunded), net                                                          |                         |                                                                           
|                                                                                                                                                                                    |                                                                                           

See
accompanying notes to consolidated financial statements.

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Aquila, Inc.  Notes to Consolidated Financial Statements

Note 1: Summary of Significant Accounting Policies

Description of Business

Aquila, Inc. (Aquila) is a regulated utility headquartered in Kansas City, Missouri. We operate in three business segments, Electric Utilities, Gas
Utilities and Merchant Services.

Electric
Utilities operates in the distribution and transmission of electricity to retail and wholesale customers in Colorado and Missouri. Our electric generation facilities and
purchase power contracts supply electricity to our own distribution systems in these two 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 former Kansas electric utility was sold on April 1, 2007, and has been reclassified as discontinued operations.

Gas
Utilities operates in the distribution of natural gas to retail and wholesale customers in Colorado, Iowa, Kansas and Nebraska. Our former Michigan, Missouri and Minnesota gas
operations were sold in 2006 and have been reclassified as discontinued operations.

Our
Merchant Services business includes our contractual interest in the Crossroads Energy Center, a "peaking" power generation facility, and our Aquila Merchant subsidiary, whose assets
and liabilities are limited to its energy trading portfolio of natural gas delivery and transportation contracts. Two former merchant peaking plants, which were sold in March 2006, have been
reclassified as discontinued operations.

Corporate
and Other includes the costs of the Company that are not allocated to our operating businesses. Our former communications business, Everest Connections, was sold on
June 30, 2006 and is reported in discontinued operations.

Pending Merger

We have entered into a merger agreement with Great Plains Energy. We discuss our pending merger with a subsidiary of Great Plains Energy in more detail in
Note 19 to the Consolidated Financial Statements.

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, 2007 and 2006, and the reported
amounts of sales and expenses during the three years ended December 31, 2007. Significant items subject to such estimates and assumptions include the carrying value of property, plant and
equipment and goodwill; the valuation of derivative instruments; unbilled utility revenues; valuation allowances for receivables and deferred income taxes; reserves for potential litigation
obligations; and assets and liabilities related to employee benefits. Actual results could differ materially from those estimates and assumptions.

Collective Bargaining Agreements

Approximately 43% of our employees are represented by local unions under collective bargaining agreements. The collective bargaining agreements covering
approximately 54% of those employees expire and are subject to renegotiation in 2008.

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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.

Utility and Non-Utility Plant

We initially record utility and non-utility plant 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 utility plant is replaced, removed or abandoned, its cost, less salvage, is charged to accumulated depreciation. See
Note 8 for further information.

Impairment of Long-Lived Assets

In accordance with SFAS 144, long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to
estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the
amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the
carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately as
discontinued operations in the appropriate asset and liability sections of the balance sheet.

Goodwill
is tested annually for impairment, and is tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. Our annual assessment date
is November 30. An impairment loss is recognized to the extent that the carrying amount exceeds
the goodwill's fair value. For goodwill, the impairment determination is made at the reporting unit level and consists of two steps. First, we determine the fair value of a reporting unit and compare
it to its carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized for any excess of the carrying amount of the reporting unit's
goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price
allocation, in accordance with SFAS No. 141, "Business Combinations." The residual fair value after this allocation is the implied fair value of the reporting unit goodwill.

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.
Currently the only significant goodwill we have recorded has been allocated to our Electric Utilities segment. We performed our annual assessment of the realizability of this goodwill at the Missouri
electric reporting unit level as of November 30, 2007. We concluded that the goodwill was not impaired. At December 31, 2007, we had goodwill in continuing operations of
$113.6 million, less accumulated amortization of $2.6 million.

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Our
goodwill was allocated to each segment as follows:

|In millions                |                                        | Electric
Utilities |       | Discontinued
Operations
Corporate and
Other |  
|-------------------------- | -------------------------------------- | ------------------ | ----- | -------------------------------------------- | -
|                           |                                       
|Balance, December 31, 2004 |                                        | $                  | 111.0 |                                              | $
|                           | Other                                  |                    |       |                                             |  
|                           |                                       
|Balance, December 31, 2005 |                                        |                    | 111.0 |                                              |  
|                           | Reserve for minority market-based puts |                    |       |                                             |  
|                           | Sale of Everest Connections            |                    |       |                                             |  
|                           |                                       
|Balance, December 31, 2006 |                                        |                    | 111.0 |                                              |  
|                           | None                                   |                    |       |                                             |  
|                           |                                       
|Balance, December 31, 2007 |                                        | $                  | 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.

Franchise
fees and other taxes imposed on sales or gross receipts which are collected from customers and remitted to government authorities are presented net in sales.

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. Under SFAS 133, our energy commodity trading contracts, including physical transactions (mainly gas) 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 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 recorded 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

Our utility business also uses weather derivatives to offset inherent weather risks, but not for trading or speculative purposes. EITF
No. 99-2, "Accounting for Weather Derivatives,"

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

Inventories

Our inventories consist primarily of natural gas in storage, coal, purchased emission allowances, materials and supplies that are valued at weighted average cost.
Coal and emission allowances are charged to fuel expense in cost of sales as they are used in operations. Natural gas in storage is charged to the PGA account as it is withdrawn and is included in
cost of sales as it is recovered from ratepayers.

Pension and Other Post-retirement Plans

We have a defined benefit pension plan covering substantially all of our employees. We also provide post-retirement health care and life insurance
benefits for certain retired employees. See Note 16 for further discussion.

Regulatory Matters

Our regulated utility operations are subject to the provisions of 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 9 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 net operating and capital loss 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 and provide valuation allowances when we determine it is more likely than not that such assets will not be realized. See Note 15
for further discussion.

Environmental Matters

We accrue environmental costs on an undiscounted basis when we determine 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 we determine it is probable that we will receive regulatory recovery, we record these costs as a
regulatory asset.

Legal Costs

Litigation accruals are recorded when we determine it is probable we will incur costs and the amount can be reasonably estimated. Receivables for insurance
recoveries are recorded when probable. Costs of defending against litigation are expensed as incurred.

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Cash and Cash Equivalents

Cash and cash equivalents includes cash in banks and temporary investments with an original maturity of three months or less. As of December 31, 2007 and
2006, our cash held in foreign countries was $.1 million and $3.9 million, respectively. In addition, as of December 31, 2007 and 2006, we had restricted cash in foreign countries
of $1.2 million and $1.1 million, respectively.

Currency Adjustments

For income statement items, we translate the financial statements of our foreign subsidiaries and operations into U.S. dollars using the average exchange rate
during the period. For balance sheet items, we use the year-end exchange rate. When translating foreign currency-based assets and liabilities to U.S. dollars, we show any differences
between accounts as unrealized translation adjustments in common shareholders' equity. Currency translation 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 2007 presentation, including the
reclassification of $13.8 million of Electric Utilities' unbilled fuel adjustment clause balances from accounts receivable to current regulatory assets to be more consistent with industry
presentation.

During
the fourth quarter of 2007 we identified immaterial changes in certain accounts payable balances that had not been correctly presented in our prior period cash flow statements.
Changes in accounts payable balances representing capital expenditures had previously been classified with cash flows from operating activities and should have been classified with capital
expenditures as part of investing activities. Accordingly, the Consolidated Statements of Cash Flows for all periods presented have been reclassified to conform to the current presentation. As a
result of these reclassifications, cash provided by operating activities for decreased by $7.0 million from $60.1 million to $53.1 million for the year ended December 31, 2006. This same
adjustment also increased cash provided from capital expenditures by investing activities to $788.6 million from $781.6 million in 2006. For 2005, cash provided by operating activities increased by
$2.2 million from $48.5 million to $50.7 million and cash used for investing activities decreased by the same amount from $208.7 million to $210.9 million. The reclassifications did not impact
operating income or net income, working capital, any earnings per share measures or net change in cash and cash equivalents as previously reported.

Note 2: New Accounting Standards

Fair Value Measurements

In September 2006, the FASB issued SFAS 157, "Fair Value Measurements", which defines fair value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. This statement is effective for our financial statements as of January 1, 2008. We have determined the adoption of SFAS 157 will not
have a material impact on our financial condition or results of operations.

Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plansan amendment of
FASB Statements No. 87, 88, 106, and 132(R)". SFAS 158 requires an employer to recognize the over-funded or under-funded status of a defined benefit postretirement plan
(other than a multiemployer plan) as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the

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changes
occur through comprehensive income. Under SFAS 158, we were required to recognize the funded status of our defined benefit and other postretirement plans and to provide the required
disclosures commencing as of December 31, 2006. SFAS 158 also requires companies to use a measurement date that is the same as its fiscal year-end. For our financial
statements as of December 31, 2008, we will have to change our September 30 measurement date for our plans' assets and obligations to comply with this requirement. In addition, we have
recorded a deferred tax benefit associated with the temporary differences between liabilities recognized for tax and book purposes under SFAS 158. See Note 16 for discussion of the
impact of adopting SFAS 158 as of December 31, 2006.

Accounting for Uncertainty in Income Taxes

We adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes," (FIN 48) effective January 1, 2007. This interpretation
sets a "more likely than not" threshold before tax benefits can be recognized in our financial statements. Our practice prior to FIN 48 was to recognize income tax benefits when they were
reflected on filed income tax returns and establish a reserve against these tax benefits when their ultimate realization was not deemed to be "probable." See Note 15 for discussion of the
impact of the adoption of FIN 48.

Accounting for Planned Major Maintenance

In September 2006, the FASB issued FSP AUG AIR-1, "Accounting for Planned Major Maintenance Activities". FSP AUG AIR-1 amends the guidance
on the accounting for planned major maintenance activities; specifically, it precludes the use of the previously acceptable "accrue in advance" method, which we currently follow as allowed by
regulatory authorities. FSP AUG AIR-1 was effective for our financial statements as of January 1, 2007, and was applied retrospectively. Before considering the effect of our
regulatory "accrue-in-advance" method, we adopted the direct
expense method under FSP AUG AIR-1. We, however, believe that it is probable that the cost of planned major maintenance will be recovered through customer rates charged by our
rate-regulated utility operations in advance of such maintenance being performed. Therefore, a regulatory liability was recorded. As of December 31, 2006, our accrued liability for
planned major maintenance in our continuing operations was $4.7 million.

Considering the Effects of Prior Year Misstatements

In September 2006, the SEC issued SAB 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements", which addresses how the effects of prior year misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 was effective as of
the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to beginning retained earnings as of January 1, 2006 for errors that were not
previously deemed material, but would be material under the guidance in SAB 108. The implementation of SAB 108 has not had a material impact on our financial condition and results of
operations.

Noncontrolling Interests

In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB
No. 51" (SFAS 160). SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It
clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160
is effective for fiscal years beginning after December 15, 2008. We do not expect SFAS 160 to have a material impact on our financial position or results of operations.

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Business Combinations

In December 2007, the FASB issued SFAS No. 141R "Business Combinations" (SFAS 141R). SFAS 141R establishes principles and requirements for
how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree.
SFAS 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for business combinations with acquisition dates in fiscal years beginning after
December 15, 2008. As we have no business acquisitions pending, we do not expect that SFAS 141R will have a material impact on our financial position or results of operations.

Note 3: Risk Management

Overview

We use derivative financial instruments to reduce our exposure to adverse fluctuations in interest 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.

Merchant Trading Activities

Prior to exiting the merchant energy business, Aquila Merchant traded energy commodity contracts daily. The trading activities attempted to match the portfolio of
physical and financial contracts to current or anticipated market conditions. Within the trading portfolio, Aquila Merchant took certain positions to hedge physical sale or purchase contracts and to
take advantage of market trends and conditions. Aquila Merchant continues to use all forms of financial instruments, including futures, forwards, and swaps, to help hedge its remaining portfolio. Each
type of financial instrument involves different risks. We believe financial instruments help Aquila Merchant manage its remaining contractual commitments and reduce its exposure to changes in market
prices.

We
record most trading 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.

Regulated Commodity Management

Our utility businesses produce, purchase and distribute power in two states and purchase and distribute gas in four states. All of our Gas Utilities have PGA
provisions that allow them to pass the prudently-incurred cost of the gas to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are
made on a periodic basis to "true-up" billed amounts to actual gas 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 financial instruments
are considered derivatives under SFAS 133 and are marked-to-market and recorded in our PGA accounts as they are collectible under the provisions of the PGA upon
settlement.

In
2007, our continuing regulated electric business generated approximately 52% of the power that we sold and purchased the remaining 48% through long-term contracts or in
the open

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market.
The regulatory provisions for recovering power costs vary by state. In Colorado, we have an ECA that serves a purpose similar to that of the PGAs for the gas utilities. To the extent that our
fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, we also have the ability to pass
through 95% of the changes in purchased power and fuel costs outside of a rate case filing through a fuel clause adjustment.

We
have also entered into a program for our electric utility customers in Missouri to mitigate price exposure to natural gas price volatility in the market. This program extends multiple
years and the mark-to-market value of the portfolio, a loss of $3.9 million, relates to contracts that will settle against actual purchases of natural gas and purchased
power in 2008 through 2010. In connection with the 2005 Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they settle. The settlement cost is a
component of the energy cost included in the Missouri fuel adjustment clause. A regulatory asset has been recorded under SFAS 71 in the amount of $3.9 million to reflect the change in
the timing of recognition authorized by the Missouri Commission.

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.

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, 2007 are below:

|                    |                             | December 31, 2007
|------------------- | --------------------------- | -----------------
|
|
|
|Energy Commodities: |                             |                  
|                    | Natural gas(trillion Btu's) |                  
|Financial Products: |                             |                  
|                    | Interest rate instruments   |                  
|                   

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

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 and future contracts are discounted to December 31, 2007, 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

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monitor
the portfolio and value it daily based on present market conditions. The following table displays the fair values of our price risk management assets and liabilities at December 31,
2007, and the average value for the year ended December 31, 2007:

|            |  | Price Risk
Management Assets |      | Price Risk
Management Liabilities
|----------- |  | ---------------------------- | ---- | ---------------------------------
|
|
|            |  |                              |      |                                  
|Natural gas |  | $                            | 89.0 |                                  
|Electricity |  |                              | .1   |                                  
|Other       |  |                              | .2   |                                  
|           
|Total       |  | $                            | 89.3 |                                  
|           

Our
price risk management assets are concentrated with less than 15 counterparties representing 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

We have not designated any derivatives as cash flow or fair value hedges.

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 fuel and 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.

Note 4: Restructuring Charges

We recorded the following restructuring charges:

|                                    |  | Year Ended December 31,
|----------------------------------- |  | -----------------------
|
|
|Merchant Services lease agreements  |  | $                      
|Corporate and Other severance costs |  |                        
|                                   
|Total restructuring charges         |  | $                      
|                                   

Lease Agreements

In the first quarter of 2005, we terminated the majority of the remaining leases associated with our former Merchant Services headquarters. In connection with
this termination we made a

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lump-sum
payment of $13.0 million which exceeded our restructuring reserve obligation as of the termination date. This resulted in an additional lease restructuring charge of
$6.6 million in the first quarter of 2005.

Severance Costs and Retention Payments

We recorded $1.5 million of one-time termination benefits in 2007 primarily related to the departure of our Chief Operating Officer. These
benefits are being paid over a two-year period beginning April 28, 2007.

In
connection with the sale of our Kansas electric and Michigan, Minnesota and Missouri gas utility operations, our management adopted and communicated to employees a plan to reduce
corporate and central services costs, which included the elimination of approximately 220 positions through attrition and employee terminations. The 83 employees who were involuntarily terminated
received severance and other one-time termination benefits. The total cost of one-time termination benefits was approximately $5.7 million, which was recognized in 2006
over the remaining service period of terminated employees and was paid out over time.

In
addition, upon closing of the sale of Everest Connections in June 2006, its employees received retention payments of approximately $2.0 million, which were recognized over the
period through the closing of the sale. These charges were included in discontinued operations.

Restructuring Reserve Activity

The following table summarizes activity in accrued restructuring charges for our continuing and discontinued operations:

|                                                       |                                                              | 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 |                                                              | $                       | 1.1
|                                                       |                                                             
|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     |                                                              | $                       |   
|                                                       |                                                             

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

Pretax net (gains) losses on sale of assets and other charges we recorded for the years ended December 31, 2007, 2006 and 2005 are shown below:

|                                                   |                                          | Year Ended December 31, |    
|-------------------------------------------------- | ---------------------------------------- | ----------------------- | ---
|
|
|                                                   |                                          |                         |    
|Merchant Services:                                 |                                          |                         |    
|                                                   | Elwood tolling contract                  |                         | $  
|                                                   | Batesville tolling agreement             |                         |    
|                                                   | ICE sale                                 |                         |    
|                                                   | Red Lake gas storage development project |                         |    
|                                                   | Other                                    |                         |    
|                                                   |                                         
|Total Merchant Services                            |                                          |                         |   
|                                                   |                                         
|Corporate and Other:                               |                                          |                         |    
|                                                   | Early retirement of debt                 |                         |    
|                                                   | Early conversion of the PIES             |                         |    
|                                                   | Turbines impairment                      |                         |    
|                                                   |                                         
|Total Corporate and Other                          |                                          |                         | 1.3
|                                                   |                                         
|Total net loss on sale of assets and other charges |                                          | $                       | 1.3
|                                                   |                                         

After-tax
losses and gains in the following paragraphs are reported after giving consideration to the effects of capital loss carryback and carryforward limitations. As a
result, the net tax effect may differ substantially from our expected statutory tax rates.

