10-K

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

FORM 10-K

(Mark One)
ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2006 or
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                            to                           

Commission file number: 1-03562

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 7.875% Quarterly Interest Bonds, due March 1, 2032 Premium Income Equity Securities, 6.75%, mandatorily convertible to common shares on September 15, 2007	New York Stock Exchange New York Stock Exchange New York Stock Exchange

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

        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.    ý

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

        Large accelerated filer    ý                        Accelerated Filer    o                        Non-accelerated Filer    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, 2006 as reported on the New York Stock Exchange, was approximately $1,179,115,910. 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 23, 2007
Common Stock, par value $1.00 per share	374,636,015
Documents Incorporated by Reference: Proxy Statement for 2007 Annual Shareholders Meeting	Where Incorporated: Parts II and III

INDEX

			Page
Part I
	Item 1	Business	5
	Item 1A	Risk Factors	21
	Item 1B	Unresolved Staff Comments	25
	Item 2	Properties	26
	Item 3	Legal Proceedings	26
	Item 4	Submission of Matters to a Vote of Security Holders	26
Part II
	Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
	Item 6	Selected Financial Data	28
	Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
	Item 7A	Quantitative and Qualitative Disclosures About Market Risk	66
	Item 8	Financial Statements and Supplementary Data	70
	Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	145
	Item 9A	Controls and Procedures	145
	Item 9B	Other Information	145
Part III
	Item 10	Directors, Executive Officers and Corporate Governance	145
	Item 11	Executive Compensation	145
	Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	145
	Item 13	Certain Relationships and Related Transactions, and Director Independence	145
	Item 14	Principal Accountant Fees and Services	146
Part IV
	Item 15	Exhibits, Financial Statement Schedules	147
Index to Exhibits			149
Signatures			152

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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 non-regulated, 340 MW electric generation "peaking" facility located in Clarksdale, Mississippi which is contractually controlled by Aquila Merchant.

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.

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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.

LIBOR—London Inter-Bank Offering Rate.

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.

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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, 2006, we had 2,456 employees in the United States, 1,095 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 unregulated energy activities operated by Aquila Merchant. All other operations are included in Corporate and Other, including costs that are not allocated to our operating businesses; our former controlling interest in a broadband company operating in Kansas City, Everest Connections, which was classified as "held for sale" prior to its sale on June 30, 2006 and reported in discontinued operations; and our former investment in the United Kingdom. Substantially all of our revenues are generated by our Electric and Gas Utilities.

        We have entered into an agreement to sell our Electric utility in Kansas and in 2006 sold our Gas utilities in Michigan, Minnesota, and Missouri, which results in these operations being reported as discontinued operations. Excluding discontinued operations, our Electric Utilities include 1,843 MWs of generation and 14,992 pole miles of electric transmission and distribution lines, and our Gas Utilities include 516 miles of intrastate gas transmission pipelines and 11,283 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated revenues from continuing and discontinued operations of $1,379.2 million and $489.1 million, respectively, in the year ended December 31, 2006, and had total assets in continuing and discontinued operations of $2.6 billion and $.3 billion, respectively, at December 31, 2006.

        Through 2004 our operations also included significant international utility investments and Merchant Services was a much larger component of our business. In 2002 we began to reposition our business to concentrate on our Electric and Gas utilities and reduce our financial obligations. As part of that repositioning, we sold all of our international investments and a substantial portion of our Merchant Services assets. Additionally, we wound down most of our Merchant Services energy trading portfolio. Our remaining Merchant Services group contractually controls the Crossroads Energy Center, a non-regulated domestic power generation facility, and owns our remaining wholesale energy trading portfolio. In 2006 we sold our Raccoon Creek and Goose Creek merchant power plants, which resulted in these operations being reported as discontinued operations. See Management's Discussion and Analysis for further discussion of our strategic and financial repositioning.

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. The companies expect that upon consummation of the Merger our shareholders will own approximately 27% of the outstanding common stock of Great Plains Energy, and the Great

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Plains Energy shareholders will own approximately 73% of the outstanding common stock of Great Plains Energy.

        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.

        Further information concerning the Merger and asset sales will be included in a merger proxy statement we will file with the SEC and mail to our shareholders. This proxy statement will also constitute a prospectus for the Great Plains Energy common stock to be issued to our shareholders in the Merger and be included in a registration statement on Form S-4 to be filed with the SEC by Great Plains Energy. See Note 20 to the Consolidated Financial Statements for additional information related to these transactions.

        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.

Access to Company Information and Officer Certifications

        The reports we file with the SEC are available free of charge at our website www.aquila.com as 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 2006 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, 2006 is included in Note 17 to the Consolidated Financial Statements.

I. Electric and Gas Utilities

        Electric Utilities generates, transmits and distributes electricity to 396,829 customers in our continuing operations in Colorado and Missouri and to 68,972 customers in our discontinued operations in Kansas. 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 66% of our electric customers are located in Missouri. Gas Utilities distributes natural gas to 515,760 customers in Colorado, Iowa, Kansas, and Nebraska. Approximately 65% of our continuing utility operations, based on the book value of our regulated assets, are located in Missouri.

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Electric Utilities

        As of December 31, 2006, our owned or leased interests in electric generation plants were as follows:

Unit			Location	Year Installed	Unit Capability (MW)	Fuel
Missouri:
	Sibley #1-3		Sibley	1960, 1962, 1969	508	Coal
	Ralph Green #3		Pleasant Hill	1981	71	Gas
	Nevada		Nevada	1974	20	Oil
	Greenwood #1-4		Greenwood	1975-1979	232	Gas/Oil
	KCI #1-2		Kansas City	1970	34	Gas
	Lake Road #1, 3		St. Joseph	1951, 1962	33	Gas/Oil
	Lake Road #2, 4		St. Joseph	1957, 1967	125	Coal/Gas
	Lake Road #5		St. Joseph	1974	68	Gas/Oil
	Lake Road #6-7		St. Joseph	1989, 1990	43	Oil
	Iatan 1		Iatan	1980	118	Coal
	Jeffrey #1-3		St. Mary's	1978, 1980, 1983	175	Coal
	South Harper #1-3		Peculiar	2005	315	Gas
Colorado:
	W.N. Clark #1-2		Canon City	1955, 1959	42	Coal
	Pueblo #6		Pueblo	1949	20	Gas
	Pueblo #5		Pueblo	1941, 2001	9	Gas
	AIP Diesel		Pueblo	2001	10	Oil
	Diesel #1-5		Pueblo	1964	10	Oil
	Diesel #1-5		Rocky Ford	1964	10	Oil
Total continuing operations					1,843
Kansas:
	Judson Large #4		Dodge City	1969	142	Gas
	Arthur Mullergren #3		Great Bend	1963	99	Gas
	Cimarron River #1-2		Liberal	1963, 1967	75	Gas
	Clifton #1-2		Clifton	1974	76	Gas/Oil
	Jeffrey #1-3		St. Mary's	1978, 1980, 1983	175	Coal
Total discontinued operations					567
		Total capability			2,410

        The following table shows Electric Utilities' overall fuel mix and generation capability for 2006:

Fuel Source (MW)		Continuing	Discontinued
Coal		843	175
Gas		449	316
Oil		93	—
Coal and gas		125	—
Gas and oil		333	76
	Total generation capability	1,843	567

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        At December 31, 2006, Electric Utilities owned or leased the electric transmission and distribution lines shown below:

Line Type—In Miles	Continuing	Discontinued
Electric transmission	2,131	2,500
Electric distribution	12,861	3,851

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

		2006			2005			2004
Sales (in millions)
	Residential	$	328.7		$	303.8		$	263.3
	Commercial		206.9			190.0			173.0
	Industrial		91.9			91.6			84.2
	Other		140.4			98.5			73.6
Total continuing electric operations			767.9			683.9			594.1
Total discontinued electric operations			188.8			190.9			165.2
Total		$	956.7		$	874.8		$	759.3
Volumes Generated and Purchased (GWh)
	Coal		5,463			5,248			5,275
	Gas		149			91			2
	Coal/Gas		521			611			686
	Gas/Oil		82			61			21
Total generated			6,215			6,011			5,984
Purchased			5,547			5,860			4,630
Total generated and purchased			11,762			11,871			10,614
Company use			(15	)		(15	)		(14	)
Line loss			(713	)		(691	)		(668	)
Total continuing electric operations			11,034			11,165			9,932
Total discontinued electric operations			2,304			2,311			2,431
Total			13,338			13,476			12,363
Volumes Sold (GWh)
	Residential		3,997			3,961			3,603
	Commercial		3,244			3,050			2,893
	Industrial		1,863			1,870			1,838
	Other		1,930			2,284			1,598
Total continuing electric operations			11,034			11,165			9,932
Total discontinued electric operations			2,304			2,311			2,431
Total			13,338			13,476			12,363

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		2006		2005		2004
Customers at Year End
	Residential		347,352		341,589		335,003
	Commercial		46,486		46,029		45,084
	Industrial		336		372		383
	Other		2,655		3,416		3,359
Total continuing electric operations			396,829		391,406		383,829
Total discontinued electric operations			68,972		68,920		68,817
Total			465,801		460,326		452,646
Continuing Operations Statistics—
Average annual volume per residential customer (kWh)			11,508		11,597		10,755
Average annual sales per residential customer		$	946	$	889	$	786
Average residential sales per kWh (cents)			8.22		7.67		7.31
Units of Fuel Used in Generation
	Coal—thousand tons		3,607		3,569		3,582
	Natural gas—Mmcf		3,548		2,120		782
Average Cost of Fuel
	Coal—per ton	$	29.91	$	24.97	$	23.34
	Natural gas—per Mcf		11.55		9.85		6.97

Gas Utilities

        At December 31, 2006, Gas Utilities owned the gas transmission and distribution lines shown below:

Line Type—In Miles	Continuing
Intrastate gas transmission pipelines	516
Gas distribution mains and service lines	11,283

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

		2006		2005		2004
Sales (in millions)
	Residential	$	381.5	$	400.7	$	334.6
	Commercial		144.6		156.7		124.5
	Industrial		26.6		27.3		25.0
	Transportation and other		28.7		21.6		22.4
Total continuing gas operations			581.4		606.3		506.5
Total discontinued gas operations			294.6		614.2		525.5
Total		$	876.0	$	1,220.5	$	1,032.0

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Volumes Sold (Mcf)
	Residential	23,462	34,922	34,331
	Commercial	10,666	14,886	14,230
	Industrial	5,342	3,399	3,789
	Transportation and other	44,950	42,580	41,341
Total continuing gas operations		84,420	95,787	93,691
Total discontinued gas operations		52,659	123,136	121,285
Total		137,079	218,923	214,976
Customers at Year End
	Residential	464,825	456,592	448,889
	Commercial	42,825	43,213	42,921
	Industrial	1,529	1,699	1,691
	Transportation and other	6,581	7,039	7,306
Total continuing gas operations		515,760	508,543	500,807
Total discontinued gas operations		—	414,556	409,309
Total		515,760	923,099	910,116

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	Peak
Gas Utilities	November through March
Electric 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 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.

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        Our regulated businesses produce, purchase and distribute power in three 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 2006, we generated approximately 53% of the power that we sold and we purchased the remaining 47% through long-term contracts or in the open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have Energy Cost Adjustment (ECA) clauses which serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, we currently do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our electric earnings can fluctuate more in Missouri than in our other electric rate jurisdictions. The Missouri Commission approved a settlement agreement in April 2004 for our electric operations that established our right to recover costs up to $13.98/Mwh in our St. Joseph Light & Power operations and $19.71/Mwh in our Missouri Public Service operations for a two-year period. If our actual costs were higher than those allowed costs, we could not recover the excess costs through rates. If our actual costs were less than those allowed costs, we would refund the difference to our customers, except to the extent actual costs were below $12.64/Mwh for our St. Joseph Light & Power operations and $16.65/Mwh for our Missouri Public Service operations. In the period after the rate increase went into effect, our actual costs exceeded the allowed costs for our Missouri Public Service operations. However, in connection with our settlement of the Missouri electric rate case in February 2006, we agreed to refund $1.0 million to our St. Joseph Light & Power customers and terminate our interim energy charge when new base rates became effective on March 1, 2006.

        On July 14, 2005, new legislation in Missouri established a means for recovering prudently-incurred fuel and purchased power costs without going through a general rate case. This legislation, which also permits the recovery of government-mandated environmental investments, has been implemented through the issuance of rules by the Missouri Commission. The initial filing of fuel and environmental tariffs must be made in connection with a general rate proceeding. The Missouri Commission established rules subsequent to the conclusion of our most recent rate decision in March 2006. These rules became effective on January 30, 2007 and we expect these provisions to be considered in our current electric rate case, which we filed in July 2006. We cannot estimate with certainty the impact that implementing these provisions may have on our financial results and financial condition.

        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:

•

pledge for the benefit of our current and prospective lenders any regulated utility assets presently devoted to serving Kansas retail customers;

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•

invest any money in new non-utility businesses or invest in any existing business except in the ordinary course of business or to fulfill an existing financial, contractual or operational obligation;



•

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;



•

pay any dividends; or



•

enter into any contract or agreement that: (1) alienates, conveys or creates an interest in our assets (e.g., through issuing stock or debt or arranging other securitization), including any agreement to modify an existing obligation to alienate, convey or create an interest in our assets, or (2) relates 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.

        The following summarizes our recent rate case activity:

In millions	Type of Service	Date Requested	Date Effective	Amount Requested		Amount Approved
Kansas (1)	Electric	6/2004	4/2005	$	16.4	$	8.0
Kansas (2)	Gas	11/2004	6/2005		6.2		2.7
Iowa (3)	Gas	5/2005	4/2006		4.1		2.9
Missouri (4)	Electric	5/2005	3/2006		78.6		44.8
Missouri (4)	Steam	5/2005	3/2006		5.0		4.5
Missouri (5)	Electric	7/2006	Pending		118.9		Pending
Kansas (6)	Gas	11/2006	Pending		7.2		Pending
Nebraska (7)	Gas	11/2006	Pending		16.3		Pending

(1)

In connection with the settlement, our ECA provision was modified to allow the pass through of SO₂ emission allowance costs to customers.



(2)

The Kansas gas settlement included $244,000 per year for three years for a pipe replacement program.



(3)

Under Iowa regulations, we instituted interim rates, subject to refund, totaling approximately $1.7 million in May 2005. On March 1, 2006, the IUB issued an order approving a $2.9 million rate increase, including recovery of rate case costs. The order denied a settlement provision that would have provided a more timely recovery mechanism for investments in distribution system integrity. Final rates became effective March 17, 2006.



(4)

The Missouri electric settlement terminated the interim energy charge established in our 2003 rate case filing and required a $1.0 million refund to our St. Joseph Light & Power customers as part of the termination. The settlement also established the value of our South Harper peaking facility at approximately $140 million, resulting in an additional $4.4 million impairment of the plant's turbines. See Note 5 to the Consolidated Financial Statements for further discussion. The settlement was approved by the Missouri Commission on February 23, 2006, and the new rates became effective on March 1, 2006. In addition, in February 2006, we settled the Missouri steam rate case for a $4.5 million

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rate increase. This settlement includes a provision for sharing 80% of fuel cost variability from the established base fuel rates. It was approved by the Missouri Commission in February 2006 and the new rates became effective on March 6, 2006.

(5)

On July 3, 2006, we filed for a $94.5 million rate increase, or 22.0%, in our Missouri Public Service territory and a $24.4 million increase, or 22.1%, in our St. Joseph Light & Power territory. These increases were requested to recover increases in the cost of fuel and purchased power capacity and increased operating costs. The amount of the request is based, among other things, on a return on equity of 11.5% and an adjusted equity ratio of 47.5%. In addition, we requested the implementation of a fuel adjustment clause.

Our original filing reflected flow-through power capacity costs equivalent to the estimated revenue requirement for the purchase of the Aries plant, for which we had been named the stalking horse bidder in an auction process run on behalf of creditors of Calpine Corporation. However, the bidding reached a point at which it did not make economic sense for Aquila to continue in the process. Consequently, we secured lower cost short-term purchased power contracts.

The Missouri Commission staff's case was filed January 18, 2007. The staff recommended a return on equity in the range of 9% to 10.25% which, together with other recommendations of the staff, would yield a rate increase in the range of $45.9 million to $56.4 million. The staff's case included the effects of not acquiring Aries, as discussed above. The staff also recommended implementing an interim energy charge instead of a fuel adjustment clause. Rebuttal testimony was filed on February 20, 2007. Surrebuttal testimony will be filed by all parties on March 20, 2007, following the filing on February 27, 2007 of the staff's revised position based upon a "true-up" of major revenue requirement issues through December 31, 2006. Evidentiary hearings are scheduled to begin April 2, 2007. We expect the Commission to rule on our request in May 2007, with approved rate changes taking effect no later than June 1, 2007.

(6)

On November 1, 2006, we filed for a $7.2 million rate increase, or 5.1%, in our Kansas natural gas service territory. Also included in the filing is a redesign of the rate structure to shift most fixed cost of service recovery from the usage-based delivery charge to a flat monthly fee for service and system costs. The change in rates is expected to take effect in June 2007.



(7)

In November 2006, we filed for a $16.3 million rate increase, or 7.7%, in our Nebraska natural gas service territory. Interim rates were implemented February 15, 2007, and the Nebraska Commission has up to 240 days to analyze the rate request. If the interim rates are higher than final approved rates, the difference plus interest will be refunded or credited to customers.

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, Kansas 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.

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        The FERC order approving our merger with St. Joseph Light & Power Company contained a stipulation requiring us to file with the FERC a plan to join an RTO. At that time, MISO was the only FERC-approved RTO in the Midwest. Thus, we informed the FERC that our Kansas and Missouri facilities planned to join MISO, subject to obtaining the necessary state regulatory approvals.

        With respect to our Missouri facilities, in 2001 we submitted an application to the FERC and to the Missouri Commission to join MISO and transfer operational control of our transmission system to MISO. The FERC application was approved, but the application to the Missouri Commission was dismissed in early 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 June 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, requested and were granted approval by the Missouri Commission to become members of the Southwest Power Pool (SPP). We are currently conducting a cost/benefit study to determine whether to join MISO, SPP or neither. We do not expect a significant impact to our financial statements upon participation.

        In Kansas, we submitted an application to join the SPP RTO in August 2005 along with the other FERC jurisdictional utilities in Kansas. The Kansas Commission order approving our participation in the SPP RTO and Energy Imbalance Services market was issued on September 19, 2006.

        Effective February 8, 2006, the Energy Act repealed the Public Utility Holding Company Act of 1935, as amended (PUHCA), and gave the FERC access to books and records of holding companies and other affiliate companies within a holding company system as the FERC determines it is necessary for the protection of utility customers. The Energy Act also authorized state regulatory commissions to obtain access to the books and records of holding companies, as well as their affiliates, if access to the books and records is necessary for the effective discharge of the FERC's responsibilities. The Energy Act has not had a material impact on our operations, as we were not a public utility holding company under PUHCA and we were otherwise subject to extensive "books and records" review by various state and federal regulatory authorities previously.

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:

•

the protection of air and water quality;



•

the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos;



•

the protection of plant and animal species and minimization of noise emissions; and

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•

safety and health standards, practices and procedures that apply to the workplace and to the operation of our facilities.

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 are currently completing the required studies and working with state and federal agencies involved with the Missouri River regulations to determine compliance options and benefits to Missouri River fish populations for these two plants. 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.

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.

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Multi-pollutant regulations

        Approximately 53% of our continuing 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. The rules are being challenged in the courts. We are completing a study to determine the best options for compliance with CAIR and CAMR and participating in state work groups that will adopt the final Federal regulations. 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. We anticipate additional capital costs to comply with the CAIR and CAMR rules.

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.

        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 84% owned by Westar and operated exclusively by Westar. We have a 16% interest in the Jeffrey Energy Center and are generally responsible for this portion of its operating costs and capital expenditures. The electric generation plants we own or lease are described in the table at Item 1, page 7. 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. In either case, we could potentially be responsible for up to 16% of those costs, including the 8% lease interest held by our Kansas electric utility which is expected to be sold by April 1, 2007, and is included in discontinued operations.

        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 will be responsible for 18% of the costs of the additional air pollution control equipment for Iatan 1.

        Our capital expenditure forecasts include $215.2 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.

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        In 2006, we had a multi-disciplinary team perform a comprehensive review of all our greenhouse gas impacts. Our February 2007 integrated resource plan for Missouri incorporates the estimated impacts of 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 is set to expire in 2007. Therefore, we have begun permitting of a new landfill for this waste disposal and beneficial utilization of additional fly ash. We estimate that we will incur approximately $3 million of capital expenditures in 2007 to close the current landfill and 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, 2006, we estimate probable costs of future investigation and remediation on our identified MGP sites, PCB sites and retained liabilities to be $3.5 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 $4.9 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.

        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 in the geographic area in which the plant is located. The table below shows information about the Crossroads plant as of December 31, 2006:

Plant & Location	Location	Type of Investment	Capacity (MW)	Heat Rate	Date in Service
Crossroads Energy Center	Mississippi	Contractually Controlled	340	11.9	September 2002

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        Although we have exited the wholesale energy trading business, we were previously one of the largest marketers and traders of wholesale natural gas, electricity and other commodities in North America and Western Europe. We stopped wholesale energy trading during 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 other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies in the development and operation of energy-producing projects. There is an oversupply of power in the geographic area in which the Crossroads plant is located, resulting in strong price competition for electric power. Often our marginal cost of producing power exceeds the marginal costs of other generators or normal market prices. Our Crossroads plant, which is a peaking plant, is generally dependent on outages and transmission difficulties occurring at generation facilities and distribution networks of others or short-term spikes in demand for power resulting from extreme weather. Those events, if they occur, can create short-term opportunities for 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. The plant has not operated since August 2005.

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 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.

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Our Executive Team

Name	Age at December 31, 2006	Position
Richard C. Green (Rick)	52	President, Chief Executive Officer and Chairman (our principal executive officer)
Keith G. Stamm	46	Senior Vice President and Chief Operating Officer
Beth A. Armstrong	44	Vice President and Chief Accounting Officer (our principal financial officer)
Leo E. Morton	61	Senior Vice President and Chief Administrative Officer
Christopher M. Reitz (Chris)	40	Senior Vice President, General Counsel and Corporate Secretary
Jon R. Empson	61	Senior Vice President, Regulated Operations
Scott H. Heidtbrink	45	Vice President, Power Generation and Energy Resources

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

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

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

        Keith joined our Company in 1983 as a staff engineer at the Sibley Generating Station. Between 1985 and 1995, he held various operating positions. In 1995, Keith was promoted to Vice President, Energy Trading and in 1996, to Vice President and General Manager, Regulated Power. In 1997, he became the Chief Executive Officer of United Energy Limited, an affiliated electric distribution company that was listed on the Australian Stock Exchange in 1998. From January 2000 to November 2001, he served as Chief Executive Officer of what is now Aquila Merchant. In November 2001, he was appointed President and Chief Operating Officer of what is now our Electric and Gas Utilities. In October 2002, Keith became Chief Operating Officer of Aquila, Inc.

Beth A. Armstrong (B.S., Business Administration, Southeast Missouri State University)

        Beth joined our Company in 1991 as Manager of Financial Reporting and Property Accounting for our Missouri Public Service division. Between 1991 and July 2005, she served in various accounting and financial analysis positions, including Controller of Missouri Public Service and analytical positions within Aquila Merchant. In July 2005, she was appointed Vice President, Controller of the Company. In July 2006, Beth was appointed Vice President and Chief

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Accounting Officer. Prior to joining the Company, Beth served as an audit manager with Price Waterhouse LLP.

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

        Leo joined our Company in 1994 as Vice President, Performance Management. He was appointed Senior Vice President in 1995 and Senior Vice President, Human Resources and Operations Support in 1997. In 2000, he was named Senior Vice President and Chief Administrative Officer. Prior to working for us, Leo held executive and management positions in manufacturing and engineering for AT&T beginning in 1973.

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

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

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

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

Scott H. Heidtbrink (B.S., Electrical Engineering, Kansas State University)

        Scott joined our Company in 1987 as a field engineer at our Lee's Summit, Missouri service center. He has held various engineering, field and customer operations management positions involving both gas and electric utility operations. Prior roles with the Company include State President and General Manager—Kansas from 1994 to 1997; Vice President, Network Management from 1998 to 2000; Vice President, Aquila Gas Operations in 2001; and Vice President, Kansas/Colorado Gas from 2002 to 2004. Scott led the deployment of Six Sigma into our utility operations in 2004 and 2005 and is a certified Six Sigma Black Belt. In January 2006, Scott was appointed Vice President, Power Generation and Energy Resources.

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Item 1A. Risk Factors

Operating Risks

Our strategic repositioning plan depends on our ability to raise adequate proceeds from the Kansas electric asset sale and retire a sufficient amount of debt and other long-term liabilities with the net sale proceeds.

        In March 2005, we announced our strategic repositioning plan. Asset divestitures, including the sale of our Kansas electric utility property, were a key element of our plan. We have signed definitive agreements to sell our electric utility operations in Kansas for a base purchase price of $249.7 million. We anticipate using the net proceeds generated by this divestiture to retire debt and other obligations, and to fund capital expenditures, including rate-base investments required to satisfy our long-term power generation and transmission needs and comply with environmental rules and regulations. On February 23, 2007, the Kansas Commission issued an order approving the settlement agreement signed in connection with the sale of our Kansas electric operations. We expect this transaction to close by April 1, 2007.

        If we cannot complete this asset sale, or if we are not able to retire a principal amount of debt sufficient to reduce our interest expense to a level that can be satisfied by the cash flow generated by our remaining utility operations, we will continue to have a cash flow shortfall. We may also need to explore alternatives with respect to financing the significant capital expenditures anticipated in connection with environmental upgrades and compliance, as well as capital expenditures generally required to continue to provide safe and reliable service to our remaining utility customers.

We must sustain the reduced level of corporate costs.

        In 2005, we allocated $42.3 million of operating costs, comprised of corporate overhead and central services, to our utility divisions held for sale. During 2006, we eliminated the majority of these costs following the sale of the Michigan, Minnesota and Missouri gas operations. Our 2007 plan includes a $39.5 million reduction in corporate costs compared to 2005. A portion of the cost reductions were achieved in non-allocated corporate costs. The remaining corporate costs have been reallocated to our remaining utilities. There can be no assurances that we will be successful in our efforts to sustain these cost reductions and/or recover the remaining costs in rates in our continuing utility operations.

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 our Crossroads merchant peaking power plant. 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 "B2" (Stable Outlook) by Moody's, and "B" (Positive Outlook) 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, 2006, we had posted $265.1 million of collateral (in the form of cash or letters of credit) with counterparties.

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Our ability to further reposition our Company as a regulated utility could be restricted by the terms of our finance agreements and our regulatory orders.

        Our credit facilities and regulatory orders contain restrictive covenants that could negatively impact our ability to continue to implement our strategic plan. For example, we must generally obtain the approval of the Kansas Commission prior to selling assets, and certain negative covenants contained in our credit facilities limit our ability to sell assets (or use the sale proceeds for various purposes) unless certain conditions are satisfied.

        The terms of our credit facilities and regulatory orders also 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.

Our utility operations are subject to risks associated with higher fuel and purchased power prices, and we may not be able to recover costs of fuel and purchased power.

        Our regulated utilities produce, purchase and distribute power in three states and purchase and distribute natural gas in four states. Generally, the regulations of the states in which we operate allow us to pass through changes in the costs of natural gas to our natural gas utility customers through PGA provisions in the applicable tariffs. 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 match the actual cost we incurred. There is, however, a timing difference between our purchases of natural gas and the ultimate recovery of these costs.

        In our continuing regulated electric business, we generated approximately 53% of the power utilized by our utility customers and we purchased the remaining 47% through long-term contracts or in the open market in 2006. The regulatory provisions for recovering energy costs vary by state. In Kansas and Colorado, we have ECAs that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, which is our largest service area, we currently do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for fuel we use in generating electricity or for purchased power (i.e., a fuel adjustment mechanism). These costs could substantially reduce our operating results.

        We filed a rate case in July 2006 to implement a mechanism that will allow us to fully recover these costs; however, even if we are successful, we will not realize any rate relief until June 2007. Our inability to pass through fuel and purchased power costs to our Missouri electric customers may also adversely affect our ability to satisfy the financial covenants in our credit agreements, which if breached could cross default our other debt instruments.

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

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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.

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

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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. 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 Circuit Court of Cass County 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 is expected to hear oral arguments in May 2007. If we exhaust all of our legal options and are ordered to remove the plant and substation, we estimate the cost to dismantle the plant and substation to be up to $20 million based on an engineering study. Significant additional costs would be incurred to store the equipment, secure replacement power and/or build the plant and substation on other sites. We cannot estimate with certainty the total amount of these 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 cost exceeds the amount allowed for recovery in rates.

We have several matters pending before the Internal Revenue Service, the negative outcome of which could materially impact our financial condition.

        All of our federal income tax returns are examined by the IRS. Currently, our federal income tax returns for the years 1998-2004 are under audit. As of December 31, 2006, we had approximately $377.3 million of cumulative tax provisions for tax deduction or income positions that we believe are proper but for which it is reasonably likely that these deductions or income positions will be challenged upon audit by the IRS. The timing of the resolution of these issues is uncertain. If our positions are not sustained, we may be required to utilize our capital loss and net operating loss or alternative minimum tax credit carryforwards and/or make cash payments plus interest.

Risks Relating to the Merger

The Merger and asset sales may not be completed, which could adversely affect our business operations and stock price.

        We will not be able to complete the Merger and the associated asset sales until we obtain regulatory approvals from the Missouri Commission, the Kansas Commission, the IUB, the Colorado Public Utilities Commission, the Nebraska Public Service Commission, and the FERC, as well as obtain regulatory clearance under the Hart-Scott-Rodino Antitrust Improvements Act. If these regulatory approvals and clearances 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 and the associated asset sales are 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 between signing of the merger agreement and closing. Shareholder approval of the Merger and the issuance of

24

Great Plains Energy common stock in connection with the Merger is also required from our shareholders and Great Plains Energy's shareholders, respectively.