During
2007, 2006 and 2005, we also incurred net loss (gain) on sale of assets and other charges of $(3.6) million, $(267.9) million and $159.5 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.

Elwood Tolling Contract

In 2006, we paid $218 million to a third party to assume our rights and obligations under the Elwood tolling contract. This transaction resulted in a
pretax and after-tax loss of $218 million, and terminated approximately $405 million of our fixed capacity payments through August 2017. For income tax purposes, we treated
the $218 million payment as an ordinary loss on our 2006 income tax return. However, because we did not conclude that it was probable that the IRS would agree with this treatment, we increased
our reserve for uncertain tax positions by $84.6 million, thereby fully offsetting the tax benefit of the loss. When we implemented FIN 48 on January 1, 2007 we recognized this
tax benefit through a reduction of our reserve for uncertain tax positions because we concluded that the benefit satisfied the FIN 48 "more likely than not" threshold.

Batesville Tolling Contract

In 2005, we terminated our power sales contract and assigned our rights and obligations under the tolling contract in exchange for approximately
$16.3 million. This transaction resulted in a pretax gain of approximately $16.3 million, or $10.2 million after tax.

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ICE Sale

In February 2005, we sold our 4.5% interest in IntercontinentalExchange, Inc. (ICE) to other shareholders for approximately $13.8 million. This
transaction resulted in a pretax and after-tax gain of approximately $9.3 million. The gain was realized as a capital gain for income tax purposes resulting in the reversal of
previously provided valuation allowances on capital loss carryforwards.

Red Lake Storage Development Project

In 2002, we acquired land in Arizona to develop natural gas storage facilities. In 2004, we recorded a pretax impairment charge of $8.9 million, or
$5.6 million after tax, to write this investment down to its estimated fair value. In 2005, we sold the land for $21.2 million. We recorded a pretax gain of $6.2 million, or
$3.9 million after tax, in the fourth quarter of 2005.

Early Retirement of Debt

As discussed in more detail in Note 11, we completed a cash tender offer that resulted in the early retirement of approximately $350 million of
outstanding senior notes in June 2006. We recorded a pretax early retirement loss of $22.7 million, or $14.0 million after tax, in connection with this transaction. We also incurred fees
of $5.5 million, or $3.4 million after tax, primarily on the prepayment of the $220 million outstanding on our five-year term loan.

As
discussed in more detail in Note 11, we retired $344 million of callable debt in June 2007. We recorded a pretax early retirement loss of $1.3 million, or
$.8 million after tax, in connection with this transaction.

Early Conversion of the Premium Income Equity Securities (PIES)

As discussed in more detail in Note 11, we completed an exchange offer that resulted in the early conversion of approximately 98.9% of our PIES in July
2005. We recorded a pretax and after-tax early conversion loss of approximately $82.3 million in connection with this transaction. We did not record a tax benefit from this
transaction as the premium paid to complete the conversion is not deductible for tax purposes.

Turbines Impairment

In 2004, we determined that the carrying value of three combustion turbines held by one of our non-regulated subsidiaries was impaired. These turbines
were transferred to our Missouri electric division for our South Harper peaking facility. Missouri affiliate 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. The transfer was subject to the final determination of the Missouri Commission. In connection with our rate case
settlement in February 2006, we lowered the turbines fair value an additional $4.4 million, and recorded a pretax impairment charge of $4.4 million, or $2.7 million after tax.

74

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Note 6: Discontinued Operations

As part of a strategic repositioning of our company, we have sold or wound-down a number of operations since 2002 to generate cash to be used to
reduce debt and eliminate other long-term obligations. We have sold the assets discussed below, which are considered discontinued operations in accordance with SFAS 144.

After-tax
losses discussed below are reported after giving consideration to the effect of capital loss carryback and carryforward limitations. As a result, the net tax effect
may differ substantially from our expected statutory tax rates.

Electric and Gas Utilities

In September 2005, we entered into agreements to sell our Kansas electric distribution business and our Michigan, Minnesota and Missouri natural gas distribution
businesses. We completed these asset sales in 2006, except for the Kansas electric sale, which was completed on April 1, 2007. These sales resulted in pretax and after tax gains. The
classification of the tax gains between ordinary income and capital gain depends upon the final allocation of the purchase price based upon the terms of the respective asset purchase agreements.
Ordinary income has been offset by current year net operating losses and/or net operating loss carryforwards. Capital gains have been offset by capital loss carryforwards. To the extent capital loss
carryforwards were utilized, the valuation allowance against the tax benefit of the capital loss carryforwards has been reversed for 2006 sales. The tax gains have been adjusted for the 2006 sales
based upon the final allocations included in our 2006 income tax return. The tax gain on the sale of the Kansas electric properties will be adjusted when the final determination is made and as the
2007 income tax return is filed in 2008.

On
April 1, 2006, we closed the sale of our Michigan gas operations and received gross cash proceeds of $338.1 million, including the base purchase price of
$269.5 million plus preliminary working capital and other adjustments of $68.6 million. In connection with this sale we recorded a pretax gain of approximately $92.2 million after
transaction fees and expenses in 2006. The estimated after-tax gain in 2006 was approximately $99.5 million, including an
estimate of $44.0 million for the valuation allowance reversal related to the estimated capital gain amount discussed above. The final after-tax gain is $103.7 million,
including the final valuation allowance reversal related to capital gains realized on our 2006 income tax return.

On
June 1, 2006, we closed the sale of our Missouri gas operations and received gross cash proceeds of $101.3 million, including the base purchase price of
$85.0 million plus preliminary working capital and other adjustments of $16.3 million. In connection with this sale we recorded a pretax gain of approximately $30.7 million after
transaction fees and expenses in 2006. The estimated after-tax gain in 2006 was approximately $31.1 million, including an estimate of $11.7 million for the valuation
allowance reversal related to the estimated capital gain amount discussed above. In 2007, final adjustments related to pensions and other items reduced the pretax gain by $.6 million, or
$.4 million after tax. The final after-tax gain is $34.1 million, including the final valuation reversal related to capital gains realized in our 2006 income tax return.

On
July 1, 2006, we closed the sale of our Minnesota gas operations and received gross cash proceeds of $317.1 million, including the base purchase price of
$288.0 million plus preliminary working capital and other adjustments of $29.1 million. In connection with this sale we recorded a pretax gain of approximately $120.5 million
after transaction fees and expenses in 2006. The estimated after-tax gain in 2006 was approximately $127.5 million, including an estimate of $56.9 million for the valuation
allowance reversal related to the estimated capital gain amount discussed above. In 2007, final adjustments primarily related to pensions increased the pretax

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gain
$.7 million, or $.4 million after tax. The final after-tax gain is $126.3 million, including the final valuation allowance reversal related to capital gains
realized in our 2006 income tax return.

On
April 1, 2007, we closed the sale of our Kansas electric operations and received gross cash proceeds of $292.2 million, including the base purchase price of
$249.7 million plus preliminary working capital and other adjustments of $42.5 million. In connection with this sale we recorded a pretax gain of approximately $1.8 million in
2007 after transaction fees and expenses, including an adjustment for the final determination of pension assets transferred to the buyer as discussed below. The estimated after-tax gain
was approximately $1.1 million, subject to the determination of the capital gain amount discussed above.

The
operating results of the utility divisions sold or held for sale include the direct operating costs associated with those businesses but do not include the allocated operating costs
of central services and corporate overhead in accordance with EITF Consensus 87-24, "Allocation of Interest to Discontinued Operations" (EITF 87-24). We provide
corporate and centralized support services to all of our utility divisions, including customer care, billing, collections, information technology, accounting, tax and treasury services, regulatory
services, gas supply services, human resources, safety and other services. The operating costs
related to these functions are allocated to the utility divisions based on various cost drivers. The total of expenses allocated to our Kansas electric and Michigan, Minnesota and Missouri gas
operations was $42.3 million in 2005. Effective January 1, 2006, we ceased allocating costs to our held-for-sale utilities. These allocated costs were not
included in the reclassification to earnings from discontinued operations because these support services were necessary to maintain ongoing operations until the sales were completed.

The
discontinued utility operations participate in our qualified pension plan, non-qualified Supplemental Executive Retirement Plan (SERP) and other
post-retirement benefit plan. Under the asset purchase agreements, the buyers assumed the accrued pension obligations owed to the current and former employees of the operations they
acquired. After closing, benefit plan assets were transferred to comparable plans established by the buyers in accordance with the terms of the asset purchase agreements and the applicable ERISA
requirements. These benefit plan asset transfers resulted in plan curtailments. In connection with the sale of our Michigan, Minnesota and Missouri gas operations we included $13.0 million of
net prepaid pension assets and pension and post-retirement benefit obligations, including the effect of plan curtailment and settlement losses, in the determination of the pretax gains on
these sales. The plan curtailment and settlement losses related to the sale of our Kansas electric operations was $5.3 million.

Other Asset Sales

In March 2006, we sold two merchant "peaking" power plants located in Illinois for gross proceeds of $175 million. We recorded a pretax,
non-cash impairment charge of $159.5 million, or $99.7 after tax relating to these plants in 2005. Final adjustments to contingent liabilities decreased the pretax loss by
$1.7 million, or $1.0 million after tax in 2007. In June 2006, we sold our telecommunication business (Everest Connections) for net proceeds of approximately $78 million. We
recorded a pretax gain of $25.5 million, or $15.7 million after tax in 2006.

Interest Allocation to Discontinued Operations

The buyers of the assets in discontinued operations did not assume any of our long-term debt. The direct debt and related interest of Everest
Connections was included in discontinued operations as this debt was required to be repaid from the proceeds from the sale. We allocated a portion of consolidated interest expense to discontinued
operations based on the ratio of net assets of discontinued operations to consolidated net assets plus consolidated debt in accordance

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with
EITF 87-24. As we completed each asset sale the allocation of interest to discontinued operations ceased, thereby increasing interest expense in continuing operations, without
impacting total interest expense, until the sales proceeds were used to reduce debt.

Summary

We have reported the results of operations from these assets in discontinued operations for the three years ended December 31, 2007 in the Consolidated
Statements of Income.

Operating
results of discontinued operations are as follows:

|                                             |                                                     | Year Ended December 31, |     
|-------------------------------------------- | --------------------------------------------------- | ----------------------- | ----
|
|
|Sales                                        |                                                     | $                       | 45.8
|Cost of sales                                |                                                     |                         | 23.4
|                                             |                                                    
|Gross profit                                 |                                                     |                         | 22.4
|                                             |                                                    
|Operating expenses:                          |                                                     |                         |     
|                                             | Operation and maintenance expense                   |                         |     
|                                             | Taxes other than income taxes                       |                         |     
|                                             | Restructuring charges                               |                         |     
|                                             | Net loss (gain) on sale of assets and other charges |                         |     
|                                             | Depreciation and amortization expense               |                         |     
|                                             |                                                    
|Total operating expenses (income)            |                                                     |                         | 9.7 
|                                             |                                                    
|Other income (expense):                      |                                                     |                         |     
|                                             | Other income                                        |                         |     
|Interest expense                             |                                                     |                         | 4.1 
|                                             |                                                    
|Earnings (loss) before income taxes          |                                                     |                         | 8.8 
|Income tax expense (benefit)                 |                                                     |                         | (3.9
|                                             |                                                    
|Earnings (loss) from discontinued operations |                                                     | $                       | 12.7
|                                             |                                                    

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The
related assets and liabilities included in the sale of these businesses, as detailed below, have been reclassified as current and non-current assets and liabilities of
discontinued operations on the December 31, 2007 and 2006 Consolidated Balance Sheets as follows:

|                                                         |                                      | December 31,
|-------------------------------------------------------- | ------------------------------------ | ------------
|
|
|Current assets of discontinued operations:               |                                      |             
|                                                         | Accounts receivable, net             |             
|                                                         | Inventories and supplies             |             
|                                                         | Other current assets                 |             
|                                                        
|Total current assets of discontinued operations          |                                      | $           
|                                                        
|Non-current assets of discontinued operations:           |                                      |             
|                                                         | Utility plant, net                   |             
|                                                         | Regulatory assets                    |             
|                                                         | Other non-current assets             |             
|                                                        
|Total non-current assets of discontinued operations      |                                      | $           
|                                                        
|Current liabilities of discontinued operations:          |                                      |             
|                                                         | Other current liabilities            |             
|                                                        
|Total current liabilities of discontinued operations     |                                      | $           
|                                                        
|Non-current liabilities of discontinued operations:      |                                      |             
|                                                         | Pension and post-retirement benefits |             
|                                                         | Deferred credits                     |             
|                                                        
|Total non-current liabilities of discontinued operations |                                      | $           
|                                                        

Note 7: Accounts Receivable

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

|                                      |  | December 31, |      
|------------------------------------- |  | ------------ | -----
|
|
|Merchant Services accounts receivable |  | $            | 42.3 
|Utilities billed accounts receivable  |  |              | 117.4
|Utilities unbilled revenue            |  |              | 86.4 
|Other accounts receivable             |  |              | 15.2 
|Allowance for doubtful accounts       |  |              | (5.2 
|                                      | 
|Total                                 |  | $            | 256.1
|                                      | 

In
2005, we entered into a $150 million four-year secured revolving credit facility. Borrowings under this facility are secured by the accounts receivable generated by
our regulated utility operations in Colorado, Iowa, Kansas, Missouri and Nebraska. We had $25.0 million of borrowings outstanding under this facility as of December 31, 2007. See
Note 10 for further discussion.

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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 aging.

Note 8: Utility and Non-Utility Plant

The components of utility and non-utility plant from continuing operations are listed below:

|Utility Plant                                          |                          | December 31, |         
|------------------------------------------------------ | ------------------------ | ------------ | --------
|
|
|Electric utility                                       |                          | $            | 2,248.1 
|Gas utility                                            |                          |              | 691.0   
|Corporate and other                                    |                          |              | 241.2   
|Electric and gas utility plantconstruction in process |                          |              | 223.7   
|                                                       |                         
|                                                       |                          |              | 3,404.0 
|Lessaccumulated depreciation and amortization         |                          |              | (1,382.0
|                                                       |                         
|                                                       | Total utility plant, net |              | $       
|                                                       |                         

|
|

|Non-Utility Plant                              |                              | December 31, |      
|---------------------------------------------- | ---------------------------- | ------------ | -----
|
|
|Non-regulated electric and gas plant           |                              | $            | 4.1  
|Non-regulated electric power generation        |                              |              | 132.3
|Corporate and other                            |                              |              | 28.6 
|                                               |                             
|                                               |                              |              | 165.0
|Lessaccumulated depreciation and amortization |                              |              | (42.2
|                                               |                             
|                                               | Total non-utility plant, net |              | $    
|                                               |                             

Our
utility plant from continuing operations includes acquisition-related adjustments that are being amortized over useful lives not exceeding 40 years. Net
utility plant assets from continuing operations not included in our rate base were $17.0 million and $19.8 million at December 31, 2007 and 2006, respectively.

|                                        |  | Composite Depreciation Rates |  
|--------------------------------------- |  | ---------------------------- | -
|
|
|Continuing Operations                  |  |                              |  
|Electric utility                        |  | 2.9                          | %
|Gas utility                             |  | 2.7                          | %
|Corporate and other                     |  | 10.8                         | %
|Non-regulated electric power generation |  | 2.8                          | %
|                                        | 
|Discontinued Operations                |  |                              |  
|Electric utility                        |  | n/a                          |  
|Gas utility                             |  | n/a                          |  
|Non-regulated electric power generation |  | n/a                          |  
|Communications                          |  | n/a                          |  
|                                        | 

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Depreciation
and amortization of our discontinued operations ceased in accordance with SFAS 144 upon the classification of these assets as
held-for-sale.

Jointly Owned Electric Utility Plant

We own an 8% interest in a coal-fired plant (Jeffrey Energy Center) with generating capacity of approximately 2,190 MWs, operated by Westar. We also
own an 18% interest in a 654-megawatt coal-fired plant (Iatan 1) operated by KCPL and an 18% interest in an 850-megawatt coal-fired plant (Iatan
2) being constructed by KCPL. Our pro rata share of Jeffrey Energy Center's and Iatan 1's operating costs are included in our Consolidated Statements of Income.