        Furthermore, 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 failure of the Merger to close could have a material adverse effect on the financial results of operations or the trading price of our common stock.

We will be 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 and the associated asset sales on employees and customers may have an adverse effect on us, regardless of whether the transactions are eventually 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.

We will incur significant costs in connection with the Merger and associated asset sales.

        We expect to incur significant costs (primarily investment banking, legal and employee retention costs) in connection with the Merger and associated asset sales, regardless of whether or not the transactions are completed. We will expense these costs as they are incurred. In 2006, we incurred approximately $2.3 million of costs (primarily investment banking and legal costs) related to these transactions. In February 2007, we incurred fees payable to our financial advisors of $6.1 million in connection with the signing and announcement of the merger agreement. In February 2007, we also executed retention agreements totaling $8.4 million with numerous non-executive employees to mitigate employee attrition prior to the closing of the Merger. The agreements will be paid on the earlier of the closing of the Merger or January 31, 2008. We cannot at this time estimate the total costs to be incurred by the Company prior to consummation of the Merger and the associated asset sales. In addition, if the Merger is completed, the combined company will incur significant transaction costs, such as fees payable to our financial advisors, amounts payable to employees under change-in-control agreements, and employee severance costs.

Item 1B. Unresolved Staff Comments

        None.

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Item 2. Properties

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

        In addition, we lease or own various real property and facilities relating to our regulated and non-regulated electricity generation assets. Our principal assets are generally described under "Electric and Gas Utilities" and "Merchant Services."

Item 3. Legal Proceedings

        See Note 18 to the Consolidated Financial Statements.

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

        There were no matters submitted to a vote of security holders in the fourth quarter of 2006.

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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 23, 2007, we had approximately 25,700 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 23, 2007, the last reported sale price of the common stock on the NYSE was $4.16 per share.

Market Price Per Share

	High		Low		Cash Dividends
2006 Quarters
Fourth	$	4.85	$	4.29	—
Third		4.77		4.12	—
Second		4.50		3.91	—
First		4.06		3.45	—
2005 Quarters
Fourth	$	4.07	$	3.29	—
Third		4.14		3.50	—
Second		3.87		2.90	—
First		4.24		3.24	—

        As part of our repositioning plan, our Board of Directors in the third quarter of 2002 suspended the payment of dividends on our common stock. Our Board of Directors regularly evaluates our common stock dividend policy. The determination whether we will pay dividends is influenced by many factors, including, among other things, our overall financial condition and cash flows, legal and contractual restrictions on the payment of dividends, and general economic and competitive conditions. We are bound by certain agreements and orders that limit our ability to pay dividends. For example, our $110 million five-year unsecured revolving credit facility and Iatan construction facility prohibit us from paying dividends if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by S&P. In addition, an order of the Kansas Commission prohibits us from paying any dividends without its approval. We can make no determination at this time as to whether, or when, we will begin to pay dividends in the future.

        The information regarding our stock performance graph will appear in our 2007 definitive proxy statement and is hereby incorporated by reference in this Annual Report on Form 10-K.

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Item 6. Selected Financial Data

In millions, except per share amounts		2006			2005			2004			2003			2002
Sales		$	1,369.6		$	1,314.1		$	971.0		$	983.1		$	1,496.0
Gross profit			488.0			450.4			249.8			303.6			329.9
Loss from continuing operations			(282.0	)(a)		(158.0	)(b)		(348.3	)(c)		(356.5	)(d)		(1,597.5	)(e)
Basic and diluted loss per common share—
	Continuing operations		(.75	)		(.40	)		(1.35	)		(1.83	)		(9.88	)
Cash dividends per common share			—			—			—			—			.775
Total assets			3,472.4			4,630.7			4,777.3			7,719.1			9,319.1
Short-term debt			—			12.0			—			—			287.8
Long-term debt (including current maturities)			1,405.6			1,979.5			2,366.4			2,706.0			2,624.8
Common shareholders' equity			1,306.1			1,309.9			1,130.5			1,359.3			1,607.9

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

        (a)   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.

        (b)   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. and the Red Lake gas storage development project.

        (c)   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 the BAF power partnership that sold its cogeneration facility.

        (d)   Included in loss from continuing operations for the year ended December 31, 2003 are (a) a $105.5 million termination payment regarding our 20-year tolling agreement for the Acadia power plant; (b) an $87.9 million impairment charge on our equity method investments in 12 independent power plants; and (c) $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.

        (e)   Included in loss from continuing operations for the year ended December 31, 2002 are (a) a $696.1 million impairment charge on our investment in Quanta Services; (b) a $247.5 million impairment charge on our investment in Midlands Electricity in the United Kingdom; (c) a $127.2 million impairment charge on our investment in Multinet Gas and AlintaGas in Australia; (d) a $29.8 million impairment charge related to our investments in Everest Connections and various communications projects; (e) a $181.2 million write-down of Merchant Services' goodwill; (f) other impairment charges and losses on sale of assets of $91.9 million; and (g) $210.2 million of restructuring charges from our exit from the wholesale energy trading business and the restructuring of our utility business. We also recorded a $130.5 million gain on the sale of our shares of UnitedNetworks in New Zealand.

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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 64 and Risk Factors beginning on page 21.

Strategic and Financial Repositioning Overview

Pending Merger

        We have entered into a merger agreement with Great Plains Energy, which is discussed in Note 20 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 regulated utility growth strategy. The key elements of our remaining repositioning initiatives are to:

•

Complete the pending sale of our Kansas electric utility assets.



•

Significantly reduce our debt levels and interest expense.

        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.

Strengthen Credit Profile

        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.

        In 2006, we completed a cash tender offer for $350 million of senior notes and exited the Elwood tolling contract for $218 million in June 2006 using the proceeds from the sale of the Illinois peaking power plants and our Michigan and Missouri gas operations. In September 2006, we elected to prepay the remaining $210 million outstanding on our five-year term loan. We also expect to use the proceeds from our Kansas electric asset sale to retire debt and reduce interest expense. We have not made a final determination of which debt will be retired. The particular debt instruments to be retired will depend upon market conditions, the market price of the particular debt instrument, the call provisions, the remaining life of the instrument, our short term capital needs and the timing of the receipt of the sales proceeds. We intend to apply the sales proceeds in a manner which maximizes the improvement to our credit profile and cash flow.

Historical Review of Repositioning Efforts

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

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        As part of this repositioning, we have sold or wound-down a number of operations since 2002 to generate cash to reduce debt and eliminate other long-term obligations. Significant repositioning efforts include:

•

Substantially completed the wind-down of our Merchant Services trading portfolio;



•

Sold almost all of our Merchant Services assets, including gas gathering and processing assets in Texas and Oklahoma, gas storage facilities in both North America and the United Kingdom, investments in independent power plants, two peaking power plants in Illinois, and a merchant loan portfolio;



•

Sold our 38% investment in Quanta Services, Inc.;



•

Sold our investments in regulated utility operations in Australia, Canada, New Zealand and the United Kingdom;



•

Exited other merchant obligations, such as tolling obligations and four long-term natural gas supply contracts;



•

Sold Everest Connections, our telecommunication business serving the Kansas City area;



•

Sold our regulated gas utility operations in Michigan, Minnesota and Missouri; and



•

Entered into an agreement to sell our regulated Kansas electric operations.

        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 $1.4 billion at December 31, 2006.

        As a result of these repositioning efforts, we have reduced our total staffing from 5,989 at the end of 2001 to 2,456 at the end of 2006, 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 $127 million since 2002.

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 peak working capital needs for our utility operations to

30

be up to $200 million. 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, 2006
		In millions
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		108.3
$50 Million Unsecured Revolving Credit and Letter of Credit Facility	December 19, 2007		50.0		48.1

(1)

Borrowings under these facilities must be repaid within 364 days unless we obtain regulatory approval to incur long-term indebtedness under these facilities.

Cash Flows

        Our Statement of Cash Flows for the three years ended December 31, 2006 includes the cash flows related to our discontinued operations. Included in our cash provided from operating activities in 2006 is approximately $158.5 million of cash flows associated with our discontinued operations. Our cash from investing activities in 2006 includes $996 million of cash received on the sale of our assets offset by $28.1 million of additions to utility plant. Our cash flows from financing activities for 2006 include $.8 million for the retirement of long-term debt related to our discontinued operations.

        We do not expect the disposition of our discontinued operations and their related cash flows to have a material adverse effect on our liquidity and capital resources as we expect to utilize the proceeds of these sales to retire outstanding long-term debt and other obligations, thereby reducing our net financing costs. In addition, as a result of the sale of our Michigan, Minnesota and Missouri gas utilities, our winter peak working capital requirements have been significantly reduced. In turn, our liquidity position has been strengthened.

Cash Flows from Operating Activities

        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 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.

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        Our positive 2005 operating cash flows were driven primarily by the return of $88.2 million of funds on deposit as a result of the replacement of cash deposits with letters of credit. The increase in natural gas prices required our merchant and utilities counterparties to post an additional $54.6 million of collateral with us. Offsetting these increases were the use of $33.3 million of cash to inject higher cost natural gas into storage for the winter heating season, a 2005 income tax payment of $30.9 million related to the sale of our Canadian utilities business in 2004, and the $28.0 million settlement with Enron in connection with the netting of amounts owed under various contracts at the time of Enron's bankruptcy filing in 2001.

        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, retiring debt and completing the wind-down of our Merchant Services business.

Cash Flows from Investing Activities

        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.

        The decrease in cash provided from (used for) investing activities in 2005 compared to 2004 was primarily the result of the 2004 receipt of cash proceeds on the sale of our former investments in independent power plants and Canadian utility businesses.

Cash Flows from Financing Activities

        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.

        Cash flows used for financing activities decreased in 2005 compared to 2004, primarily due to funds used in 2004 to terminate four of our long-term gas contracts, and retire debt associated with our acquisition of Midlands Electricity, our 7.00% and 6.875% senior notes, our three-year secured term loan and debt related to our Canadian utility operations. Partially offsetting this decrease was the issuance of common stock and the PIES which generated approximately $446.6 million in August 2004.

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, 2006, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

Agency	Rating	Commentary
Moody's	B2	Stable Outlook
S&P	B	Positive Outlook
Fitch	B+	Stable Outlook

        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

32

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.

        In February 2007, in conjunction with the announcement of our pending merger with Great Plains Energy, the rating agencies reviewed our ratings and took the following actions:

•

S&P affirmed our ratings and credit watch positive outlook,



•

Moody's placed our ratings on review for possible upgrade, and



•

Fitch affirmed our ratings and assigned a ratings watch positive outlook.

        We discuss the pending merger in more detail in Note 20 to the Consolidated Financial Statements.

Collateral Positions

        As of December 31, 2006, we had posted cash collateral for the following:

In millions
Trading positions	$	36.9
Utility cash collateral requirements		70.3
Other		.7
Total Funds on Deposit	$	107.9

        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.

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Contractual Obligations

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

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

In millions		2007		2008		2009		2010		2011		Thereafter		Total
Continuing Operations—
Short-term and long-term debt obligations (a)		$	17.1	$	2.5	$	71.0	$	1.9	$	337.5	$	973.0	$	1,403.0
Interest on long-term debt (b)			146.5		146.1		145.3		140.5		119.6		631.4		1,329.4
Long-term gas contracts			23.9		2.0		—		—		—		—		25.9
Lease and other obligations			11.8		9.7		6.5		5.1		4.3		8.8		46.2
Merchant gas transportation obligations			6.2		6.2		6.2		6.2		5.6		17.0		47.4
Non-qualified pension and other post-retirement benefits (c)			6.9		7.5		8.2		8.6		8.5		35.5		75.2
Regulated purchase obligations			251.7		203.6		167.5		169.3		157.0		224.8		1,173.9
	Total Continuing Operations		464.1		377.6		404.7		331.6		632.5		1,890.5		4,101.0
Discontinued Operations—
Lease and other obligations			11.3		12.7		13.4		13.2		13.1		45.4		109.1
Regulated purchase obligations			39.2		39.4		32.2		24.9		25.7		126.2		287.6
	Total Discontinued Operations		50.5		52.1		45.6		38.1		38.8		171.6		396.7
Total		$	514.6	$	429.7	$	450.3	$	369.7	$	671.3	$	2,062.1	$	4,497.7

(a)

Long-term debt obligations maturing in 2007 do not include the non-cash, mandatory conversion of $2.6 million of PIES to common stock on September 15, 2007.



(b)

Interest on long-term debt is estimated based on scheduled maturity dates of debt outstanding at December 31, 2006 and does not reflect anticipated early redemptions, tenders or exchanges or possible reductions due to improved credit ratings. Variable rate interest obligations are estimated based on rates as of December 31, 2006.



(c)

Includes total estimated contributions for non-qualified pension benefits and other post-retirement benefits continuing and discontinuing operations as described in Note 16 to Consolidated Financial Statements.

Regulated business purchase obligations

        In 2006, our continuing electric utility operations generated 53% 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.

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Long-Term Gas Contracts

        We accounted for the advance cash payments we received under these contracts as liabilities. We reduce our obligation for these long-term gas contracts as the gas is delivered to the customer under the units of revenue method. If we were to default on these obligations, or were unable to perform on them, we would be required to pay the issuers of the surety bonds or the counterparties on these arrangements approximately $27.0 million. This amount is greater than the long-term gas contract balance on our Consolidated Balance Sheet due to our use of the units of revenue method versus a present value method applied under the default provisions of the contractual agreements. We do not intend to terminate these remaining 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, we incurred approximately $2.3 million of costs (primarily investment banking and legal costs) relating to these transactions, and in February 2007, we incurred fees payable to our financial advisors of $6.1 million in connection with the signing and announcement of the merger agreement. In February 2007, we also executed retention agreements totaling $8.4 million with numerous non-executive employees to mitigate employee attrition prior to the closing of the Merger. The agreements will be paid on the earlier of the closing of the Merger or January 31, 2008. See Note 20 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 December 31, 2006, 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.

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 achieved the operating targets related to these ownership units. The holders of these ownership units are disputing our conclusion that we have 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 of 9.5 million ownership units have also notified us that they intend to exercise their option to sell their 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.

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Capital Expenditures

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

				Estimated Future Cash Requirements
		Actual 2006
In millions				2007		2008		2009
Electric Utilities		$	130.6	$	284.5	$	409.2	$	362.0
Gas Utilities			33.2		46.5		43.7		41.8
Corporate and Other			12.0		10.7		8.3		6.6
Total Continuing Operations			175.8		341.7		461.2		410.4
Discontinued Operations			36.3		—		—		—
	Total capital expenditures	$	212.1	$	341.7	$	461.2	$	410.4

Iatan 2

        Our power supply plan indicates the need for additional base-load capacity in Missouri after 2009. KCPL is developing Iatan 2, an 850 MW coal-fired electric generating facility which is planned for commercial operation in 2010. Effective June 12, 2006, we entered into the Iatan Unit 2 and Common Facilities Ownership Agreement (the Ownership Agreement) with KCPL, The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri Joint Municipal Electric Utility Commission. The Ownership Agreement provides for the construction, ownership and operation of Iatan 2 adjacent to the existing Iatan electric generation station located in Platte County, Missouri. We will own an 18% undivided interest in Iatan 2, which will be constructed and operated by KCPL. We will reimburse KCPL for our pro rata share of the construction, operating and maintenance costs of, and will be entitled to the energy from our pro rata share of, Iatan 2 generating capacity. The capital requirements included in the table above for this participation, including AFUDC, are estimated as follows: 2007—$92.7 million, 2008—$138.2 million, and 2009—$78.7 million.

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, NO_X and mercury. We completed engineering studies in 2006 that evaluated costs and likely controls for compliance with CAIR, BART and CAMR. For our Missouri electric operations, we estimate that probable capital expenditures through 2009 will be approximately $215.2 million based on engineering bids received in 2006. Costs have been increasing due to a number of factors including higher material prices and a shortage of labor needed in the power sector. At this point we are not able to reasonably estimate if additional costs may be incurred. If our Kansas electric utility is not sold, our total estimated probable capital expenditures would be approximately $242 million. We believe these costs would likely be allowed for recovery in future rate cases.

Combustion Turbine

        We filed an Integrated Resource Plan with the Missouri Commission in February 2007 which included the construction of a combustion turbine plant between 2008 and 2010. The estimated capital expenditures listed above include approximately $156 million of the estimated total cost of $186 million to complete this project.

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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. 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 20 million shares of preferred stock. Of the 400 million shares of common stock authorized to be issued, 385 million shares have either been issued or reserved for issuance in connection with the conversion of our PIES or pursuant to employee compensation plans. Accordingly, unless our certificate of incorporation is amended with the approval of our shareholders, our ability to raise capital through the sale of common stock is severely restricted.

FINANCIAL REVIEW

        This review of performance is organized by business segment, reflecting the way we managed our business during the periods covered by this report. Each business group leader is responsible for operating results down to earnings before interest, 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 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 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.

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        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,
In millions, except per share amounts		2006			2005			2004
Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization:
Electric Utilities		$	141.9		$	147.7		$	130.3
Gas Utilities			44.2			33.6			34.9
Total Utilities			186.1			181.3			165.2
Merchant Services			(244.7	)		(22.6	)		(416.7	)
Corporate and Other			(27.6	)		(103.2	)		(23.8	)
Total EBITDA			(86.2	)		55.5			(275.3	)
Depreciation and amortization expense			103.9			106.4			102.8
Interest expense			159.2			150.2			184.5
Income tax benefit			(67.3	)		(43.1	)		(214.3	)
Loss from continuing operations			(282.0	)		(158.0	)		(348.3	)
Earnings (loss) from discontinued operations, net of tax			305.9			(72.0	)		55.8
Net income (loss)		$	23.9		$	(230.0	)	$	(292.5	)
Diluted earnings (loss) per share:
	Continuing operations	$	(.75	)	$	(.40	)	$	(1.35	)
	Discontinued operations		.81			(.20	)		.22
	Net income (loss)	$	.06		$	(.60	)	$	(1.13	)

Key Factors Impacting Continuing Operating Results

        Our total EBITDA decreased significantly in 2006 compared to 2005. Key factors affecting 2006 results were as follows:

•

Total Utilities EBITDA increased $4.8 million primarily due to growth in the number of utility customers served and rate increases in several states, offset in part by higher costs for fuel used to generate electricity in Missouri, decreased sales for resale, and increased labor and compensation costs.



•

The continued wind-down of our energy trading businesses in 2006, including a $218.0 million net loss on the exit of the Elwood tolling contract, was the primary cause of the $222.1 million increase in losses before interest, taxes, depreciation and amortization from Merchant Services.



•

Corporate and other loss before interest, taxes, depreciation and amortization decreased $75.6 million in 2006 compared to 2005, primarily due to the 2005 non-cash loss of $82.3 million on the early conversion of the PIES.

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Restructuring Charges

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

		Year Ended December 31,
		2006		2005		2004
Merchant Services:
	Severance costs	$	—	$	—	$	.7
	Lease agreements		—		6.6		—
Total Merchant Services			—		6.6		.7
Corporate and Other severance costs			5.7		—		.2
Total restructuring charges		$	5.7	$	6.6	$	.9

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

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

		Year Ended December 31,
In millions		2006		2005			2004
Merchant Services:
	Elwood tolling contract	$	218.0	$	—		$	—
	Batesville tolling contract		—		(16.3	)		—
	ICE sale		—		(9.3	)		—
	Aries power project and tolling agreement		—		—			46.6
	Termination of long-term gas contracts		—		—			156.2
	Red Lake gas storage development project		—		(6.2	)		8.9
	Independent power plants		—		—			(6.1	)
	Investment in BAF Energy		—		(.7	)		(9.1	)
	Enron bankruptcy		—		—			(6.0	)
	Marchwood development project		—		—			(5.0	)
	Other		.7		1.2			—
Total Merchant Services			218.7		(31.3	)		185.5
Corporate and Other:
	Early retirement of debt		28.2		—			—
	Early conversion of the PIES		—		82.3			—
	Everest Connections target-based put rights		—		—			(4.5	)
	Midlands		—		—			(3.3	)
	Turbines impairment		—		4.4			10.6
Total Corporate and Other			28.2		86.7			2.8
Total net loss on sale of assets and other charges		$	246.9	$	55.4		$	188.3

        During 2006, 2005, and 2004, we also incurred net (gains) losses on asset sales and other charges of $(267.9) million, $159.5 million, and $(74.0) million, respectively, that are reflected in discontinued operations and are not included in the table above.

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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,
Dollars in millions		2006			2005		2004
Sales:
	Electricity—regulated	$	767.9		$	683.9	$	594.1
	Other—non-regulated		.7			.7		.8
Total sales			768.6			684.6		594.9
Cost of sales:
	Electricity—regulated		420.4			355.4		295.8
	Other—non-regulated		.4			.3		.3
Total cost of sales			420.8			355.7		296.1
Gross profit			347.8			328.9		298.8
Operation and maintenance expense			183.2			166.3		149.4
Taxes other than income taxes			21.7			18.9		20.9
Other income (expense)			(1.0	)		4.0		1.8
EBITDA		$	141.9		$	147.7	$	130.3
Reconciliation of EBITDA to Income Before Income Taxes:
	EBITDA	$	141.9		$	147.7	$	130.3
	Depreciation and amortization expense		70.5			64.0		60.1
	Interest expense		49.4			50.5		50.7
Income before income taxes		$	22.0		$	33.2	$	19.5
Electric sales and transmission volumes (GWh)			11,034			11,165		9,932
Electric customers			396,829			391,406		383,829

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:

•

Sales and gross profit increased by $29.0 million due to rate increases and rate redesign in Missouri effective March 2006 and in Colorado effective March 2005, plus $8.6 million of additional margin from an increase in customers and customer billings and $4.1 million due to increased transmission revenues, the sale of green energy credits, and transition services revenues.



•

Unfavorable derivative settlements related to fuel hedges as well as higher fuel, purchased power, and transmission costs in 2006 increased cost of sales and decreased gross profit by $24.8 million. Partially offsetting these impacts was a $12.7 million decrease in demand charges for purchased capacity from the Aries plant in 2005 but not in 2006.



•

Sales and cost of sales increased $31.3 million and $48.1 million, respectively, from higher sales for resale. Gross profit decreased by $16.8 million from $28.5 million in 2005 due to decreased volatility in the spot market.

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•

Favorable weather-related retail volume and other variances increased gross profit by $6.9 million in 2006.

Operation and Maintenance Expenses

        Operation and maintenance expenses consisted of the following:

	Year Ended December 31,
In millions	2006		2005		2004
Operating expenses of Colorado and Missouri electric	$	183.2	$	155.3	$	139.3
Allocated expenses of Kansas electric		—		11.0		10.1
Total operating expenses	$	183.2	$	166.3	$	149.4

        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 Allowance for Funds Used During Construction (AFUDC) associated with the construction of our South Harper peaking facility in 2005. AFUDC represents the cost of both debt and equity funds 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.

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.

2005 versus 2004

Sales, Cost of Sales and Gross Profit

        Sales, cost of sales and gross profit for the Electric Utilities business increased $89.7 million, $59.6 million, and $30.1 million, respectively, in 2005 compared to 2004. These changes were primarily due to the following factors:

•

Sales and gross profit increased by $15.7 million due to rate increases in Colorado effective in September 2004 and in Missouri effective in April 2004, plus $8.8 million of additional margin from an increase in customers.



•

Favorable weather-related volume and other variances increased gross profit by $9.1 million in 2005.

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•

The favorable impacts above were offset in part by higher costs of fuel, purchased power, transmission and emission allowances, net of offsetting derivative settlements and off-system sales, which reduced margins by approximately $3.1 million as compared to 2004.

Operation and Maintenance Expenses

        Operation and maintenance expense increased $16.9 million from 2004 primarily due to approximately $9.7 million of higher labor and benefit costs, $3.5 million of increased outside service costs associated with storm-related outages in 2005, and $1.3 million of increased insurance costs.

Other Income

        Other income increased $2.2 million in 2005 compared to 2004 primarily due to increased AFUDC associated with the construction of our South Harper peaking facility, which began in late 2004. AFUDC represents the cost of both debt and equity funds 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.

Depreciation and Amortization Expense

        Depreciation and amortization expense increased $3.9 million in 2005 compared to 2004 due to additional plant placed in service, primarily the South Harper peaking facility.

Earnings Trend

        Our Missouri electric assets comprise a majority of our utility assets, and the earnings generated by our Missouri electric 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 electric operations, as we complete the sale of our Kansas electric business and the wind-down of our remaining Merchant Services operations. As we increase rates and eliminate costs formerly allocated to our other operations, we expect the earnings generated by our Missouri electric operations to improve.

        The Missouri Commission's order approving our February 2006 electric rate case settlement is expected to increase annual sales by approximately $26.3 million, net of the former interim energy charge. To the extent that our costs of natural gas used for fuel and purchased power or other operating expenses increase or decrease from the level of costs recovered in that rate case settlement, the impact of the change will affect our operating results. The $4.5 million settlement of our Missouri steam case includes an 80% sharing of fuel cost changes from the base fuel rate.

        As discussed on page 13, we have filed for a $118.9 million increase in our Missouri electric rates. Missouri Commission staff has recommended a rate increase in the range of $45.9 million to $56.4 million. We expect the Missouri Commission to rule on our request in May 2007, with approved rates taking effect no later than June 1, 2007. We have also requested the implementation of a fuel adjustment clause as part of this rate request.

        As discussed in Note 6 to the Consolidated Financial Statements, certain allocated corporate and centralized services costs associated with our electric and gas utility divisions sold or held for sale cannot be immediately eliminated when the asset sales close. We have eliminated these costs to the greatest extent possible. Fixed costs that could not be eliminated such as depreciation of corporate shared assets and corporate governance costs have been reallocated to the remaining

42

utility divisions. We will seek recovery of these fixed costs in current and future rate proceedings. To the extent we are unsuccessful our earnings could be adversely affected.

        We have entered into a program for our electric utility operations in Missouri to mitigate our exposure to natural gas price volatility in the market. The mark-to-market liability position of the portfolio of $17.9 million relates to contracts that will settle against actual purchases of natural gas and purchased power in 2007 through 2009. In connection with the recently settled 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 Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), in the amount of $17.9 million to reflect the change in the timing of recognition authorized by the Missouri Commission.

        As a result of the fuel adjustment clause legislation signed into law in July 2005, the Missouri Commission set forth rules regarding the implementation and definition of costs to be recovered in the fuel adjustment mechanism for our Missouri electric operations. The rules became final on January 30, 2007. We expect the value of our NYMEX financial contracts to be a part of the defined costs to be recovered through the fuel adjustment clause. If so, the settlement of the contracts, as well as the cost of the physical fuel and purchased power from the marketplace, will flow through to our customers.

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Three-Year Review—Gas Utilities

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

		Year Ended December 31,
Dollars in millions		2006			2005			2004
Sales:
	Natural gas—regulated	$	581.4		$	606.3		$	506.5
	Other—non-regulated		29.2			24.8			22.5
Total sales			610.6			631.1			529.0
Cost of sales:
	Natural gas—regulated		424.2			452.1			356.3
	Other—non-regulated		18.3			14.7			12.8
Total cost of sales			442.5			466.8			369.1
Gross profit			168.1			164.3			159.9
Operation and maintenance expense			112.8			121.8			114.0
Taxes other than income taxes			10.4			10.3			11.1
Other income (expense)			(.7	)		1.4			.1
EBITDA		$	44.2		$	33.6		$	34.9
Reconciliation of EBITDA to Income (Loss) Before Income Taxes:
	EBITDA	$	44.2		$	33.6		$	34.9
	Depreciation and amortization expense		30.4			35.8			35.0
	Interest expense		10.9			11.5			10.4
Income (loss) before income taxes		$	2.9		$	(13.7	)	$	(10.5	)
Gas sales and transportation volumes (Mcf)			84,420			95,787			93,691
Gas customers			515,760			508,543			500,807

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:

•

Sales and cost of sales increased approximately $4.1 million due to a 2% increase in natural gas prices on the average in 2006 compared to 2005. However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit.



•

Sales and gross profit increased by $3.9 million due to an interim rate increase in Iowa effective in May 2005 on an interim basis and finalized in March 2006, and a rate increase in Kansas effective in June 2005, plus $1.3 million of additional margin from an increase in customers.

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•

Unusually mild winter weather decreased gas volumes sold and reduced sales, cost of sales and gross profit by $43.8 million, $39.2 million and $4.6 million, respectively, in 2006 compared to 2005.



•

Sales and gross profit increased $1.7 million due to revenue from transition services provided to the purchaser of our Michigan and Missouri gas utility assets.



•

Non-regulated sales, cost of sales and gross profit increased $4.4 million, $3.6 million and $.8 million, respectively, primarily due to the sale of excess pipeline capacity.

Operation and Maintenance Expenses

        Operation and maintenance expenses consisted of the following:

	Year Ended December 31,
In millions	2006		2005		2004
Operating expenses of Colorado, Iowa, Kansas and Nebraska gas	$	112.8	$	90.5	$	84.5
Allocated expenses of Michigan, Minnesota and Missouri gas		—		31.3		29.5
Total operating expenses	$	112.8	$	121.8	$	114.0

        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.

2005 versus 2004

Sales, Cost of Sales and Gross Profit

        Sales, cost of sales and gross profit for the Gas Utilities business increased $102.1 million, $97.7 million and $4.4 million, respectively, in 2005 compared to 2004. These changes were primarily due to the following factors:

•

Sales and cost of sales increased approximately $88.6 million due to a 25% increase in natural gas prices since December 31, 2004. However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit.



•

Gross profit increased by approximately $2.9 million due to rate increases in Kansas effective in June 2005 and an interim rate increase in Iowa effective in May 2005, as well as $1.5 million of additional margins from customer growth in 2005. Final Iowa rates were effective in April 2006.