Our
investment in jointly-owned plant at December 31, 2007 was as follows:

|In millions                                     |  | Jeffrey Energy Center |       | Iatan 1 |   | Iatan 2
|----------------------------------------------- |  | --------------------- | ----- | ------- | - | -------
|
|Utility plant                                   |  | $                     | 110.8 |         | $ | 68.1   
|Construction in progress                        |  |                       | 16.5  |         |   | 27.0   
|                                               
|                                                |  |                       | 127.3 |         |   | 95.1   
|Less: Accumulated depreciation and amortization |  |                       | (72.4 | )       |   | (49.4  
|                                               
|Jointly-owned utility plant, net                |  | $                     | 54.9  |         | $ | 45.7   
|                                               

AFUDC

AFUDC represents the capitalized cost of debt and equity funds used to finance construction projects for our regulated utilities. For the years ended
December 31, 2007, 2006 and 2005, our continuing Electric and Gas Utilities recorded approximately $7.0 million, $1.9 million and $5.3 million, respectively, of additional
income and construction work in progress related to AFUDC. The non-cash earnings are classified as other income (expense) in our Consolidated Statements of Income. The increase in AFUDC in
2007 primarily related to the construction of Iatan 2.

Under
accepted rate making practices, we are allowed cash recovery of AFUDC, as well as other capitalized construction costs, once completed construction projects are placed into service
and reflected in customer rates. The rates used for capitalizing AFUDC are generally computed using agreed upon methods prescribed by the FERC. The rate used for capitalizing AFUDC on Iatan 2
construction is computed based on the financing cost of our Iatan Facility (see further discussion in Note 11) per the stipulation agreement settling our 2005 Missouri rate case.

Asset Retirement Obligations

In August 2001, the FASB issued 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.

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

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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
March 2005, the FASB issued FIN 47, which clarifies the term "conditional asset retirement obligation" used in SFAS 143, and specified when an entity has sufficient
information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 on December 31, 2005, required us to update an existing inventory of
identified legal obligations, originally created under SFAS 143, for conditional asset retirement obligations.

We
identified asbestos abatement costs associated with the closure of certain owned power plants and other structures as conditional asset retirement obligations. The ability to
reasonably estimate when the obligation would occur was a matter of judgment, based upon our ability to estimate the dates and methods of asbestos abatement. We considered historical practices,
industry practices, our management's intent and the estimated useful lives of our assets in
determining settlement dates and methods. Based on our estimates, we measured the fair value of our obligations using the present value of future abatement costs discounted at our credit adjusted risk
free borrowing rates.

Our
continuing Electric and Gas Utilities recorded an asset retirement obligation of $8.4 million and increased property, plant and equipment, net of accumulated depreciation, by
$.2 million in 2005. Because this business is a regulated utility subject to the provisions of SFAS 71, the $8.2 million cumulative effect of adoption of FIN 47 was
recorded as a regulatory asset and therefore had no impact on net income. In addition, our discontinued utility operations recognized an asset retirement obligation of $4.4 million, increased
net property, plant and equipment by $.1 million, and recorded an offsetting regulatory asset of $4.3 million in 2005. These liabilities will be adjusted on an ongoing basis due to the
passage of time, new laws and regulations and revisions to either the timing or amount of our original cost estimates.

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 $11.4 million and $10.4 million as of December 31, 2007 and 2006, respectively.

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. Under
SFAS 143, the net provision for these "non-legal" removal costs has been classified as a regulatory liability. See Note 9 for further discussion.

Note 9: Regulatory Assets and Liabilities

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 71. This means our Consolidated Balance Sheets show some assets and liabilities that would not be found on the balance sheets of a non-regulated company.

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The
following table details our regulatory assets and liabilities.

|                             |                                       | December 31,
|---------------------------- | ------------------------------------- | ------------
|
|
|Regulatory Assets:           |                                       |             
|                             | Energy clause adjustment              |             
|                             | Under-recovered gas costs             |             
|                             | Income taxes                          |             
|                             | Environmental                         |             
|                             | Regulatory accounting orders          |             
|                             | Gas price derivatives                 |             
|                             | Asset retirement obligations          |             
|                             | Pensions and post-retirement benefits |             
|                             | Other                                 |             
|                            
|                             | Total regulatory assets               |             
|                            
|Regulatory Liabilities:      |                                       |             
|                             | Cost of removal                       |             
|                             | Income taxes                          |             
|                             | Revenue subject to refund             |             
|                             | Over-recovered gas costs              |             
|                             | Pensions                              |             
|                             | Other                                 |             
|                            
|Total regulatory liabilities |                                       | $           
|                            

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.

Note 10: Short-Term Debt

We had $25.0 million in short-term borrowings outstanding under our four-year secured revolving credit facility on
December 31, 2007. No short-term borrowings were outstanding on December 31, 2006.

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Five-Year Unsecured Revolving Credit Facility

In September 2004, we completed a $110 million unsecured revolving credit facility that matures in September 2009 (the Five-Year Unsecured
Revolving Credit Facility). There were no borrowings outstanding on this facility as of December 31, 2007. The Five-Year Unsecured Revolving Credit Facility bears interest at the
Eurodollar Rate plus 5.50%, subject to reduction if our credit rating improves. Among other restrictions, the Five-Year Unsecured Revolving Credit Facility contains financial covenants
similar to, but less restrictive than, those contained in the Iatan Facility described in Note 11. We were in compliance with these covenants as of December 31, 2007.

The
Five-Year Unsecured Revolving Credit Facility contains a $40 million "cross default" provision, as well as 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.

$180 Million Unsecured Revolving Credit and Letter of Credit Facility

In April 2005, we entered into a five-year credit agreement with a commercial lender. Subject to the satisfaction of certain conditions, the facility
provides for up to $180 million of cash advances and letters of credit for working capital purposes. Cash advances must be repaid within 364 days unless we obtain the necessary
regulatory approvals to incur long-term indebtedness under the facility. As of December 31, 2007, we had $150.0 million of uncollateralized capacity at an average cost of
3.65% under this agreement,
which contains a $40 million "cross default" provision. As of December 31, 2007, $146.4 million of the available capacity had been utilized for letters of credit under this
facility.

Four-Year Secured Revolving Credit Facility

In April 2005, we executed a four-year $150 million secured revolving credit facility (the AR Facility). Proceeds from this facility may be
used for working capital and other general corporate purposes. Borrowings under this facility are secured by the accounts receivable generated by our regulated utility operations in Colorado, Iowa,
Kansas, Missouri and Nebraska. Borrowings under the AR Facility bear interest at LIBOR plus 1.375%, subject to reduction if our credit ratings improve. Borrowings must be repaid within 364 days
unless we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility. 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 Revolving Credit Facility
discussed above. The credit agreement also contains a $40 million "cross default" provision. We had borrowed $25.0 million under this facility as of December 31, 2007 at a rate of
7.75%.

$50 Million Revolving Credit and Letter of Credit Facility

In January 2006, we closed on a $50 million short-term letter of credit facility with a commercial lender that allows us to issue letters of
credit under the facility. The credit agreement contains a $40 million "cross default" provision. On December 19, 2007, we extended the maturity date to December 17, 2008, and
increased the advance rate to 1.10%. There were $41.1 million of letters of credit outstanding under this facility as of December 31, 2007.

Other

We had an additional $.8 million of letters of credit outstanding as of December 31, 2007.

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Note 11: Long-Term Debt

This
table summarizes our long-term debt:

|                                                              |                                                                                                                                           | December 31,
|------------------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------- | ------------
|
|                                                             
|First Mortgage Bonds:                                         |                                                                                                                                           |             
|                                                              | 9.44% Series, due annually through 2021(a)                                                                                                |             
|Senior Notes:                                                 |                                                                                                                                           |             
|                                                              | 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, 7.2%*, due 2013-2023                                                                                                             |             
|Mandatorily Convertible Notes:                                |                                                                                                                                           |             
|                                                              | 6.75% Series, converted on September 15, 2007 into common shares at a conversion rate of 8.0386 shares per $25 par value convertible note |             
|Convertible Subordinated Debentures:                          |                                                                                                                                           |             
|                                                              | 6.625% due July 1, 2011                                                                                                                   |             
|Other:                                                        |                                                                                                                                           |             
|                                                              | Other notes and obligations 4.88%*, due 2008-2028(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
Amounts2008

$
2.42009


70.82010


1.12011


335.52012


501.2Thereafter


126.8Total

$
1,037.8


Each
series of our unsecured senior notes is subject to a "cross default" provision ranging from $5 million to $40 million, as applicable.

Early Retirement of Senior Notes

In May 2006, we announced a cash tender offer for the early retirement of certain of our outstanding senior notes. Noteholders that accepted the tender received
the accrued interest from the last interest payment date, and those that properly tendered their notes before the early tender time date were also entitled to receive an additional early tender
premium of 2% of the debt tendered. We completed the cash tender offer in June 2006, which resulted in the early retirement of $350 million of aggregate debt principal. We recorded a pretax
early retirement loss of $22.7 million, or $14.0 million after tax, in connection with the transaction. The table below provides the detail on the notes retired:

Title of Security

Principal Amount
Retired (in millions)6.7% Notes due 10/15/2006

$
84.58.2% Notes due 1/15/2007


22.37.625% Notes due 11/15/2009


130.59.95% Notes due 2/01/2011


112.7Total

$
350.0


In
May 2007, we announced that call notices had been issued for the redemption of certain of our senior notes. In June 2007, we completed the redemption, which resulted in the early
retirement of $344 million of aggregate debt principal. We recorded a pretax early retirement loss of $1.3 million, or $.8 million after tax, in connection with the transaction in
the second quarter of 2007. The table below provides the detail on the notes retired:

Title of Security

Principal Amount
Retired (in millions)7.875% Notes due 3/1/2032

$
287.58.0% Notes due 3/1/2023


51.59.0% Notes due 11/15/2021


5.0Total

$
344.0


86

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Mandatorily Convertible Senior Notes

In 2004, we issued 13.8 million PIES units at $25 per PIES unit, including an over-allotment of 1.8 million PIES, representing
$345.0 million of mandatorily convertible senior notes. These unsecured notes paid interest at 6.75% and converted automatically into shares of our common stock on September 15, 2007, at
a conversion rate
ranging from 8.0386 to 9.8039 shares of common stock per PIES unit. Our net proceeds on the issuance of the PIES were $334.3 million.

In
2005, we announced an exchange offer related to the optional conversion of our PIES into shares of our common stock. Holders who tendered their securities received a conversion
premium of 1.5896 shares of common stock in addition to the 8.0386 shares of common stock per PIES unit they would receive upon exercising their conversion option under the existing terms of the PIES.
Holders of approximately 98.9% of the PIES units accepted our exchange offer and tendered their PIES units for conversion. As a result, we issued approximately 131.4 million shares of common
stock pursuant to the terms of the PIES exchange offer, and recorded a pretax and after-tax early conversion loss of approximately $82.3 million related to the PIES exchange offer
and certain cash repurchases of PIES units. We did not record a tax benefit from these transactions as the premiums paid were not deductible for tax purposes. The completion of these transactions
reduced our annual cash interest payments by approximately $23.1 million through September 2007. In connection with the exchange offer, approximately $7.7 million of unamortized debt
issue costs related to the PIES were reclassified to premium on capital stock.

On
September 15, 2007, the remaining $2.6 million of PIES units automatically converted into 835,640 shares of our common stock.

Five-Year Unsecured Term Loan

In September 2004, we completed a $220 million unsecured term loan. We borrowed the full amount of the term loan and received $211.3 million of net
proceeds after upfront fees and expenses. In June 2006, the holder of $10 million of term loan notes elected to receive an optional prepayment from the proceeds of the sale of our Missouri gas
operations. In September 2006, we prepaid the remaining $210 million outstanding and paid a 2.5% prepayment fee of approximately $5.5 million.

Iatan Construction Financing

In August 2005, we entered into a $300 million credit agreement that allows us to obtain loans and issue letters of credit (limited to $175 million
of letters of credit) in support of our participation in the construction of Iatan 2 and our obligation to fund pollution controls being installed at an adjacent facility. Extensions of credit under
the facility will be due and payable on August 31, 2010. Loans bear interest at the Eurodollar Rate plus 1.375%, subject to reduction if our credit rating improves. A fee based on our credit
ratings will be paid on the amount of letters of credit outstanding. Obligations under the credit agreement are secured by the assets of our Missouri Public Service electric operations. There were no
borrowings or letters of credit
outstanding under this facility at December 31, 2007. Among other restrictions, the Iatan Facility contains the following financial covenants with which we were in compliance as of
December 31, 2007:

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The
Iatan Facility contains a $40 million "cross default" provision, as well as 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.

Credit Ratings

As
of December 31, 2007, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

|Agency  |  | Rating |  | Commentary                               
|------- |  | ------ |  | -----------------------------------------
|
|Moody's |  | Ba3    |  | Ratings Under Review for
Possible Upgrade
|S&P     |  | B+     |  | Credit Watch Positive                    
|Fitch   |  | BB-    |  | Rating Watch Positive                    
|       

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 downgraded our credit ratings after the issuance of these notes, 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 downgraded our credit ratings after the issuance of these notes, the
interest rate on these notes has been adjusted to a maximum rate of 9.95%. The current balance outstanding on these notes after our tender offer in June 2006 is $137.3 million.

If
our credit ratings improve to certain levels, the interest rates on these notes will be lowered.

Note 12: 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.

88

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Suspension of Dividend

In November 2002, the Board of Directors suspended the annual dividend on common stock for an indefinite period. Currently three 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.

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. Matching contributions are made in cash and invested as directed by the employee. Company contributions for
continuing operations were $6.4 million, $6.4 million and $6.3 million and for discontinued operations were $.2 million, $1.2 million and $1.9 million during
the years ended December 31, 2007, 2006, and 2005, respectively. The Savings Plan also includes a discretionary contribution fund to which the Company historically contributed an additional 3%
of base wages for eligible full-time employees. These contributions are made in cash and invested as directed by the employee. For 2007, 2006 and 2005, compensation expense discretionary
contributions for continuing operations of $3.7 million, $3.9 million and $3.7 million, respectively, and for discontinued operations of $- million,
$.4 million and $1.0 million, respectively, was recognized. Any Aquila common shares that have been elected by the employee related to this program are classified as outstanding when
calculating earnings per share. Under the terms of the ERISA class action lawsuit settlement, all existing and future matching and discretionary contributions will become immediately 100% vested.

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 fair
market value with one to three year vesting terms and have been exercisable for seven to 10 years from the date of grant. Fair Market Value is defined as the average of the high and low prices
for the day the grant was awarded. Cash received on stock options exercised was $1.0 million, the intrinsic value of options exercised was $.5 million and the tax benefit realized was
$.2 million for the year ended December 31, 2007. As of December 31, 2007, we have approximately 4.4 million shares of common stock available for grant under this plan.
Shares awarded are generally issued first from treasury shares then from newly issued shares.

The
terms of all grants outstanding under our Omnibus Incentive Compensation Plan provide for accelerated vesting of restricted stock awards and for accelerated vesting at target levels
for performance-based restricted stock awards in the event of a change in control. A change in control also causes the time restrictions in our restricted stock awards to lapse.

Share-Based Payments

In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payments" (SFAS 123R), that requires all companies to expense the value of employee
stock options. SFAS 123R became

89

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effective
for us as of January 1, 2006, and was applied to all outstanding unvested share-based awards on that date, consisting of 74,700 unvested stock options. We elected to use the modified
prospective method to adopt SFAS 123R. The 2006 impact of the adoption of SFAS 123R was immaterial.

We
issued stock options to employees from time to time and had accounted for these options under APB Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25),
through December 31, 2005. All stock options issued are granted at the common stock's market price on the date of grant. Therefore, prior to 2006 we recorded no compensation expense related to
stock options.