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•

The impact of warmer 2005 weather decreasing gross profit was mitigated by a weather hedge and the Kansas weather normalization adjustment.

Operation and Maintenance Expenses

        Operation and maintenance expenses for 2005 increased $7.8 million from 2004 primarily as a result of increased labor and benefit costs.

Three-Year Review—Merchant Services

        We conduct our remaining Merchant Services business through Aquila Merchant, which contractually controls our non-regulated power generation asset and owns our remaining energy trading assets.

		Year Ended December 31,
In millions		2006			2005			2004
Sales		$	(9.7	)	$	(1.6	)	$	(152.9	)
Cost of sales			18.3			41.2			56.0
Gross loss			(28.0	)		(42.8	)		(208.9	)
Operating expenses:
	Operation and maintenance expense		9.9			16.8			28.0
	Taxes other than income taxes		(4.8	)		(6.2	)		.6
	Restructuring charges		—			6.6			.7
	Net loss (gain) on sale of assets and other charges		218.7			(31.3	)		185.5
Total operating expenses			223.8			(14.1	)		214.8
Other income:
	Other income		7.1			6.1			7.0
Earnings (loss) before interest, taxes, depreciation and amortization		$	(244.7	)	$	(22.6	)	$	(416.7	)
Reconciliation of EBITDA to Loss Before Income Taxes:
	EBITDA	$	(244.7	)	$	(22.6	)	$	(416.7	)
	Depreciation and amortization expense		4.1			6.3			7.3
	Interest expense		17.3			15.2			5.6
Loss before income taxes		$	(266.1	)	$	(44.1	)	$	(429.6	)

        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.

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2006 versus 2005

Sales, Cost of Sales and Gross Loss

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

•

In 2006, we recorded net margin losses associated with our Elwood tolling agreement of $17.6 million. We did not generate material revenues on this capacity.



•

We incurred margin losses of $7.7 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts and the net cost of gas delivered under these contracts.



•

We also incurred a $2.7 million gross loss related to the settlement of various contracts and trade positions and other settlements due to the continued wind-down of our merchant operations.

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

•

In 2005, we recorded a net margin loss of $32.4 million associated with our Elwood tolling agreement. We made fixed capacity payments evenly throughout the year that entitled us to generate power at the Elwood plant. The cost to purchase natural gas to fuel this power plant generally exceeded the value of the power that could be generated. Accordingly, we did not generate material revenues.



•

As part of the continued wind-down of our wholesale energy trading operations, we assigned the final year of our obligation under a stream flow contract to a third party in the second quarter of 2005. Included in our gross loss for 2005 were mark-to-market losses and settlements of approximately $7.4 million, related to our stream flow transaction.



•

We recorded a margin loss of $4.5 million on the 2005 write-off of certain balances retained in our previous sale of gas pipeline investments.



•

We also incurred margin losses of $7.1 million resulting from the difference between revenue recognized on our two remaining long-term gas delivery contracts compared to the net cost of gas delivered under these contracts.



•

Partially offsetting the gross loss for 2005 was the termination of certain commodity and interest rate hedges. The termination of the hedges and the release of our contingent obligation to the buyer of our former merchant loan portfolio resulted in the reversal of the related liability of $7.1 million associated with these contracts.

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.

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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.

2005 versus 2004

Sales, Cost of Sales and Gross Loss

        The significant factors causing our $42.8 million gross loss for 2005 are described above.

        Gross loss for our Merchant Services operations for 2004 was $208.9 million, primarily due to the following factors:

•

Approximately $22.6 million was a non-cash loss related to the discounting of our trading portfolio, primarily driven by our long-term gas contracts. After updating the future cash flow stream based on the new forward natural gas prices, we discount the future cash flows of our price risk management assets based on our counterparties' credit standing, versus our future cash flows of our price risk management liabilities that are discounted based on our current credit standing. In prior periods, primarily in 2002, when our credit standing deteriorated compared to our counterparties' that make up the vast majority of our price risk management assets, we recorded non-cash earnings related to the discounting of our price risk management assets and liabilities. During 2004, the benchmark indices we used to determine the discount rate appropriate for our credit standing decreased, resulting in the partial reversal of the previous earnings and assets recorded. Due to the settlement of four of our long-term gas contracts, the future impact of non-cash mark-to-market movements described above was significantly reduced.



•

In 2004, we incurred margin losses of $30.3 million resulting from the difference between revenue recognized on our long-term gas delivery contracts and the net cost of gas delivered under these contracts.



•

During 2004, we made fixed capacity payments evenly throughout the year that entitled us to generate power at merchant power plants owned by others. For 2004, we recorded net margin loss associated with these agreements of $36.9 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate material revenues.



•

The settlement of our price risk management assets and liabilities associated with four of our long-term gas delivery contracts resulted in non-cash, mark-to-market losses of approximately $40.3 million related to the discounting of our trading portfolio. We discounted the future cash flows of our price risk management assets based on our counterparties' credit standing, versus our future cash flows of our price risk management liabilities that are discounted based on our then current credit standing. This resulted in the recording of a net asset related to these four long-term contracts and their corresponding commodity hedges of approximately $40.3 million prior to our settlement.

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Additionally, we recorded a margin loss of approximately $16.5 million for margin recorded on these long-term contracts and approximately $7.1 million related to replacement gas payments we made under the termination provisions of these contracts.

•

We incurred approximately $23.9 million of costs to manage our remaining natural gas hedge positions related to the Onondaga swap derivative sold in connection with the sale of our independent power plants, cash flow hedge option premium expirations, the exit of other hedges related to previous contracts and settlements of various open positions during 2004.



•

Our remaining gross loss for 2004 mainly stems from mark-to-market losses and unfavorable settlements of approximately $32.4 million, related to a long-term power supply transaction with New York State Electric and Gas Corp. and our stream flow transaction. In May 2004, we settled our obligation under the long-term power supply contract with New York State Electric and Gas Corp. by making a cash payment of $37.7 million to a third party that assumed our obligations under this contract.

Operation and Maintenance Expense

        Operation and maintenance expense decreased $11.2 million primarily due to the reduction of our allowance for bad debts by $7.1 million, $5.4 million of reduced surety payments due to the settlement of four long-term gas contracts in 2004, and $5.3 million of reduced costs for staffing needed to manage our remaining trading positions and non-regulated power generation assets. These cost reductions were offset in part by the provision of $9.0 million in 2005 relating to certain price reporting litigation.

Taxes Other Than Income Taxes

        Taxes other than income taxes decreased $6.8 million primarily due to the refund of approximately $7.2 million of value-added taxes previously paid and expensed by our European merchant trading business.

Restructuring Charges

        Restructuring charges increased $5.9 million in 2005 compared to 2004, primarily due to the termination of the majority of the remaining leases associated with our former Merchant Services headquarters in March 2005 for $13.0 million which exceeded the reserve obligation by $6.6 million.

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

        Net gain on sale of assets and other charges in 2005 consists primarily of pretax gains of $16.3 million on the termination of 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.

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

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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. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. It is generally expected that the fuel and start-up costs of operating our Crossroads plant will exceed the revenues that would be generated from the power sold. We therefore believe that during the next few years we have limited ability to generate power at the Crossroads facility for a profit. We have assessed the realizability of our investment in this 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. 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, and we continue to deliver gas under our remaining long-term gas contracts which expire by early 2008. 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, and our former equity method investment in the United Kingdom, which has been sold. Our United Kingdom investment consisted of an indirect 79.9% interest in Aquila Sterling Limited, the holding company for Midlands Electricity, an electric distribution company in central England. We sold our United Kingdom investment in January 2004.

        We sold our former Canadian utility businesses in May 2004 and our former 97% owned subsidiary, Everest Connections, a communications provider, in June 2006. The results of Everest

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Connections and our Canadian utility businesses have been reclassified as discontinued operations and are not included below (see Note 6 to the Consolidated Financial Statements).

		Year Ended December 31,
In millions		2006			2005			2004
Sales		$	.1		$	—		$	—
Cost of sales			—			—			—
Gross profit			.1			—			—
Operating expenses:
	Operation and maintenance expense		17.0			21.0			28.6
	Taxes other than income taxes		3.9			.1			.5
	Restructuring charges		5.7			—			.2
	Net loss on sale of assets and other charges		28.2			86.7			2.8
Total operating expenses			54.8			107.8			32.1
	Other income:
Other income			27.1			4.6			8.3
Earnings (loss) before interest and taxes, depreciation and amortization		$	(27.6	)	$	(103.2	)	$	(23.8	)
Reconciliation of EBITDA to Loss Before Income Taxes:
	EBITDA	$	(27.6	)	$	(103.2	)	$	(23.8	)
	Depreciation and amortization expense		(1.1	)		.3			.4
	Interest expense		81.6			73.0			117.8
Loss before income taxes		$	(108.1	)	$	(176.5	)	$	(142.0	)

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 20 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.

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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.

2005 versus 2004

Operation and Maintenance Expense

        Operation and maintenance expense decreased $7.6 million in 2005 compared to 2004, due to the 2004 settlement of the appraisal rights shareholder lawsuit for an additional $8.8 million above our estimate, an $8.5 million decrease in costs associated with our former international networks investments in Canada and Australia compared to 2004 and a $3.3 million decrease in insurance costs in 2005. These decreases were offset in part by $7.9 million of increased legal fees related to litigation and $4.0 million of increased consulting fees and other costs associated with the process of selling certain of our Gas and Electric Utilities in 2005.

Net Loss on Sale of Assets and Other Charges

        The $86.7 million loss on sale of assets and other charges in 2005 was primarily the result of the $82.3 million loss on the early conversion of the PIES. In addition, we recognized an additional $4.4 million loss 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. In connection with the settlement of our recent Missouri electric rate case, we agreed with the Missouri Commission staff and other interveners that fair value was approximately $4.4 million lower than that estimated in 2004. The 2004 loss on sale of assets and other charges of $2.8 million is mainly due to the $10.6 million impairment on the transfer of the three natural gas combustion turbines. The impairment was partially offset by the reversal of a $4.5 million liability we recorded at Corporate related to our Everest Connections target-based put rights due to the meeting of certain financial and operational performance measures, and the $3.3 million gain we recorded in connection with the sale of our interest in Midlands Electricity in January 2004.

Other Income

        Other income decreased $3.7 million in 2005 compared to 2004, primarily due to $3.4 million of fees on the $180 million facility supporting our unsecured letters of credit in 2005, and $3.3 million of net gains in 2004 that did not recur in 2005, offset by $3.8 million of interest on taxes paid in 2004.

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Interest Expense and Income Tax Benefit

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

	Year Ended December 31,
In millions	2006			2005			2004
Interest expense	$	159.2		$	150.2		$	184.5
Income tax benefit	$	(67.3	)	$	(43.1	)	$	(214.3	)

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

        The 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.

2005 versus 2004

Interest Expense

        Interest expense decreased $34.3 million in 2005 compared to 2004. The decrease was primarily the result of the following:

•

Lower interest costs of $18.5 million related to the scheduled retirements of senior notes in 2004 and 2005;



•

A $24.9 million decrease in interest expense related to our former $430.0 million secured term loan which was repaid in September 2004; and



•

The repayment of our $430.0 million secured term loan also resulted in the expensing of $10.3 million of unamortized debt issuance costs in 2004.

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

•

Interest expense increased approximately $15.1 million related to our $220 million unsecured term loan borrowing in September 2004; and

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•

Interest expense increased approximately $3.4 million related to the PIES issued in August 2004.

Income Tax Benefit

        The income tax benefit decreased $171.2 million in 2005 compared to 2004, primarily due to decreased pretax losses and non-deductible expenses in 2005 related to the $82.3 million loss on the PIES exchange. In addition, in 2005 a $53.2 million decrease in valuation allowances related to capital losses was substantially offset by an increase in the reserve for contingent liabilities.

Discontinued Operations

        Operating results of discontinued operations are as follows:

		Year Ended December 31,
In millions		2006			2005			2004
Sales		$	516.4		$	879.8		$	870.9
Cost of sales			343.3			608.0			518.1
Gross profit			173.1			271.8			352.8
Operating expenses:
	Operation and maintenance expense		71.5			104.8			159.3
	Taxes other than income taxes		10.8			7.3			23.7
	Restructuring charges		2.0			-			-
	Net loss (gain) on sale of assets and other charges		(267.9	)		159.5			(74.0	)
Total operating expenses (income)			(183.6	)		271.6			109.0
Other income (expense):
	Other income		.1			.5			3.5
EBITDA			356.8			.7			247.3
	Depreciation and amortization expense		.9			42.5			47.5
	Interest expense		34.6			71.2			88.6
Earnings (loss) before income taxes			321.3			(113.0	)		111.2
Income tax expense (benefit)			15.4			(41.0	)		55.4
Earnings (loss) from discontinued operations		$	305.9		$	(72.0	)	$	55.8

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.

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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 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.

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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.

2005 versus 2004

Sales, Cost of Sales and Gross Profit

Electric Utilities

        Sales, cost of sales and gross profit for our Kansas electric utility increased $25.7 million, $15.7 million, and $10.0 million, respectively, in 2005 compared to 2004. Sales and gross profit increased by $6.2 million due to a rate increase in Kansas effective in April 2005. The favorable impacts of weather on electricity usage increased 2005 gross profit by an additional $2.2 million over 2004, and electric wheeling revenue increased by $2.5 million in 2005.

Gas Utilities

        Sales, cost of sales, and gross profit for Michigan, Minnesota, and Missouri gas utilities increased $89.5 million, $88.2 million, and $1.3 million, respectively. Sales and cost of sales increased approximately $80.9 million due to a 25% increase in natural gas prices since December 31, 2004. However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit. Sales and gross profit increased by $1.4 million due to rate increases in Missouri effective in May and July 2004. Sales and gross profit increases of $1.9 million due to the pipeline supplier metering adjustments in 2005 associated with prior periods were offset by the impacts of milder winter weather and other volume variances in 2005 as compared to 2004.

Other

        Other sales, cost of sales and gross profit decreased $106.3 million, $14.0 million, and $92.3 million, respectively, in 2005 compared to 2004. Our Canadian utilities and independent power plants, which had 2004 gross profit of $105.7 million, were sold in the first half of 2004. Slightly offsetting this lost profit was a $5.8 million increase in Everest Connections 2005 gross profit as compared to 2004 due to an increase in customers served and a $7.7 million increase in gross profit earned by the Illinois peaking power plants related to increased demand for peaking power and short-term capacity contracts in 2005.

Operation and Maintenance Expense

        Operation and maintenance expense decreased $54.5 million in 2005 compared to 2004 primarily due to the sale of our consolidated independent power plants and our Canadian utility businesses in the first half of 2004. Both the electric and gas utility operations also experienced operating expense decreases in 2005, related primarily to reductions in the reserves needed for bad debt and general claims.

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Taxes Other Than Income Taxes

        Taxes other than income taxes decreased $16.4 million in 2005 compared to 2004 primarily due to property tax settlements in Michigan and Minnesota and the sale of our Canadian utility businesses in 2004.

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

        In 2005, net loss on sales of assets and other charges of $159.5 million was the result of an impairment of the Illinois peaking power plants to reduce their book value to current fair market value. In 2004, net gain on sale of assets and other charges of $74.0 million consisted of a $65.6 million gain on the sale of our Canadian utility businesses in May 2004 and an $8.4 million gain on the sale of our consolidated independent power plants, Lake Cogen and Onondaga, in March 2004.

Other Income (Expense)

        Other income decreased $3.0 million in 2005 compared to 2004, primarily due to 2004 interest income earned by our Canadian subsidiaries that were sold in 2004.

Depreciation and Amortization Expense

        Depreciation and amortization expense decreased $5.0 million in 2005 compared to 2004. The elimination of depreciation from our Kansas electric and Michigan, Minnesota, and Missouri gas utility businesses in the fourth quarter of 2005, due to their classification as held for sale in accordance with SFAS 144, decreased depreciation expense by $7.5 million. SFAS 144 requires that depreciation expense no longer be recorded for those assets classified for accounting purposes as held for sale. The decrease was partially offset by increased depreciation expense related to the expansion of Everest Connections' communication network to accommodate customer growth.

Interest Expense

        Interest expense decreased $17.4 million in 2005 compared to 2004, primarily due to the repayment or assumption of debt associated with our Canadian utility businesses that were sold in May 2004.

Income Tax Expense (Benefit)

        Income tax expense decreased $96.4 million in 2005 compared to 2004, primarily due to the pretax loss in 2005 related to the impairment of our investments in Illinois peaking power plants in 2005. The 2005 income tax benefit on a pretax loss from discontinued operations was primarily the result of the impairment of our Illinois peaking facilities, while the 2004 income tax expense on pretax income from discontinued operations resulted from the pretax gain on the sale of our Canadian utility businesses. The tax expense on that 2004 gain was substantially higher than the statutory federal tax rate due to the following factors. The U.S. taxes reflect the partial deduction of Canadian taxes, including withholding taxes, from the U.S. taxable income instead of the full utilization of foreign tax credits. Taxes on the sale also reflect our inability to fully utilize the tax loss on the sale of the Alberta business against the tax gain on the sale of the British Columbia business.

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OTHER ITEMS

Critical Accounting Policies and Estimates

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

Energy Trading and Derivative Accounting

        The portion of our trading activities that qualify as derivatives under SFAS 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:

•

We have variability in our mark-to-market earnings due to changes in the market price for gas. Our portfolio is valued from current and expected future gas prices. Changes in these prices can cause fluctuations in our earnings.



•

We discount our price risk management assets and liabilities using risk-free interest rates adjusted for our credit standing and the credit standings of our counterparties in accordance with SFAS 133 which is more fully described in Statement of Financial Accounting Concepts No. 7, "Using Cash Flow Information and Present Value in Accounting Measurement." Because our price risk management liabilities are discounted using our credit standing, versus the receivable side of these transactions which are discounted based on our counterparties' credit standings (which on average are higher than ours), non-cash mark-to-market earnings or losses are created. As these spreads narrow, we record mark-to-market losses; as they widen, we record mark-to-market gains. These gains and losses can fluctuate if our credit or the credit of a group of our counterparties deteriorates or improves significantly.

        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

58

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 $17.9 million related to contracts that will settle against actual purchases of natural gas and purchased power in 2007 through 2009. In connection with the recently settled 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 $17.9 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 for continuing operations at December 31, 2006 were $84.4 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 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 that we expect will continue for the next few years. This situation has prevented the plant from producing significant margins and, in turn, has created losses for us. It is forecasted that these losses will continue for the next few years. We separately tested the cash flows for 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 exceeded its 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. If at some future date we determine this asset is held for sale, based on current market values, we would likely record a material impairment charge. As of December 31, 2006, we reviewed market conditions and the assumptions used in the 2005

59

assessment and determined that no significant adverse changes had occurred. Therefore, a full assessment was not required. As of December 31, 2006, the carrying value of this plant was $118.9 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, 2006 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 earnings. Total regulatory assets and liabilities at December 31, 2006 were $178.0 million and $78.5 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 generated from net operating losses and capital losses incurred on the sale of assets using a "more likely than not" assessment of realization. This assessment takes into consideration tax planning strategies within our control. This assessment, however, does not take into consideration the expected taxable gains, both capital and ordinary, from the pending sales of our Kansas and Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska gas properties. In addition the assessment does not take into consideration the pending merger with Great Plains Energy. Lastly, the assessment also does not take into consideration the expected results from filed rate cases or debt reductions expected to be completed after the sale of our Kansas electric property.

        As of December 31, 2006, we have recorded $139.7 million of valuation allowances against deferred tax assets for which the ultimate realization of the tax asset is mainly dependent on the

60

availability of future capital gains and taxable income in certain states. The ultimate amount of deferred tax assets realized could be materially different from that recorded, as impacted by changes in federal income tax laws and upon the generation of future capital gains or state taxable income to enable us to realize the related tax assets.

        As of December 31, 2006, we had approximately $454.5 million of federal net operating loss carryforwards originating in 2003, $579.0 million of estimated federal net operating losses originating in 2004, $195.3 million of federal net operating loss carryforward and originating in 2005 and an estimated $227.6 million of federal net operating losses originating in 2006. 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. We did not record valuation allowances against the deferred tax assets related to federal net operating losses. However, we have recorded valuation allowances against federal net operating losses in conjunction with the adoption of FIN 48, "Accounting for Uncertainty in Income Taxes" in the first quarter of 2007. See further discussion in Note 2 of the Consolidated Financial Statements.

Reserve for Uncertain Tax Positions

        As of December 31, 2006, we have recorded liabilities of $377.3 million for cumulative tax provisions for tax deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is reasonably likely that these deductions or income positions will be challenged when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The reserve is included as an offset to deferred tax assets because the timing of the resolution of these audits is uncertain and if the positions taken on the tax returns are not ultimately sustained, we may be required to utilize our net operating loss carryforwards, alternative minimum tax credit carryforwards, and/or general business credit carryforwards and/or make cash payments plus interest. We use significant judgment in both the determination of probability and the determination as to whether an uncertain tax position is reasonably estimable. Because of uncertainties related to these matters, reserves are based only on the best information at that time. As additional information becomes available, we reassess the potential liability related to our tax deductions or income positions and may revise our estimates. Such revisions in the estimates of uncertain tax positions could have a material impact on our financial position and results of operations. We adopted FIN 48 in the first quarter of 2007. See Note 2 of the Consolidated Financial Statements for discussion regarding the impact of adopting FIN 48.

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

61

rates of return on plan assets could also increase or decrease recorded pension costs. As of September 30, 2006, our average assumed discount rate was 6.01% and our average expected return on plan assets was 8.50%.

        The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, we and our actuaries expect that the inverse of this change would impact the projected benefit obligation (PBO) at December 31, 2006, and our estimated annual pension cost (APC) on the income statement for 2007 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 Assumption Incr.(decr.)		Impact on PBO Incr.(decr.)			Impact on APC Incr.(decr.)
Discount rate	.25	%	$	(12.2	)	$	(1.4	)
Rate of return on plan assets	.25	%		—			(.9	)

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 $1,158.3 million since December 31, 2005. This decrease is primarily due to the following:

•

Cash increased $218.6 million. See our Consolidated Statement of Cash Flows for analysis of this increase.



•

Funds on deposit decreased $157.0 million, primarily due to the return of margin deposits paid to counterparties in connection with the continued wind-down of our wholesale energy-trading portfolio, decreased collateral posted in connection with our regulated utilities due to lower volumes hedged and lower gas prices and the replacement of cash collateral with uncollateralized letters of credit.



•

Accounts receivable decreased $142.7 million, primarily due to decreased natural gas prices since December 31, 2005, and lower volumes of natural gas and electricity delivered due to the continued wind-down of wholesale energy trading business.



•

Price risk management assets decreased $263.0 million, primarily due to a decrease in natural gas prices since December 31, 2005.



•

Utility plant, net, increased $83.2 million primarily due to continued investment in our Electric Utilities including our participation in Iatan 2 in 2006.

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•

Prepaid pension decreased $68.3 million primarily as a result of the adoption of a new accounting standard for defined benefit pension plans.



•

Regulatory assets increased $66.0 million primarily due to the recording of regulatory assets for pension and post-retirement benefit costs in connection with the adoption of the new accounting standard.



•

Current and non-current assets of discontinued operations decreased $854.3 million, primarily due to the sale of our Michigan, Minnesota and Missouri gas operations, Everest Connections and our Illinois merchant peaking plants during 2006.

        Total liabilities decreased by $1,154.5 million and common shareholders' equity decreased by $3.8 million since December 31, 2005. These changes are primarily attributable to the following:

•

Accounts payable decreased $150.8 million primarily due to lower volumes of natural gas purchased and lower natural gas prices.



•

Price risk management liabilities decreased $202.2 million, primarily due to a decrease in natural gas prices since December 31, 2005.



•

Customer funds on deposit decreased $58.4 million, primarily due to decreased margin deposits received from counterparties on derivative contracts for natural gas resulting from decreased natural gas prices.



•

Short-term and long-term debt, including current maturities of long-term debt, together decreased by $585.9 million, primarily due to the early retirement of $350 million of senior notes and the $220 million term loan.



•

Pensions and post-retirement benefit obligations increased $39.3 million primarily as a result of the adoption of the new accounting standard for defined benefit pensions and post-retirement benefit plans in 2006.



•

Current and non-current liabilities of discontinued operations decreased $56.8 million, primarily due to the sale of our Michigan, Minnesota and Missouri gas operations, Everest Connections and our Illinois merchant peaking plants during 2006.



•

Deferred income taxes and credits decreased $52.2 million primarily as the result of current year net operating losses and deferred tax assets on a comprehensive loss recorded in 2006 in connection with the adoption of the new accounting standard for defined benefit pensions and post-retirement benefit plans.



•

Common shareholders' equity decreased $3.8 million, primarily as a result of a $30.6 million cumulative adjustment to comprehensive loss from pension and post-retirement benefits offset in part by the $23.9 million net income in 2006.

New Accounting Standards

        In 2005 and 2006, 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 2005, the FASB issued Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47) and SFAS No. 154, "Accounting Changes and Error Corrections" (SFAS 154). 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,

63

"Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements" (SAB 108). See Notes 2, 8 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.

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:

•

We expect to merge with a subsidiary of Great Plains Energy and, if completed, we will become a wholly-owned subsidiary of Great Plains Energy and our shareholders will receive a combination of 0.0856 shares of Great Plains Energy common stock and $1.80 in cash upon the effectiveness of the merger. Some important factors that could cause actual results to differ materially from those anticipated include:



•

We or Great Plains Energy may not receive in a timely manner the shareholder, regulatory and third-party approvals required to complete the Merger. Even if we and Great Plains Energy obtain the regulatory and third-party approvals required to complete the Merger, the approvals may contain unacceptable terms or conditions that would permit us or Great Plains Energy to terminate the Merger.



•

We may not complete the sale of our Colorado electric utility assets and Colorado, Iowa, Kansas and Nebraska gas utility assets to Black Hills, which must occur prior to the completion of the Merger.



•

The occurrence of certain events outside of our control may permit Great Plains Energy to terminate the Merger, to the extent the events result in a material adverse effect on our Missouri electric operations.



•

We expect to use the net proceeds from asset sales to retire debt and other liabilities and fund our anticipated capital expenditures, in a manner that maximizes the improvement of our credit profile. Some important factors that could cause actual results to differ materially from those anticipated include:



•

We may not be able to retire a sufficient principal amount of debt and other liabilities in a manner that maximizes our net sale proceeds or improves our credit sufficiently.



•

We may not close the sale of our Kansas electric utility division or we may receive less net sale proceeds than anticipated due to purchase price adjustments or changes required to satisfy the conditions of regulatory orders pertaining to the asset sales.



•

We expect our financial condition to be increasingly dependent upon the revenues and earnings generated by our Missouri electric operations, and for these earnings to increase in the future. Some important factors that could cause actual results to differ materially from those anticipated include:



•

Although we have requested the implementation of a fuel adjustment clause in our current rate case, we are currently unable to pass through fuel costs and environmental capital expenditures to our Missouri electric customers. If we are not permitted in the future to pass these costs through to our Missouri electric customers,

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the earnings of our Missouri electric operations (and, therefore, our overall financial condition) may not improve.

•

If the Missouri Commission does not approve our requested rate increases or rate increases requested in the future, the earnings of our Missouri electric operations (and, therefore, our overall financial condition) may not improve.



•

We anticipate that our current revolving credit capacity and available cash will be sufficient to fund our working capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:



•

Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our winter needs and working capital requirements.



•

Unanticipated increases in the price of natural gas that we purchase for our utility customers could exhaust our liquidity in the winter months.



•

Counterparties may default on their obligations to supply commodities or return collateral to us or to meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.



•

We believe that we have strong defenses to litigation pending against us. Some important factors that could cause actual results to differ materially from those anticipated include:



•

Judges and juries can be difficult to predict and may, in fact, rule against us.



•

Our positions may be weakened by adverse developments in the law or the discovery of facts that hurt our cases.

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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 three 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 2006, we generated approximately 53% of the power that we sold and we purchased the remaining 47% through long-term contracts or in the open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have ECAs that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, we currently do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our exposure to commodity price changes has historically been concentrated in the Missouri electric operations, resulting in greater earnings volatility from year to year there than in our other electric rate jurisdictions.

        In July 2005, legislation was adopted establishing a means for the recovery of prudently incurred fuel, purchased power costs and government-mandated environmental expenditures without going through a general rate case. On September 19, 2006 the Missouri Commission approved rules regarding fuel adjustment recovery, which became final on January 30, 2007. We have requested the implementation of the fuel adjustment clause in our pending Missouri rate case. The Missouri Commission has not yet issued rules pertaining to environmental expenditures.

        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 2007 and 62% in 2008, respectively. The price risk associated with our natural gas and on-peak spot market purchased power requirements is also mitigated through a dollar-cost averaging hedging plan using NYMEX futures contracts and options. This is a multi-year hedging plan. As of December 31, 2006, we had financial contracts in place to hedge approximately 76% of our expected on-peak natural gas and natural gas equivalent purchased power price exposure for 2007. The mark-to-market value of these contracts at December 31, 2006 was a liability of $17.9 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

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

•

Selection of a confidence level (we use 95%);



•

Holding period (this is the time needed to liquidate a position—we use one day); and



•

Use of historical volatility and correlations with the most recent activity weighted more heavily.

        The average value-at-risk for all commodities during 2006 was $.3 million. Our Board of Directors sets our value-at-risk limit. We are currently limited to $3.0 million for the remaining commodity trading portfolio and a $5.0 million target for the aggregate book that includes the first 18 months of Merchant Services asset positions. In addition to value-at-risk, we also apply other risk control measures that incorporate volumetric limits by commodity, loss limits, durational limits and application of stress testing to our various risk portfolios.

        All merchant interest risks are monitored within the commodity portfolios and value-at-risk calculation. The merchant commodity portfolios are valued on a mark-to-market basis which requires that the trading book be discounted on a net present value basis utilizing risk adjusted current interest rates based on our credit standing and those of our counterparties. Because interest rate movements impact the value of our trading portfolio, we have used interest rate derivatives to hedge this risk and may do so in the future as the portfolio continues to wind down.