Because
we accounted for options under APB 25 in 2005, we disclosed a pro forma net loss and basic and diluted earnings (loss) per share as if we reflected the estimated fair
value of options as compensation expense in accordance with SFAS 123R. Our pro forma net loss and basic and diluted loss per share were as follows:

|In millions, except per share amounts |                                                                                                                 | Year Ended
December 31, 2005 |       
|------------------------------------- | --------------------------------------------------------------------------------------------------------------- | ---------------------------- | ------
|
|Net loss:                             |                                                                                                                 |                              |       
|                                      | As reported                                                                                                     |                              | $     
|                                      | PIES adjustment (Note 14)                                                                                       |                              |       
|                                      |                                                                                                                
|Loss available for common shares      |                                                                                                                 |                              | (217.4
|                                      | Total stock-based employee compensation expense determined under fair value method, net of related tax benefits |                              |       
|                                      |                                                                                                                
|                                      | Pro forma loss available for common shares                                                                      |                              | $     
|                                      |                                                                                                                
|Basic and diluted loss per share:     |                                                                                                                 |                              |       
|                                      | As reported                                                                                                     |                              | $     
|                                      | Pro forma                                                                                                       |                              |       
|                                      |                                                                                                                

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:

|                                      |  | Year Ended
December 31, 2005
|------------------------------------- |  | ----------------------------
|
|Weighted average fair value per share |  | $2.08                       
|Expected volatility                   |  | 83%                         
|Risk-free interest rate               |  | 3.82%                       
|Expected lives                        |  | 3.7 years                   
|Dividend yield                        |  |                            
|                                     

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Summary of Stock Options

This table summarizes all stock option activity:

|                         |  | Year Ended December 31, |          
|------------------------ |  | ----------------------- | ---------
|
|
|Shares:                  |  |                         |          
|Beginning balance        |  |                         | 4,865,866
|Granted                  |  |                         |         
|Exercised                |  |                         | (362,115 
|Forfeited                |  |                         | (763,031 
|                         | 
|Ending balance           |  |                         | 3,740,720
|                         | 
|Weighted average prices: |  |                         |          
|Beginning balance        |  | $                       | 15.57    
|Granted price            |  |                         |         
|Exercised price          |  |                         | 2.83     
|Forfeited price          |  |                         | 19.55    
|                         | 
|Ending balance           |  | $                       | 16.00    
|                         | 

This
table summarizes all outstanding and exercisable stock options as of December 31, 2007:

|               |       | Outstanding Options |           | Exercisable Options
|-------------- | ----- | ------------------- | --------- | -------------------
|
|              
|$1.44 - 1.83   |       | 518,281             |           | 1.97               
|$3.75          |       | 1,137,125           |           | 3.99               
|$18.50 - 24.90 |       | 1,321,853           |           | 1.01               
|$28.42 - 39.52 |       | 763,461             |           | 3.24               
|              
|               | Total |                     | 3,740,720 |                    
|              

The
aggregate intrinsic value of "in-the-money" outstanding and exercisable options was $1.0 million as of December 31, 2007.

Time-Based Restricted Stock Awards

In 2005, 183,823 shares of restricted stock were awarded to certain managers and executives, excluding senior management, as an incentive to retain their services
through this transition time. These awards vested in 2007 and have no further restrictions on the sale of the shares. On July 31, 2007, 106,000 shares of restricted stock were awarded to senior
management; each recipient is a named executive officer of the Company. These awards will vest in three years, and no restrictions on the sale of shares will apply thereafter. The fair value of these
stock awards is determined based on the number of shares granted and the average of the high and low quoted price of our stock on the date of the award. The compensation expense related to these
awards was $.3 million for the year ended December 31, 2007. As of December 31, 2007, the estimated total compensation cost not yet recognized was $.3 million. This
compensation cost will be recognized over the respective restriction periods. The total fair value of restricted stock released

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for
the year ended December 31, 2007 was $2.4 million. Non-vested, time-based restricted stock awards and changes for the three years ended December 31,
2007 were as follows:

|                                     |  | Year Ended December 31, |         
|------------------------------------ |  | ----------------------- | --------
|
|
|Shares:                              |  |                         |         
|Beginning balance                    |  |                         | 351,515 
|Awarded                              |  |                         | 106,000 
|Released                             |  |                         | (196,533
|Forfeited                            |  |                         | (2,000  
|                                     | 
|Ending balance                       |  |                         | 258,982 
|                                     | 
|Weighted average prices:             |  |                         |         
|Beginning balance                    |  | $                       | 16.79   
|Awarded price                        |  |                         | 3.80    
|Released price                       |  |                         | 12.05   
|Forfeited price                      |  |                         | 3.60    
|                                     | 
|Ending balance                       |  | $                       | 15.17   
|                                     | 
|Remaining Contractual Terms in Years |  |                         | 1.18    
|                                     | 

The
aggregate intrinsic value of outstanding time-based restricted stock was $1.0 million as of December 31, 2007.

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards were granted in the third quarter of 2006 to qualified individuals, excluding senior management, consisting of the right
to receive a number of shares of common stock at the end of the restriction period, March 1, 2008, assuming performance criteria
were met. Additional performance based restricted stock awards were granted to senior management in the third quarter of 2007 and will vest on December 31, 2008. The performance measure for the
awards was the ratio of 2007 adjusted EBITDA to 2007 average net utility plant investment. The threshold level of performance was a ratio of 10.0%, target at a ratio of 11.5%, and maximum at a ratio
of 13.0%. Shares would be earned at the end of the performance period as follows: 100% of the target number of shares if the target level of performance was reached, 50% if the threshold was reached,
and 150% if the ratio was at or above the maximum, with the number of shares interpolated between these levels. No shares would be payable if the threshold is not reached.

For
the senior management who received these awards, the amount of performance-based restricted stock earned based upon the EBITDA-to-net utility plant investment
ratio described above would be reduced if the Company failed to achieve one or more of the operating metrics. If the Company failed to achieve one of the four operating metrics, the amount of
performance-based restricted stock would be reduced by 25%. If the Company failed to achieve two or three of the four operating metrics, the amount of performance-based restricted stock would be
reduced by 50% or 75%, respectively. If the Company failed to achieve all four operating metrics for fiscal year 2007, the shares of performance-based restricted stock earned under the
EBITDA-to-net utility plant investment calculation would be reduced to zero.

The
fair value of these stock awards was determined based on the number of shares granted and the average of the high and low quoted price of our stock on the date of the award. An
estimated annual turnover rate of 8% was assumed to determine the compensation expense

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related
to the 2006 award. No estimated turnover was assumed to determine the compensation expense in the 2007 award to members of senior management. The compensation expense related to these awards
was $.8 million for the year ended December 31, 2007. As of December 31, 2007, the estimated total compensation cost not yet recognized was $.5 million. This deferred
compensation cost is reflected as a deduction from our premium on capital stock and will be recognized over the period through March 1, 2008 for the 2006 award and December 31, 2008 for
the 2007 award. Non-vested, performance-based restricted stock awards (based on target number) as of December 31, 2007 and changes during the years ended December 31, 2007
and 2006 were as follows:

|                                     |  | Year Ended December 31,
|------------------------------------ |  | -----------------------
|
|
|Shares:                              |  |                        
|Beginning balance                    |  |                        
|Awarded                              |  |                        
|Released                             |  |                        
|Forfeited                            |  |                        
|                                    
|Ending balance                       |  |                        
|                                    
|Weighted average prices:             |  |                        
|Beginning balance                    |  | $                      
|Awarded price                        |  |                        
|Released price                       |  |                        
|Forfeited price                      |  |                        
|                                    
|Ending balance                       |  | $                      
|                                    
|Remaining Contractual Terms in Years |  |                        
|                                    

The
aggregate intrinsic value of outstanding performance-based restricted stock was $1.1 million as of December 31, 2007.

On
February 26, 2008, committees of the Company's Board of Directors verified the 2007 actual results of the performance metrics applicable to the performance-based restricted
stock awards, as set forth below.

|Financial Metric                                             |  | Threshold |   | Target |   | Maximum |   | 2007
Actual |   | Payout as of %
of Target |  
|------------------------------------------------------------ |  | --------- | - | ------ | - | ------- | - | ----------- | - | ------------------------ | -
|
|2007 Adjusted EBITDA to Average Net Utility Plant Investment |  | 10        | % | 11.5   | % | 13      | % | 13.8        | % | 150                      | %
|                                                             | 

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In determining the 2007 actual results above, the committees verified that the Company's non-GAAP 2007 Adjusted EBITDA was $265.0 million and the Company's 2007
average net utility plant investment was $1.9 billion. To compute the Company's 2007 Adjusted EBITDA, the Company's actual 2007 EBITDA from continuing operations of $239.0 million was
increased by excluding $26.0 million of merger-related costs and severance costs incurred last year.

|                                                                        |  | Electric
States |   | Gas States |   |     
|----------------------------------------------------------------------- |  | --------------- | - | ---------- | - | ----
|
|
|Network Reliability (Target)                                            |  | n/a             |   | n/a        |   | 2   
|Network Reliability (2007 Actual)                                       |  | n/a             |   | n/a        |   | 1   
|                                                                       
|Network ReliabilitySAIFI (Target)                                      |  | 1.32            |   | 1.73       |   | n/a 
|Network ReliabilitySAIFI (2007 Actual)                                 |  | .93             |   | 1.58       |   | n/a 
|                                                                       
|Customer ServiceMeter Reading Accuracy (Target)                        |  | 99.4            | % | 99.4       | % | 99.4
|Customer ServiceMeter Reading Accuracy (2007 Actual)                   |  | 99.8            | % | 99.9       | % | 99.5
|                                                                       
|Customer ServiceCustomer Service Calls within 20 Seconds (Target)      |  | n/a             |   | n/a        |   | n/a 
|Customer ServiceCustomer Service Calls within 20 Seconds (2007 Actual) |  | n/a             |   | n/a        |   | n/a 
|                                                                       

Because
the 2007 actual performance for each operating metric exceeded target, none of the shares of performance-based restricted stock awarded to our senior officers (including Jon
Empson, Leo Morton, Beth Armstrong, and Christopher Reitz) will be forfeited. As a result, 100% of the shares of performance-based restricted stock granted to these named executive officers was
earned.

Director Stock Awards

Non-employee directors receive as part of his or her annual retainer, an annual award of 7,500 shares of fully vested common stock of the Company.
Each director may elect to defer receipt of their shares until retirement or until they are no longer a member of our Board of Directors. Shares are awarded on the last trading day of each calendar
quarter. Compensation

94

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expense
is based upon the fair market value defined as the average of the high and low quoted price of the Company's common stock at the date of issuance.

|                         |  | Year Ended December 31, |  
|------------------------ |  | ----------------------- | -
|
|
|Shares:                  |  |                         |  
|Beginning balance        |  | 208,372                 |  
|Awarded                  |  | 52,500                  |  
|Released                 |  | (15,000                 | )
|                         | 
|Ending balance           |  | 245,872                 |  
|                         | 
|Weighted average prices: |  |                         |  
|Beginning balance        |  | $4.45                   |  
|Awarded price            |  | 4.03                    |  
|Released price           |  | 4.03                    |  
|                         | 
|Ending balance           |  | $4.38                   |  
|                         | 

The
aggregate intrinsic value of outstanding director stock awards was $.9 million as of December 31, 2007.

Note 13: Accumulated Other Comprehensive Income (Loss)

The table below reflects the activity for accumulated other comprehensive income (loss) for 2005, 2006 and 2007:

|In millions                 |  | Foreign Currency
Adjustments |     | Unrecognized
Pension and Post-
retirement Benefit
Costs |   | Accumulated
Other
Comprehensive
Income (Loss) |  
|--------------------------- |  | ---------------------------- | --- | ------------------------------------------------------- | - | --------------------------------------------- | -
|
|Balance December 31, 2004   |  | $                            | .8  |                                                         | $ |                                              |  
|2005 Change                 |  |                              | (.9 | )                                                       |   |                                              |  
|                            | 
|Balance December 31, 2005   |  |                              | (.1 | )                                                       |   |                                              |  
|2006 Change                 |  |                              | .1  |                                                         |   |                                              |  
|Effect of SFAS 158 adoption |  |                              |    |                                                         |   | (30.6                                         | )
|                            | 
|Balance December 31, 2006   |  |                              |    |                                                         |   | (30.6                                         | )
|2007 Change                 |  |                              | .1  |                                                         |   | 31.0                                          |  
|                            | 
|Balance December 31, 2007   |  | $                            | .1  |                                                         | $ | .4                                            |  
|                            | 

See
Note 16 for further discussion of the effects of the adoption of SFAS 158 as of December 31, 2006.

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Note 14: Earnings (Loss) Per Common Share

The table below shows how we calculated basic and diluted earnings (loss) per share. 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 our earnings (loss) available for common shares by weighted average shares outstanding,
without adjusting for dilutive items. Diluted earnings (loss) per share is calculated by dividing our earnings (loss), after assumed conversion of dilutive securities, by our weighted average shares
outstanding, adjusted for the effect of dilutive securities. However, as a result of the losses from continuing operations in 2007, 2006 and 2005, the potential issuances of common stock for dilutive
securities of 240,299, 497,803 and 526,020, respectively, were considered anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.

|                                                                                             |                                                             | Year Ended December 31, |       
|-------------------------------------------------------------------------------------------- | ----------------------------------------------------------- | ----------------------- | ------
|
|                                                                                             |                                                            
|Loss from continuing operations                                                              |                                                             | $                       | (18.1 
|Interest and debt amortization costs associated with the PIES                                |                                                             |                         | .1    
|                                                                                             |                                                            
|Loss available for common shares from continuing operations                                  |                                                             |                         | (18.0 
|Earnings (loss) from discontinued operations                                                 |                                                             |                         | 12.7  
|                                                                                             |                                                            
|Income (loss) available for common shares and assumed conversions                            |                                                             | $                       | (5.3  
|                                                                                             |                                                            
|Basic and diluted earnings (loss) per share:                                                 |                                                             |                         |       
|                                                                                             | Loss available for common shares from continuing operations |                         | $     
|                                                                                             | Earnings (loss) from discontinued operations                |                         |       
|                                                                                             |                                                            
|                                                                                             | Basic and diluted income (loss) per share                   |                         | $     
|                                                                                             |                                                            
|Weighted average number of common shares used in basic and diluted earnings (loss) per share |                                                             |                         | 375.68
|                                                                                             |                                                            

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Note 15. Income Taxes

Loss from continuing operations before income taxes consisted of:

|         |       | Year Ended December 31, |      
|-------- | ----- | ----------------------- | -----
|
|         |      
|Domestic |       | $                       | (18.4
|Foreign  |       |                         | 6.3  
|         |      
|         | Total |                         | $    
|         |      

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

|                                                           |         | Year Ended December 31, |     
|---------------------------------------------------------- | ------- | ----------------------- | ----
|
|                                                           |        
|Current:                                                   |         |                         |     
|                                                           | Federal |                         | $   
|                                                           | Foreign |                         |     
|                                                           | State   |                         |     
|Deferred:                                                  |         |                         |     
|                                                           | Federal |                         |     
|                                                           | Foreign |                         |     
|                                                           | State   |                         |     
|                                                           |        
|Income tax expense (benefit) from continuing operations    |         |                         | 6.0 
|                                                           |        
|Income tax expense (benefit) from discontinued operations: |         |                         |     
|Current                                                    |         |                         |    
|Deferred                                                   |         |                         | (3.9
|                                                           |        
|Income tax expense (benefit) from discontinued operations  |         |                         | (3.9
|                                                           |        
|                                                           |         | 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           |               | $    
|                                           | General business credit carryforward                  |               |      
|                                           | Capital loss carryforward                             |               |      
|                                           | Unrealized capital losses                             |               |      
|                                           | U.S. net operating loss carryforward                  |               |      
|                                           | State net operating loss carryforward                 |               |      
|                                           | Pension and post-retirement benefits obligations      |               |      
|                                           | Other                                                 |               |      
|                                           | Less: valuation allowance                             |               |      
|                                           |                                                      
|Total deferred tax assets                  |                                                       |               | 296.4
|                                           |                                                      
|Deferred Tax Liabilities and Credits:      |                                                       |               |      
|                                           | Accelerated depreciation and other plant differences: |               |      
|                                           |                                                       | Regulated     |      
|                                           |                                                       | Non-regulated |      
|                                           | Regulatory assetincome taxes                         |               |      
|                                           | Regulatory assetpension and post-retirement benefits |               |      
|                                           | Other                                                 |               |      
|                                           |                                                      
|Total deferred tax liabilities and credits |                                                       |               | 296.4
|                                           |                                                      
|Deferred income taxes and credits, net     |                                                       | $             |     
|                                           |                                                      



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

|                                  |                                              | Year Ended December 31, |       
|--------------------------------- | -------------------------------------------- | ----------------------- | ------
|
|                                  |                                             
|Statutory Federal Income Tax Rate |                                              | (35.0                   | )%    
|Tax effect of:                    |                                              |                         |       
|                                  | State income taxes, net of federal benefit   |                         | (2.0  
|                                  | Increased state NOL benefit                  |                         | (68.7 
|                                  | Change in unrecognized tax benefits          |                         | (222.1
|                                  | PIES conversion costs/amortization           |                         |      
|                                  | Canadian tax audit                           |                         | 70.9  
|                                  | Settlement of 1996-1997 IRS audit            |                         | (23.7 
|                                  | Estimate of non-deductible transaction costs |                         | 39.9  
|                                  | Valuation allowance adjustments              |                         | 292.3 
|                                  | Other                                        |                         | (2.8  
|                                  |                                             
|Effective Income Tax Rate         |                                              | 48.8                    | %     
|                                  |                                             

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FIN 48 Unrecognized Tax Benefits

Impact of Adoption of FIN 48

We adopted FIN 48 on January 1, 2007. This interpretation sets a "more likely than not" threshold before tax benefits can be recognized in our
financial statements. Our practice prior to FIN 48 was to recognize income tax benefits when they were reflected on filed income tax returns and establish a reserve against these tax benefits
when their ultimate realization was deemed to be not "probable." Our reserve for uncertain tax positions was $377.3 million at December 31, 2006.