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.

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        The changes in fair value of our Utilities and Merchant Services derivative contracts for 2006 are summarized below:

In millions	Utilities			Merchant Services			Total
Fair value at December 31, 2005	$	42.3		$	31.6		$	73.9
Increase (decrease) in fair value during the year		(65.2	)		(2.0	)		(67.2	)
Contracts realized or cash settled		3.8			2.6			6.4
Fair value at December 31, 2006	$	(19.1	)	$	32.2		$	13.1

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

In millions	2007			2008		2009		2010		Thereafter		Total
Prices actively quoted	$	(3.2	)	$	7.4	$	1.2	$	—	$	—	$	5.4
Prices provided by other external sources		—			—		.9		—		—		.9
Priced based on models and other valuation methods		—			—		—		1.0		5.8		6.8
Net price risk management assets	$	(3.2	)	$	7.4	$	2.1	$	1.0	$	5.8	$	13.1

Credit Risk

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

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

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

        The following table details our credit exposures at December 31, 2006, associated with our forward positions within our trading portfolio and our billed receivables (excluding tariff

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

In millions		Investment Grade		Non-investment Grade		Total
Utilities and merchants		$	57.8	$	36.2	$	94.0
Financial institutions			94.3		—		94.3
	Total	$	152.1	$	36.2	$	188.3

        A majority of the customers in our continuing 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 substantially wound down our United Kingdom and Canadian merchant trading businesses, which were included in our Merchant Services segment, and have sold our international utility businesses in Canada, Australia, New Zealand and the United Kingdom. Our remaining currency rate exposure relates only to approximately $3.9 million of cash held in foreign countries, a limited trading portfolio in Canada and the resolution of outstanding tax obligations and receivables.

Interest Rate Exposure

        We do not have a material amount of unhedged variable rate financial obligations at December 31, 2006.

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Item 8.  Financial Statements and Supplementary Data

		Page
Consolidated Statements of Income for the three years ended December 31, 2006		71
Consolidated Balance Sheets at December 31, 2006 and 2005		72
Consolidated Statements of Common Shareholders' Equity for the three years ended December 31, 2006		73
Consolidated Statements of Comprehensive Income for the three years ended December 31, 2006		74
Consolidated Statements of Cash Flows for the three years ended December 31, 2006		75
Notes to Consolidated Financial Statements:		77
	Summary of Significant Accounting Policies	77
	New Accounting Standards	82
	Risk Management	84
	Restructuring Charges	87
	Net Loss on Sale of Assets and Other Charges	89
	Discontinued Operations	93
	Accounts Receivable	99
	Utility and Non-Utility Plant	100
	Regulatory Assets and Liabilities	103
	Short-Term Debt	105
	Long-Term Debt	107
	Capital Stock and Stock Compensation	111
	Accumulated Other Comprehensive Income (Loss)	117
	Earnings (Loss) Per Share	117
	Income Taxes	118
	Employee Benefits	123
	Segment Information	130
	Commitments and Contingencies	133
	Quarterly Financial Data (Unaudited)	139
	Pending Merger	140
Report of Independent Registered Public Accounting Firm		142
Report of Independent Registered Public Accounting Firm		143

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Aquila, Inc.
Consolidated Statements of Income

		Year Ended December 31,
In millions, except per share amounts		2006			2005			2004
Sales:
	Electricity—regulated	$	767.9		$	683.9		$	594.1
	Natural gas—regulated		581.4			606.3			506.5
	Other—non-regulated		20.3			23.9			(129.6	)
Total sales			1,369.6			1,314.1			971.0
Cost of sales:
	Electricity—regulated		420.4			355.4			295.8
	Natural gas—regulated		424.2			452.1			356.3
	Other—non-regulated		37.0			56.2			69.1
Total cost of sales			881.6			863.7			721.2
Gross profit			488.0			450.4			249.8
Operating expenses:
	Operation and maintenance expense		322.9			325.9			320.0
	Taxes other than income taxes		31.2			23.1			33.1
	Restructuring charges		5.7			6.6			.9
	Net loss on sale of assets and other charges		246.9			55.4			188.3
	Depreciation and amortization expense		103.9			106.4			102.8
Total operating expenses			710.6			517.4			645.1
Operating income (loss)			(222.6	)		(67.0	)		(395.3	)
Other income (expense), net			32.5			16.1			17.2
Interest expense			159.2			150.2			184.5
Loss from continuing operations before income taxes			(349.3	)		(201.1	)		(562.6	)
Income tax expense (benefit)			(67.3	)		(43.1	)		(214.3	)
Loss from continuing operations			(282.0	)		(158.0	)		(348.3	)
Earnings (loss) from discontinued operations, net of tax			305.9			(72.0	)		55.8
Net income (loss)		$	23.9		$	(230.0	)	$	(292.5	)
Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.75	)	$	(.40	)	$	(1.35	)
	Discontinued operations		.81			(.20	)		.22
	Net income (loss)	$	.06		$	(.60	)	$	(1.13	)

See accompanying notes to consolidated financial statements.

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Aquila, Inc.
Consolidated Balance Sheets

		December 31,
In millions		2006		2005
Assets
Current assets:
	Cash and cash equivalents	$	232.8	$	14.2
	Restricted cash		9.1		10.9
	Funds on deposit		107.9		264.9
	Accounts receivable, net		257.0		399.7
	Inventories and supplies		116.0		107.3
	Price risk management assets		71.3		200.0
	Regulatory assets, current		29.0		27.7
	Other current assets		24.4		50.4
	Current assets of discontinued operations		26.5		269.0
Total current assets			874.0		1,344.1
	Utility plant, net		1,825.1		1,741.9
	Non-utility plant, net		130.2		135.4
	Price risk management assets		43.4		177.7
	Goodwill, net		111.0		111.0
	Regulatory assets		149.0		83.0
	Prepaid pension		—		68.3
	Deferred charges and other assets		53.6		71.4
	Non-current assets of discontinued operations		286.1		897.9
Total Assets		$	3,472.4	$	4,630.7
Liabilities and Shareholders' Equity
Current liabilities:
	Current maturities of long-term debt	$	19.7	$	88.3
	Short-term debt		—		12.0
	Accounts payable		205.4		356.2
	Accrued interest		49.7		64.6
	Regulatory liabilities, current		10.8		43.4
	Accrued compensation and benefits		26.8		23.5
	Pension and post-retirement benefits, current		3.5		—
	Other accrued liabilities		94.3		117.4
	Price risk management liabilities		74.5		164.9
	Customer funds on deposit		15.6		74.0
	Current liabilities of discontinued operations		1.4		30.6
Total current liabilities			501.7		974.9
Long-term liabilities:
	Long-term debt, net		1,385.9		1,891.2
	Deferred income taxes and credits		19.3		71.5
	Price risk management liabilities		27.1		138.9
	Pension and post-retirement benefits		72.5		36.7
	Regulatory liabilities		67.7		72.3
	Deferred credits		56.2		71.8
	Non-current liabilities of discontinued operations		35.9		63.5
Total long-term liabilities			1,664.6		2,345.9
Common shareholders' equity			1,306.1		1,309.9
Total Liabilities and Shareholders' Equity		$	3,472.4	$	4,630.7

See accompanying notes to consolidated financial statements.

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Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

		Year Ended December 31,
In millions, except share amounts		2006			2005			2004
Common stock: authorized 400 million shares at December 31, 2006, 2005 and 2004, par value $1 per share, 374,611,194 shares issued at December 31, 2006, 373,603,277 at December 31, 2005 and 241,739,573 at December 31, 2004; authorized 20 million shares of Class A common stock, par value $1 per share, none issued
	Balance beginning of year	$	373.6		$	241.7		$	195.3
	Issuance of shares in public offerings		—			—			46.0
	Issuance of shares through PIES exchange		—			131.4			—
	Issuance of shares under compensation arrangements		1.0			.5			.4
Balance end of year			374.6			373.6			241.7
Premium on capital stock:
	Balance beginning of year		3,507.0			3,228.6			3,161.3
	Issuance of shares in public offerings		—			—			66.3
	Issuance of shares through PIES exchange		—			280.2			—
	Issuance of shares under compensation arrangements		2.2			(1.8	)		1.0
Balance end of year			3,509.2			3,507.0			3,228.6
Retained deficit:
	Balance beginning of year		(2,570.6	)		(2,340.6	)		(2,047.9	)
	Net income (loss)		23.9			(230.0	)		(292.5	)
	Other		—			—			(.2	)
Balance end of year			(2,546.7	)		(2,570.6	)		(2,340.6	)
Treasury stock, at cost, 90,063 shares at December 31, 2006 (7 shares at December 31, 2005 and 251 shares at December 31, 2004)			(.4	)		—			—
Accumulated other comprehensive income (loss)			(30.6	)		(.1	)		.8
Total Common Shareholders' Equity		$	1,306.1		$	1,309.9		$	1,130.5

See accompanying notes to consolidated financial statements.

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Aquila, Inc.
Consolidated Statements of Comprehensive Income

		Year Ended December 31,
In millions		2006			2005			2004
Net income (loss)		$	23.9		$	(230.0	)	$	(292.5	)
Other comprehensive income (loss), net of related tax:
Foreign currency adjustments:
Foreign currency translation adjustments, net of deferred tax expense (benefit) of $(.1) million, $(.2) million and $(14.5) million for 2006, 2005 and 2004, respectively			(.1	)		(.3	)		(22.0	)
Reclassification of foreign currency (gains) losses to income due to sale of businesses and other, net of deferred tax (expense) benefit of $.1 million, $(.4) million and $(26.2) million for 2006, 2005 and 2004, respectively			.2			(.6	)		(41.0	)
	Total foreign currency adjustments		.1			(.9	)		(63.0	)
Cash flow hedges:
Unrealized losses on hedging instruments during the period, net of deferred tax benefit of $(1.0) million for 2004			—			—			(1.6	)
Reclassification of net losses on hedging instruments to net income, net of deferred tax benefit of $.8 million for 2004			—			—			1.3
Reclassification of net losses to income on cash flow hedges in equity method investments due to sale, net of deferred tax benefit of $5.5 million for 2004			—			—			9.1
	Total cash flow hedges		—			—			8.8
Decrease in minimum pension liability, net of deferred tax expense of $2.7 million for 2004			—			—			4.4
Other comprehensive income (loss)			.1			(.9	)		(49.8	)
Total Comprehensive Income (Loss)		$	24.0		$	(230.9	)	$	(342.3	)

See accompanying notes to consolidated financial statements.

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Aquila, Inc.
Consolidated Statements of Cash Flows

				Year Ended December 31,
In millions				2006			2005			2004
Cash Flows From Operating Activities:
	Net income (loss)			$	23.9		$	(230.0	)	$	(292.5	)
	Adjustments to reconcile net income (loss) to net cash provided from (used for) operating activities:
		Depreciation and amortization expense			104.8			148.9			150.3
		Restructuring charges			7.7			6.6			.9
		Cash paid for restructuring and other charges			(223.5	)		(2.3	)		(171.2	)
		Net (gain) loss on sale of assets and other charges			(21.0	)		214.9			114.3
		Net changes in price risk management assets and liabilities			69.7			(61.2	)		107.9
		Deferred income taxes and investment tax credits			(33.8	)		(81.5	)		(194.7	)
		Changes in certain assets and liabilities, net of effects of divestitures:
			Restricted cash		9.8			11.8			232.9
			Funds on deposit		157.0			88.2			43.7
			Accounts receivable/payable, net		57.8			(102.3	)		27.4
			Inventories and supplies		27.8			(33.3	)		(10.4	)
			Other current assets		23.9			13.5			(22.7	)
			Deferred charges and other assets		3.8			(13.8	)		30.4
			Accrued interest and other accrued liabilities		(86.2	)		16.8			(107.8	)
			Customer funds on deposit		(58.4	)		54.6			(235.9	)
			Deferred credits		(4.1	)		18.8			(8.0	)
			Other		.9			(1.2	)		(6.1	)
Cash provided from (used for) operating activities					60.1			48.5			(341.5	)
Cash Flows From Investing Activities:
	Utilities capital expenditures				(191.9	)		(228.9	)		(219.4	)
	Investments in communication services				(8.2	)		(11.4	)		(14.0	)
	Cash proceeds received on sale of assets				1,003.7			36.0			1,267.9
	Other				(22.0	)		(4.4	)		(8.2	)
Cash provided from (used for) investing activities					781.6			(208.7	)		1,026.3

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

		Year Ended December 31,
In millions		2006			2005			2004
Cash Flows From Financing Activities:
	Premium on the retirement of long-term debt		(28.2	)		—			—
	Issuance of common stock		—			—			112.3
	Issuance of long-term debt		—			2.0			551.2
	Retirement of long-term debt		(574.7	)		(45.9	)		(943.9	)
	Short-term borrowings (repayments), net		(12.0	)		12.0			(215.0	)
	Cash paid on long-term gas contracts		(15.7	)		(15.0	)		(623.1	)
	Other		2.7			1.0			1.3
Cash used for financing activities			(627.9	)		(45.9	)		(1,117.2	)
Increase (decrease) in cash and cash equivalents			213.8			(206.1	)		(432.4	)
Cash and cash equivalents at beginning of year (includes $4.8 million, $6.6 million and $60.9 million of cash included in current assets of discontinued operations in 2006, 2005 and 2004, respectively)			19.0			225.1			657.5
Cash and Cash Equivalents at End of Year (includes $4.8 million and $6.6 million of cash included in current assets of discontinued operations in 2005 and 2004, respectively)		$	232.8		$	19.0		$	225.1
Supplemental cash flow information:
	Interest paid, net of amount capitalized	$	209.0		$	223.1		$	299.7
	Income taxes paid (refunded), net		(15.9	)		28.8			21.1

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, Kansas and Missouri. Our electric generation facilities and purchase power contracts supply electricity to our own distribution systems in these three states. We also sell a small amount of excess power to wholesale customers outside our service areas. During peak periods, we buy energy in the wholesale market for our utility load. Our Kansas electric utility is currently held for sale 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 Michigan, Missouri and Minnesota gas operations were sold on April 1, 2006, June 1, 2006 and July 1, 2006, respectively and have been reclassified as discontinued operations.

        Our Merchant Services business operates as Aquila Merchant Services, Inc. (Aquila Merchant), which, until we began to wind down these operations during the second quarter of 2002, marketed natural gas, electricity and other commodities throughout North America and Western Europe. Aquila Merchant contractually controls one non-regulated merchant power plant, and owns the remaining contracts in our energy trading portfolio. Two of our former merchant peaking plants were sold on March 31, 2006 and have been reclassified as discontinued operations. Our former investments in 13 independent power plants were sold in the first quarter of 2004. Two of these plants that were consolidated are also reported in discontinued operations.

        Corporate and Other includes the costs of the Company that are not allocated to our operating businesses. We also formerly owned investments in the United Kingdom and Canada, which we sold in January 2004 and May 2004, respectively, and which are reported in discontinued operations. Our former communications business, Everest Connections, was sold on June 30, 2006 and is reported in discontinued operations.

        We also owned and operated electric utilities in two Canadian provinces, which were sold in May 2004 and are 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 20 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, 2006 and 2005, and the reported amounts of sales and expenses during the three years ended December 31, 2006. 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

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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 45% of our employees are represented by local unions under collective bargaining agreements. The collective bargaining agreements covering approximately 70% of those employees expire and are subject to renegotiation in 2007.

Principles of Consolidation

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

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

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

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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, 2006. We concluded that the goodwill was not impaired. At December 31, 2006, we had goodwill in continuing operations of $113.6 million, less accumulated amortization of $2.6 million.

        Our goodwill was allocated to each segment as follows:

In millions		Total Continuing Operations— Electric Utilities		Total Discontinued Operations
Balance, December 31, 2003		$	111.0	$	229.5
	Sales of businesses		—		(218.2	)
	Exchange rate change		—		(11.3	)
Balance, December 31, 2004			111.0		—
	Other		—		.3
Balance, December 31, 2005			111.0		.3
	Reserve for minority market-based puts		—		2.7
	Sale of Everest Connections		—		(3.0	)
Balance, December 31, 2006		$	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

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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," 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.

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Income Taxes

        We use the liability method to reflect income taxes on our financial statements. We recognize deferred tax assets and liabilities by applying enacted tax rates and regulations to the differences between the carrying value of existing assets and liabilities and their respective tax basis and capital loss and tax credit carryforwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change is enacted. We amortize deferred investment tax credits over the lives of the related properties. We assess the realizability of deferred tax assets for capital and operating loss carryforwards and provide valuation allowances when we determine it is more likely than not that such losses will not be realized within the applicable carryforward period. See Note 15 for further discussion.

Environmental Matters

        We accrue environmental costs on an undiscounted basis when it is probable that a liability has been incurred and the liability can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. If it is probable that we will receive regulatory recovery, we record these costs as a regulatory asset.

Legal Costs

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

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, 2006 and 2005, our cash held in foreign countries was $3.9 million and $3.0 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 2006 presentation. In particular, as discussed in Note 6, certain assets that have been classified as held for sale and the results of operations from those assets have been reclassified as discontinued operations in the accompanying balance sheets and statements of income for all periods presented.

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Note 2: New Accounting Standards

Conditional Asset Retirement Obligations

        In March 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations—An Interpretation of SFAS No. 143", which clarifies the term "conditional asset retirement obligation" used in SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143), and specifically when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 effective December 31, 2005. As further discussed in Note 8, the adoption of FIN 47 had no impact on our results of operations but did result in the recognition of $.2 million of additional property, plant and equipment, $8.4 million of asset retirement obligations and an offsetting regulatory asset of $8.2 million.

Accounting Changes and Error Corrections

        In May 2005, the FASB issued SFAS 154, which replaces APB Opinion No. 20, "Accounting Changes", and SFAS No. 3 "Reporting Accounting Changes in Interim Financial Statements." SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS 154 has not had a material impact on our financial statements.

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 are currently evaluating the impact SFAS 157 may have 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 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.

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Accounting for Uncertainty in Income Taxes

        In July 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes", effective for fiscal years beginning after December 15, 2006. This interpretation sets a "more likely than not" threshold that must be met before a tax benefit can be recognized in our financial statements. Our practice prior to FIN 48 was to recognize tax benefits when their ultimate realization was deemed to be "probable." We adopted FIN 48 effective January 1, 2007. Based upon our analysis of the impact of adoption we reduced our reserve for uncertain tax positions by $175.4 million which resulted in net deferred tax assets of $156.1 million. The primary deferred tax asset was the tax benefit related to our net operating loss carryforwards. We were required to assess the ultimate realization of deferred tax assets generated from net operating losses and capital losses incurred on the sale of assets using a "more likely than not" assessment of realization. This assessment took into consideration tax planning strategies within our control. This assessment, however, does not take into consideration the expected taxable gains, both capital and ordinary, from the pending sales of our Kansas and Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska properties. In addition, the assessment did not take into consideration the pending merger with Great Plains Energy. Lastly, the assessment also did not take into consideration the expected results from filed rate cases or debt reductions expected to be completed after the sale of our Kansas electric property.

        Since the implementation of FIN 48 resulted in a net deferred tax asset position and the primary deferred tax asset relates to net operating loss carryovers, we recorded a valuation allowance of $156.1 million against the tax benefit related to the net operating loss carryovers equal to the net deferred tax assets.

        The net effect of the implementation of FIN 48 including the adjustment for related valuation allowance was effected through an increase of $19.3 million to beginning retained earnings in the first quarter of 2007.

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 is 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.

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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

        During the second half of 2002, Aquila Merchant began exiting from the wholesale energy trading business. Because of this decision, it liquidated many of its energy trading contracts in the market. However, it was not able to liquidate all of its contracts. Aquila Merchant is no longer a market maker and no longer trades to take advantage of market trends and arbitrage opportunities.

        Prior to the decision to exit this 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 three 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 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 2006, our continuing regulated electric business generated approximately 53% of the power that we sold and purchased the remaining 47% through long-term contracts or in the open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have ECAs that serve a purpose similar to that of the PGAs for the gas utilities. To the extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, there is no provision to pass through changes in costs except through a rate case filing. Variability in the cost of natural gas and coal used for the production of electricity and the price of power purchased in the open

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market can impact the stability of utility earnings. We manage this commodity risk through a purchasing strategy designed to minimize the effect of variability in energy costs on earnings.

        We 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 value of the portfolio, a loss of $17.9 million, relates to contracts that will settle against actual purchases of natural gas and purchased power in 2007 through 2009. In connection with the recently settled Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they settle. A regulatory asset has been recorded under SFAS 71 in the amount of $17.9 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 Merchant and Utilities financial instruments at December 31, 2006 are below:

		December 31, 2006
Dollars in millions		Fixed Price Payor	Fixed Price Receiver	Maximum Term in Years
Energy Commodities:
	Natural gas (trillion Btu's)	90	41	4
	Heating oil (barrels)	105,000	7,000	2
Financial Products:
	Interest rate instruments	$.3	$.6	15

        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, 2006, using market interest rates for the contract term adjusted for our credit rating for liabilities or the credit rating of the counterparty for assets. We continuously monitor the portfolio and value it daily based on present market conditions. The following table

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displays the fair values of Merchant and Utilities price risk management assets and liabilities at December 31, 2006, and the average value for the year ended December 31, 2006:

	Price Risk Management Assets				Price Risk Management Liabilities
In millions	Average Value		December 31, 2006		Average Value		December 31, 2006
Natural gas	$	212.7	$	114.7	$	177.2	$	98.6
Electricity		6.1		—		4.2		—
Coal		1.8		—		—		—
Other		.3		—		3.9		3.0
Total	$	220.9	$	114.7	$	185.3	$	101.6

        Our price risk management assets are concentrated with six counterparties representing 82% of the total asset value of the portfolio. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Hedging Activities

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

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

Cash Flow Hedges

        Changes in the fair value of a derivative that is designated and qualifies as a cash flow hedge are recorded in OCI to the extent that the derivative is effective as a hedge. As of December 31, 2006, we did not have any outstanding cash flow hedges.

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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,
		2006		2005		2004
Merchant Services:
	Severance costs	$	—	$	—	$	.7
	Lease agreements		—		6.6		—
Total Merchant Services			—		6.6		.7
Corporate and Other severance costs			5.7		—		.2
Total restructuring charges		$	5.7	$	6.6	$	.9

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 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

        In connection with the sale of our Kansas electric and Michigan, Minnesota and Missouri gas utility operations, during the first quarter of 2006 our management adopted and communicated to employees a plan to reduce corporate and central services costs, which includes 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 estimated total cost of one-time termination benefits is approximately $5.7 million, which was recognized in 2006 over the remaining service period of terminated employees and will be 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.

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        We incurred severance and other related costs of $.9 million in 2004 related to the continued exit from our Merchant Services business and the sale of our investments in international networks.

Restructuring Reserve Activity

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

		Year Ended December 31,
In millions		2006			2005			2004
Severance and Retention Costs:
	Accrued severance and retention costs at beginning of period	$	.1		$	.8		$	.9
	Additional expense during the period		7.7			—			.9
	Cash payments during the period		(5.5	)		(.7	)		(1.0	)
Accrued severance and retention costs at end of period		$	2.3		$	.1		$	.8
Other Restructuring Costs:
	Accrued other restructuring costs at beginning of period	$	—		$	7.0		$	16.0
	Additional expense during the period		—			6.6			—
	Cash payments during the period		—			(13.6	)		(9.0	)
Accrued other restructuring costs at end of period		$	—		$	—		$	7.0

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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, 2006, 2005 and 2004 are shown below:

		Year Ended December 31,
In millions		2006		2005			2004
Merchant Services:
	Elwood tolling contract	$	218.0	$	—		$	—
	Batesville tolling agreement		—		(16.3	)		—
	ICE sale		—		(9.3	)		—
	Aries power project and tolling agreement		—		—			46.6
	Termination of long-term gas contracts		—		—			156.2
	Red Lake gas storage development project		—		(6.2	)		8.9
	Independent power plants		—		—			(6.1	)
	Investment in BAF Energy		—		(.7	)		(9.1	)
	Enron bankruptcy		—		—			(6.0	)
	Marchwood development project		—		—			(5.0	)
	Other		.7		1.2			—
Total Merchant Services			218.7		(31.3	)		185.5
Corporate and Other:
	Early retirement of debt		28.2		—			—
	Early conversion of the PIES		—		82.3			—
	Everest Connections target-based put rights		—		—			(4.5	)
	Midlands		—		—			(3.3	)
	Turbines impairment		—		4.4			10.6
Total Corporate and Other			28.2		86.7			2.8
Total net loss on sale of assets and other charges		$	246.9	$	55.4		$	188.3

        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 2006, 2005 and 2004, we also incurred net loss (gain) on sale of assets and other charges of $(267.9) million, $159.5 million and $(74.0) 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 June 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 expect to treat the $218 million payment as an ordinary loss on our 2006 income tax return. However, because we have not concluded that it is probable that the IRS will agree with this treatment, we have increased our reserve for uncertain tax positions by $84.6 million, thereby fully offsetting the tax benefit of the loss. We have evaluated the impact of FIN 48 on our financial statements, and based on this analysis we

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recognized this tax benefit through a reduction of our reserve for uncertain tax positions when we adopted FIN 48 in the first quarter of 2007.

Batesville Tolling Contract

        In February 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.

ICE Sale

        In February 2005, we sold our 4.5% interest in Intercontinental Exchange, 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.

Aries Power Project and Tolling Agreement

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

Termination of Long-Term Gas Contracts

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

        In 2004, we terminated four long-term gas contracts, which included three American Public Energy Agency (APEA) contracts, two of which the Chubb Group of Insurance Companies provided surety bonds and our Municipal Gas Authority of Mississippi (MGAM) contract, for which St. Paul/Travelers provided surety bonds. As a result, we were required to pay APEA, Chubb, St. Paul/Travelers and MGAM approximately $712.9 million under the liquidated damages and other provisions of the gas supply contracts and termination agreements. We recorded a pretax charge of $156.2 million, or $97.6 million after tax, on the termination of these four contracts.

Red Lake Storage Development Project

        In January 2002, we acquired land in Mohave County, Arizona, for development of two salt cavern natural gas storage facilities. In December 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. On August 31, 2005, we executed an agreement to sell the land to a real estate development company for $21.2 million. The transaction closed in November 2005. We recorded a pretax gain on this transaction of $6.2 million, or $3.9 million after tax, in the fourth quarter of 2005.

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Independent Power Plants

        In November 2003, we agreed to sell our interests in 12 independent power plants. Two of the power plants were consolidated on our balance sheet. Therefore, in accordance with SFAS 144, we have reported the results of operations and assets of these two plants in discontinued operations. See Note 6 for further explanation.

        The remaining plants were equity method investments that did not qualify for reporting as discontinued operations under SFAS 144 and were therefore included in continuing operations. In the third quarter of 2003, we evaluated the carrying value of these equity method investments based on the bids received and other internal valuations. The results of this assessment indicated that these investments were impaired. Therefore, we recorded a pretax impairment charge of $87.9 million, or $69.9 million after tax, to reduce the carrying value of our investments to their estimated fair value. This sale closed in March 2004. We received adjusted proceeds of approximately $256.9 million and paid approximately $4.1 million in transaction fees. As the actual proceeds were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $6.1 million, or $22.6 million after tax in 2004. The after-tax gain was greater than the pretax gain because an income tax benefit of $16.2 million was recognized for the reversal of a valuation allowance provided in 2003. The 2003 valuation allowance was provided as it was expected that a substantial portion of the loss would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale and detailed allocation of the purchase price for tax purposes based on an independent appraisal resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in 2004.

Investment in BAF Energy

        We own a 23.11% non-voting limited partnership interest in BAF Energy, a California limited partnership that formerly owned a 120 MW natural gas-fired combined cycle cogeneration facility in King City, California. In May 2004, Calpine King City Cogen, LLC purchased 100% of the King City cogeneration facility from BAF Energy. Our share of the proceeds, approximately $24.3 million, was received as a distribution from the partnership in June 2004. As a result of the distribution, we recorded a pretax gain of $9.1 million, or $5.7 million after tax, in the second quarter of 2004. In 2005, we received a final distribution which resulted in a pretax gain of $.7 million, or $.4 million after tax.

Enron Bankruptcy

        On March 7, 2005, we reached an agreement with Enron Corp. and certain of its affiliates (Enron). Under this agreement, we paid $28 million to Enron to settle all outstanding claims between Enron and Aquila associated with the various bankruptcy filings of Enron in December 2001 and two lawsuits filed by Enron Canada Corp. in January 2003. In 2001, we reserved for substantially all of our then outstanding receivables from Enron, which resulted in a charge of $66.8 million. This charge did not reflect potential gains we would record in the event we were successful in netting certain obligations to Enron against these receivables. Approximately $33.5 million of liabilities remained on our books related to contracts with Enron after the 2001 charge. As a result of the settlement, we reduced our net liability to Enron by approximately $6.0 million, or $3.7 million after tax.

Marchwood Development Project

        In January 2004, we sold undeveloped land and site licenses for a proposed merchant power plant development project in the United Kingdom for approximately $5.0 million. As a final

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decision to proceed with construction of this project had not been made, all project development costs had been expensed as incurred. As a result, the pretax gain on the sale was equal to the net proceeds of $5.0 million, or $3.1 million after tax.

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.

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.

Everest Connections Target-Based Put Rights

        Certain minority owners of Everest Connections had the option to sell their ownership units to us if Everest did not meet certain financial and operational performance measures as of December 31, 2004 (target-based put rights). If the put rights were exercised, we would have been obligated to purchase up to 4.0 million and 4.75 million ownership units at a price of $1.00 and $1.10 per unit, respectively, for a total potential cost of $9.2 million. As a result of our reduced funding of this business, management assessed the likelihood of achieving these metrics and during 2002 recorded a probability-weighted expense of $7.1 million. In 2004, Everest achieved the operating targets related to 4.0 million and 1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million pretax and after tax of this liability. We did not achieve the targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their option and were paid $3.6 million for their ownership units in February 2005. We had fully reserved for this payment as of December 31, 2004.