In
connection with the adoption of FIN 48 we analyzed our uncertain tax positions using the new "more likely than not" threshold. Based on this analysis, the reserve for uncertain
tax positions was reduced by $175.4 million. This reduction was substantially offset by the establishment of a valuation allowance against net deferred tax assets (discussed below) in the
amount of $156.1 million. These two adjustments were effected through a $19.3 million net increase to beginning accumulated deficit in the first quarter of 2007.

As
discussed above, our practice prior to implementing FIN 48 was to record tax benefits based on returns as filed and establish a reserve against tax benefits when they were
deemed to be uncertain. Under FIN 48, however, tax benefits are not recorded when their ultimate realization is deemed to be uncertain. Rather, they are separately disclosed as unrecognized tax
benefits. As such, in conjunction with the implementation of FIN 48, we reclassified our deferred tax accounts at January 1, 2007 to reduce deferred tax assets that relate to
unrecognized tax benefits. The reserve for uncertain tax benefits was reduced by the same amount.

Significant
deferred tax accounts impacted by these adjustments related to net operating loss (NOL) carryforwards, AMT credit carryforwards, general business credit carryforwards and
deferred tax liabilities. In addition, some tax uncertainties relate to the characterization of certain taxable gains as capital gains instead of ordinary income. Thus, the reduction in deferred tax
assets for NOL carryforwards was partially offset by an increase in deferred tax assets for capital loss carryforwards. However, we maintain a full valuation allowance against the tax benefits from
our capital loss carryforwards (discussed below), so this valuation allowance was likewise increased. These adjustments did not change the amount of net deferred tax assets. The following table
illustrates the FIN 48 adjustments and the reclassification of our deferred tax accounts.

|In millions                       |                                                    | Pre FIN 48
12/31/2006 |        | Adjustment |   | Reclass |        | Post FIN 48
1/1/2007 |      
|--------------------------------- | -------------------------------------------------- | --------------------- | ------ | ---------- | - | ------- | ------ | -------------------- | -----
|                                  |                                                   
|Summary Deferred Tax Assets:      |                                                    |                       |        |            |   |         |        |                      |      
|                                  | Alternative minimum tax credit carryforward        |                       | $      | 92.3       |   |         |        |                      | $    
|                                  | General business credits                           |                       |        | 6.8        |   |         |        |                      |      
|                                  | Federal and State net operating loss carryforwards |                       |        | 596.9      |   |         |        |                      |      
|                                  | Realized and unrealized capital loss carryforwards |                       |        | 120.3      |   |         |        |                      |      
|                                  | Other deferred tax assets                          |                       |        | 53.7       |   |         |        |                      |      
|                                  | Reserve for uncertain tax positions                |                       |        | (377.3     | ) |         | 175.4  |                      |      
|                                  | Valuation allowances                               |                       |        | (139.7     | ) |         | (156.1 | )                    |      
|                                  |                                                   
|Total deferred tax assets         |                                                    |                       | 353.0  |            |   | 19.3    |        |                      | (36.8
|                                  |                                                   
|Summary Deferred Tax Liabilities: |                                                    |                       |        |            |   |         |        |                      |      
|                                  | Accelerated depreciation                           |                       |        | (286.0     | ) |         |        |                      |      
|                                  | Other deferred tax liabilities                     |                       |        | (86.3      | ) |         |        |                      |      
|                                  |                                                   
|Total deferred tax liabilities    |                                                    |                       | (372.3 | )          |   |         |        |                      | 36.8 
|                                  |                                                   
|Net deferred tax liability        |                                                    | $                     | (19.3  | )          | $ | 19.3    |        | $                    |     
|                                  |                                                   

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Unrecognized Tax Benefits

The amount of unrecognized income tax benefits at January 1, 2007 was $222.6 million. Of this amount, $196.9 million would have impacted the
effective rate, if recognized. We recognize accrued interest and penalties associated with uncertain tax positions as part of the tax provision. As of January 1, 2007, we had
$8.2 million of accrued interest and penalties, net of $3.2 million of tax benefit, included in the reserve for uncertain tax positions. At December 31, 2007, the amount of
unrecognized income tax benefits decreased to $205.2 million. Of this amount, $169.2 million would impact the effective rate if recognized. Accrued interest and penalties associated with
uncertain tax positions at December 31, 2007 were $9.5 million, net of $3.7 million tax benefit. The following table illustrates the changes to our unrecognized tax benefits
during 2007.

Rollforward of Unrecognized Tax Benefits from Uncertain Tax Positions

|In millions                                         |  | Unrecognized Tax Benefits |       | Accrued Interest
|--------------------------------------------------- |  | ------------------------- | ----- | ----------------
|
|Balance at Adoption (January 1, 2007)               |  | $                         | 222.6 |                 
|Additions related to 2007 tax positions             |  |                           |      |                 
|Additions related to tax positions prior years      |  |                           | 8.4   |                 
|Reductions related to tax positions prior years     |  |                           | (15.9 | )               
|Reduction related to lapse of statue of limitations |  |                           |      |                 
|Settlements                                         |  |                           | (9.9  | )               
|                                                   
|Balance at December 31, 2007                        |  | $                         | 205.2 |                 
|                                                   

In
addition to our consolidated Federal and various state tax returns, we file separate subsidiary tax returns in Canada and certain other states. All of our federal income tax returns
are examined by the Internal Revenue Service (IRS). The IRS is currently auditing the years 2003-2004 and the audit report for years 1998-2002 is currently under review by The
Joint Committee on Taxation.

On
May 7, 2007 the Canada Revenue Agency (CRA) proposed to disallow certain deductions relating to Goods and Service Taxes and intercompany accounts taken on the 2002 Canadian
income tax return of our wholly-owned subsidiary, Aquila Canada Corp (ACC). ACC was part of our Merchant Services business in Canada. We contested the proposed adjustments. Pursuant to FIN 48,
during the second quarter we wrote off our Canadian current income tax receivable of $4.8 million and recorded a current income tax payable of $3.6 million. This increased our
unrecognized tax benefits by $8.4 million in the second quarter. In November 2007, we agreed with the CRA to a reduced adjustment to ACC's 2002 taxable income consistent with the amount of our
second quarter adjustment. No additional write off or expense was recorded due to the settlement. This settlement reduced unrecognized tax benefits by $8.4 million in the fourth quarter.

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On October 9, 2007 we agreed to adjustments contained in IRS audit reports related to our 1998 to 2002 taxable years. In addition, the agreement stipulates consistent treatment
during our 2003 and 2004 taxable years for certain issues related to our former Networks businesses in Australia and Canada. The audit report and agreements must be approved by the Joint Committee on
Taxation. There is no timetable for such approval, but the statute of limitations for the years 1998 to 2002 is scheduled to expire on November 30, 2008. We expect the following consequences
upon conclusion of these audits: (i) tax refunds of $19.7 million, $4.8 million of which will be received after the full 2003-2004 audit is complete; (ii) our
federal net operating loss carryforwards will be decreased by $250.1 million ($87.6 million of tax benefit); (iii) our capital loss carryforwards will be decreased by
$53 million ($18.6 million of tax benefit offset by a reduction in valuation allowance by the same amount); (iv) our AMT credit will be decreased by $7.5 million;
(v) our general business credit carryforward will be decreased by $5.6 million; and (vi) we will pay interest to the IRS of $7.7 million, $3.4 million of which is
currently on deposit with the IRS. In addition, we expect our deferred tax liability to decrease by $34.4 million for those IRS adjustments that do not impact our effective tax rate. We do not
anticipate additional income statement or balance sheet impact upon conclusion of these audits. Rather, the impact of these adjustments, both positive and negative, is currently included in our
unrecognized tax benefits.

It
is reasonably possible that the amount of unrecognized tax benefits will change significantly within the next twelve months. These benefits relate to income, deductions and foreign
tax credits of our former international operations in New Zealand, Australia and Canada as well as the deduction of certain other transaction costs and expenses. In addition the benefits relate to the
character (capital vs. ordinary) of certain gains and losses. This change will occur if the Joint Committee on Taxation approves our agreement with the IRS regarding our 1998 to 2002 taxable years and
we determine these taxable years are effectively settled. In such case, we estimate that our unrecognized tax benefits would decrease by $111.4 million primarily reflecting the audit
consequences discussed above. In addition, we estimate that accrued interest associated with uncertain tax benefits would decrease by $5.8 million, net of tax benefit.

Significant Deferred Tax Assets

Tax Credits

At December 31, 2007 and 2006, after implementation of FIN 48 we had tax benefits related to alternative minimum tax credit carryforwards of
$76.1 million and $63.4 million, respectively. These credits do not expire and can be used to decrease future cash tax payments.

At
December 31, 2007 and 2006, after implementation of FIN 48 we had tax benefits related to general business tax credit carryforwards of $.4 million and
$1.1 million, respectively.

Capital Loss Carryforwards

As of December 31, 2007 and 2006, respectively, after implementation of FIN 48, we had approximately $187 million and $198.9 million
of tax benefits related to capital loss carryforwards. The benefits from the capital loss carryforwards at December 31, 2007 expire as follows: $88.6 million in 2008,
$85.1 million in 2009, and $13.3 million in 2012. Included in the tax benefits that expire in 2008 and 2009 respectively are $20.1 million and $52.4 million of tax benefits
for capital losses that we treated as ordinary losses on filed income tax returns. The tax benefits from the ordinary losses on the returns as filed are included in unrecognized tax benefits for net
operating loss carryforwards discussed below. If the unrecognized tax benefits from the net operating loss carryforwards are recognized, then the recognized tax benefits from capital loss

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carryforwards
will be decreased by the same amount. The tax benefits from capital loss carryforwards are subject to a full valuation allowance, as discussed below. Thus, any changes to unrecognized
tax benefits impacting capital loss carryforwards will have an offsetting impact on the related valuation allowance.

Net Operating Loss Carryforwards

At December 31, 2007 and 2006, after implementation of FIN 48 we had tax benefits of $311.6 million and $327.5 million, respectively,
related to federal NOL carryforwards. As of December 31, 2007, $83.1 million related to NOLs originating in 2003, $103.2 million originating in 2004, $74.1 million
originating in 2005 and $82.3 million originating in 2006. We estimate 2007 taxable income to be $88.8 million. The $31.1 million federal tax liability related to this income will
be offset by tax benefits from the 2003 NOL. The balance of 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, 2005 and 2006 federal net operating loss carryforwards expire in 2024, 2025 and 2026, respectively, and cannot be carried back due to losses in the carryback years.

In
addition to the deferred tax benefits related to federal NOLs, after implementation of FIN 48, we also have deferred tax benefits of $73.7 million and
$67.1 million related to state net operating losses as of December 31, 2007 and 2006, respectively. In addition to our normal tax provision, during 2007 we recorded $11.5 million
of incremental tax benefit substantially due to the increase in our apportionment factor for Missouri and we recorded $3.2 million of tax expense to write off the benefit of NOLs because we no
longer operate in certain states. The state net operating loss carryforwards expire in various years.

Valuation Allowances

We are required to assess the ultimate realization of deferred tax assets using a "more likely than not" assessment threshold. This assessment takes into
consideration tax planning strategies within our control. This assessment, however, does not take into consideration the expected taxable gains, both ordinary and capital, from pending sales of our
Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska gas properties. In addition, the assessment does not take into consideration our pending merger with a subsidiary of Great
Plains Energy.

As
a result of this assessment, we have established a full valuation allowance against tax benefits from net capital loss carryforwards, a partial valuation allowance against tax
benefits from state net operating loss carryforwards, and a full valuation allowance against the remaining balance of net deferred tax assets. The valuation allowance against our net deferred tax
assets was initially established in an amount of $156.1 million on January 1, 2007 in conjunction with the implementation of FIN 48. It was recorded through a decrease to
beginning accumulated

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deficit,
partially offsetting the FIN 48 increase to retained earnings of $175.4 million. The following table illustrates the changes to our tax valuation allowances during 2007.

|In millions                  |                            | Pre FIN 48 12/31/2006 |        | Adjustment |   | Reclass |        | Post FIN 48 1/1/2007 |       | 2007 Adjustments |   | 12/31/2007 |       
|---------------------------- | -------------------------- | --------------------- | ------ | ---------- | - | ------- | ------ | -------------------- | ----- | ---------------- | - | ---------- | ------
|                             |                           
|                             |                            |                       |        |            |   |         |        |                      |       |                  |   |            |       
|Valuation Allowance Against: |                            |                       |        |            |   |         |        |                      |       |                  |   |            |       
|                             | Capital Loss Carryforwards |                       | $      | (120.3     | ) |         |        |                      | $     | (78.6            | ) | $          | (198.9
|                             | State NOL Carryforwards    |                       |        | (19.4      | ) |         |        |                      |       | 4.4              |   |            | (15.0 
|                             | Net Deferred Tax Assets    |                       |        |           |   |         | (156.1 | )                    |       | (4.3             | ) |            | (160.4
|                             |                           
|Total                        |                            | $                     | (139.7 | )          | $ | (156.1  | )      | $                    | (78.5 | )                | $ | (374.3     | )     
|                             |                           

The
2007 adjustments include $35.4 million of tax expense recorded in continuing operations primarily related to the valuation allowance against net deferred tax assets and
$11.9 million tax
benefit in other comprehensive income. The tax benefit recorded in other comprehensive income relates to the decrease in valuation allowance due to the decrease in deferred tax assets associated with
SFAS 158 pension, SERP and post-retirement benefit adjustments which were also recorded in other comprehensive income. In addition, 2007 adjustments include a $7.2 million tax benefit
recorded in discontinued operations related to the release of valuation allowance against capital loss carryforwards. Lastly, 2007 adjustments also include a $5.2 million FIN 48
adjustment primarily related to the valuation allowance against capital losses. This adjustment did not impact our provision since it was fully offset by an adjustment to our deferred tax assets.

Loss on PIES Exchange

As discussed in Note 11, we recorded a pretax loss of $82.3 million in 2005 on the early conversion of the PIES. In addition, in 2007, 2006 and 2005
we recorded interest and amortization of debt issue costs on our PIES of $.1 million, $.2 million and $12.6 million, respectively. No tax benefits were recorded as these costs
were not deductible for income tax purposes.

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Note 16: 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 fund the net periodic post-retirement benefit costs to the extent that they are tax-deductible and/or recoverable in our utility rates.

On
August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the "Pension Protection Act") into law. The Pension Protection Act makes changes to important aspects
of qualified retirement plans. Among other things, it introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis
for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan
participants. We have conformed to the Pension Protection Act.

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 Comprehensive Income. For measurement purposes, projected benefit obligations and the fair value of plan assets were determined as of September 30, 2007 and 2006.