Midlands

        In October 2003, we and FirstEnergy Corp. agreed to sell 100% of the shares in Aquila Sterling Limited (ASL), the owner of Midlands Electricity plc, for approximately £36 million. As a result of this agreement and our analysis of fair value surrounding this investment, in the third quarter of 2003 we recorded a $4.0 million pretax and after-tax impairment charge to write this investment down to its estimated fair value. We completed the sale of ASL in January 2004, received proceeds of $55.5 million and paid approximately $7.6 million in transaction fees. We recorded a pretax and after-tax gain from this sale of approximately $3.3 million in 2004 due to strengthening in the British pound exchange rate in the fourth quarter of 2003 and early 2004.

Turbines Impairment

        In December 2004, we determined that the carrying value of three Westinghouse Siemens natural gas combustion turbines held by one of our non-regulated subsidiaries was impaired. These turbines were transferred from the non-regulated subsidiary to our Missouri regulated electric division for the construction of our South Harper peaking facility. Missouri affiliate

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transaction rules require that such transfers be made at the lower of fair market value or fully distributed cost. We obtained an appraisal of the fair value of the turbines, which was less than the carrying value of the turbines and related costs. As a result, we recorded a pretax impairment charge of approximately $10.6 million, or $6.5 million after tax. The transfer was subject to the final determination of the Missouri Commission. In connection with our rate case filed in July 2005 and settled in February 2006, we agreed to lower 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.

Note 6: Discontinued Operations

        In response to significant changes in the energy industry, we undertook a strategic review of our business in the second quarter of 2002 and announced a change in our strategic direction. Our revised strategy features a concentrated focus on our 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 since 2002 to generate cash to be used to reduce debt and eliminate other long-term obligations. We have sold, or are in the process of selling, 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

        On September 21, 2005, we entered into asset purchase agreements to sell our Kansas electric distribution business and our Michigan, Minnesota and Missouri natural gas distribution businesses.

        The sale of our Michigan, Minnesota and Missouri gas utility assets resulted in, and the sale of our Kansas electric utility division is expected to result in, pretax and after tax gains. The Michigan, Minnesota and Missouri sales also resulted in, and the Kansas electric sale is expected to result in, gains for tax purposes. 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 have been reversed. The tax gains will be adjusted when final determinations are made and as income tax returns are filed in the third quarter of 2007.

        On April 1, 2006, we closed the sale of our Michigan gas operations and received gross cash proceeds of $314.9 million, including the base purchase price of $269.5 million plus preliminary working capital and other adjustments of $45.4 million. During the third quarter, we received $25.0 million as part of the working capital and other adjustments "true up." We are currently working to resolve the remaining adjustments, the largest of which relates to the value of gas in storage. We recorded a reserve of $2.4 million for expected resolution of this issue. These items are expected to be resolved during the first quarter of 2007. In connection with this sale we have recorded a pretax gain of approximately $92.2 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below and the value of gas in storage. The estimated after-tax gain 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.

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        On June 1, 2006, we closed the sale of our Missouri gas operations and received gross cash proceeds of $102.1 million, including the base purchase price of $85.0 million plus preliminary working capital and other adjustments of $17.1 million. The working capital and other adjustments were "trued up" in the fourth quarter of 2006 through a final payment of $.2 million to the buyer. In connection with this sale we recorded a pretax gain of approximately $30.7 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below. The estimated after-tax gain 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.

        On July 1, 2006, we closed the sale of our Minnesota gas operations and received gross cash proceeds of $333.3 million, including the base purchase price of $288.0 million plus preliminary working capital and other adjustments of $45.3 million. We paid $16.9 million as part of the working capital and other adjustments "true up." In connection with this sale we recorded a pretax gain of approximately $120.5 million after transaction fees and expenses, subject to the final determination of pension assets transferred to the buyer as discussed below. The estimated after-tax gain 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 August 2006, we and the buyer amended the asset purchase agreement relating to the sale of our Kansas electric utility assets. Under the amendment, the base purchase price payable by the buyer will be reduced by an amount equal to (i) the book value of our 8% interest in the Jeffrey Energy Center associated with our Kansas electric utility assets (the JEC Interest), plus (ii) $2 million, or a net base price of $235.3 million. The parties also agreed not to terminate the asset purchase agreement before October 2, 2006 (subsequently extended by the parties to April 16, 2007) if the only closing conditions that remain unsatisfied relate to the receipt of regulatory approvals. The asset sale depends on several conditions being satisfied, including: (i) the non-occurrence of a material adverse event, as described in the asset purchase agreement; and (ii) the other closing conditions set forth in the asset purchase agreement. On February 23, 2007, the Kansas Commission issued an order approving the settlement agreement signed in connection with the sale of our Kansas electric operations. We expect this sale to close by April 1, 2007. The Kansas electric employees are expected to be transferred to the buyer upon completion of the sale, upon the terms and conditions contained in the asset purchase agreement.

        In August 2006, we and Westar entered into a transfer agreement whereby we will transfer the JEC Interest to Westar, rather than to the buyer as originally contemplated by the asset purchase agreement described above. Westar will acquire the JEC Interest from us for a purchase price equal to the book value of the JEC Interest, minus $3.5 million, or a net base price of $14.4 million. The closing of this transaction is subject to, among other things, (i) the closing of the sale of our Kansas electric utility assets; and (ii) the consent of certain financial parties with ownership or other interests in the JEC Interest. We expect this transfer to close by April 1, 2007.

        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. 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

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necessary to maintain ongoing operations until the sales are final and cannot be eliminated immediately upon closing of the asset sales. We have eliminated the majority of these costs following the closing of the Michigan, Minnesota and Missouri gas operations. The allocated operating costs related to the utility divisions held for sale were as follows:

	Year Ended December 31,
In millions	2005		2004
Allocated expenses of Kansas electric and Michigan, Minnesota and Missouri gas retained in continuing operations	$	42.3	$	39.6

        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 or will assume upon closing the accrued pension obligations owed to the current and former employees of the operations they acquired or are acquiring. After closing, benefit plan assets were or will be transferred to comparable plans established by the buyers in accordance with the terms of the asset purchase agreements and the applicable requirements of the ERISA. We expect these benefit plan asset transfers to result 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 are estimated to be approximately $5.6 million. The effect of the plan curtailments will depend on the final determination of the asset transfers, which will not be completed until 2007.

Merchant Peaking Power Plants

        In December 2005, two of our subsidiaries agreed to sell to AmerenUE the Goose Creek Energy Facility and Raccoon Creek Energy Facility. The Goose Creek Energy Facility is a 510 MW natural gas-fired, simple-cycle peaking power plant in Piatt County, Illinois, and the Raccoon Creek Energy Facility is a 340 MW natural gas-fired, simple-cycle peaking power plant in Clay County, Illinois. In connection with the sale of these facilities, we determined that they should be classified as "held for sale" and included in discontinued operations, rather than "held and used" as they had previously been classified. As a result, we reassessed the realizability of the carrying value of our investments in these facilities and concluded that they were impaired. We based this conclusion on the anticipated net sale proceeds of the sale transactions described above.

        In the fourth quarter of 2005, based on the expected net sale proceeds and transaction-related costs, we recorded a pretax non-cash impairment charge of approximately $93.6 million and $65.9 million for the Goose Creek Energy Facility and the Raccoon Creek Energy Facility, respectively, or an after-tax loss of approximately $58.5 million and $41.2 million, respectively. We expect to receive an aggregate book tax benefit on the asset sales of approximately $59.8 million (tax calculation on the pre-tax loss of approximately $159.5 million), although there will be no immediate cash tax receivable on the asset sales due to our net operating loss carryovers. On March 31, 2006, we closed the sales of these facilities and received gross proceeds of $175 million.

Everest Connections

        In the fourth quarter of 2005, we began a sales process for our Everest Connections communications business. Based on the level of bidder participation and the bid valuations, we

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determined that the business should be classified as "held for sale" and included it in discontinued operations.

        In March 2006, our subsidiary, Everest Global Technologies Group, LLC (EGTG), agreed to sell to Everest Connections Holdings, Inc., an acquisition subsidiary of Seaport Capital Partners III, L.P., certain EGTG subsidiaries conducting its communications business for a base purchase price of $85.7 million. On June 30, 2006, EGTG closed the sale and received net cash proceeds of $80.2 million after the repayment of $6.8 million of direct debt of Everest Connections and including working capital and other adjustments of approximately $1.3 million. The working capital and other adjustments were "trued up" in the third quarter of 2006 through a final payment of $.2 million to the buyer. We expect net proceeds available to be approximately $76 million, after payment of transaction costs and certain amounts owed to EGTG minority partners. In connection with this sale we recorded a pretax gain of approximately $25.5 million after transaction fees and expenses. The estimated after-tax gain was approximately $15.7 million.

Interest Allocation to Discontinued Operations

        The buyers of our former Michigan, Minnesota and Missouri gas utility divisions, Illinois peaking facilities and Everest Connections did not assume, and the buyer of our held-for-sale Kansas electric utility division will not assume any of our long-term debt. Other than $6.8 million of direct debt of Everest Connections, none of our long-term debt was required to be repaid with the proceeds of these asset sales although the lenders of our $220 million five-year term loan (see Note 11) had the opportunity to elect prepayment without premium from the proceeds of utility asset sales. These lenders did not elect prepayment with regard to the proceeds of the Michigan or Minnesota gas utility sales, but one lender elected to receive prepayment of $10 million from the proceeds of the Missouri gas utility sale. The direct debt and related interest of Everest Connections was included in discontinued operations. 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 with EITF 87-24. The amount of interest expense allocated to discontinued operations may not be representative of the actual interest reductions we may achieve from future debt retirements using the proceeds of the asset sales. As we complete each asset sale the allocation of interest to discontinued operations ceases, thereby increasing interest expense in continuing operations, without impacting total interest expense, until the sales proceeds are used to reduce debt.

Canada

        On May 31, 2004, we completed the sale of our Canadian utility operations in Alberta and British Columbia to two subsidiaries of Fortis Inc. for approximately $1.08 billion (CDN$1.476 billion), including the assumption of debt of $113 million (CDN$155 million) by the purchasers. The closing proceeds included $85 million (CDN$116 million) of adjustments for working capital and capital expenditures. We recorded a pretax gain from this sale of $65.6 million, or $9.1 million after tax, including final working capital and capital expenditure adjustments.

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

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

Independent Power Plants

        In November 2003, we agreed to sell our interests in 12 independent power plants. Two of the power plants were consolidated on our balance sheet. We have reported the results of operations and assets of these two plants in discontinued operations. In the third quarter of 2003, we evaluated the carrying value of these assets based on the bids received and other internal valuations. The results of this assessment indicated these assets were impaired. We recorded a pretax impairment charge of $47.5 million, or $39.8 million after tax, to reduce the carrying value of these assets to their estimated fair value less costs to sell. We closed the sale of these plants in March 2004. Because the actual proceeds realized were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $8.4 million, or $16.2 million after tax, in the first quarter of 2004. The after-tax gain was greater than the pretax gain because an income tax benefit of $11.1 million was recognized for the partial reversal of a valuation allowance provided in 2003. The 2003 valuation allowance was provided as it was expected that a substantial portion of the loss would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale and a detailed allocation of the purchase price for tax purposes based on an independent appraisal resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in 2004.

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Summary

        We have reported the results of operations from these assets in discontinued operations for the three years ended December 31, 2006 in the Consolidated Statements of Income.

        Operating results of discontinued operations are as follows:

		Year Ended December 31,
In millions		2006			2005			2004
Sales		$	516.4		$	879.8		$	870.9
Cost of sales			343.3			608.0			518.1
Gross profit			173.1			271.8			352.8
Operating expenses:
	Operation and maintenance expense		71.5			104.8			159.3
	Taxes other than income taxes		10.8			7.3			23.7
	Restructuring charges		2.0			—			—
	Net loss (gain) on sale of assets and other charges		(267.9	)		159.5			(74.0	)
	Depreciation and amortization expense		.9			42.5			47.5
Total operating expenses (income)			(182.7	)		314.1			156.5
Other income (expense):
	Other income		.1			.5			3.5
	Interest expense		34.6			71.2			88.6
Earnings (loss) before income taxes			321.3			(113.0	)		111.2
Income tax expense (benefit)			15.4			(41.0	)		55.4
Earnings (loss) from discontinued operations		$	305.9		$	(72.0	)	$	55.8

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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, 2006 and 2005 Consolidated Balance Sheets as follows:

		December 31,
In millions		2006		2005
Current assets of discontinued operations:
	Cash and cash equivalents	$	—	$	4.8
	Accounts receivable, net		13.0		160.5
	Inventories and supplies		5.7		81.0
	Other current assets		7.8		22.7
Total current assets of discontinued operations		$	26.5	$	269.0
Non-current assets of discontinued operations:
	Utility plant, net	$	236.6	$	610.6
	Non-utility plant, net		—		220.8
	Prepaid pension		—		26.6
	Regulatory assets		28.9		16.7
	Other non-current assets		20.6		23.2
Total non-current assets of discontinued operations		$	286.1	$	897.9
Current liabilities of discontinued operations:
	Current maturities of long-term debt	$	—	$	1.3
	Other current liabilities		1.4		29.3
Total current liabilities of discontinued operations		$	1.4	$	30.6
Non-current liabilities of discontinued operations:
	Long-term debt, net	$	—	$	6.2
	Pension and post-retirement benefits		17.7		6.5
	Deferred credits		18.2		50.8
Total non-current liabilities of discontinued operations		$	35.9	$	63.5

Note 7: Accounts Receivable

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

	December 31,
In millions	2006			2005
Merchant Services accounts receivable	$	40.8		$	173.5
Utilities billed accounts receivable		130.3			131.4
Unbilled utility revenue		84.4			101.2
Other accounts receivable		6.3			2.9
Allowance for doubtful accounts		(4.8	)		(9.3	)
Total	$	257.0		$	399.7

        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

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operations in Colorado, Iowa, Kansas, Missouri and Nebraska. We had no borrowings outstanding under this facility as of December 31, 2006. See Note 10 for further discussion.

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

Note 8: Utility and Non-Utility Plant

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

Utility Plant		December 31,
In millions		2006			2005
Electric utility		$	2,186.7		$	2,084.4
Gas utility			661.2			634.1
Corporate and other			252.0			251.3
Electric and gas utility plant—construction in process			61.8			35.0
			3,161.7			3,004.8
Less—accumulated depreciation and amortization			(1,336.6	)		(1,262.9	)
	Total utility plant, net	$	1,825.1		$	1,741.9

Non-Utility Plant		December 31,
In millions		2006			2005
Non-regulated electric and gas plant		$	3.2		$	5.4
Non-regulated electric power generation			135.2			135.2
Corporate and other			29.6			30.0
			168.0			170.6
Less—accumulated depreciation and amortization			(37.8	)		(35.2	)
	Total non-utility plant, net	$	130.2		$	135.4

        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

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continuing operations not included in our rate base were $19.8 million and $22.9 million at December 31, 2006 and 2005, respectively.

	Composite Depreciation Rates
	2006		2005		2004
Continuing Operations—
Electric utility	2.8	%	2.6	%	2.7	%
Gas utility	2.7	%	3.2	%	3.3	%
Corporate and other	11.3	%	11.3	%	11.6	%
Non-regulated electric power generation	2.8	%	2.8	%	2.8	%
Discontinued Operations—
Electric utility	n/a		3.3	%	3.0	%
Gas utility	n/a		2.7	%	2.6	%
Non-regulated electric power generation	n/a		2.8	%	2.8	%
Communications	n/a		9.2	%	9.0	%

        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 and lease another 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) currently being constructed by KCPL. Concurrent with the sale of our Kansas electric utility, our 8% leased interest in the Jeffrey Energy Center will transfer to Westar. This leased interest represents approximately $21.0 million of our total net investment in the Jeffrey plant as of December 31, 2006. 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, 2006 was as follows:

In millions	Jeffrey Energy Center			Iatan 1			Iatan 2
Utility plant	$	136.2		$	67.4		$	—
Construction in progress		1.6			6.8			18.6
		137.8			74.2			18.6
Less: Accumulated depreciation and amortization		(76.7	)		(48.2	)		—
Jointly-owned utility plant, net	$	61.1		$	26.0		$	18.6

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, 2006, 2005 and 2004, our continuing Electric and Gas Utilities recorded approximately $1.9 million, $5.3 million and $3.0 million, respectively, of additional income and construction work in progress related to

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AFUDC. The non-cash earnings are classified as other income (expense) in our Consolidated Statements of Income. The increase in AFUDC in 2005 primarily related to the construction of our South Harper peaking facility.

        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. This standard became effective for us on January 1, 2003.

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

        In 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 FAS 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.

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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 $10.4 million and $9.3 million as of December 31, 2006 and 2005, 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. Concurrent with the adoption of SFAS 143, the net provision for these "non-legal" removal costs has been reclassified from accumulated depreciation, where it has been recorded previously, to a regulatory liability. See Note 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.

        The following table details our regulatory assets and liabilities.

		December 31,
In millions		2006		2005
Regulatory Assets:
	Under-recovered gas costs	$	25.3	$	27.7
	Income taxes		55.8		59.3
	Environmental		3.1		2.2
	Regulatory accounting orders		3.2		5.8
	Gas price derivatives		17.9		—
	Asset retirement obligations		10.2		9.2
	Pensions and post-retirement benefits		50.2		—
	Other		12.3		6.5
	Total regulatory assets	$	178.0	$	110.7
Regulatory Liabilities:
	Cost of removal	$	52.3	$	48.4
	Income taxes		4.0		5.3
	Revenue subject to refund		.4		1.5
	Over-recovered gas costs		10.4		28.8
	Gas price derivatives		—		20.7
	Pensions		10.4		9.9
	Other		1.0		1.0
Total regulatory liabilities		$	78.5	$	115.6

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

•

Under-recovered gas costs represent the cost of gas delivered to our gas utility customers in excess of that allowed in current rates. We do not earn a return on these costs which are collected from customers in future periods of less than one year as rates are periodically adjusted.



•

Income taxes represent amounts of accelerated tax benefits previously flowed through to customers and expected to be collected from customers over the remaining life of the utility plant as accelerated tax benefits reverse. We do not earn a return on these items.



•

Environmental costs include certain site clean-up costs that are deferred and expected to be collected from customers in future periods when authorized by regulatory authorities. Prudently incurred environmental remediation costs have traditionally been allowed for recovery by our regulatory jurisdictions over periods of five to 10 years. We do not earn a return on these items.



•

Regulatory accounting orders include costs such as ice storm recovery and others that have been specifically approved for recovery over future periods, generally five years or less. We do not earn a return on these items.



•

In connection with adoption of SFAS 158 we reflected the unrecognized prior service cost and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans as regulatory assets rather than accumulated other comprehensive income in jurisdictions where we believe it is probable we will recover these costs in future rates. Whether we earn a return on these costs, in addition to the return of these costs, varies by jurisdiction.



•

Asset retirement obligations represent the estimated recoverable costs for legally required removal obligations. See Note 8 for further discussion. We do not earn a return on these items.



•

Gas price derivatives represents the mark-to-market value of the portfolio of natural gas financial contracts that will settle against actual purchases of natural gas and purchased power in future periods. In connection with the recently settled Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they settle. A regulatory asset has been recorded under SFAS 71 to reflect the change in the timing of recognition authorized by the Missouri Commission.



•

Other primarily includes costs related to energy efficiency, demand side management and regulatory proceedings that are deferred and expected to be recovered from customers in future periods. Prudent costs such as these have traditionally been allowed for recovery by our regulatory jurisdictions over various periods. We do not earn a return on these items.

        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:

•

Cost of removal represents the estimated cumulative net provision for future removal costs included in depreciation expense for which there is no legal removal obligation. See Note 8 for further discussion.



•

Income taxes generally represent taxes previously collected at tax rates that were greater than the rates we expect to pay. We expect to refund this amount to customers in future periods.

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•

Revenue subject to refund represents revenues collected from customers under interim rate orders that we expect to return to customers. This amount is estimated by management based on the particular facts and circumstances of the cases and the historical actions of the regulatory jurisdictions.



•

Over-recovered gas costs represent the cost of gas paid by gas utility customers in allowed rates in excess of actual costs incurred. These costs will be returned to customers in future periods as rates are periodically adjusted.



•

Gas price derivatives represents the mark-to-market value of the portfolio of natural gas financial contracts that will settle against actual purchases of natural gas and purchased power in future periods. In connection with the recently settled Missouri electric rate case, we agreed that these contracts would be recognized into cost of sales when they settle. A regulatory liability has been recorded under SFAS 71 to reflect the change in the timing of recognition authorized by the Missouri Commission.



•

Pensions represent the cumulative excess of pension costs recovered in rates over pension expense recorded under SFAS No. 87, "Employers' Accounting for Pensions" (SFAS 87). We expect to return this amount to customers in future periods through reduced cost of service in rates.

        In addition, our discontinued Electric Utilities had recognized $28.9 million of regulatory assets and $1.7 million of regulatory liabilities as of December 31, 2006.

        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 $12.0 million in short-term borrowings outstanding under our four-year secured revolving credit facility on December 31, 2005. No short-term borrowings were outstanding on December 31, 2006.

Five-Year Unsecured Revolving Credit Facility

        In September 2004, we completed a $110 million 364-day unsecured revolving credit facility. This facility automatically extended to September 2009 when we received extension approval from the FERC and various state public utility commissions (the Five-Year Unsecured Revolving Credit Facility). There were no borrowings outstanding on this facility as of December 31, 2006. The Five-Year Unsecured Revolving Credit Facility bears interest at the LIBOR plus 5.75%, 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, 2006.

        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.

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$180 Million Unsecured Revolving Credit and Letter of Credit Facility

        On April 13, 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, 2006, 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, 2006, $108.3 million of the available capacity had been utilized for letters of credit under this facility.

Four-Year Secured Revolving Credit Facility

        On April 22, 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 $12.0 million under this facility as of December 31, 2005 at a rate of 7.75%. No borrowings were outstanding under this facility as of December 31, 2006.

        The accounts receivable of our Michigan and Missouri gas businesses were released in 2006 upon closing of those asset sales, which reduced our borrowing base under the AR Facility. We subsequently pledged our Iowa utility receivables as collateral in 2006 to increase our borrowing capacity under this facility. As we close the sale of our Kansas electric business, the accounts receivable generated by this utility will be released from the AR Facility and the maximum borrowing limit may be reduced.

$50 Million Revolving Credit and Letter of Credit Facility

        On January 13, 2006, we closed on a $50 million short-term letter of credit facility with a commercial lender, which was originally scheduled to terminate on December 20, 2006, that allows us to either issue letters of credit or make cash drawings under the facility. This facility, which initially included a 2.50% advance rate on letters of credit, is expected to be nearly fully utilized through letter of credit issuances. The credit agreement also contains a $40 million "cross default" provision. In November 2006, we entered into amendments to extend the maturity date to December 19, 2007 and lower the advance rate to 1.07%. There were $48.1 million of letters of credit outstanding under this facility as of December 31, 2006.

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Note 11: Long-Term Debt

This table summarizes our long-term debt:

		December 31,
In millions		2006		2005
First Mortgage Bonds:
	9.44% Series, due annually through 2021 (a)	$	16.9	$	18.0
Unsecured Term Loan:
	LIBOR plus 5.75% (9.9913% at December 31, 2005)		—		220.0
Senior Notes:
	6.70% Series, due October 15, 2006		—		85.9
	8.2% Series, due January 15, 2007		14.6		36.9
	7.625% Series, due November 15, 2009		68.5		199.0
	9.95% Series, due February 1, 2011		137.3		250.0
	7.75% Series, due June 15, 2011		197.0		197.0
	14.875% Series, due July 1, 2012		500.0		500.0
	8.27% Series, due November 15, 2021		80.9		80.9
	9.0% Series, due November 15, 2021		5.0		5.0
	8.0% Series, due March 1, 2023		51.5		51.5
	7.875% Series, due March 1, 2032		287.5		287.5
Medium Term Notes:
	Various, 7.19%*, due 2013-2023		17.0		17.0
Mandatorily Convertible Notes:
	6.75% Series, mandatorily convertible on September 15, 2007 into common shares at a conversion rate of 8.0386 to 9.8039 shares per $25 par value convertible note		2.6		2.6
Convertible Subordinated Debentures:
	6.625%, due July 1, 2011 (convertible into 126,182 common shares at $15.79 per share)		2.0		2.1
Other:
	Other notes and obligations 5.16%*, due 2007-2028 (a)		24.8		26.1
Total long-term debt			1,405.6		1,979.5
Less current maturities			19.7		88.3
Long-term debt, net		$	1,385.9	$	1,891.2
Fair value of long-term debt, including current maturities (b)		$	1,600.5	$	2,199.1

*

Weighted average interest rate.



(a)

Approximately $36.1 million of our long-term debt, including $19.2 million of other notes, is secured by certain assets of the Company as specified in various mortgages, indentures and security agreements.



(b)

The fair value of long-term debt is based on current rates at which we could borrow funds with similar remaining maturities.

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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 Amounts
2007 (a)		$	19.7
2008			2.5
2009			71.0
2010			1.9
2011			337.5
Thereafter			973.0
	Total	$	1,405.6

(a)

Includes the non-cash, mandatory conversion of $2.6 million of PIES to common stock on September 15, 2007.

        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. Under the offer, the total consideration paid in exchange for the notes was based either on a fixed spread over the yield to maturity of a U.S. Treasury reference security or on a fixed price basis. 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 two percent of the debt tendered.

        In June 2006, we completed the cash tender offer, 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		$	84.5
8.2% Notes due 1/15/2007			22.3
7.625% Notes due 11/15/2009			130.5
9.95% Notes due 2/01/2011			112.7
	Total	$	350.0

Mandatorily Convertible Senior Notes

        In August 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 bear interest at 6.75% through September 15, 2007. Unless converted earlier by the holder into our common stock, on September 15, 2007, these securities automatically convert into shares of our common stock at a conversion rate ranging from 8.0386 to 9.8039 shares of common stock per PIES unit, based on the average closing price of our

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common stock for the 20-day trading period prior to the mandatory conversion date. Our net proceeds on the issuance of the PIES were $334.3 million, after underwriting discounts, commissions and other costs. The proceeds were used to retire long-term debt and other long-term liabilities.

        In June 2005, we announced an exchange offer related to the optional conversion of our PIES into shares of our common stock. Pursuant to the offer, holders of the PIES units would receive 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. In July 2005, the 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.

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, our Iatan Facility, our Five-Year Unsecured Revolving Credit Facility and our Four-Year Secured Revolving Credit Facility will be lowered.

Three-Year Secured Term Loan

        In April 2003, we closed on a $430.0 million, three-year secured loan. The initial interest rate on the facility was LIBOR (with a 3% floor) plus 5.75%. This rate was reduced to LIBOR (with a 3% floor) plus 5.00% when additional regulated utility collateral was pledged. In addition, we were required to pay up-front arrangement fees of $17.8 million. Proceeds from the financing were used to retire debt and support letters of credit.

        The secured term loan became immediately due and payable in September 2004 when we did not refinance or retire 80% of our $150.0 million, 6.875% senior note series due October 1, 2004. We paid our lenders an early termination fee of 2%, or $8.7 million, pursuant to this provision. We also wrote off $10.3 million of unamortized debt issue costs.

Five-Year Unsecured Term Loan

        In September 2004, we completed a $220 million 364-day unsecured term loan. This facility automatically extended to September 2009 when we received extension approval from the FERC and various state public utility commissions (the Five-Year Unsecured Term Loan). We borrowed the full amount of the term loan and received $211.3 million of net proceeds after upfront fees

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and expenses on the two facilities. 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 utility operations. In September 2006, we elected to prepay the remaining $210 million outstanding and paid a 2.5% prepayment fee of approximately $5.5 million.

Iatan Construction Financing

        On August 31, 2005, we entered into a $300 million credit agreement with a commercial lender and a syndicate of other lenders (the Iatan Facility). The credit agreement 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 the Iatan 2 facility being developed by KCPL near Weston, Missouri (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 LIBOR plus a margin determined by our credit ratings. 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, 2006. Among other restrictions, the Iatan Facility contains the following financial covenants with which we were in compliance as of December 31, 2006:

(1)

We are required to maintain a ratio of total debt to total capital (expressed as a percentage) of not more than 75% through September 30, 2008; 70% from October 1, 2008 through September 30, 2009; and 65% thereafter.

(2)

We must maintain a trailing 12-month ratio of EBITDA, as defined in the agreement, to interest expense of no less than 1.3 to 1.0 from October 1, 2006 through September 30, 2007; 1.4 to 1.0 from October 1, 2007 through September 30, 2008; 1.6 to 1.0 from October 1, 2008 through September 30, 2009; and 1.8 to 1.0 thereafter.

(3)

We must maintain a trailing 12-month ratio of debt outstanding to EBITDA of no more than 7.5 to 1.0 from October 1, 2006 through September 30, 2007; 6.0 to 1.0 from October 1, 2007 through September 30, 2008; 5.5 to 1.0 from October 1, 2008 through September 30, 2009; and 5.0 to 1.0 thereafter.

(4)

We must maintain a ratio of mortgaged property to extensions of credit (borrowings plus outstanding letters of credit) of no less than 2.0 to 1.0 as of the last day of each fiscal quarter.

        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

        Our non-investment grade credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and the execution of our commercial strategies. Our financial flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment grade borrowers.

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        As of December 31, 2006, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

Agency	Rating	Outlook
Moody's	B2	Stable Outlook
S&P	B	Positive Outlook
Fitch	B+	Stable Outlook

        In February 2007, in conjunction with the announcement of our pending merger with Great Plains Energy, the rating agencies reviewed our ratings and took the following actions:

•

S&P affirmed our ratings and credit watch positive outlook,



•

Moody's placed our ratings on review for possible upgrade, and



•

Fitch affirmed our ratings and assigned a ratings watch positive outlook.