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|                                                                           |  | Pension Benefits |       | Other
Post-retirement
Benefits |  
|-------------------------------------------------------------------------- |  | ---------------- | ----- | ------------------------------ | -
|
|
|
|                                                                           |  |                  |       |                                |  
|Change in Projected Benefit Obligation:                                    |  |                  |       |                                |  
|Benefit obligation at start of year                                        |  | $                | 381.7 |                                | $
|Service cost                                                               |  |                  | 8.9   |                                |  
|Interest cost                                                              |  |                  | 19.9  |                                |  
|Plan participants' contribution                                            |  |                  |      |                                |  
|Transfers                                                                  |  |                  | .3    |                                |  
|Effects of curtailments                                                    |  |                  | (.9   | )                              |  
|Effects of settlements                                                     |  |                  | (22.9 | )                              |  
|Actuarial (gain) loss                                                      |  |                  | (35.9 | )                              |  
|Benefits paid                                                              |  |                  | (14.9 | )                              |  
|                                                                           | 
|Projected benefit obligation at end of year                                |  | $                | 336.2 |                                | $
|                                                                           | 
|Change in Plan Assets:                                                     |  |                  |       |                                |  
|Fair value of plan assets at start of year                                 |  | $                | 325.7 |                                | $
|Actual return on plan assets                                               |  |                  | 32.4  |                                |  
|Employer contribution                                                      |  |                  | 1.0   |                                |  
|Transfers                                                                  |  |                  | (22.9 | )                              |  
|Plan participants' contribution                                            |  |                  |      |                                |  
|Benefits paid                                                              |  |                  | (14.9 | )                              |  
|                                                                           | 
|Fair value of plan assets at end of year                                   |  | $                | 321.3 |                                | $
|                                                                           | 
|Funded status:                                                             |  |                  |       |                                |  
|Funded status                                                              |  | $                | (14.9 | )                              | $
|4th quarter employer contribution                                          |  |                  | .2    |                                |  
|                                                                           | 
|Liability for pension and post-retirement benefits                         |  | $                | (14.7 | )                              | $
|                                                                           | 
|Assets and Liabilities Recognized in the Consolidated Balance Sheets:      |  |                  |       |                                |  
|Pension and post-retirement benefits, current                              |  | $                | (.8   | )                              | $
|Pension and post-retirement benefits                                       |  |                  | (13.9 | )                              |  
|Non-current assets of discontinued operations                              |  |                  |      |                                |  
|Non-current liabilities of discontinued operations                         |  |                  |      |                                |  
|SFAS 71 regulatory assetunrecognized costs                                |  |                  | 23.4  |                                |  
|SFAS 71 net regulatory liabilityMissouri                                  |  |                  | (9.0  | )                              |  
|Amounts Recognized in the Consolidated Statements of Comprehensive Income: |  |                  |       |                                |  
|Unrecognized transition amount                                             |  | $                |      |                                | $
|Unrecognized net actuarial (gain) loss                                     |  |                  | 15.3  |                                |  
|Unrecognized prior service cost                                            |  |                  | 29.0  |                                |  
|Accumulated regulatory (gain) loss adjustment                              |  |                  | (3.4  | )                              |  
|Less: SFAS 71 regulatory assets (continuing and discontinued)              |  |                  | (23.4 | )                              |  
|                                                                           | 
|Accumulated other comprehensive loss                                       |  |                  | 17.5  |                                |  
|Provision for deferred taxes                                               |  |                  | (18.6 | )                              |  
|                                                                           | 
|Accumulated other comprehensive (gain) loss                                |  | $                | (1.1  | )                              | $
|                                                                           | 

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|                                                 |  | Pension Benefits |   | Other
Post-retirement
Benefits |  
|------------------------------------------------ |  | ---------------- | - | ------------------------------ | -
|
|
|
|                                                 |  |                  |   |                                |  
|Weighted Average Assumptions as of September 30: |  |                  |   |                                |  
|Discount rate for expense                        |  | 6.01             | % | 5.80                           | %
|Discount rate for disclosure                     |  | 6.51             | % | 6.01                           | %
|Expected return on plan assets for expense       |  | 8.50             | % | 8.50                           | %
|Expected return on plan assets for disclosure    |  | 8.25             | % | 8.50                           | %
|Rate of compensation increase                    |  | 4.40             | % | 4.40                           | %
|                                                 | 

Included
in the $336.2 million projected benefit obligation for pension benefits and $321.3 million of fair value of pension plan assets is an
$11.9 million estimated transfer made to the buyer of our Kansas electric operations on December 31, 2007.

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 7% in 2007 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 11% in 2007 and decreasing 1% annually until the rate levels out at 5% for years 2013 and thereafter.

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|                                                                                              |                                      | Pension Benefits |       | Other
Post-retirement
Benefits |  
|--------------------------------------------------------------------------------------------- | ------------------------------------ | ---------------- | ----- | ------------------------------ | -
|
|
|
|                                                                                              |                                      |                  |       |                                |  
|Components of Net Periodic Benefit Cost:                                                      |                                      |                  |       |                                |  
|Service cost                                                                                  |                                      | $                | 9.0   |                                | $
|Interest cost                                                                                 |                                      |                  | 19.8  |                                |  
|Expected return on plan assets                                                                |                                      |                  | (23.8 | )                              |  
|Amortization of transition amount                                                             |                                      |                  |      |                                |  
|Amortization of prior service cost                                                            |                                      |                  | 4.5   |                                |  
|Recognized net actuarial (gain) loss                                                          |                                      |                  | 2.6   |                                |  
|                                                                                              |                                     
|Net periodic benefit cost before regulatory expense adjustments                               |                                      |                  | 12.1  |                                |  
|Regulatory gain/loss adjustment                                                               |                                      |                  | 5.6   |                                |  
|SFAS 71 regulatory adjustment                                                                 |                                      |                  | (1.1  | )                              |  
|                                                                                              |                                     
|Net periodic benefit cost after regulatory expense adjustments                                |                                      |                  | 16.6  |                                |  
|Effect of curtailments and settlements included in gain on sale of assets                     |                                      |                  | 10.4  |                                |  
|                                                                                              |                                     
|Total periodic benefit costs                                                                  |                                      | $                | 27.0  |                                | $
|                                                                                              |                                     
|Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income |                                      |                  |       |                                |  
|Amounts arising during the period:                                                            |                                      |                  |       |                                |  
|                                                                                              | Recognized net actuarial (gain)/loss |                  | $     | (21.4                          | )
|                                                                                              |                                     
|Total arising during the period                                                               |                                      | $                | (21.4 | )                              |  
|                                                                                              |                                     
|Components of Net Periodic Benefit Cost Amortized to Income:                                  |                                      |                  |       |                                |  
|                                                                                              | Prior service cost                   |                  | $     | (2.3                           | )
|                                                                                              | Recognized net actuarial (gain)/loss |                  |       | (1.4                           | )
|                                                                                              | Regulatory (gain)/loss adjustment    |                  |       | (5.6                           | )
|                                                                                              |                                     
|Total pension and post-retirement benefit costs amortized to income                           |                                      | $                | (9.3  | )                              |  
|                                                                                              |                                     
|Total recognized in other comprehensive income                                                |                                      | $                | (30.7 | )                              |  
|                                                                                              |                                     
|Total recognized in net periodic benefit cost and other comprehensive income                  |                                      | $                | (3.7  | )                              |  
|                                                                                              |                                     

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The
other changes in plans assets and benefit obligations recorded in the regulatory asset and other comprehensive income accounts during 2007 are as follows:

|                                     |  | Pension Benefits |       | Other
Post-retirement Benefits |  
|------------------------------------ |  | ---------------- | ----- | ------------------------------ | -
|
|
|
|                                     |  |                  |       |                                |  
|Amounts arising during the period:   |  |                  |       |                                |  
|Recognized net actuarial (gain)/loss |  | $                | (14.9 | )                              | $
|                                     | 
|Total arising during the period      |  | $                | (14.9 | )                              | $
|                                     | 

The
unrecognized net periodic benefit costs amortized to income from the regulatory asset and accumulated other comprehensive income accounts during 2007 are as follows:

|                                                             |  | Pension Benefits |     | Other
Post-retirement Benefits
|------------------------------------------------------------ |  | ---------------- | --- | ------------------------------
|
|
|
|                                                             |  |                  |     |                               
|Components of Net Periodic Benefit Cost Amortized to Income: |  |                  |     |                               
|Transition amount                                            |  | $                |    |                               
|Prior service cost                                           |  |                  | 2.2 |                               
|Recognized net actuarial (gain)/loss                         |  |                  | 1.2 |                               
|Regulatory (gain)/loss adjustment                            |  |                  |    |                               
|                                                            
|Total pension and post-retirement benefit costs amortized    |  | $                | 3.4 |                               
|                                                            

In
connection with the sale of our Kansas electric operations in 2007 and our Michigan, Minnesota and Missouri gas operations in 2006, we included the effects of curtailments and
settlements in the determination of the gains on sales of these operations by considering the prepaid pension asset and pension and post-retirement benefit obligations in the net asset
basis sold.

In
a 2004 settlement with the Missouri Commission, we agreed to recover our Missouri-related pension funding at an agreed-upon annual amount for ratemaking purposes. As
ordered by the Missouri Commission, the difference between the agreed-upon expense for ratemaking purposes and the amount determined under SFAS 87 has been recognized as a
regulatory liability of $9.0 million as of December 31, 2007, in accordance with SFAS 71. Previously, the Missouri Commission ordered the recognition of actuarial gains/losses for
our Missouri-related pension and

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post-retirement
benefit plans to follow an alternative method to the prescribed "corridor" method outlined in SFAS 87 and SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pension." The difference between the "Missouri" method and the "corridor" method is noted as regulatory gain/loss adjustment or accumulated regulatory gain/loss adjustment in the
preceding tables.

As
disclosed in Note 6, our former Kansas electric operations and our former Michigan, Minnesota and Missouri gas operations have been reclassified as discontinued operations. The
components of net periodic benefit cost presented in the tables above disclose information for the plans in total. In 2007, the net periodic pension benefit cost charged to discontinued operations for
our Kansas electric operations prior its sale in 2007, was $.5 million. In addition, the net periodic other post-retirement benefits cost charged to discontinued operations was
$.4 million. In 2006, the net periodic pension benefit cost charged to discontinued operations, including the Michigan, Minnesota and Missouri gas operations prior to their sales in 2006, was
$2.3 million. In addition, the net periodic other post-retirement benefits cost charged to discontinued operations was $1.9 million.

The
regulatory gain/loss adjustment and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic
benefit cost over the next fiscal year are $4.1 million and $2.2 million, respectively. The prior service cost for the defined benefit pension plans that will be amortized from the
regulatory asset accounts into net periodic benefit cost over the next fiscal year is $2.1 million. The prior service cost and transition obligation for the other post-retirement
benefit plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are immaterial. The regulatory gain/loss adjustment, prior
service cost and transition obligation for the other post-retirement benefit plan that will be amortized from the regulatory asset accounts into net periodic benefit cost over the next
fiscal year are $(.3) million, $2.0 million and $.9 million, respectively.

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The
funded status for the SERP plan with an accumulated benefit obligation in excess of plan assets is summarized below:

|In millions                                               |  | 2007 |       | 2006 |  
|--------------------------------------------------------- |  | ---- | ----- | ---- | -
|
|                                                          |  |      |       |      |  
|Accumulated Benefit Obligations in Excess of Plan Assets: |  |      |       |      |  
|Fair value of plan assets at end of year                  |  | $    |      |      | $
|Accumulated benefit obligation at end of year             |  |      | 17.5  |      |  
|                                                          | 
|Funded status(a)                                          |  | $    | (17.5 | )    | $
|                                                          | 



The
accumulated benefit obligation for all our defined benefit pension plans was $302.5 million and $339.0 million at September 30, 2007 and 2006, respectively.

On
February 29, 2008, we amended the SERP to clarify (i) that a participant's combined benefit under our pension plan and SERP will not be less than his or her combined
benefit under such plans as of December 31, 2004, and (ii) the formula used to compute benefits and the time at which small benefit amounts will be paid. These revisions are consistent
with our past administrative practice and do not change the substantive provisions of the SERP. The foregoing description is qualified by reference to the plan amendment filed as an exhibit to this
Form 10-K.

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.

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Pension Plan Investment Objectives

Our
qualified pension plan weighted-average asset allocations by asset category at September 30, 2007 and 2006 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         |       | 20.4                         | %     | 20.5                          | %    
|High yield bonds          |       | 9.5                          |       | 9.8                           |      
|Large cap equities        |       | 27.4                         |       | 27.3                          |      
|Mid cap equities          |       | 11.0                         |       | 10.5                          |      
|Small cap equities        |       | 3.9                          |       | 3.3                           |      
|International equities    |       | 14.5                         |       | 14.2                          |      
|Emerging markets equities |       | 2.9                          |       | 2.4                           |      
|Real estate               |       | 9.9                          |       | 9.0                           |      
|Private equity            |       | .3                           |       | .7                            |      
|Cash                      |       | .2                           |       | 2.3                           |      
|                          |      
|                          | Total |                              | 100.0 | %                             | 100.0
|                          |      

Our
other post-retirement benefit plan assets at December 31, 2007 and 2006 were invested in government securities and short-term investments.

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, 2007 and our estimated

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annual
pension cost (APC) on the income statement for 2008 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                              | % | $                         | (10.4 | )                         | $
|Rate of return on plan assets |  | .25                              | % |                           |      |                           |  
|                              | 

The
discount rate is defined as the rate at which plan obligations could effectively be settled. We utilize the Hewitt Yield Curve (HYC) in selecting the discount rate assumption for our
pension and other post-retirement benefit plans. The HYC method is to project all benefit payments (PBO benefit payments) payable over the life of the plan. Then, stripped investment grade
coupons (the top quartile of non-callable, Corporate Aa bonds or higher) are matched to the benefit payments and discounted back to the current date. The result is a PBO. Then, a single
discount rate is produced that generates the same PBO. This single discount rate is the weighted-average of the stripped investment grade coupon rates.

In
selecting the expected rate of return on plan assets, we reviewed the three, five and ten year average historical returns of the plan. In addition, we considered current economic
conditions, inflation and market dynamics. Finally, we reviewed benchmark information to ensure that our assumption was in line with rates used by other companies.

Our
health care plans are contributory, with participants' contributions adjusted annually. The life insurance plans are generally non-contributory. In estimating future
health
care costs, we have assumed future cost-sharing changes. 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 2008:

|                                                        |  | 1 Percentage-Point |    
|------------------------------------------------------- |  | ------------------ | ---
|
|
|                                                        |  |                    |    
|Effect on total of service and interest cost components |  | $                  | .1 
|Effect on post-retirement benefit obligation            |  |                    | 2.0
|                                                        | 

Based
on actuarial projections, we expect to contribute $.8 million and $5.1 million to our defined benefit pension plans and other post-retirement benefit
plans, respectively, in 2008. Discretionary contributions in 2008 will be based upon fluctuations in the plan investments and discount rates.

To
comply with a regulatory condition related to the closing of the sale of our Kansas electric operations, we contributed $3.4 million to our qualified defined benefit pension
plan and $1.1 million to our other post-retirement benefit plan in April 2007. As a result of the transfer of pension plan assets and pension benefits obligations in accordance with
ERISA requirements to the buyers of our utility assets as discussed in Note 6, we expect to make an additional voluntary contribution of approximately $7.7 million to our defined benefit
plan to maintain the funded status of our pension plan.

Following
are estimated future benefit payments, which reflect expected future service, as appropriate. Other post-retirement benefits are reflected gross without considering
the estimated

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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: |  |                  |       |                                |   |                       | 
|2008                               |  | $                | 14.0  |                                | $ | 5.1                   | 
|2009                               |  |                  | 15.1  |                                |   | 5.4                   | 
|2010                               |  |                  | 16.5  |                                |   | 5.6                   | 
|2011                               |  |                  | 17.6  |                                |   | 5.8                   | 
|2012                               |  |                  | 18.9  |                                |   | 5.6                   | 
|2013-2017                          |  |                  | 116.6 |                                |   | 23.5                  | 
|                                   | 

Note 17: Segment Information

We manage our business in three business segments: Electric Utilities, Gas Utilities and Merchant Services. Our Electric and Gas Utilities currently consist of
our regulated electric utility operations in two states and our natural gas utility operations in four states. We manage our electric and gas utility divisions by state. However, as each of our
electric utility divisions and each of our gas utility divisions have similar economic characteristics, we aggregate our electric utility divisions into the Electric Utilities reporting segment and
our gas utility divisions into the Gas Utilities reporting segment. The operating results of our former Kansas (sold April 1, 2007), Michigan (sold April 1, 2006), Missouri (sold
June 1, 2006), and Minnesota (sold July 1, 2006) utility divisions have been reclassified to discontinued operations. Merchant Services includes the residual operations of Aquila
Merchant Services, Inc. These operations include its commitments under long-term gas contracts and remaining wholesale energy contracts. Merchant Services also includes Aquila's
contractual interest in the Crossroads plant, which is an investment of Aquila, Inc. and is not an asset of Aquila Merchant Services, Inc. The operating results of our two former
Illinois merchant power plants, which were sold on March 31, 2006, have been reclassified to discontinued operations. The operating results of Everest Connections, which was sold on
June 30, 2006, have also been reclassified to discontinued operations. All other operations are included in Corporate and Other, including the costs not allocated to our operating businesses.