        We discuss the pending merger in more detail in Note 20 to the Consolidated Financial Statements.

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

Secured Financing

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

        In addition, we are required to obtain prior approval from the FERC before we can issue long-term or short-term debt. We currently have authority from the FERC to have up to $500 million of short-term debt outstanding from time to time. Our authority to issue short-term debt expires in April 2008. The FERC recently issued an order in which it announced that any future debt authorization orders would prohibit companies subject to its jurisdiction from using their utility properties as collateral for loans unless the loan proceeds will be used to support their utility operations.

        Except in limited circumstances, holders of our senior notes and bonds, which represent the majority of our unsecured obligations, do not have the right to restrict our use of collateral or to be equally or ratably secured if we provide collateral to other creditors. The terms of our Five-Year Unsecured Revolving Credit Facility and Iatan Facility prohibit us from pledging our assets as collateral except in certain circumstances.

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.

Equity Offerings

        In August 2004, we sold 46.0 million shares of our common stock to the public, including an over-allotment option of 6.0 million shares, which raised $112.3 million in net proceeds. We used the proceeds of this offering to retire long-term debt and reduce other long-term liabilities.

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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. This decision followed a detailed analysis of the Company's then current financial condition, its liquidity forecast and its earnings prospects after completion of certain asset sales. 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.

Aquila Merchant Dissenters' Rights

        In January 2002, we completed an exchange offer and merger in which we acquired all the outstanding publicly-held shares of Aquila Merchant in exchange for shares of Aquila common stock. The public shareholders of Aquila Merchant received .6896 shares of Aquila common stock in a tax-free exchange for each outstanding share of Aquila Merchant Class A common stock. Aquila Merchant shareholders holding approximately 1.7 million shares of Aquila Merchant Class A shares exercised dissenters' rights to request an appraisal of the fair value of their shares with respect to the merger. In June 2004, we paid approximately $38 million, including interest from 2002, to settle this litigation. This resulted in the recognition of additional expense of $8.8 million including litigation costs in 2004.

Stockholder Rights Plan

        The rights plan adopted by our Board of Directors previously expired in December 2006. We do not expect to adopt a new stockholders rights plan.

Retirement Investment Plan

        A defined contribution plan, the Retirement Investment Plan (Savings Plan), covers all of our full-time and eligible part-time employees. Participants may generally elect to contribute up to 50% of their annual pay on a before- or after-tax basis subject to certain limitations. The Company generally matches contributions up to 6% of pay. Participants may direct their contributions into various investment options. Matching contributions are made in cash and invested as directed by the employee. Company contributions for continuing operations were $6.4 million, $6.3 million and $6.6 million and for discontinued operations were $1.2 million, $1.9 million and $1.8 million during the years ended December 31, 2006, 2005, and 2004, 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. Vesting occurs ratably over five years of employment with distribution upon termination of employment. For 2006, 2005 and 2004, compensation expense for continuing operations of $3.9 million, $3.7 million and $3.4 million, respectively, and for discontinued operations of $.4 million, $1.0 million and $.9 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.

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

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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. In December 2004, we granted fully vested stock options for approximately 1.9 million shares to all employees other than senior executive officers of the Company. These options are exercisable for seven years from the date of grant. Cash received on stock options exercised was $2.0 million, the intrinsic value of options exercised was $3.3 million and the tax benefit realized was $.5 million for the year ended December 31, 2006. As of December 31, 2006, we have approximately 5.7 million shares of common stock available for grant under this plan and preceding plans.

        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 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 have elected to use the modified prospective method to adopt SFAS 123R. The estimated 2006 impact of the adoption of SFAS 123R was immaterial.

        We issue 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:

		Year Ended December 31,
In millions, except per share amounts		2005			2004
Net loss:
	As reported	$	(230.0	)	$	(292.5	)
	PIES adjustment (Note 14)		12.6			9.4
Loss available for common shares			(217.4	)		(283.1	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax benefits		(1.9	)		(9.3	)
	Pro forma loss available for common shares	$	(219.3	)	$	(292.4	)
Basic and diluted loss per share:
	As reported	$	(.60	)	$	(1.13	)
	Pro forma		(.60	)		(1.16	)

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

	Year Ended December 31,
	2005		2004
Weighted average fair value per share	$	2.08	$	2.25
Expected volatility		83%		83%
Risk-free interest rate		3.82%		3.40%
Expected lives		3.7 years		3.7 years
Dividend yield		—		—

Summary of Stock Options

        This table summarizes all stock option activity:

	Year Ended December 31,
	2006		2005		2004
Shares:
Beginning balance	6,545,607		9,638,099		8,558,048
Granted	—		30,000		1,900,760
Exercised	(779,852	)	(308,763	)	(472,591	)
Forfeited	(899,889	)	(2,813,729	)	(348,118	)
Ending balance	4,865,866		6,545,607		9,638,099
Weighted average prices:
Beginning balance	$14.92		$17.73		$20.22
Granted price	—		3.44		3.75
Exercised price	2.61		2.28		4.06
Forfeited price	21.95		25.76		21.57
Ending balance	$15.57		$14.92		$17.73

        This table summarizes all outstanding and exercisable stock options as of December 31, 2006:

		Outstanding Options				Exercisable Options
Exercise Price Range		Number	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number	Weighted Average Exercise Price
$1.44-1.83		711,406	2.97	$	1.81	711,406	$	1.81
$3.44-3.75		1,366,430	4.99		3.75	1,366,430		3.75
$18.50-24.90		1,951,135	1.59		21.60	1,951,135		21.60
$28.42-39.52		836,895	4.24		32.68	836,895		32.68
	Total	4,865,866				4,865,866

        The aggregate intrinsic value of "in-the-money" outstanding and exercisable options was $6.4 million as of December 31, 2006.

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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 will vest two years after the award date and have no restrictions on the sale of the shares thereafter. The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock. The compensation expense related to these awards was $.4 million for year ended December 31, 2006. As of December 31, 2006, the total compensation cost not yet realized was $.2 million. This deferred compensation cost is reflected as a deduction from our premium on capital stock and will be recognized over the period through December 31, 2007. The total fair value of restricted stock released for the year ended December 31, 2006 was $1.1 million. Non-vested, time-based restricted stock awards and changes for the three years ended December 31, 2006 were as follows:

	Year Ended December 31,
	2006		2005		2004
Shares:
Beginning balance	632,210		453,326		526,000
Awarded	—		183,823		—
Released	(273,695	)	(4,939	)	(72,674	)
Forfeited	(7,000	)	—		—
Ending balance	351,515		632,210		453,326
Weighted average prices:
Beginning balance	$17.81		$23.64		$24.32
Awarded price	—		3.59		—
Released price	19.47		24.19		28.56
Forfeited price	3.60		—		—
Ending balance	$16.79		$17.81		$23.64
Remaining Contractual Terms in Years	.97		1.33		2.04

        The aggregate intrinsic value of outstanding time-based restricted stock was $1.7 million as of December 31, 2006.

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 are met. The performance measure for the award is the ratio of 2007 annual EBITDA to 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 is reached, 50% if the threshold is reached, and 150% if the ratio is 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. The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock on date of the award. An estimated annual turnover rate of 8% was assumed to determine the compensation expense related to this award. The compensation expense related to this award was $.1 million for the year ended December 31, 2006. As of December 31, 2006, the estimated total compensation cost

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not yet recognized was $.4 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. Non-vested, performance-based restricted stock awards (based on target number) as of December 31, 2006 and changes during the year ended December 31, 2006 were as follows:

	Shares	Weighted average award date fair value		Remaining Contractual Term in Years
Beginning balance	—	$	—
Awarded	176,000		4.44
Released	—		—
Forfeited	—		—
Ending balance	176,000	$	4.44	1.25

        The aggregate intrinsic value of outstanding performance-based restricted stock was $.8 million as of December 31, 2006.

Director Stock Awards

        Non-employee directors receive as part of his or her annual retainer, an annual award of 7,500 shares of 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 expense is based upon the fair market value of the Company's common stock at the date of issuance.

	Year Ended December 31,
	2006		2005		2004
Shares:
Beginning balance	211,187		164,312		113,687
Awarded	50,625		56,250		65,625
Released	(53,440	)	(9,375	)	(15,000	)
Ending balance	208,372		211,187		164,312
Weighted average prices:
Beginning balance	$4.33		$4.51		$4.85
Awarded price	4.30		3.71		3.73
Released price	3.83		3.71		3.75
Ending balance	$4.45		$4.33		$4.51

        The aggregate intrinsic value of outstanding director stock awards was $1.0 million as of December 31, 2006.

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Note 13: Accumulated Other Comprehensive Income (Loss)

        The table below reflects the activity for accumulated other comprehensive income (loss) for 2004, 2005 and 2006:

In millions	Foreign Currency Adjustments			Cash Flow Hedges			Minimum Pension Liability			Unrecognized Pension and Post- retirement Benefit Costs			Accumulated Other Comprehensive Income (Loss)
Balance December 31, 2003	$	63.8		$	(8.8	)	$	(4.4	)	$	—		$	50.6
2004 change		(63.0	)		8.8			4.4			—			(49.8	)
Balance December 31, 2004		.8			—			—			—			.8
2005 Change		(.9	)		—			—			—			(.9	)
Balance December 31, 2005		(.1	)		—			—			—			(.1	)
2006 Change		.1			—			—			—			.1
Effect of SFAS 158 adoption		—			—			—			(30.6	)		(30.6	)
Balance December 31, 2006	$	—		$	—		$	—		$	(30.6	)	$	(30.6	)

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

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. Weighted average shares used in basic earnings (loss) per share includes 110.9 million shares issuable on the conversion of the mandatorily convertible PIES from August 24, 2004, the date of issuance of the PIES. On July 7, 2005, approximately 98.9% of the PIES units were converted to 131.4 million shares of common stock pursuant to an exchange offer. See Note 11 for further discussion. 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 net losses in 2005 and 2004, the potential issuances of common stock for dilutive securities were considered anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share. There was no significant dilutive effect on Aquila's earnings (loss) per share from other securities in 2006.

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		Year Ended December 31,
In millions, except per share amounts		2006			2005			2004
Loss from continuing operations		$	(282.0	)	$	(158.0	)	$	(348.3	)
Interest and debt amortization costs associated with the PIES			.2			12.6			9.4
Loss available for common shares from continuing operations			(281.8	)		(145.4	)		(338.9	)
Earnings (loss) from discontinued operations			305.9			(72.0	)		55.8
Income (loss) available for common shares and assumed conversions		$	24.1		$	(217.4	)	$	(283.1	)
Basic and diluted earnings (loss) per share:
	Loss available for common shares from continuing operations	$	(.75	)	$	(.40	)	$	(1.35	)
	Earnings (loss) from discontinued operations		.81			(.20	)		.22
	Basic and diluted income (loss) per share	$	.06		$	(.60	)	$	(1.13	)
Weighted average number of common shares used in earnings (loss) per share			375.08			363.30			251.35
Effect of dilutive stock options and restricted stock units			.37			—			—
Weighted average number of common shares used in diluted earnings (loss) per share			375.45			363.30			251.35

Note 15. Income Taxes

        Loss from continuing operations before income taxes consisted of:

		Year Ended December 31,
In millions		2006			2005			2004
Domestic		$	(347.7	)	$	(183.2	)	$	(560.9	)
Foreign			(1.6	)		(17.9	)		(1.7	)
	Total	$	(349.3	)	$	(201.1	)	$	(562.6	)

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

			Year Ended December 31,
In millions			2006			2005			2004
Current:
	Federal		$	(11.4	)	$	—		$	—
	Foreign			(4.8	)		(2.6	)		(.5	)
	State			(2.0	)		—			—
Deferred:
	Federal			(105.0	)		(20.7	)		(168.9	)
	Foreign			(1.3	)		(5.1	)		—
	State			(34.5	)		(3.7	)		(29.9	)
	Change in valuation allowance			3.0			(53.2	)		(8.1	)
	Change in reserve for uncertain tax positions			89.7			43.5			(5.4	)
	Investment tax credit amortization			(1.0	)		(1.3	)		(1.5	)
Income tax benefit from continuing operations				(67.3	)		(43.1	)		(214.3	)
Income tax expense (benefit) from discontinued operations:
Current				—			—			36.3
Deferred (net of valuation allowance reversals of $(112.6) million and $(11.1) million in 2006 and 2004, respectively)				15.4			(41.0	)		19.1
Income tax expense (benefit) from discontinued operations				15.4			(41.0	)		55.4
		Total	$	(51.9	)	$	(84.1	)	$	(158.9	)

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

			December 31,
In millions			2006			2005
Deferred Tax Assets:
	Alternative minimum tax credit carryforward		$	92.3		$	103.6
	U.S. net operating loss carryforward			596.9			449.9
	Mark-to-market losses			8.0			14.9
	Accrued bonuses and deferred compensation			6.8			8.4
	Pension and post-retirement benefit obligations			36.8			—
	Asset impairments			—			73.4
	Realized capital loss carryforward for income tax purposes			109.0			225.7
	Unrealized capital losses			11.3			11.3
	Other			8.9			14.8
	Less: reserve for uncertain tax positions			(377.3	)		(287.6	)
	Less: valuation allowance			(139.7	)		(248.9	)
Total deferred tax assets				353.0			365.5
Deferred Tax Liabilities and Credits:
	Accelerated depreciation and other plant differences:
		Regulated		269.9			306.2
		Non-regulated		16.1			42.4
	Prepaid pension costs			—			29.7
	Regulatory asset-pension and post-retirement benefit costs			28.5			—
	Regulatory asset-income taxes			50.8			54.0
	Other			7.0			4.7
Total deferred tax liabilities and credits				372.3			437.0
Deferred income taxes and credits, net			$	19.3		$	71.5

        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,
		2006		2005		2004
Statutory Federal Income Tax Rate		(35.0	)%	(35.0	)%	(35.0	)%
Tax effect of:
	State income taxes, net of federal benefit	(3.8	)	(1.7	)	(3.8	)
	Benefit of state net operating loss apportionment	(4.8	)	—		—
	Deferred tax adjustments to returns	(2.6	)	—		—
	Change in valuation allowance	.9		(26.4	)	(1.5	)
	Reserve for uncertain tax positions	25.7		21.6		(.8	)
	Non-deductible loss on PIES exchange	—		14.3		—
	Non-deductible interest and amortization of PIES	.1		2.2		.6
	Other	.2		3.6		2.4
Effective Income Tax Rate		(19.3	)%	(21.4	)%	(38.1	)%

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Tax Credits

        At December 31, 2006 and 2005, we had alternative minimum tax credit carryforwards of $92.3 million and $103.6 million, respectively. These credits do not expire and can be used to decrease future cash tax payments. In addition, at December 31, 2006 and 2005, we had general business tax credit carryforwards of $6.9 million and $6.7 million, respectively. The substantial majority of the general business credits expire in 2018, after which time they become a deduction against taxable income instead of a credit against tax. We did not record valuation allowances against the deferred tax asset related to the general business credits as we believe that more likely than not they will be utilized.

Capital Loss Carryforwards

        As of December 31, 2006 and 2005, respectively, we had approximately $283.9 million and $588.1 million, respectively, of net realized capital loss carryforwards available for federal income tax purposes that expire in 2008 and 2009 and recognized impairment charges of $29.4 million and $29.4 million, respectively, that we expect to realize (for income tax purposes) as capital losses when a related partnership is liquidated. The tax benefit of these carryforwards and impairments is reflected on our balance sheets as of December 31, 2006 and 2005, as deferred tax assets of $120.3 million and $237.0 million, respectively. The decrease in capital loss carryforwards and valuation allowance from 2005 to 2006 is primarily due to the release of $112.6 million of valuation allowance due to capital gains recognized on the sale of our Michigan, Minnesota and Missouri gas operations in 2006 and $4.1 million of capital gains and valuation allowance adjustments related to our 2005 income tax returns.

        We are required to assess the ultimate realization of deferred tax assets generated from capital losses using a "more likely than not" assessment of realization. This assessment takes into consideration tax planning strategies within our control. This assessment, however, does not take into consideration the expected capital gains from pending sales of our Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska gas properties. As a result of such assessment, we determined that it was more likely than not that deferred tax assets relating to capital losses would not be realized. Therefore, we have established full valuation allowances of $120.3 million and $237.0 million, respectively, against these tax benefits as of December 31, 2006 and 2005, respectively.

Net Operating Loss Carryforwards

        As of December 31, 2006, we had approximately $454.5 million of federal net operating loss carryforwards originating in 2003, $579.0 million originating in 2004, $195.3 million of originating in 2005 and an estimated $227.6 million originating in 2006. 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. At December 2006 and 2005, we had recorded deferred tax benefits of $596.9 million and $449.9 million, respectively, related to our cumulative net operating loss carryforwards. Included in these amounts are deferred tax benefits of $86.9 million and $58.1 million related to state net operating losses as of December 31, 2006 and 2005, respectively. The state net operating loss carryforwards expire in various years.

        We are required to assess the ultimate realization of deferred tax assets generated from net operating losses and capital losses incurred on the sale of assets using a "more likely than not" assessment of realization. This assessment takes into consideration tax planning strategies within our control. This assessment, however, does not take into consideration the expected taxable

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ordinary gains from the pending sales of our Kansas and Colorado electric properties and our Colorado, Kansas, Iowa and Nebraska gas properties. In addition, the assessment does not take into consideration the pending merger with Great Plains Energy. Lastly, the assessment also does not take into consideration the expected results from filed rate cases or debt reductions expected to be completed after the sale of our Kansas electric property.

        We did not record valuation allowances against the deferred tax assets related to the federal net operating losses as we believe it is more likely than not that sufficient taxable income to utilize these losses during the carryforward period will be generated from continuing operations, including the reversal of deferred tax liabilities on our regulated business. In addition, the reserve for uncertain tax positions offsets the deferred tax assets related to a significant portion of the net operating losses.

        However, as of December 31, 2006 and 2005 we have recorded a valuation allowance related to state net operating losses of $19.4 million and $11.9 million, respectively. During 2006, we recorded additional valuation allowance of $8.0 million related to state tax benefits from net operating losses and an adjustment for 2005 state income tax returns filed in 2006 and wrote off $.5 million of deferred tax assets and related valuation allowance in states where we no longer operate. During 2005, we recorded additional valuation allowance of $2.6 million related to state tax benefits from net operating losses and an adjustment for 2004 state income tax returns filed in 2005. We also wrote off $2.6 million of deferred tax assets and related valuation allowance because we no longer operate in certain states. This valuation allowance is necessary because we believe that it is more likely than not that we will not realize the deferred tax assets related to these state net operating losses during the applicable carryforward periods. This assessment considered the decline in future business activity in certain states and the taxable income we expect to generate in the applicable state carryforward periods.

        After reduction of our reserve for uncertain tax positions pursuant to FIN 48 in the first quarter of 2007, we had net deferred tax assets of $156.1 million. The primary deferred tax asset was the tax benefit related to our net operating loss carryforwards. In conjunction with the implementation, we recorded a valuation allowance against the tax benefit related to the net operating loss carryovers in an amount equal to the $156.1 million of net deferred tax assets. This adjustment offset the $175.4 million decrease to the reserve for uncertain tax positions and was effected through a net increase of $19.3 million to beginning retained earnings in the first quarter of 2007.

Reserve for Uncertain Tax Positions

        As of December 31, 2006 and 2005, we have recorded liabilities of $377.3 million and $287.6 million, respectively, of cumulative tax provisions for tax deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is reasonably likely that these deductions or income positions will be challenged when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The reserve is included in deferred taxes because the timing of the resolution of these audits is uncertain and if the positions taken on the tax returns are not ultimately sustained, we may be required to make cash payments plus interest and/or utilize our net operating loss carryforwards, alternative minimum tax credit carryforwards, and/or general business credit carryforwards. The increase of $89.7 million in 2006 is primarily related to the loss on assignment of our obligations under the Elwood tolling agreement discussed in Note 5. See discussion above of the effects of implementing FIN 48 in the first quarter of 2007.

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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 2006 and 2005 we recorded interest and amortization of debt issue costs on our PIES of $.2 million and $12.6 million, respectively. No tax benefits were recorded as these costs were not deductible for income tax purposes.

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 regulated 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 are currently analyzing the impact of the Pension Protection Act on our pension plans.

        In February 2005, we amended our pension and other post-retirement benefit plans to bring our benefits into line with our regulated utility peers. The effect of these amendments on our projected pension benefit obligation and accumulated post-retirement benefit obligation was an increase of $40.9 million and $24.8 million, respectively, as of our most recent measurement date, September 30, 2005. This unrecognized prior service cost is recognized prospectively as a component of net periodic benefit cost, amortized on a straight-line basis over the average future service of active plan participants.

        As discussed in Note 2, we adopted SFAS 158 effective December 31, 2006, which required us to separately disclose the items that have not yet been recognized as components of net periodic benefit cost including any net actuarial gain or loss, prior service cost and net transition obligation at December 31, 2006. Most of our regulated utility operations and have historically recovered and currently recover pension and post-retirement benefit plan expense in our rates. In these jurisdictions, we have evaluated whether the SFAS 71 requirements are met and believe that future pension and post-retirement benefit costs are probable of future recovery. Therefore, we have recorded the net actuarial gain or loss, prior service cost and net transition obligation as a regulatory asset for the costs related to the states where future recovery is probable. In operations where we do not meet SFAS 71 requirements, we have recorded these costs in

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accumulated other comprehensive income. The incremental effect of applying SFAS 158 on the individual line items in the consolidated balance sheet at December 31, 2006 is set out below:

In millions	Before Application of SFAS 158		Adjustments			After Application of SFAS 158
Assets
Prepaid pension	$	55.4	$	(55.4	)	$	—
Regulatory assets		98.8		50.2			149.0
Deferred charges and other assets (intangible asset)		61.1		(7.5	)		53.6
Non-current assets of discontinued operations		273.4		12.7			286.1
Liabilities and Shareholders' Equity
Pension and post-retirement benefits, current		—		3.5			3.5
Pension and post-retirement benefits		39.0		33.5			72.5
Deferred income taxes and credits		38.4		(19.1	)		19.3
Non-current liabilities of discontinued operations		23.2		12.7			35.9
Accumulated other comprehensive income (loss)		—		(30.6	)		(30.6	)
Common shareholders' equity		1,336.7		(30.6	)		1,306.1

        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, 2006 and 2005.

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	Pension Benefits						Other Post-retirement Benefits
Dollars in millions	2006			2005			2006			2005
Change in Projected Benefit Obligation:
Benefit obligation at start of year	$	408.9		$	337.6		$	85.4		$	68.2
Service cost		9.3			8.9			.8			.6
Interest cost		20.9			22.0			4.0			5.0
Plan participants' contribution		—			—			7.5			2.2
Amendments		—			40.9			—			24.8
Effects of curtailments		(17.8	)		—			(5.7	)		—
Effects of settlements		(32.9	)		—			(15.6	)		—
Actuarial (gain) loss		10.7			15.1			(13.5	)		(7.8	)
Benefits paid		(17.4	)		(15.6	)		(6.0	)		(7.6	)
Projected benefit obligation at end of year	$	381.7		$	408.9		$	56.9		$	85.4
Change in Plan Assets:
Fair value of plan assets at start of year	$	353.4		$	313.6		$	13.1		$	13.9
Actual return on plan assets		21.8			46.6			(4.2	)		.6
Employer contribution		.8			8.8			13.0			4.0
Transfers		(32.9	)		—			(6.2	)		—
Plan participants' contribution		—			—			7.5			2.2
Benefits paid		(17.4	)		(15.6	)		(6.0	)		(7.6	)
Fair value of plan assets at end of year	$	325.7		$	353.4		$	17.2		$	13.1
Funded status:
Funded status	$	(56.0	)	$	(55.5	)	$	(39.7	)	$	(72.3	)
4th quarter employer contribution		.2			.2			2.6			7.0
Unrecognized transition amount		—			(.6	)		—			10.8
Unrecognized net actuarial loss		—			82.7			—			6.9
Unrecognized prior service cost		—			48.7			—			26.0
Accumulated regulatory gain/loss adjustment		—			7.3			—			(2.0	)
Liability for pension and post-retirement benefits	$	(55.8	)		n/a		$	(37.1	)		n/a
Assets and Liabilities Recognized in the Consolidated Balance Sheets:
Prepaid benefit cost	$	—		$	68.3		$	—		$	—
Pension and post-retirement benefits, current		(.7	)		—			(2.8	)		—
Pension and post-retirement benefits		(46.3	)		(18.9	)		(25.4	)		(17.7	)
Non-current assets of discontinued operations		19.2			26.6			4.0			—
Non-current liabilities of discontinued operations		(8.8	)		(.6	)		(8.9	)		(5.9	)
SFAS 71 regulatory asset		41.7			—			8.5			—
SFAS 71 regulatory liability		(10.1	)		(10.5	)		—			—
Intangible asset		—			7.5			—			—
Amounts Recognized in the Consolidated Statements of Comprehensive Income:
Unrecognized transition amount	$	—			n/a		$	6.7			n/a
Unrecognized net actuarial (gain) loss		69.8			n/a			(10.0	)		n/a
Unrecognized prior service cost		36.9			n/a			19.9			n/a
Accumulated regulatory gain/loss adjustment		2.3			n/a			(2.5	)		n/a
Less: SFAS 71 regulatory assets (continuing and discontinued)		(60.9	)		n/a			(12.5	)		n/a
Accumulated other comprehensive loss		48.1			n/a			1.6			n/a
Provision for deferred taxes		(18.5	)		n/a			(.6	)		n/a
Accumulated other comprehensive loss	$	29.6			n/a		$	1.0			n/a

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	Pension Benefits				Other Post-retirement Benefits
Dollars in millions	2006		2005		2006		2005
Weighted Average Assumptions as of September 30:
Discount rate for expense	5.80	%	6.00	%	5.53	%	6.00	%
Discount rate for disclosure	6.01	%	5.80	%	5.76	%	5.53	%
Expected return on plan assets for expense	8.50	%	8.50	%	7.00	%	7.00	%
Expected return on plan assets for disclosure	8.50	%	8.50	%	7.00	%	7.00	%
Rate of compensation increase	4.40	%	4.40	%	n/a		n/a

        Included in the $381.7 million projected benefit obligation for pension benefits and $325.7 million of fair value of pension plan assets are $16.1 million of estimated transfers to be made to the buyers of our Michigan, Minnesota and Missouri gas operations.

        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 10% in 2006 and decreasing 1% annually until the rate levels out at 5% for years 2011 and thereafter. For prescription drug costs, we used a graded rate starting at 12% in 2006 and decreasing 1% annually until the rate levels out at 5% for years 2013 and thereafter.

	Pension Benefits									Other Post-retirement Benefits
In millions	2006			2005			2004			2006			2005			2004
Components of Net Periodic Benefit Cost:
Service cost	$	9.4		$	8.9		$	7.8		$	.8		$	.6		$	.2
Interest cost		20.9			22.0			19.4			4.0			5.0			4.7
Expected return on plan assets		(26.8	)		(27.6	)		(23.9	)		(.6	)		(1.0	)		(1.0	)
Amortization of transition amount		(.8	)		(.8	)		(1.2	)		1.3			1.5			1.5
Amortization of prior service cost		5.1			4.2			1.1			2.3			2.2			.7
Recognized net actuarial (gain) loss		3.6			4.1			8.1			—			.5			1.7
Net periodic benefit cost before regulatory expense adjustments		11.4			10.8			11.3			7.8			8.8			7.8
Regulatory gain/loss adjustment		4.9			3.4			.2			.8			1.0			.9
SFAS 71 regulatory adjustment		.7			3.9			4.3			—			—			—
Net periodic benefit cost after regulatory expense adjustments		17.0			18.1			15.8			8.6			9.8			8.7
Effect of curtailments and settlements included in gain on sale of assets		13.5			—			—			(.5	)		—			—
Total periodic benefit costs	$	30.5		$	18.1		$	15.8		$	8.1		$	9.8		$	8.7

        In connection with the sale of our Michigan, Minnesota and Missouri gas operations, 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.

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        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 $10.1 million as of December 31, 2006, in accordance with SFAS 71.

        Previously, the Missouri Commission ordered the recognition of actuarial gains/losses for our Missouri-related pension and 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, the Kansas electric utility operations being held for sale 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 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 estimated net loss, 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 $1.4 million, $5.7 million and $2.2 million, respectively. The estimated net loss and 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 are $1.9 million and $2.6 million, respectively. The estimated net loss, 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 estimated net gain, 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 $(.4) million, $.4 million, $2.3 million and $1.1 million, respectively.

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

In millions	2006			2005
Accumulated Benefit Obligations in Excess of Plan Assets:
Fair value of plan assets at end of year	$	—		$	—
Accumulated benefit obligation at end of year		17.9			19.5
Funded status (a)	$	(17.9	)	$	(19.5	)

(a)

The SERP is reflected as an unfunded accumulated benefit obligation as plan assets are not netted against the obligations for non-qualified plans. We have segregated approximately $4.4 million of assets for the SERP as of December 31, 2006. We expect to fund estimated future benefit payments from these assets and company contributions as needed.

        The accumulated benefit obligation for all our defined benefit pension plans was $339.0 million and $361.7 million at September 30, 2006 and 2005, respectively.

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        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.

Pension Plan Investment Objectives

1.

We desire to maintain an appropriately funded status of the defined benefit pension plan. This implies an investment posture that is intended to increase the probability of investment performance exceeding the actuarial assumed rate of return over the long-term.

2.

The investment objective is intended to be strategic in nature. Over the long-term, it is expected to protect the funded status of the Plan, enhance the real purchasing power of Plan assets, and not threaten the Plan's ability to meet currently committed obligations.

3.

Distinct asset classes and investment approaches have unique return and risk characteristics. The combination of asset classes and approaches produces diversification benefits in the form of enhancement of expected return at a given risk level and/or reduction of the risk level associated with a specific expected return.

        Our qualified pension plan weighted-average asset allocations by asset category at September 30, 2006 and 2005 along with the long-term targets and target ranges, are as follows:

		Plan Assets at September 30,				Plan Asset Allocation Targets
		2006		2005		Long-Term		Range
Asset Category:
Core fixed income		20.5	%	19.8	%	21.0	%	5.0-25.0	%
High yield bonds		9.8		9.5		10.0		6.0-10.0
Large cap equities		27.3		28.0		29.0		27.0-37.0
Mid cap equities		10.5		10.2		10.0		8.0-12.0
Small cap equities		3.3		3.4		3.5		2.5-12.0
International equities		14.2		14.3		14.0		10.0-15.0
Emerging markets equities		2.4		2.6		2.5		0.0-5.0
Real estate		9.0		8.5		7.5		5.0-10.0
Private equity		.7		.7		2.5		0.0-5.0
Cash		2.3		3.0		—		—
	Total	100.0	%	100.0	%	100.0	%	100.0	%

        Our other post-retirement benefit plan assets at December 31, 2006 were invested in government securities and short-term investments. At December 31, 2005, the assets were primarily invested in short-term investments and cash equivalents.

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

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        The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase 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, 2006 and our estimated annual pension cost (APC) on the income statement for 2007 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 Assumption Incr.(decr.)		Impact on PBO Incr.(decr.)			Impact on APC Incr.(decr.)
Discount rate	.25	%	$	(12.2	)	$	(1.4	)
Rate of return on plan assets	.25	%		—			(.9	)

        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 discounted benefit payments.

        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 2007

	1 Percentage-Point
In millions	Increase		Decrease
Effect on total of service and interest cost components	$	.1	$	(.1	)
Effect on post-retirement benefit obligation		1.2		(1.2	)

        Based on actuarial projections, we expect to contribute $.7 million and $2.9 million to our defined benefit pension plans and other post-retirement benefit plans, respectively, in 2007. Discretionary contributions in 2007 will be based upon fluctuations in the plan investments and discount rates.

        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 $10 million to our defined benefit plan upon completion of the final plan asset transfers to sustain the funded status of our pension plan.

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

In millions	Pension Benefits		Other Post-retirement Benefits		Medicare Drug Subsidy
Estimated Future Benefit Payments:
2007	$	15.3	$	6.2	$	(.8	)
2008		16.2		6.8		(.9	)
2009		17.3		7.3		(.9	)
2010		18.4		7.6		(.8	)
2011		19.5		7.5		(.7	)
2012-2016		114.2		29.9		(2.1	)

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 three 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 three electric utility divisions into the Electric Utilities reporting segment and our four gas utility divisions into the Gas Utilities reporting segment. The operating results of our Kansas electric division, which is in the process of being sold, and our Michigan, Missouri and Minnesota gas divisions, which were sold on April 1, 2006, June 1, 2006 and July 1, 2006, respectively, have been reclassified to discontinued operations. Merchant Services consists of the residual operations of our Aquila Merchant subsidiary. These operations include its investment in the Crossroads plant and its commitments under long-term gas contracts and the remaining contracts from its wholesale energy trading operations. The operating results of Merchant Services' two Illinois merchant power plants, which were sold on March 31, 2006, have been reclassified to discontinued operations. All other operations are included in Corporate and Other, including the costs not allocated to our operating businesses. The operating results of Everest Connections, which was sold on June 30, 2006, have also been reclassified to discontinued operations.

        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.

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Business Lines

		Year Ended December 31,
In millions		2006			2005			2004
Sales:(a)
Utilities:
	Electric Utilities	$	768.6		$	684.6		$	594.9
	Gas Utilities		610.6			631.1			529.0
Total Utilities			1,379.2			1,315.7			1,123.9
Merchant Services			(9.7	)		(1.6	)		(152.9	)
Corporate and Other			.1			—			—
	Total	$	1,369.6		$	1,314.1		$	971.0

(a)

For the years ended December 31, 2006, 2005 and 2004, respectively, the following (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities sales of $189.0, $191.0 and $165.4; Gas Utilities sales of $300.1, $625.8 and $536.3; Merchant Services sales of $2.2, $17.0 and $8.0; and Corporate and Other sales related to our former Canadian utility businesses and Everest Connections of $25.1, $46.0 and $161.2.

		Year Ended December 31,
In millions		2006			2005			2004
Earnings (Loss) Before Interest, Taxes, Depreciation and Amortization (EBITDA):(a)
Utilities:
	Electric Utilities	$	141.9		$	147.7		$	130.3
	Gas Utilities		44.2			33.6			34.9
Total Utilities			186.1			181.3			165.2
Merchant Services			(244.7	)		(22.6	)		(416.7	)
Corporate and Other			(27.6	)		(103.2	)		(23.8	)
Total EBITDA			(86.2	)		55.5			(275.3	)
Depreciation and amortization			103.9			106.4			102.8
Interest expense			159.2			150.2			184.5
Loss from continuing operations before income taxes		$	(349.3	)	$	(201.1	)	$	(562.6	)

(a)

For the years ended December 31, 2006, 2005 and 2004, respectively, the following (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities EBITDA of $48.1, $47.9 and $31.4; Gas Utilities EBITDA of $279.3, $96.9 and $88.9; Merchant Services EBITDA of $(.8), $(156.1) and $2.4; and Corporate and Other EBITDA relating to our former Canadian utility businesses and Everest Connections of $30.2, $12.0 and $124.6.

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		Year Ended December 31,
In millions		2006			2005		2004
Depreciation and Amortization Expense:(a)
Utilities:
	Electric Utilities	$	70.5		$	64.0	$	60.1
	Gas Utilities		30.4			35.8		35.0
Total Utilities			100.9			99.8		95.1
Merchant Services			4.1			6.3		7.3
Corporate and Other			(1.1	)		.3		.4
	Total	$	103.9		$	106.4	$	102.8

(a)

For the years ended December 31, 2006, 2005 and 2004, respectively, the following depreciation and amortization expense (in millions) have been reclassified to discontinued operations and are not included in the above amounts: Electric Utilities $-, $9.7 and $11.4; Gas Utilities $.9, $16.1 and $19.9; Merchant Services $-, $9.2 and $10.1; and Corporate and Other relating to our former Canadian utility businesses and Everest Connections $-, $7.5 and $6.1.

		December 31,
In millions		2006		2005
Identifiable Assets:(a)
Utilities:
	Electric Utilities	$	2,169.5	$	2,065.7
	Gas Utilities		689.5		1,430.0
Total Utilities			2,859.0		3,495.7
Merchant Services			316.2		918.6
Corporate and other			297.2		216.4
	Total	$	3,472.4	$	4,630.7

(a)

Included in identifiable assets as of December 31, 2006 and 2005, are current and non-current assets of discontinued operations as follows (in millions): Electric Utilities, $312.6 and $273.6; Gas Utilities, $— and $657.3; Merchant Services, $— and $175.0; and Corporate and Other related to Everest Connections, $— and $61.0, respectively.

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		Year Ended December 31,
In millions		2006		2005		2004
Capital Expenditures:(a)
Utilities:
	Electric Utilities	$	148.7	$	175.5	$	96.3
	Gas Utilities		43.3		53.4		50.3
Total Utilities			192.0		228.9		146.6
Merchant Services			—		—		—
Corporate and other			20.2		18.9		95.3
	Total	$	212.2	$	247.8	$	241.9

(a)

Included in the years ended December 31, 2006, 2005 and 2004, respectively, are capital expenditures of discontinued operations as follows (in millions): Electric Utilities, $18.1, $24.3 and $15.5; Gas Utilities, $10.0, $22.6 and $22.2; and Corporate and Other relating to our former Canadian utility businesses and Everest Connections, $8.2, $11.4 and $86.8.

Geographical Information

		Year Ended December 31,
In millions		2006		2005		2004
Sales:(a)
United States		$	1,345.8	$	1,304.3	$	971.0
Canada			23.8		.3		1.3
Other international			—		9.5		(1.3	)
	Total	$	1,369.6	$	1,314.1	$	971.0

(a)

For the years ended December 31, 2006, 2005 and 2004, respectively, the following (in millions) sales have been reclassified to discontinued operations and are not included in the above amounts: United States sales of $516.4, $879.8, and $748.0; Canadian sales of $-, $-, and $122.9.

Note 18: Commitments and Contingencies

Capital Expenditures

        We have made certain construction commitments in connection with our 2007 capital expenditure plan. During 2007, we estimate that our total capital expenditures will be approximately $341.7 million, which does not include any capital expenditures for discontinued operations.

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Commitments

        We have various commitments of our continuing and discontinued operations relating to power, gas and coal supply commitments and lease commitments as summarized below.

In millions		2007		2008		2009		2010		2011		Thereafter		Total
Future minimum payments Continuing Operations—
Facilities and equipment		$	11.1	$	9.2	$	6.5	$	5.1	$	4.3	$	8.8	$	45.0
Other services			.7		.5		—		—		—		—		1.2
Merchant gas transportation obligations			6.2		6.2		6.2		6.2		5.6		17.0		47.4
Regulated business purchase obligations:
	Purchased power obligations		112.7		104.1		106.7		109.3		104.8		45.7		583.3
	Purchased gas obligations		54.7		46.2		35.6		34.1		30.5		60.3		261.4
	Coal and rail contracts		84.3		53.2		25.2		25.9		21.7		118.9		329.2
Future minimum payments Discontinued Operations—
Facilities and equipment			.7		.6		.5		.3		.2		.3		2.6
Jeffrey Energy Center lease			10.6		12.1		12.9		12.9		12.9		45.1		106.5
Regulated business purchase obligations:
	Purchased power obligations		19.8		19.4		11.5		3.5		3.5		3.5		61.2
	Coal and rail contracts		19.3		20.0		20.7		21.4		22.2		122.8		226.4

Operating Lease Obligations

        Future minimum payments include operating leases of coal rail cars, vehicles and office space over terms of up to 20 years. Rent expense for continuing operations for the years 2006, 2005 and 2004 was (in millions), $9.6 $10.9 and $13.1, respectively, and for discontinued operations was $1.8 $3.4 and $6.5, respectively.

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

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 2006, our continuing electric utility operations generated 53% 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.

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Contingent Obligations

Guarantees

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

        We have entered into various agreements that require letters of credit for financial assurance purposes. These letters of credit are available to fund the payment of such obligations. At December 31, 2006, we had $157.2 million of letters of credit outstanding with expiration dates generally ranging from one month to 27 months.

        In the normal course of business, we guarantee certain payment obligations of our wholly-owned subsidiaries.

Equity Put Rights

        Certain minority owners of Everest Connections had the option to sell their ownership units to us if Everest Connections did not meet certain financial and operational performance measures as of December 31, 2004 (target-based put rights). If the target-based put rights were exercised, we would have been obligated to purchase up to 4.0 million and 4.75 million ownership units at a price of $1.00 and $1.10 per unit, respectively, for a total potential cost of $9.2 million. As a result of our reduced funding of this business, management assessed the likelihood of achieving these metrics and during 2002 recorded a probability-weighted expense of $7.1 million. In 2004, we achieved the operating targets related to 4.0 million and 1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million of this liability. 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. We did not achieve the targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their options and were paid $3.6 million for their ownership units in February 2005.

        The minority owners notified us that they 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

Price Reporting Litigation

        On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, alleging that the companies manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market. The suit does not specify alleged damages and was filed on behalf of all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002. The suit was certified as a class-action lawsuit. In 2006, we paid $6.59 million to settle this case. This settlement is subject to approval of the court.

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        On June 7, 2004, the City of Tacoma, Washington, filed suit against 56 companies, including Aquila Merchant, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in violation of the Sherman Act. This case was dismissed in February 2005. The City of Tacoma has appealed to the Ninth Circuit Court of Appeals.

        On July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies and their subsidiaries and affiliates, including Aquila and Aquila Merchant, in the Superior Court of California for San Diego County alleging manipulation of the California natural gas market in 1999 through 2002. Since that date, 14 other complaints making nearly identical allegations have been filed against Aquila and Aquila Merchant in California state courts. These lawsuits allege violations of the Cartwright Act and in some cases California's Unfair Competition Law, and also assert an unjust enrichment claim. The lawsuits have been coordinated before a single Motion Coordination Judge in the Superior Court of California for the County of San Diego, in the proceeding entitled In re Natural Gas Antitrust Cases I, II, III & IV. We believe we have strong defenses and will defend these cases vigorously. 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.

        Aquila Merchant is also a defendant in two federal actions that were filed on November 30, 2004 and June 21, 2005 in the United States District Court for the Eastern District of California. These cases were transferred by the Judicial Panel on Multidistrict Litigation to the United States District Court for the District of Nevada on January 21, 2005 and August 15, 2005, respectively. The action originally filed on November 30, 2004 was subsequently consolidated with two other actions. All of these lawsuits are now part of the proceeding known as In re Western States Wholesale Natural Gas Antitrust Litigation, MDL Docket No. 1566, and make allegations similar to those made in the In re Natural Gas Antitrust Cases I, II, III & IV. The plaintiffs in the November 2004 action allege violations of the Sherman Act, the Cartwright Act, California's Unfair Competition Law, unjust enrichment, and constructive trust, whereas the plaintiffs in the June 2005 action allege only violations of the Sherman Act. The action originally filed on November 30, 2004 has been dismissed, and the plaintiffs have appealed the dismissal to the Ninth Circuit Court of Appeals. We believe we have strong defenses and will defend these cases vigorously. 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.

        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 have 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 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 Aquila Merchant must remedy tariff violations that 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.

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        Aquila Merchant provided a liability of $9.0 million for the above claims in 2005. Based on our continuing evaluation of the above claims, we determined that the ultimate resolution of such claims could result in an obligation of between $15.6 million and $35 million, excluding the recent Cornerstone settlement. In the third quarter of 2006, we recorded an additional provision of $9.3 million to increase the liability recorded to the lower end of the range, after reflecting a receivable of $3.9 million from our insurance carrier. The timing and amount of the ultimate resolution of these claims remains uncertain and could exceed that reserve by a material amount.

        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. 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 are responsible for losses that participants in the 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 seek damages for the plan's losses resulting from the alleged breaches of fiduciary duties. On January 26, 2005, the court ordered that all of these lawsuits be consolidated into a single case captioned In re Aquila ERISA Litigation. The plaintiffs filed an amended consolidated complaint in March 2005, which largely repeats each of the allegations in the first complaint. This case has been certified as a class action and set for trial in December 2007. We believe we have strong defenses and will defend this case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

South Harper Peaking Facility

        We have constructed a 315 MW natural gas "peaking" 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 July 2005, we requested that the Court of Appeals either rehear the case or transfer the case to the Missouri Supreme Court and, 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,

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we filed an application for approval with the Missouri Commission on January 24, 2006. On January 27, 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 is expected to hear oral arguments in May 2007. If we exhaust all of our legal options and are ordered to remove the plant and substation, we estimate the cost to dismantle the plant and substation to be up to $20 million based on an engineering study. Significant additional costs would be incurred to store the equipment, secure replacement power and/or build the plant and substation on other sites. We cannot estimate with certainty the total amount of these 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 cost exceeds the amount allowed for recovery in rates.

Coal Supply Litigation

        In the spring of 2006, one of our coal suppliers, C. W. Mining Company, terminated a long term, fixed price coal supply agreement allegedly because of a force majeure event. We have incurred significant costs procuring replacement coal and dispute that the supplier was entitled to terminate the contract. We filed a lawsuit against it in federal court in Salt Lake City and the trial was held in February 2007. We are awaiting the court's ruling.

Shareholder Lawsuits

        On February 8, 2007, two lawsuits were filed against us and our board of directors in the Circuit Court of Jackson County, Missouri. The complaints were filed as purported class actions on behalf of a proposed class of holders of Aquila common stock. In general, these complaints allege, among other things, breaches of fiduciary duties by the defendants in connection with the approval of the merger agreement. These complaints seek as relief, among other things, an injunction against the consummation of the Merger. We believe we have strong defenses and will defend these cases vigorously. However, given the nature of the claims and remedies sought, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

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, 2006, we estimate probable costs of future investigation and remediation on our identified MGP sites, PCB sites and retained liabilities to be $3.5 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

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"reasonably possible" to be incurred at these sites. Based upon the results of studies at these sites and our knowledge and review of potential remedial actions, it is reasonably possible that these additional costs could exceed our best estimate by approximately $4.9 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 in 2006 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 2009 will be approximately $215.2 million based on engineering bids in 2006. 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. If our Kansas electric utility is not sold, our total estimated probable capital expenditures would be approximately $242 million. We believe these costs would likely be allowed for recovery in future rate cases.

Note 19: 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.

	2006 Quarters											2005 Quarters
In millions, except per share amounts
	First			Second			Third			Fourth		First			Second			Third			Fourth
Sales	$	431.0		$	283.0		$	316.6		$	339.0	$	352.9		$	262.7		$	300.8		$	397.7
Gross profit		116.8			117.8			134.8			118.6		97.7			105.7			149.6			97.4
Income (loss) from continuing operations		(17.6	)		(252.8	)		(20.6	)		9.0		(13.2	)		(23.6	)		(80.0	)		(41.2	)
Earnings (loss) from discontinued operations		16.5			97.8			136.3			55.3		13.9			(3.6	)		4.3			(86.6	)
Net income (loss)	$	(1.1	)	$	(155.0	)	$	115.7		$	64.3	$	.7		$	(27.2	)	$	(75.7	)	$	(127.8	)
Basic and diluted earnings (loss) per common share: (a)
From continuing operations	$	(.05	)	$	(.67	)	$	(.05	)	$	.02	$	(.02	)	$	(.05	)	$	(.21	)	$	(.11	)
From discontinued operations		.05			.26			.36			.15		.04			(.01	)		.01			(.23	)
Net income (loss)	$	—		$	(.41	)	$	.31		$	.17	$	.02		$	(.06	)	$	(.20	)	$	(.34	)

(b)

The sum of the quarterly earnings per share amounts may differ from that reflected in Note 14 due to the weighting of common shares outstanding during each of the respective periods.

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Note 20: 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 shares 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, to refrain from engaging in or otherwise limit certain transactions and activities during this interim period, and to use our reasonable best efforts to hold a shareholders meeting as promptly as possible to consider approval of the Merger and the other transactions contemplated by the merger agreement. We and Great Plains Energy have also agreed, subject to customary exceptions, that (i) each party's board of directors will recommend that its shareholders approve the transactions and (iii) neither party will solicit proposals relating to alternative business combination transactions.

        Consummation of the Merger is subject to a number of conditions, including (i) approval by our shareholders and the shareholders of Great Plains Energy; (ii) approval of the FERC, the Kansas Commission and the Missouri Commission; (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iv) the completion of the asset sale transactions described below; and (v) 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 within 12 months following the date of the merger agreement (subject to extension to up to 18 months for receipt of regulatory approvals required to consummate the Merger and the asset sales). We and Great Plains Energy each have the right to terminate the merger agreement to enter into a superior transaction after giving the other party six business' days notice and an opportunity to revise the terms of the merger agreement. If the merger agreement is terminated under specified circumstances (including a termination to enter into a superior transaction), we or Great Plains Energy will pay to the other a $45 million termination fee.

        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. On February 6, 2007, Great Plains Energy, Gregory Acquisition Corp. and we entered into (i) an asset purchase agreement with Black Hills, and (ii) a partnership interests purchase agreement with Black Hills and Aquila Colorado, LLC, a Delaware limited liability company and wholly-owned subsidiary of Aquila, pursuant to which Black Hills will acquire from us, immediately before the completion of the Merger, the assets and liabilities comprising our

140

Colorado electric utility operations and our gas utility operations in Colorado, Iowa, Kansas and Nebraska.

        These agreements provide for the payment in cash of a base purchase price of $940 million, subject to working capital and certain other 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 limitations. Completion of the sale transactions is subject to various conditions, including: (i) the approval of the FERC, the Colorado Public Utilities Commission, the IUB, the Kansas Commission, and the Nebraska Public Service Commission; (ii) the expiration or early termination of any waiting period under the Hart-Scott-Rodino Antitrust Act of 1976, as amended; (iii) the absence of a material adverse effect on the utility businesses being sold to Black Hills; and (iv) 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.

        If the Merger is completed, we will incur significant costs, primarily consisting of investment banking, legal, employee retention, change-in-control, and other severance costs. In 2006, we incurred approximately $2.3 million of costs (primarily investment banking and legal costs) relating to these transactions, and in February 2007, we incurred fees payable to our financial advisors of $6.1 million in connection with the signing and announcement of the merger agreement. In February 2007, we also executed retention agreements totaling $8.4 million with numerous non-executive employees to mitigate employee attrition prior to the closing of the Merger. The agreements will be paid on the earlier of the closing of the Merger or January 31, 2008.We will expense these costs as they are incurred.

        Further information concerning the Merger and asset sales will be included in a merger proxy statement we will file with the SEC and mail to our shareholders. This proxy statement will also constitute a prospectus for the Great Plains Energy common stock to be issued to our shareholders in the Merger and be included in a registration statement on Form S-4 to be filed with the SEC by Great Plains Energy.

141

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Aquila, Inc.:

        We have audited the accompanying consolidated balance sheets of Aquila, Inc. and subsidiaries as of December 31, 2006 and 2005, 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, 2006. 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, 2006. These consolidated financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aquila, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

        As discussed in note 2 to the consolidated financial statements, effective December 31, 2006 the Company adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). Also, as discussed in note 12 to the consolidated financial statements, effective January 1, 2006 the Company adopted FASB Statement of Financial Accounting Standards No. 123 (Revised), Share-Based Payment, replacing Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control—Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2007 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP
Kansas City, Missouri

February 27, 2007

142

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Aquila, Inc.:

        We have audited management's assessment, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A, that Aquila, Inc. (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

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

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. 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 U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

        In our opinion, management's assessment that Aquila, Inc. maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control—Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Aquila, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, common

143

shareholders' equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP
Kansas City, Missouri

February 27, 2007

144

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 in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2006.

        Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Item 9B.  Other Information

        Not Applicable.

Part III

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

        Information regarding these items will appear in our 2007 definitive proxy statement and is hereby incorporated by reference in this Annual Report on Form 10-K. For information regarding our executive officers, see "Our Executive Team" in Part I, Item 1 of this Form 10-K.

Equity Compensation Plan Information

        The following table provides information as of December 31, 2006 about our compensation plans under which shares of stock have been authorized.

145

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		4,707,603	*	$	15.31	5,685,022	**
Equity compensation plans not approved by security holders		158,263	***	$	24.02	—
	Total	4,865,866				5,685,022

*

Includes 557,395 options issued upon conversion of Aquila Merchant options in connection with our acquisition of the minority interest in Aquila Merchant. These options have a weighted average price of $34.81 per share.

**

These shares are available for issuance under our 2002 Omnibus Incentive Compensation Plan. Awards may be in the form of stock options, restricted stock awards, stock appreciation rights, stock awards or other forms of equity based compensation.

***

Options issued under a broad-based employee stock option plan that has since been terminated.

Item 14.  Principal Accountant Fees and Services

        Information regarding this item will appear in our 2007 definitive proxy statement and is hereby incorporated by reference in this Annual Report on Form 10-K.

146

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.

(a)(2) Financial Statement Schedules

        Schedule II—Valuation and Qualifying Accounts for the years 2006, 2005 and 2004 on page 148.

        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)(11)	Annual and Long-Term Incentive Plan.
10(a)(12)	First Amendment to Annual and Long-Term Incentive Plan.
10(a)(13)	Life Insurance Program for Officers.
10(a)(14)	Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001.
10(a)(15)	Employment Agreement for Richard C. Green.
10(a)(16)	Aquila, Inc. Capital Accumulation Plan, as amended and restated, effective January 1, 2005.
10(a)(17)	Form of Performance Bonus Agreement.
10(a)(18)	Severance Compensation Agreement, by and between Aquila, Inc. and Keith G. Stamm, dated July 8, 2005.
10(a)(19)	Aquila, Inc. 2002 Omnibus Incentive Compensation Plan.
10(a)(20)	Executive Security Trust Amended and Restated as of April 4, 2002.
10(a)(22)	Severance Compensation Agreement, by and between Aquila, Inc. and Leo E. Morton, dated October 6, 2006.
10(a)(23)	Severance Compensation Agreement, by and between Aquila, Inc. and Jon R. Empson, dated October 6, 2006.
10(a)(24)	Severance Compensation Agreement, by and between Aquila, Inc. and Beth A. Armstrong, dated August 22, 2006.
10(a)(30)	Severance Compensation Agreement, by and between Aquila, Inc. and Christopher M. Reitz, dated August 28, 2006.
10(a)(32)	Executive Security Trust Amended and Restated as of April 4, 2002.

*

Incorporated by reference to the Index to Exhibits.

(b) Exhibits

        The Index to Exhibits follows on page 149.

147

AQUILA, INC.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2006
(in millions)

Column A		Column B		Column C			Column D			Column E
Description		Beginning Balance at January 1		Additions Charged to Expense			Deductions from Reserves for Purposes for Which Created			Ending Balance at December 31
Allowance for Doubtful Accounts
	2006	$	9.3	$	4.2		$	(8.7	)	$	4.8
	2005		27.7		1.2			(19.6	)		9.3
	2004		34.4		6.7			(13.4	)		27.7
Maintenance Reserves (a)
	2006	$	3.5	$	4.5		$	(3.3	)	$	4.7
	2005		2.9		2.9			(2.3	)		3.5
	2004		3.8		2.9			(3.8	)		2.9
Other Reserves (b)
	2006	$	24.7	$	50.9		$	(45.7	)	$	29.9
	2005		22.1		36.1			(33.5	)		24.7
	2004		26.5		32.4			(36.8	)		22.1
Restructuring Reserves (c)
	2006	$	.1	$	7.7		$	(5.5	)	$	2.3
	2005		7.8		6.6			(14.3	)		.1
	2004		16.9		.9			(10.0	)		7.8
Deferred Tax Valuation Allowance
	2006	$	248.9	$	(108.7	)	$	(.5	)	$	139.7
	2005		304.7		(53.2	)		(2.6	)		248.9
	2004		341.7		(19.2	)		(17.8	)		304.7
Reserve for Uncertain Tax Positions (d)
	2006	$	287.6	$	89.7		$	—		$	377.3
	2005		244.0		43.6			—			287.6
	2004		208.7		35.3			—			244.0

(a)

Costs to be incurred related to scheduled maintenance outages on regulated generating facilities are accrued in advance of the scheduled outage consistent with current regulatory treatment.



(b)

Includes reserves for self-insurance, environmental claims and other.



(c)

Includes restructuring reserves for severance, lease and other costs.



(d)

The additions to this reserve include amounts originally charged to current or deferred tax expense, and reclassified to the reserve for tax contingencies after the tax returns were filed. See Note 2 to the Consolidated Financial Statements for discussion of the impact of adopting FIN 48 effective January 1, 2007.

148

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)	Third Supplemental Indenture to the August 24, 2001 Indenture, between the Company and J.P. Morgan Trust Company (Exhibit 4 to the Company's Current Report on Form 8-K filed August 20, 2004).
*10(a)(4)	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)(5)	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)(6)	$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)(7)	$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)(8)	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).

149

*10(a)(9)	$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).
*10(a)(10)	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)(11)	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)(12)	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)(13)	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)(14)	Supplemental Executive Retirement Plan, Amended and Restated, effective January 1, 2001 (Exhibit 10(a)(1) to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
*10(a)(15)	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)(16)	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)(17)	Form of Performance Bonus Agreement (Exhibit 10.5 to the Company's Current Report on Form 8-K filed September 27, 2005 (the "September 27 Form 8-K")).
*10(a)(18)	Severance Compensation Agreement, by and between Aquila, Inc. and Keith G. Stamm, dated July 8, 2005 (Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
*10(a)(19)	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)(20)	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)(21)	Asset Purchase Agreement by and between the Company and Mid-Kansas Electric Company, dated September 21, 2005 (Exhibit 10.4 to the September 27 Form 8-K).
*10(a)(22)	Severance Compensation Agreement, by and between Aquila, Inc. 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)(23)	Severance Compensation Agreement, by and between Aquila, Inc. 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)(24)	Severance Compensation Agreement, by and between Aquila, Inc. 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).

150

*10(a)(25)	Asset Purchase Agreement Amendment No. 1, by and between Aquila, Inc. and Mid-Kansas Electric Company, dated August 11, 2006 (Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 17, 2006).
*10(a)(26)	Jeffrey Energy Center Transfer Agreement, by and between Aquila, Inc., Westar Energy, Inc., and Kansas Gas and Electric Company, dated August 11, 2006 (Exhibit 10.2 to the Company's Current Report on Form 8-K filed on August 17, 2006).
*10(a)(27)	Asset Purchase Agreement Amendment No. 2, by and between Aquila, Inc. and Mid-Kansas Electric Company, dated October 20, 2006 (Exhibit 10.1 on the Company's Current Report on Form 8-K filed on October 25, 2006).
*10(a)(28)	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)(29)	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)(30)	Severance Compensation Agreement, by and between Aquila, Inc. and Christopher M. Reitz, dated August 28, 2006.
*10(a)(31)	Iatan 2 and Common Facilities Ownership Agreement by and among Kansas City Power & Light Company, Aquila, Inc., 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).
*10(a)(32)	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).
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).

*

Exhibits marked with an asterisk are incorporated by reference herein. Parenthetical references describe the SEC filing that included the document incorporated by reference.

151

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 28, 2007.

Aquila, Inc.
By:	/s/  RICHARD C. GREEN Richard C. Green President, Chief Executive Officer and Chairman of the Board of Directors

        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 28, 2007.