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Each
segment is managed based on operating results, expressed as EBITDA. Generally, decisions on finance, dividends and taxes are made at the Corporate level. The current and
non-current assets of our discontinued operations are included in the segments referenced above.

|                    |                    | Year Ended December 31, |        
|------------------- | ------------------ | ----------------------- | -------
|
|
|                    |                    |                         |        
|Sales:(a)           |                    |                         |        
|Utilities:          |                    |                         |        
|                    | Electric Utilities |                         | $      
|                    | Gas Utilities      |                         |        
|                    |                   
|Total Utilities     |                    |                         | 1,475.0
|                    |                   
|Merchant Services   |                    |                         | (8.4   
|Corporate and Other |                    |                         |       
|                    |                   
|                    | Total              |                         | $      
|                    |                   



|                                                                                   |                    | Year Ended December 31, |      
|---------------------------------------------------------------------------------- | ------------------ | ----------------------- | -----
|
|
|                                                                                   |                    |                         |      
|Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization (EBITDA):(a) |                    |                         |      
|Utilities:                                                                         |                    |                         |      
|                                                                                   | Electric Utilities |                         | $    
|                                                                                   | Gas Utilities      |                         |      
|                                                                                   |                   
|Total Utilities                                                                    |                    |                         | 260.5
|                                                                                   |                   
|Merchant Services                                                                  |                    |                         | (5.6 
|Corporate and Other                                                                |                    |                         | (15.9
|                                                                                   |                   
|Total EBITDA                                                                       |                    |                         | 239.0
|Depreciation and amortization                                                      |                    |                         | 108.3
|Interest expense                                                                   |                    |                         | 142.8
|                                                                                   |                   
|Loss from continuing operations before income taxes                                |                    | $                       | (12.1
|                                                                                   |                   



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



|                        |                    | December 31,
|----------------------- | ------------------ | ------------
|
|
|                        |                    |             
|Identifiable Assets:(a) |                    |             
|Utilities:              |                    |             
|                        | Electric Utilities |             
|                        | Gas Utilities      |             
|                       
|Total Utilities         |                    |             
|                       
|Merchant Services       |                    |             
|Corporate and other     |                    |             
|                       
|                        | Total              |             
|                       



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

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Note 18: Commitments and Contingencies

Capital Expenditures

We have made certain construction commitments in connection with our 2008 capital expenditure plan. During 2008, we estimate that our total capital expenditures
will be approximately $503.6 million, including $116.1 million related to Iatan 2 and $120.1 million of environmental upgrades.

Commitments

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

|In millions                              |                             | 2008 |      | 2009  |   | 2010 |       | 2011 |     | 2012  |   | Thereafter |       | Total
|---------------------------------------- | --------------------------- | ---- | ---- | ----- | - | ---- | ----- | ---- | --- | ----- | - | ---------- | ----- | -----
|
|                                         |                             |      |      |       |   |      |       |      |     |       |   |            |       |      
|Future minimum payments                 |                             |      |      |       |   |      |       |      |     |       |   |            |       |      
|Facilities, equipment and other          |                             | $    | 12.3 |       | $ | 9.6  |       | $    | 7.7 |       | $ | 6.5        |       | $    
|Merchant gas transportation obligations  |                             |      | 5.5  |       |   | 5.5  |       |      | 5.5 |       |   | 5.0        |       |      
|Regulated business purchase obligations: |                             |      |      |       |   |      |       |      |     |       |   |            |       |      
|                                         | Purchased power obligations |      |      | 120.3 |   |      | 112.9 |      |     | 115.5 |   |            | 108.3 |      
|                                         | Purchased gas obligations   |      |      | 58.5  |   |      | 56.6  |      |     | 56.3  |   |            | 53.5  |      
|                                         | Coal and rail contracts     |      |      | 95.9  |   |      | 65.7  |      |     | 61.5  |   |            | 22.5  |      
|                                        

Operating Lease Obligations

Future minimum payments include operating leases of coal rail cars, vehicles and office space over terms of up to 20 years. Included in lease commitments
above are approximately $28.1 million for vehicles and equipment under a one-year term renewable master personal property lease. We routinely exercise various lease renewal options and from
time to time purchase leased assets for fair value at the end of lease terms. Contingent residual value obligations under this master lease were approximately $32.5 million at
December 31, 2007. Rent expense for continuing operations for the years 2007, 2006 and 2005 was (in millions), $9.9, $9.6 and $10.9, respectively, and for discontinued operations was $.7, $1.8
and $3.4, respectively.

We
previously leased an 8% interest in the Jeffrey Energy Center through 2019. The lease payments varied by year but were recognized as lease expense on a straight-line basis
of approximately $10.4 million annually. This lease interest was transferred to Westar in connection with the sale of our Kansas electric operations and is included in discontinued operations.

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 2007, our continuing electric utility operations generated 52% 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 operations also purchase power and gas to meet customer needs under short-term
and long-term purchase contracts. Our gas utility operations purchase natural gas, including transportation capacity to meet customer needs under short- and long-term contracts
through 2028.

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Contingent Obligations

Credit Support

We have entered into various agreements for commodity purchases, fleet leasing and insurance 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, 2007, we had $188.3 million of letters of credit outstanding with expiration dates
generally ranging from one month to 16 months.

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 1.5 million ownership units at a price of $1.00 and $1.10 per unit, respectively, for a total potential cost of $5.65 million. In 2004, we believe we achieved the
operating targets related to these ownership units. The holders of these ownership units are disputing our conclusion that Everest achieved these operating targets and are attempting to exercise these
target-based put rights. We do not believe we have any obligation with regard to these target-based put rights.

The
minority owners notified us that they also intend to exercise their option to sell their 9.5 million ownership units to us at fair market value (market-based put rights). We
have recorded a reserve of $2.8 million in connection with the sale of Everest Connections for this potential obligation. These minority owners have been unwilling to accept our fair market
value analysis which was based on the auction results and ultimate sale price of Everest. They have filed suit against us with respect to our disputes involving both the target-based put rights and
the market-based put rights. We believe we have strong defenses and will defend these cases vigorously.

Legal

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We
believe the amounts provided in our consolidated financial statements are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts
required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts
reflected in our consolidated financial statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2007, cannot be reasonably determined.

Price Reporting Litigation

In response to complaints of manipulation of the California energy market, in 2002 the FERC issued an order requiring net sellers of power in the California
markets from October 2, 2000 through June 20, 2001 at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market
during that time period. Because Aquila Merchant was a net purchaser of power during the refund period it has received approximately $7.6 million in refunds. However, various parties appealed
the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2,
2000. On

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August 2,
2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its
remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a
remedy for any such violations. The court remanded the matter to FERC to determine whether tariff violations occurred and, if so, the appropriate remedy. A finding by FERC that tariff violations
occurred during this period could result in Aquila Merchant being required to make substantial refunds and have a material adverse effect on its financial condition, results of operations and cash
flows.

On
October 6, 2006, the Missouri Commission filed suit in the Circuit Court of Jackson County, Missouri against 18 companies, including Aquila and Aquila Merchant, alleging that
the companies manipulated natural gas prices through the misreporting of natural gas trade data and, therefore, violated Missouri antitrust laws. The suit does not specify alleged damages and
was filed on behalf of all local distribution gas companies in Missouri who bought and sold natural gas from June 2000 to October 2002. Our motion to have the case dismissed is pending. We believe we
have strong defenses and will defend this case vigorously. We cannot predict 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 and certain members of our Board of
Directors and management, alleging they violated the ERISA and were responsible for losses that participants in our 401(k) plan experienced as a result of the decline in the value of their Aquila
common stock held in the 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 our common stock through our 401(k) plan were subsequently filed against us. The suits also sought damages for the plan's losses resulting from the alleged
breaches of fiduciary duties. The court ordered that all of these lawsuits be consolidated into a single case captioned In re Aquila ERISA Litigation and certified the case as a class action. In April
2007, we settled the case for $10.5 million, which was paid by our insurance carrier. The settlement agreement was approved by the court in November 2007.

South Harper Peaking Facility

We have constructed a 315 MW natural gas power plant and related substation in an unincorporated area of Cass County, Missouri. Cass County and local residents
filed suit claiming that county zoning approval was required to construct the project. In January 2005, a Circuit Court of Cass County judge granted the County's request for an injunction; however, we
were permitted to continue construction while the order was appealed. We appealed the Circuit Court decision to the Missouri Court of Appeals for the Western District of Missouri and, in June 2005,
the appellate court affirmed the circuit court ruling. In October 2005, the Court of Appeals granted our request for rehearing.

In
December 2005, the appellate court issued a new opinion affirming the Circuit Court's opinion, but also opining that it was not too late to obtain the necessary approval. In light of
this, we filed an application for approval with the Missouri Commission in January 2006. In January

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2006,
the trial court granted our request to stay the permanent injunction until May 31, 2006, and ordered us to post a $20 million bond to secure the cost of removing the project.
Effective May 31, 2006, the Missouri Commission issued an order specifically authorizing our construction and operation of the power plant and substation. On June 2, 2006, the trial
court dissolved the $20 million bond, further stayed its injunction, and authorized us to operate the plant and substation while Cass County appealed the Missouri Commission's order.

In
June 2006, Cass County filed an appeal with the Circuit Court, challenging the lawfulness and reasonableness of the Missouri Commission's order. On October 20, 2006, the
Circuit Court ruled that the Missouri Commission's order was unlawful and unreasonable. The Missouri Commission and Aquila have appealed the court's decision, and the Missouri Court of Appeals for the
Western District of Missouri heard oral arguments in May 2007. We expect the Court of Appeals to issue its decision in the first half of 2008. If we exhaust all of our legal options and are ordered to
remove the plant and substation, we estimate the cost to dismantle these facilities to be up to $20 million. We estimate the incremental cost of relocating and reconstructing the plant and
substation on a site that is being developed to meet future generation needs to be approximately $75 million based on recent engineering studies. Additional costs may be incurred to store the
equipment before relocating it, and to secure replacement power until the plant and substation can be reconstructed. We cannot reasonably estimate with certainty the total amount of these and other
incremental costs that could be incurred, or the potential impairment of the carrying value of our investment in the plant we could suffer to the extent the ultimate costs incurred exceed the amount
allowed for recovery in rates.

Coal Supply Litigation

In the spring of 2005, one of our coal suppliers, C. W. Mining, terminated a long term, fixed price coal supply agreement allegedly because of a force majeure
event. We incurred significant costs procuring replacement coal and disputed that the supplier was entitled to terminate the contract. We filed a lawsuit against the supplier in federal court in Salt
Lake City and the trial was held in February 2007. On October 29, 2007, the United States District Court for the District of Utah, Central Division held that C.W. Mining's performance under the
coal contract was not excused by a force majeure event and awarded us $24.8 million in damages. In order to preserve and recover on our claim, on January 8, 2008, we participated in the
filing of an involuntary Chapter 11 bankruptcy petition against C.W. Mining in the United States Bankruptcy Court in Salt Lake City, Utah. With the implementation of a fuel adjustment clause in
our recent Missouri rate case, we expect that 95% of net damages collected as a result of this litigation will be for the benefit of our Missouri customers through lower rates.

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, 2007, we estimate probable costs of future investigation and remediation on our identified MGP sites, PCB sites and retained liabilities to be
$3.6 million. This is our best estimate based upon our 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

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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 $5.1 million. This
estimate could change materially after further investigation. It could also be affected by the actions of environmental agencies and the financial viability of other responsible parties.

The
EPA finalized several Clean Air Act regulations such as CAIR, BART and CAMR regulations in 2005 that would affect our coal-fired power plants by requiring reductions in
emissions of SO2, NOx and mercury. We have completed engineering studies and obtained vendor bids which evaluated the costs and likely controls for compliance with these Clean Air Act
regulations. For Missouri electric operations, we estimate that probable capital expenditures through 2010 will be approximately $144.7 million based on current engineering bids. Costs have
been increasing because of the shortage of labor needed in the power sector and at this point we are not able to reasonably estimate if additional costs may be incurred.

Note 19: Pending Merger

On February 6, 2007, we entered into an agreement and plan of merger with Great Plains Energy, Gregory Acquisition Corp., a wholly-owned subsidiary of
Great Plains Energy, and Black Hills, which provides for the merger of Gregory Acquisition Corp. into us, with Aquila continuing as the surviving corporation. If the Merger is completed, we will
become a wholly-owned subsidiary of Great Plains Energy, and our shareholders will receive cash and shares of Great Plains Energy common stock in exchange for their shares of Aquila common stock. At
the effective time of the Merger, each share of Aquila common stock will convert into the right to receive 0.0856 of a share of Great Plains Energy common stock and a cash payment of $1.80. The
exchange ratio is fixed and will not be adjusted to reflect stock price changes prior to the completion of the Merger.
Upon consummation of the Merger, our shareholders are expected to own approximately 27% of the outstanding common stock of Great Plains Energy, and the Great Plains Energy shareholders will own
approximately 73% of the outstanding common stock of Great Plains Energy.

The
parties have made customary representations, warranties and covenants in the merger agreement. We have agreed, subject to certain exceptions set forth in the merger agreement, to
conduct our business in the ordinary course during the period between the execution of the merger agreement and consummation of the Merger, and to refrain from engaging in or otherwise limit certain
transactions and activities during this interim period. Consummation of the Merger is subject to a number of conditions, including (i) approval of the Kansas Commission and the Missouri
Commission; (ii) the completion of the asset sale transactions described below; and (iii) the absence of a material adverse effect on our businesses that remain after giving effect to
the asset sales described below.

The
merger agreement contains certain termination rights for both us and Great Plains Energy, including the right to terminate the merger agreement if the Merger has not closed by
February 6, 2008 (subject to extension until August 6, 2008 for receipt of regulatory approvals required to consummate the Merger and the asset sales). On January 31, 2008,
Aquila, Great Plains Energy and Black Hills extended the initial termination date to May 1, 2008.

In
connection with the Merger, we also entered into agreements with Black Hills under which we have agreed to sell our Colorado electric utility and our Colorado, Iowa, Kansas and
Nebraska gas utilities to Black Hills for $940 million in cash, subject to certain working capital and other purchase price adjustments. The agreements contain various provisions customary for
transactions of this size and type, including representations, warranties and covenants with respect to the Colorado, Iowa, Kansas and Nebraska utility businesses that are subject to usual

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limitations.
Completion of the sale transactions is subject to various conditions, including: (i) the approval of the Colorado Public Utilities Commission and the Kansas Commission;
(ii) the absence of a material adverse effect on the utility businesses being sold to Black Hills; and (iii) the ability and readiness of Aquila, Great Plains Energy and Gregory
Acquisition Corp. to complete the Merger immediately after the completion of the asset sales. The employees of these utility operations are expected to be transferred to Black Hills upon completion of
the sale.

The
Merger and the asset sales are contingent upon the closing of the other transaction, meaning that one transaction will not close unless the other transaction closes.

In
April 2007, we and Great Plains Energy filed joint applications with the Missouri Commission and the Kansas Commission requesting approval of the Merger, and we and Black Hills filed
joint applications with the Colorado Public Utilities Commission, IUB, Kansas Commission and
Nebraska Commission requesting approval of the asset sales to Black Hills. In May 2007, the parties filed a joint application with the FERC requesting approval of the Merger and the sale of our
Colorado electric assets to Black Hills, which we amended in June 2007. In July 2007, the parties filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust
Improvements Act (HSR Act) to complete the Merger and the asset sales to Black Hills.

On
August 27, 2007, the Federal Trade Commission granted early termination of the statutory waiting period under the HSR Act for both the Merger and the asset sales to Black
Hills. On August 31, 2007, the sale of our Iowa gas utility operation to Black Hills was approved by the IUB. On October 9, 2007, the merger agreement was adopted by Aquila's
shareholders. On October 10, 2007, the issuance of common stock by Great Plains Energy in connection with the Merger was approved by Great Plains Energy's shareholders. On October 16,
2007, the Nebraska Commission approved the sale of our Nebraska gas operations to Black Hills. On October 19, 2007, the FERC approved the Merger and the sale of our Colorado electric operations
to Black Hills.

Regulatory
hearings in Missouri began on December 3, 2007. The hearings were suspended on December 6, 2007, however, when Great Plains Energy announced its intention to
submit a revised regulatory plan in connection with the Merger. On February 20, 2008, we and Great Plains Energy proposed a procedural schedule that would resume hearings on April 21,
2008, if the parties do not negotiate a settlement before then. On February 25, Great Plains Energy filed additional testimony with the Missouri Commission regarding its revised regulatory
plan.

Regulatory
hearings in Kansas were scheduled to begin in January 2008, but were postponed until February 12, 2008 while the parties tried to negotiate a settlement. On
January 31, 2008, Black Hills filed with the Kansas Commission an agreement under which Black Hills and the other interested parties have settled all of the issues relating to the sale of our
Kansas gas operations to Black Hills. A hearing on the settlement was held on February 12, 2008, and the Kansas Commission is expected to approve the settlement in the near future. On
February 27, 2008, Great Plains Energy filed with the Kansas Commission an agreement under which Great Plains Energy and the intervenors have settled all merger-related issues. A hearing on the
proposed settlement is expected to occur in March.

On
February 14, 2008, the Colorado Commission voted to approve the sale of our Colorado electric and gas operations to Black Hills. The Colorado Commission is expected to issue an
order memorializing its approval in the near future.

We
have evaluated the accounting classification of the assets to be acquired by Black Hills relative to SFAS 144. Based on our assessment, the criteria for classification of the
assets as"held for sale" and discontinued operations have not been met. Important factors underlying our

121

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analysis
include: our management and board of directors have no intention of selling these assets separately from the contingent, two-step Merger transaction, which is not a usual and
customary provision for asset sales; the significant conditions to closing, including numerous regulatory approvals; and, the fact the asset sale will only occur upon the completion of the Merger. As
a result, we have not reclassified the assets to be acquired by Black Hills as "held for sale" and reported those results as discontinued operations.

Regardless
of whether the Merger is completed, we will incur significant costs, primarily consisting of investment banking, legal, employee retention, and other severance costs which we
will expense as they are incurred. We incurred approximately $2.3 million and $16.6 million of costs (primarily investment banking and legal costs) relating to these transactions in 2006
and 2007, respectively. These costs are included in operation and maintenance expense in Corporate and Other.

Beginning
in February 2007, we executed retention agreements totaling $8.8 million with numerous non-executive employees to mitigate employee attrition prior to the
closing of the Merger. The retention awards were paid on January 31, 2008. We accrued $7.9 million of expense related to these retention agreements in 2007. These costs are included in
operation and maintenance expense in Corporate and Other.

Further
information concerning the Merger and asset sales is included in the definitive proxy statement that we filed with the SEC and mailed to our shareholders.

Note 20: 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 and dispositions, 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.

|                                                       |  | 2007 Quarters |       | 2006 Quarters
|------------------------------------------------------ |  | ------------- | ----- | -------------
|
|
|
|
|                                                       |  |               |       |              
|Sales                                                  |  | $             | 444.2 |              
|Gross profit                                           |  |               | 116.6 |              
|Income (loss) from continuing operations               |  |               | (27.2 | )            
|Earnings (loss) from discontinued operations           |  |               | 2.9   |              
|                                                      
|Net income (loss)                                      |  | $             | (24.3 | )            
|                                                      
|Basic and diluted earnings (loss) per
common share:(a) |  |               |       |              
|From continuing operations                             |  | $             | (.07  | )            
|From discontinued operations                           |  |               | .01   |              
|                                                      
|Net income (loss)                                      |  | $             | (.06  | )            
|                                                      



122

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders Aquila, Inc.:

We have audited the accompanying consolidated balance sheets of Aquila, Inc. and subsidiaries (the Company) as of December 31, 2007 and 2006, 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,
2007. 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, 2007. We also have audited the Company's internal control over financial reporting as of December 31, 2007,
based on criteria established inInternal ControlIntegrated Framework,issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of
the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to
express an opinion on these consolidated financial statements and financial statement schedule and an opinion on the Company's internal control over financial reporting 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 audits to
obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also
included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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.

123

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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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity
with accounting principles generally accepted in the United States of America. 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. Also in our opinion, Aquila, Inc. and subsidiaries maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal ControlIntegrated
Framework,issued by COSO.

As
discussed in note 2 to the consolidated financial statements, effective January 1, 2007, the Company adopted Financial Accounting Standards Board (FASB) Interpretation
No. 48,Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement No. 109, Accounting for Income Taxes,
and FSP AUG AIR-1,Accounting for Planned Major Maintenance Activities.

/s/
KPMG LLP
Kansas City, Missouri

February 29,
2008

124

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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) (our principal executive officer) and Chief Accounting Officer (CAO) (our principal financial officer) 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 CAO. 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 CAO.
Based on this evaluation, our CEO and CAO 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 SEC. 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, 2007.

Item 9B.    Other Information

On February 26, 2008, the Compensation and Benefits Committee of our Board of Directors approved the variable compensation payable to our employees under
our 2007 annual incentive compensation plan. The corporate performance metrics established for this plan related to network reliability, customer service, employee safety, effective use of capital,
and cost reductions. After verifying that the Company met or exceeded all of the 2007 corporate performance metrics, the Committee determined that the plan participants would receive 128.5% of their
targeted payouts for the corporate portion of the plan. Our named executive officers did not participate in this incentive compensation plan.

As
part of this process, the Committee elected to grant discretionary cash awards to certain of our named executive officers in recognition of the Company's superior performance against
the corporate performance metrics established for the 2007 annual incentive compensation plan. The discretionary awards were intended to reflect what the highest-level participants to the 2007
incentive compensation plan would earn under the corporate portion of the plan (i.e., a targeted payout equal to 21% of his or her base salary). Accordingly, the discretionary cash awards were

125

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calculated
by multiplying 128.5% by an amount equal to 21% of their base salaries. The discretionary awards were paid on February 29, 2008, as follows:

Named Executive Officer

AwardBeth A. Armstrong

$
70,161Jon R. Empson

$
97,146Leo E. Morton

$
89,590Christopher M. Reitz

$
70,161


Part III

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

Information regarding these items will appear in our 2008 definitive proxy statement and is hereby incorporated by reference in this Annual Report on
Form 10-K.

Equity Compensation Plan Information

The following table provides information as of December 31, 2007, 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     |       | 3,604,907                                                                                      | *         | $                                                                              | 15.70 |                                                                                                                                               | 4,435,108
|Equity compensation plans not approved by security holders |       | 135,813                                                                                        | **        | $                                                                              | 24.02 |                                                                                                                                               |         
|                                                           |      
|                                                           | Total |                                                                                                | 3,740,720 |                                                                                |       |                                                                                                                                               |          
|                                                           |      



Item 14.    Principal Accountant Fees and Services

Information regarding this item will appear in our 2008 definitive proxy statement and is hereby incorporated by reference in this Annual Report on
Form 10-K.

Part IV

Item 15.    Exhibits and 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.

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(a)(2) Financial Statement Schedules

Schedule IIValuation and Qualifying Accounts for the years 2007, 2006 and 2005 on page 128.

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)(10) |  | Annual and Long-Term Incentive Plan.                                                                                       
|--------- |  | ---------------------------------------------------------------------------------------------------------------------------
|10(a)(11) |  | First Amendment to Annual and Long-Term Incentive Plan.                                                                    
|10(a)(12) |  | Life Insurance Program for Officers.                                                                                       
|10(a)(13) |  | Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001.                                   
|10(a)(14) |  | Amendment One to Aquila, Inc. Supplemental Executive Retirement Plan, Amended and Restated effective as of January 1, 2005.
|10(a)(15) |  | Amendment Two to Aquila, Inc. Supplemental Executive Retirement Plan, Amended and Restated effective as of January 1, 2005.
|10(a)(16) |  | Employment Agreement for Richard C. Green.                                                                                 
|10(a)(17) |  | Amendment to Employment Agreement for Richard C. Green.                                                                    
|10(a)(18) |  | Aquila, Inc. Capital Accumulation Plan, Amended and Restated, effective January 1, 2005.                                   
|10(a)(19) |  | Amendment One to Aquila, Inc. Capital Accumulation Plan, Amended and Restated effective as of January 1, 2005.             
|10(a)(21) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan.                                                                     
|10(a)(22) |  | Executive Security Trust Amended and Restated as of April 4, 2002                                                          
|10(a)(23) |  | Severance Compensation Agreement, by and between Aquila, Inc. and Leo E. Morton, dated October 6, 2006.                    
|10(a)(24) |  | Severance Compensation Agreement, by and between Aquila, Inc. and Jon R. Empson, dated October 6, 2006.                    
|10(a)(25) |  | Severance Compensation Agreement, by and between Aquila, Inc. and Beth A. Armstrong, dated August 22, 2006.                
|10(a)(26) |  | Severance Compensation Agreement, by and between Aquila, Inc. and Christopher M. Reitz, dated August 28, 2006.             
|10(a)(27) |  | Form of Amendment to Severance Compensation Agreement dated November 7, 2007.                                              
|10(a)(28) |  | Form of 2007 Senior Executive Restricted Stock Award (Time-Based Restriction), dated July 31, 2007.                        
|10(a)(29) |  | Form of 2007 Senior Executive Restricted Stock Award (Performance-Based Restriction), dated July 31, 2007.                 



(b) Exhibits

The Index to Exhibits follows on page 129.

127

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AQUILA, INC.  SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2007
(in millions)

|Column A                               |      | Column B |   | Column C |  | Column D |        | Column E
|-------------------------------------- | ---- | -------- | - | -------- |  | -------- | ------ | --------
|
|
|
|Allowance for Doubtful Accounts        |      |          |   |          |  |          |        |         
|                                       | 2007 |          | $ | 4.8      |  | $        | 7.5    |         
|                                       | 2006 |          |   | 9.3      |  |          | 4.2    |         
|                                       | 2005 |          |   | 27.7     |  |          | 1.2    |         
|Other Reserves(a)                      |      |          |   |          |  |          |        |         
|                                       | 2007 |          | $ | 29.9     |  | $        | 33.0   |         
|                                       | 2006 |          |   | 24.7     |  |          | 50.9   |         
|                                       | 2005 |          |   | 22.1     |  |          | 36.1   |         
|Restructuring Reserves(b)              |      |          |   |          |  |          |        |         
|                                       | 2007 |          | $ | 2.3      |  | $        | 1.5    |         
|                                       | 2006 |          |   | .1       |  |          | 7.7    |         
|                                       | 2005 |          |   | 7.8      |  |          | 6.6    |         
|Deferred Tax Valuation Allowance       |      |          |   |          |  |          |        |         
|                                       | 2007 |          | $ | 139.7    |  | $        | 270.0  | (c)     
|                                       | 2006 |          |   | 248.9    |  |          | (108.7 | )       
|                                       | 2005 |          |   | 304.7    |  |          | (53.2  | )       
|Reserve for Uncertain Tax Positions(c) |      |          |   |          |  |          |        |         
|                                       | 2007 |          | $ | 377.3    |  | $        |       |         
|                                       | 2006 |          |   | 287.6    |  |          | 89.7   |         
|                                       | 2005 |          |   | 244.0    |  |          | 43.6   |         
|                                      



128

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AQUILA, INC.  INDEX TO EXHIBITS

|Exhibit Number |  | Description                                                                                                                                                                                                                                                                                                                 
|-------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|               |  |                                                                                                                                                                                                                                                                                                                             
|*2(a)          |  | Agreement and Plan of Merger among the Company, Great Plains Energy Incorporated, Gregory Acquisition Corp. and Black Hills Corporation, dated as of February 6, 2007 (Exhibit 2.1 to the Company's Current Report
on Form 8-K filed February 7, 2007).                                                                     
|*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 3.1 to the Company's Current Report on Form 8-K filed May 6, 2005).                                                                                                                                                                                                    
|*4(a)          |  | Long-term debt instruments of the Company in amounts not exceeding 10% of the total assets of the Company and its subsidiaries on a consolidated basis will be furnished to the Commission upon request.                                                                                                                    
|*10(a)(1)      |  | Indenture, dated as of August 24, 2001, between the Company 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 the Company 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)      |  | Bond Indenture, Mortgage, Deed of Trust, Security Agreement and Fixture Filing, dated as of August 31, 2005, between the Company and Union Bank of California, N.A., as trustee and securities intermediary
(Exhibit 10.2 to the Company's Current Report on Form 8-K filed September 6, 2005 (the "September 6 Form 8-K")).
|*10(a)(4)      |  | First Supplemental Bond Indenture, Mortgage, Deed of Trust, Security Agreement and Fixture Filing, dated as of August 31, 2005, between the Company and Union Bank of California, N.A., as trustee and securities
intermediary (Exhibit 10.3 to the September 6 Form 8-K).                                                  
|*10(a)(5)      |  | $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
September 21, 2004).                                                                                                         
|*10(a)(6)      |  | $180 Million Credit Agreement dated as of April 13, 2005, among the Company, the lenders, Citicorp USA, Inc., as issuing bank and administrative agent, and Union Bank of California, N.A., as paying agent
(Exhibit 10.1 to the Company's Current Report on Form 8-K filed April 18, 2005).                                
|*10(a)(7)      |  | Financing Agreement dated as of April 22, 2005, among the Company, the lenders from time to time party thereto, and Union Bank of California, N.A., as agent (Exhibit 10.1 to the Company's Current Report on
Form 8-K filed April 26, 2005).                                                                               
|*10(a)(8)      |  | $300 Million Credit Agreement, dated as of August 31, 2005, among the Company, the banks and other lenders party thereto, and Union Bank of California, N.A., as issuing bank, administrative agent, and sole lead
arranger (Exhibit 10.1 to the September 6 Form 8-K).                                                     

129

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|*10(a)(9)  |  | Amendment No. 2 to Financing Agreement dated December 9, 2006, by and between the Company, the lenders from time to time party thereto, and Union Bank of California, N.A., as agent (Exhibit 10.1 to the
Company's Current Report on Form 8-K filed December 11, 2006).
|---------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*10(a)(10) |  | 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)(11) |  | 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)(12) |  | Life Insurance Program for Officers (Exhibit 10 (a)(13) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995).                                                                                                                              
|*10(a)(13) |  | Aquila, Inc. Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2005 (Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2007).                                                                  
|*10(a)(14) |  | Amendment One to Aquila, Inc. Supplement Executive Retirement Plan, Amended and Restated effective as of January 1, 2005 (Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2007).                                        
|10(a)(15)  |  | Amendment Two to Aquila, Inc. Supplemental Executive Retirement Plan, Amended and Restated effective as of January 1, 2005.                                                                                                                                             
|*10(a)(16) |  | 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)(17) |  | Amendment to Employment Agreement for Richard C. Green (Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).                                                                                                          
|*10(a)(18) |  | Aquila, Inc. Capital Accumulation Plan, as amended and restated, effective January 1, 2005 (Exhibit 10.1 to the Company's Current Report on Form 8-K filed January 6, 2006).                                                                                            
|*10(a)(19) |  | Amendment One to Aquila, Inc. Capital Accumulation Plan, Amended and Restated effective as of January 1, 2005 (Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2007).                                                        
|*10(a)(20) |  | Agreement, by and between the Company and Keith G. Stamm, dated March 16, 2007 (Exhibit 10.1 to the Company's Current Report on Form 8-K filed on March 21, 2007).                                                                                                      
|*10(a)(21) |  | Aquila, Inc. 2002 Omnibus Incentive Compensation Plan (Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).                                                                                                           
|*10(a)(22) |  | 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)(23) |  | Severance Compensation Agreement, by and between the Company and Leo E. Morton, dated October 6, 2006 (Exhibit 10.1 to the Company's Current Report on Form 8-K filed on October 10, 2006).                                                                             
|*10(a)(24) |  | Severance Compensation Agreement, by and between the Company and Jon R. Empson, dated October 6, 2006 (Exhibit 10.2 to the Company's Current Report on Form 8-K filed on October 10, 2006).                                                                             
|*10(a)(25) |  | Severance Compensation Agreement, by and between the Company and Beth A. Armstrong, dated August 22, 2006 (Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
 2006).                                                      

130

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|*10(a)(26) |  | Severance Compensation Agreement, by and between the Company and Christopher M. Reitz, dated August 28, 2006 (Exhibit 10(a)(30) to the Company's Annual Report on Form 10-K for the year ended December 31,
2006).                                                                                                                                              
|---------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*10(a)(27) |  | Form of Amendment to Severance Compensation Agreement dated November 7, 2007 (Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).                                                                                                                                                                            
|*10(a)(28) |  | Form of 2007 Senior Executive Restricted Stock Award (Time-Based Restriction), dated July 31, 2007 (Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2007).                                                                                                                                                           
|*10(a)(29) |  | Form of 2007 Senior Executive Restricted Stock Award (Performance-Based Restriction), dated July 31, 2007 (Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2007).                                                                                                                                                    
|*10(a)(30) |  | Asset Purchase Agreement by and among the Company, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1 to the Company's Current Report on
Form 8-K filed February 7, 2007).                                                                                                           
|*10(a)(31) |  | Partnership Interests Purchase Agreement by and among the Company, Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated February 6, 2007
(Exhibit 10.2 to the Company's Current Report on Form 8-K filed February 7, 2007).                                                                     
|*10(a)(32) |  | Iatan 2 and Common Facilities Ownership Agreement by and among Kansas City Power & Light Company, the Company, The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri
Joint Municipal Electric Utility Commission, dated as of May 19, 2006 (Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 14, 2006).
|12         |  | Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                                                             
|*14        |  | Code of Ethics (Exhibit 14 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004).                                                                                                                                                                                                                                                   
|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 Accounting Officer under Section 302.                                                                                                                                                                                                                                                                                                    
|32.1       |  | Certification of Chief Executive Officer under Section 906.                                                                                                                                                                                                                                                                                                     
|32.2       |  | Certification of Chief Accounting 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).                                                                                                                                            



131

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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 February 29, 2008.

| |  | 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 February 29, 2008.

|By: |  | /s/RICHARD C. GREENRichard C. Green                 |  | President, Chief Executive Officer and Chairman of
the Board of Directors (Principal Executive Officer)
|--- |  | --------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------
|By: |  | /s/BETH A. ARMSTRONGBeth A. Armstrong               |  | Senior Vice President and Chief Accounting Officer
(Principal Financial Officer)                       
|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/NICHOLAS J. SINGERNicholas J. Singer             |  | Director                                                                                               

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