By:	/s/  RICHARD C. GREEN Richard C. Green	President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer)
By:	/s/  BETH A. ARMSTRONG Beth A. Armstrong	Vice President and Chief Accounting Officer (Principal Financial Officer)
By:	/s/  HERMAN CAIN Herman Cain	Director
By:	/s/  DR. MICHAEL M. CROW Dr. Michael M. Crow	Director
By:	/s/  IRVINE O. HOCKADAY, JR. Irvine O. Hockaday, Jr.	Director
By:	/s/  HEIDI E. HUTTER Heidi E. Hutter	Director
By:	/s/  DR. STANLEY O. IKENBERRY Dr. Stanley O. Ikenberry	Director
By:	/s/  PATRICK J. LYNCH Patrick J. Lynch	Director
By:	/s/  NICHOLAS J. SINGER Nicholas J. Singer	Director

152

QuickLinks

INDEX
Glossary of Terms and Abbreviations
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

Aquila, Inc. Consolidated Statements of Income
Aquila, Inc. Consolidated Balance Sheets
Aquila, Inc. Consolidated Statements of Common Shareholders' Equity
Aquila, Inc. Consolidated Statements of Comprehensive Income
Aquila, Inc. Consolidated Statements of Cash Flows
Aquila, Inc. Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information

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 Stockholder Matters, and Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accountant Fees and Services

Part IV

Item 15. Exhibits and Financial Statement Schedules

AQUILA, INC. SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
AQUILA, INC. INDEX TO EXHIBITS
SIGNATURES

EX-10.(A)(30)

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Exhibit 10(a)(30)

SEVERANCE COMPENSATION AGREEMENT

        This Agreement is effective as of the date it is signed by both AQUILA, INC., a Delaware corporation (the "Company"), and Christopher M. Reitz ("Executive").

        WHEREAS, the Company's Board of Directors has determined that it is appropriate to reinforce and encourage the continued attention and dedication of members of the Company's management, including Executive, to their assigned duties without distraction in potentially disturbing circumstances arising from the possibility of a Change of Control; and

        WHEREAS, this Agreement sets forth the severance compensation to which Executive will be entitled upon certain conditions if Executive's employment with the Company terminates following a Change of Control.

        NOW, THEREFORE, IN CONSIDERATION of the mutual premises, covenants and agreements set forth below, it is hereby agreed as follows:

        1.    Term.    This Agreement shall terminate, except to the extent that any obligation of the Company hereunder remains unpaid as of such time, upon the earliest of: (i) two (2) years from the date hereof if a Change in Control has not occurred within such 2-year period; provided that the term of this Agreement shall be automatically extended for an additional month upon each monthly anniversary of the date hereof until a party provides notice to the other party prior to the end of any month that such automatic extension shall cease, in which case this Agreement shall terminate at the end of the then existing 2-year term; (ii) the termination of Executive's employment for any reason, including by reason of death, Disability or Retirement, prior to a Change of Control; (iii) the termination of Executive's employment for Cause following a Change of Control; (iv) the termination of Executive's employment for any reason other than for Good Reason following a Change of Control; or (v) two (2) years from the date of a Change in Control.

        2.    Severance upon Termination of Employment.

        (a)    Events Giving Rise to Benefits.    Executive shall be entitled to payments and other benefits as set forth in Sections 2(b) and 2(c) if within two (2) years following a Change in Control, the Company shall terminate Executive's employment other than for Disability, Retirement, or Cause, or, within such 2-year period, Executive shall terminate his or her employment for Good Reason. Except as specifically provided in this Section 2, Executive shall have no right to receive compensation under this Agreement. Termination of employment due to death shall not give rise to any rights to compensation under this Agreement.

        (b)    Severance Pay.    The Company shall pay a lump sum cash amount, no later than the fifth (5^th) business day following Executive's Date of Termination, equal 2 times the sum of A plus B, where

        "A" equals Executive's annual base salary (including all amounts of such salary that are deferred under any qualified and non-qualified plans of the Company) determined at the greater of the rate in effect as of the date of such termination or the highest rate in effect at any time during the 90 day period prior to the Change of Control; and

        "B" equals Executive's target annual incentive opportunity for the calendar year in which such Change in Control occurs, or if greater, the average (50^th percentile) target annual incentive opportunity for a select group of comparable companies as determined by an independent consulting firm selected by the Board of Directors of the Company.

        (c)    Other Benefits.    In addition to compensation set forth in Section 2(b) hereof, and subject to the provisions and limitations set forth below, Executive shall be entitled to the following benefits:

          (i)  Commencing on the Date of Termination and continuing for a period of three (3) months thereafter, Executive may exercise all stock options granted to Executive pursuant to the Company's equity incentive plan(s). Such stock options shall be exercisable whether or not: (i) a period of one year has elapsed from the date of grant to the date of exercise; or (ii) any installment exercise terms as stipulated in any agreement issued under such plan(s) have been satisfied. However, in no event shall Executive exercise any stock option after the expiration of the option period as stipulated in an agreement issued under such plan(s).

         (ii)  Effective as of the Date of Termination, any restrictions relating to stock awards granted under the Company's equity incentive plan(s) shall lapse.

        (iii)  No later than the fifth (5^th) business day following Executive's Date of Termination, Executive shall receive a lump sum cash amount equal to Executive's target annual and long-term incentive opportunity for the incentive period in which Executive's employment terminates times a fraction, the numerator of which is the number of days in such incentive period ending on the Date of Termination and the denominator of which is the total number of days in such incentive period.

        (iv)  Effective as of the Date of Termination and continuing for a period of three years after the Date of Termination, the Company will provide Executive with health insurance coverage at the same cost to Executive and at materially the same level of coverage for Executive as the coverage in effect immediately prior to the Date of Termination. The Company shall, at its option, contribute amounts it is required to contribute on behalf of Executive pursuant to this paragraph either to: (A) plans maintained for the Company's employees; or (B) private insurance plans. The health insurance continuation benefits paid for hereunder shall be deemed to be a part of Executive's COBRA coverage. All such health benefits shall be in addition to any other benefits relating to health or medical care benefits that are available under the Company's policies to Executive following termination of employment; provided, however, that in the event Executive becomes covered under substitute health plans of another employer with materially the same level of coverage as that provided by the Company during this period, subject to the applicable requirement of COBRA, the Company will no longer provide health coverage under this paragraph.

         (v)  Effective as of the Date of Termination, Executive shall be entitled to the services of a national executive outplacement firm, the aggregate cost to the Company of which shall not exceed the outplacement benefits comparable to the Aquila Workforce Transition Plan that is in effect as of the date of termination.

        (vi)  Effective as of the Date of Termination, Executive shall be entitled to three (3) years of additional credit for both age and service under the Company's tax-qualified and non-qualified pension plans (specifically excluding any account-based plan such as a 401(k) or profit sharing plan); provided that if applicable provisions of the Internal Revenue Code prevent payment in respect of such credit under the Company's tax-qualified pension plan, such payments shall be made under the Company's non-qualified pension plan.

        3.    Tax Reimbursement.

        (a)    Gross-Up Payment.    Notwithstanding Anything in this Agreement to the contrary, in the event it shall be determined that any payment or distribution to or for the benefit of Executive whether paid or payable or distributed or distributable pursuant to the terms of this Agreement (other than any payment under this Section 3) or otherwise would be subject to the excise tax

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imposed by Section 4999 of the Internal Revenue Code of 1986 (the "Code") or a similar section (such payment, a "Change in Control Payment" and such excise tax on all such Change in Control Payments, together with any interest and penalties thereon, collectively the "Excise Tax"), then Executive shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount determined by the Accounting Firm such that after payment by Executive of any tax thereon, Executive retains an amount of the Gross-Up Payment equal to the amount of the Excise Tax; provided, however, that if the aggregate value (as determined under Section 280G of the Code) of such Change in Control Payments is less than 110% of the product of "3 times" the Executive's "base amount" (as defined in Section 280G(b)(3) of the Code) (such product, the "Golden Parachute Threshold"), then Executive shall not be entitled to any Gross-Up Payment and, instead, the Change in Control Payments shall be reduced so that their aggregate value (as so determined) is equal to $1.00 less than the Golden Parachute Threshold.

        For purposes of this Section 3, Executive's applicable Federal, state and local taxes shall be computed at the maximum marginal rates, taking into account the effect of any loss of personal exemptions resulting from receipt of the Gross-Up Payment.

        (b)    Determinations.    All determinations required to be made under this Section 3, including whether a Gross-Up Payment is required under Section 3(a), and the assumptions to be used in determining the Gross-Up Payment, shall be made by such accounting firm as the Company may designate in writing prior to a Change in Control (the "Accounting Firm"), which shall provide detailed supporting calculations both to the Company and Executive within thirty (30) business days of the receipt of notice from Executive that there has been a Change in Control, or such earlier time as is requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the Person effecting the Change in Control or is otherwise unavailable, Executive may appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm shall be borne solely by the Company.

        (c)    Subsequent Redeterminations.    Unless requested otherwise by the Company, Executive agrees to use reasonable efforts to contest in good faith any subsequent determination by the Internal Revenue Service that Executive owes an amount of Excise Tax greater than the amount determined pursuant to Section 3(b), provided that Executive shall be entitled to reimbursement by the Company of all fees and expenses reasonably incurred by Executive in contesting such determination. In the event the Internal Revenue Service or any court of competent jurisdiction determines that Executive owes an amount of Excise Tax that is either greater or less than the amount previously taken into account and paid under this Section 3, the Company shall promptly reimburse Executive, or Executive shall promptly reimburse the Company, as the case may be, the amount of such excess or shortfall. In the case of any payment that the Company is required to make to Executive pursuant to the preceding sentence (a "Later Payment"), the Company shall also reimburse Executive an additional amount such that after payment by Executive of all of Executive's applicable Federal, state and local taxes, including any interest and penalties assessed by any taxing authority, on such additional amount, Executive will retain an amount equal to the total of Executive's applicable Federal, state and local taxes, including any interest and penalties assessed by any taxing authority, arising due to the Later Payment. In the case of any reimbursement of Excise Tax that Executive is required to make to the Company pursuant to the second sentence of this Section 3(c), Executive shall also reimburse the Company at the amount of any additional payment received by Executive from the Company in respect of applicable Federal, state and local taxes on such repaid Excise Tax, to the extent Executive is entitled to a refund of (or has not yet paid) such Federal, state or local taxes.

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        4.    Definitions.    As used in this Agreement, the following capitalized terms shall have the meaning set forth below:

        (a)   "Beneficial Owner" shall have the meaning set forth in Rule 13d-3 under the Exchange Act.

        (b)   "Benefit Plans" means any employee benefit plan or arrangement providing retirement benefits or any health, life, disability or similar welfare insurance. Executive perquisites are specifically excluded from this definition.

        (c)   "Cause" means:

          (i)  The willful and continued failure by Executive to substantially perform his or her duties of employment with Company other than any such failure resulting from Executive's incapacity due to physical or mental illness, unless Executive uses reasonable efforts to correct such failure within a reasonable time after demand for substantial performance is delivered by the Company that specifically identifies the manner in which the Company believes Executive has not substantially performed his or her duties;

         (ii)  The willful misconduct by Executive which materially injures the Company monetarily or otherwise; or

        (iii)  Conviction of, or entry of a plea of nolo contendere with regard to, any felony or any crime involving moral turpitude or dishonesty of or by Executive. For purposes of this paragraph, no act, or failure to act, on Executive's part shall be considered "willful" unless done, or omitted to be done, by him or her not in good faith and without reasonable belief that his or her action or omission was in, or not opposed to, the best interests of the Company.

        (d)   "Change in Control" means and shall be deemed to have occurred upon the occurrence of any of the following events:

          (i)  Any Person is or becomes the Beneficial Owner, directly or indirectly, of 20% or more of the Voting Securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its affiliates, other than in connection with the acquisition by the Company or its affiliates of a business) unless such Person becomes a Beneficial Owner of 20% or more of the Voting Securities of the Company as a result of an acquisition of Voting Securities by the Company which, after reducing the Voting Securities outstanding, increases the proportionate Voting Securities of the Company beneficially owned by such Person to 20% or more by reason of such Voting Securities acquisition by the Company; provided, however, if a Person shall become the Beneficial Owner of 20% or more of the combined voting power of the Voting Securities of the Company then outstanding by reason of such Voting Securities acquisition by the Company and shall thereafter become the Beneficial Owner of any additional Voting Securities of the Company which causes the proportionate voting power of Voting Securities beneficially owned by such Person to increase to more than 20% of the combined voting power of the Voting Securities of the Company then outstanding, such Person shall, upon becoming the Beneficial Owner of such additional Voting Securities, be deemed to have become the Beneficial Owner of 20% or more of the combined voting power of the Voting Securities of the Company then outstanding other than solely as a result of such Voting Securities acquisition by the Company;

         (ii)  During any period of 36 consecutive months (not including any period prior to the effective date of this Agreement), individuals who at the beginning of such period constitute the Board of Directors of the Company (and any new director, whose election by the board or

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nomination for election by the Company's stockholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was so approved), cease for any reason to constitute a majority of directors then constituting the Board of Directors of the Company;

        (iii)  A reorganization, merger or consolidation of the Company is consummated, in each case, unless, immediately following such reorganization, merger or consolidation, (i) more than 50% of, respectively, the then outstanding shares of Voting Securities of the corporation resulting from such reorganization, merger or consolidation is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners of the Voting Securities of the Company outstanding immediately prior to such reorganization, merger or consolidation, (ii) no Person (but excluding for this purpose any Person beneficially owning, immediately prior to such reorganization, merger or consolidation, directly or indirectly, 20% or more of the voting power of the outstanding Voting Securities of the Company) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of Voting Securities of the corporation resulting from such reorganization, merger or consolidation, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such reorganization, merger or consolidation were members of the Board of Directors of the Company at the time of the execution of the initial agreement providing for such reorganization, merger or consolidation; or

        (iv)  The stockholders of the Company approve (i) a complete liquidation or dissolution of the Company or (ii) the sale or other disposition of more than 50% of all of the assets of the Company, other than to any corporation with respect to which, immediately following such sale or other disposition, (A) more than 50% of, respectively, the then outstanding shares of Voting Securities of such corporation is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners of the Voting Securities of the Company outstanding immediately prior to such sale or other disposition of assets, (B) no Person (but excluding for this purpose any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 20% or more of the voting power of the outstanding Voting Securities of the Company) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of Voting Securities of such corporation and (C) at least a majority of the members of the board of directors of such corporation were members of the Board of Directors of the Company at the time of the execution of the initial agreement or action of the board providing for such sale or other disposition of assets of the Company.

        Notwithstanding the foregoing, in no event shall a "Change in Control" be deemed to have occurred if: (1) there is consummated any transaction or series of integrated transactions immediately following which the record holders of the Voting Securities of the Company immediately prior to such transaction or series of transactions continue to have substantially the same proportionate ownership in an entity which owns all or substantially all of the assets of the Company immediately following such transaction or series of transactions; or (2) Executive is part of a "group," within the meaning of Section 13(d)(3) of the Exchange Act as in effect of the effective date of this Agreement, which consummates the Change in Control transaction; or (3) any required regulatory approval of a transaction giving rise to a Change in Control has not been obtained. In addition, for purposes of the definition of "Change in Control," a Person engaged in business as an underwriter of securities shall not be deemed to be the Beneficial Owner of any securities acquired through such Person's participation in good faith in a firm commitment underwriting until the expiration of forty days after the date of such acquisition.

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        (e)   "Company" means Aquila, Inc. and any successor or assign to its business and/or assets which executes and delivers the agreement provided by this Agreement or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law.

        (f)    "Date of Termination" means (i) if this Agreement is terminated by Executive for Good Reason, the date Executive delivers notice of such termination to the Company; (ii) if Executive's employment is terminated by the Company for Disability, 30 days after Notice of Termination is given to Executive (provided that Executive shall not have offered to return and is able to return to the performance of Executive's duties on a full-time basis during such 30-day period); or (iii) if Executive's employment is terminated by the Company for any other reason, the date on which a Notice of Termination is given.

        (g)   "Disability" means Executive's incapacity due to physical or mental illness which shall have caused Executive to have been absent from his or her duties with the Company on a full-time basis for six months and Executive shall not have returned to the full-time performance of Executive's duties within 30 days after written Notice of Termination has been given by the Company.

        (h)   "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended.

        (i)    "Good Reason" means any of the following if the same shall occur, without Executive's express written consent, within two (2) years after a Change in Control:

          (i)  the assignment to Executive of duties materially inconsistent with Executive's position, duties, responsibilities and status with the Company immediately prior to the Change in Control, or a material adverse change in Executive's titles or reporting relationships as in effect immediately prior to the Change in Control, or any removal of Executive from or any failure to reelect Executive to any of such positions;

         (ii)  a reduction in Executive's base salary as in effect on the date hereof or as the same may be increased from time to time during the term of this Agreement;

        (iii)  any failure by the Company to continue in effect any Benefit Plan enjoyed by Executive at the time of the Change in Control (or plans or arrangements or other benefits providing him or her with substantially similar or better benefits, taken in the aggregate), or the taking of any action by the Company, which would adversely affect Executive's participation in or materially reduce Executive's benefits under any such Benefit Plans, taken in the aggregate;

        (iv)  any failure by the Company to continue in effect any Incentive Plan in which Executive was participating at the time of the Change in Control (or plans or arrangements providing him or her with substantially similar or better benefits, taken in the aggregate), or the taking of any action by the Company which would adversely affect Executive's participation in any such Incentive Plan or reduce Executive's benefits under any such Incentive Plan, expressed as a percentage of his or her base salary, by more than 10 percentage points in any fiscal year as compared to the immediately preceding fiscal year;

         (v)  any failure by the Company to continue in effect any Securities Plan in which Executive was participating at the time of the Change in Control (or plans or arrangements providing him or her with substantially similar or better benefits, taken in the aggregate) or the taking of any action by the Company which would adversely affect Executive's participation in or materially reduce Executive's benefits under any such Securities Plan;

        (vi)  any requirement that Executive relocate more than 50 miles from the area in which Executive performed Executive's duties prior to the Change in Control, except for required

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travel by Executive on the Company's business to an extent substantially consistent with Executive's business travel obligations at the time of the Change in Control;

        (vi)  any material breach by the Company of any provision of this Agreement;

       (vii)  any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company; or

      (viii)  any purported termination of Executive's employment which is not effected pursuant to a Notice of Termination satisfying the requirements of this Agreement.

        (l)    "Incentive Plan" means any annual or long term incentive plan or arrangement, such as a bonus or performance plan.

        (m)  "Notice of Termination" means a written notice which indicates the specific termination provisions in this Agreement relied upon and which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive's employment. For purposes of this Agreement, no such purported termination shall be effective without such Notice of Termination.

        (n)   "Person" shall have the meaning given in Section 3(a)(9) of the Exchange Act, as modified and used in Section 13(d) and 14(d) thereof, except that such terms shall not include (i) the Company or any of its affiliates (as defined in Rule 12b-2 promulgated under the Exchange Act), (ii) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its affiliates, (iii) an underwriter temporarily holding securities pursuant to an offering of such securities, or (iv) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company.

        (o)   "Retirement" means the termination by the Company or Executive of Executive's employment based on Executive having retired pursuant to the then existing retirement plan of the Company at or after age 65 or by any agreement between the Company and Executive, or by any generally applicable retirement policy of the Company.

        (p)   "Securities Plan" means any plan or arrangement providing participants the opportunity to receive securities of the Company, including without limitation stock options, stock appreciation rights, restricted stock.

        (q)   "Voting Securities" means with respect to any corporation, the common stock and other securities of the corporation entitled to vote generally in the election of the board of directors of the corporation.

        5.    Notice of Termination.    Any termination of Executive's employment for any reason shall be effected pursuant to a Notice of Termination conforming to the requirements of this section.

        6.    No Obligation to Mitigate Damages; No Effect on Other Contractual Rights.

        (a)   Executive shall not be required to mitigate damages or the amount of any payment provided for under this Agreement by seeking other employment or otherwise, nor shall the amount of any payment provided for under this Agreement be reduced by any compensation earned by Executive as the result of employment by another employer after the Date of Termination, or otherwise.

        (b)   The provisions of this Agreement, and any payment provided for hereunder, shall not reduce any amounts otherwise payable, or in any way diminish Executive's existing rights, or rights which would accrue solely as a result of the passage of time, under any Benefit Plan, Incentive Plan or Securities Plan, employment agreement or other contract, plan or arrangement.

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        7.    Successor to the Company.

        (a)   The Company will require any successor or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance reasonably satisfactory to Executive, expressly, absolutely and unconditionally to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. Any failure of the Company to obtain such agreement prior to the effectiveness of any such succession or assignment shall be a material breach of this Agreement and shall entitle Executive to terminate Executive's employment for Good Reason.

        (b)   This Agreement shall inure to the benefit of and be enforceable by Executive's personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If Executive should die while any amounts are still payable to him or her hereunder, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to Executive's devisee, legatee, or other designee, or if there be no such designee, to Executive's estate. The services to be provided by Executive to the Company under this Agreement are personal and are not delegable or assignable.

        8.    Notice.    For purposes of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States certified or registered mail, return receipt requested, postage prepaid, as follows:

If to the Company:

Aquila, Inc.
20 West Ninth Street
Kansas City, Missouri 64105


ATTN: Corporate Secretary

If to Executive to the address of
Executive on the books of the Company.

        Another address may be used if a party has furnished a different address to the other party in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt.

        9.    Sole Agreement.    This Agreement represents the entire agreement between the parties with respect to the matters contemplated herein. Any earlier agreement relating to severance compensation between the parties or between Executive and any affiliate of the Company is hereby terminated and superseded, and all obligations by either party thereunder shall cease immediately preceding the commencement of the term of this Agreement and are hereby agreed to be satisfied in full. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement. The parties acknowledge and agree that the severance benefits hereunder are in lieu of the benefits offered under the Company's Workforce Transition Program (or any successor severance plan or arrangement) and that Executive shall not be eligible for any benefits under such program.

        10.    Validity.    The invalidity or unenforceability of any provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

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        11.    Counterparts.    This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

        12.    Legal Fees and Expenses.    The Company shall pay all legal fees and expenses which Executive reasonably may incur as a result of the Company's contesting the validity, enforceability or Executive's interpretation of, or determinations under, this Agreement.

        13.    Confidential Information.    Executive agrees not to disclose during the term hereof or thereafter any of the Company's confidential or trade secret information, except as required by law. Executive recognizes that Executive shall be employed in a sensitive position in which, as a result of a relationship of trust and confidence, Executive will have access to trade secrets and other highly confidential and sensitive information. Executive further recognizes that the knowledge and informed acquired by Executive concerning the Company's materials regarding employer/employee contracts, customers, pricing schedules, advertising and interviewing techniques, manuals, systems, procedures and forms represent the most vital part of the Company's business and constitute by their very nature, trade secrets and confidential knowledge and information. Executive hereby stipulates and agrees that all such information and materials shall be considered trade secrets and confidential information. If it is at any time determined that any of the information or materials identified in this Section are, in whole or in part, not entitled to protection as trade secrets, they shall nevertheless be considered and treated as confidential information in the same manner as trade secrets, to the maximum extent permitted by law. Executive further agrees that all such trade secrets or other confidential information, and any copy, extract or summary thereof, whether originated or prepared by or for Executive or otherwise coming into Executive's knowledge, possession, custody, or control, shall be and remain the exclusive property of the Company.

        14.    Withholding.    The Company may withhold from any benefits payable under this Agreement all federal, state, city or other taxes as shall be required pursuant to any law or governmental regulation or ruling.

        15.    Arbitration.    Any claim or controversy arising out of or relating to this Agreement or any breach thereof shall be settled by arbitration. Any such arbitration shall take place in Kansas City, Missouri, in accordance with the rules of the American Arbitration Association. Any award rendered shall be final and conclusive upon the parties and judgment therein may be entered in the highest court of the forum, state or federal, having jurisdiction.

        16.    Attachment.    Except as required by law, the right to receive payments under this Agreement shall not be subject to anticipation, sale, encumbrance, charge, levy, or similar process or assignment by operation of law.

        17.    Waivers.    Any waiver by a party or any breach of this Agreement by another party shall not be construed as a continuing waiver or as a consent to any subsequent breach by the other party. Except as otherwise expressly set forth herein, no failure on the part of any party hereto to exercise and no delay in exercising any right, power or remedy hereunder shall operate s a waiver thereof, nor shall any single or partial exercise of any right, power or remedy hereunder preclude any other or further exercise thereof or the exercise of any other right, power or remedy.

        18.    Headings.    The headings of the sections of this Agreement have been inserted for convenience of reference only and shall in no way restrict or modify any of the terms or provisions hereof.

        19.    Governing Law.    This Agreement shall be governed and construed and the legal relationships of the parties determined in accordance with the laws of the State of Missouri.

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THIS CONTRACT CONTAINS A BINDING ARBITRATION PROVISION WHICH MAY BE ENFORCED BY THE PARTIES.

AQUILA, INC.
By:	/s/  RICHARD C. GREEN
Date:	August 28, 2006
EXECUTIVE
By:	/s/  CHRISTOPHER M. REITZ
Date:	August 28, 2006

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SEVERANCE COMPENSATION AGREEMENT

EX-12

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Exhibit 12

Aquila, Inc.
Ratio of Earnings to Fixed Charges

		Year Ended December 31,
		2006			2005			2004			2003			2002
		Dollars in millions
Loss from continuing operations before income taxes		$	(349.3	)	$	(201.1	)	$	(562.6	)	$	(503.5	)	$	(1,712.1	)
	Add (Subtract):
	Equity in earnings of investments		—			—			(2.1	)		(69.6	)		(166.9	)
	Dividends and fees from investments		—			.5			1.5			48.6			87.9
	Minority interest in income (loss) of subsidiaries		—			—			—			—			(7.8	)
	Total interest expense		193.8			221.3			273.1			296.9			255.2
	Interest capitalized		(.1	)		—			—			—			(1.3	)
	Portion of rents representative of an interest factor		9.9			11.8			13.6			20.5			22.3
Income (loss), as adjusted		$	(145.7	)	$	32.5		$	(276.5	)	$	(207.1	)	$	(1,522.7	)
Fixed Charges:
	Interest on long-term debt	$	190.4		$	219.3		$	264.6		$	278.0		$	238.9
	Interest on short-term debt		3.4			2.1			8.5			18.9			16.3
	Portion of rents representative of an interest factor		9.9			11.8			13.6			20.5			22.3
Fixed Charges		$	203.7		$	233.2		$	286.7		$	317.4		$	277.5
Ratio of Earnings to Fixed Charges			—	(a)		.14			—	(a)		—	(a)		—	(a)

(a)

Ratio amount not shown due to a coverage deficiency in the amount of $349.4 million, $563.2 million, $524.5 million and $1,800.2 million for the years ended December 31, 2006, 2004, 2003 and 2002, respectively.

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Aquila, Inc. Ratio of Earnings to Fixed Charges

EX-21

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Exhibit 21

Aquila, Inc.
Subsidiaries
2006 Annual Report on Form 10-K

Subsidiary	Jurisdiction of Incorporation
Aquila Merchant Services, Inc.	Delaware

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Aquila, Inc. Subsidiaries 2006 Annual Report on Form 10-K

EX-23

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Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Aquila, Inc.:

We consent to the incorporation by reference into Aquila Inc.'s previously filed registration statements on Form S-3 (Nos. 333-88280 and 333-67822) and on Form S-8 (Nos. 333-92294, 333-68042, 333-68040, 333-68044, 333-67820, 333-66233, 033-45525, 033-50260, 333-19671, 333-91305, 333-94955, 333-30742, and 333-77703) of our reports dated February 27, 2007, with respect to the consolidated balance sheets of Aquila, Inc. as of December 31, 2006 and 2005, 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, 2006, and all related financial statement schedules, management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, and the effectiveness of internal control over financial reporting as of December 31, 2006, which reports appear in the December 31, 2006, annual report on Form 10-K of Aquila, Inc. Our report refers to Aquila, Inc.'s adoption of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, and amendment of FASB Statements No. 87, 88, 106, and 132 (R) and adoption of FASB Statement of Financial Accounting Standards No. 123(Revised), Share-Based Payments, replacing Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.

Kansas City, Missouri
February 27, 2007

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CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

EX-31.1

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Exhibit 31.1

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

        I, Richard C. Green, certify that:

1.

I have reviewed the annual report of Aquila, Inc. for the annual period ending December 31, 2006;

2.

Based on my knowledge, the report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3.

Based on my knowledge, the financial statements, and other financial information included in the report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this periodic report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 28, 2007 /s/  RICHARD C. GREEN Richard C. Green
Chairman, President and
Chief Executive Officer, Aquila, Inc.

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

EX-31.2

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Exhibit 31.2

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

        I, Beth A. Armstrong, certify that:

1.

I have reviewed the annual report of Aquila, Inc. for the annual period ending December 31, 2006;

2.

Based on my knowledge, the report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3.

Based on my knowledge, the financial statements, and other financial information included in the report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this periodic report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 28, 2007 /s/  BETH A. ARMSTRONG Beth A. Armstrong
Vice President and Chief Accounting Officer,
Aquila, Inc.

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

EX-32.1

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Exhibit 32.1

Aquila, Inc.
Chief Executive Officer
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        I, Richard C. Green, certify that:

1.

Aquila, Inc.'s annual report on Form 10-K for the annual period ending December 31, 2006 accompanying this Certification, in the form filed with the Securities and Exchange Commission (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

2.

The information in the Report fairly presents, in all material respects, the financial condition and results of operations of Aquila, Inc.

Dated: February 28, 2007

/s/  RICHARD C. GREEN Richard C. Green
Chairman, President and Chief Executive Officer
Aquila, Inc.

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Aquila, Inc. Chief Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

EX-32.2

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Exhibit 32.2

Aquila, Inc.
Chief Accounting Officer
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        I, Beth A. Armstrong, certify that:

1.

Aquila, Inc.'s annual report on Form 10-K for the annual period ending December 31, 2006 accompanying this Certification, in the form filed with the Securities and Exchange Commission (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

2.

The information in the Report fairly presents, in all material respects, the financial condition and results of operations of Aquila, Inc.

Dated: February 28, 2007

/s/  BETH A. ARMSTRONG Beth A. Armstrong
Vice President and Chief Accounting Officer
Aquila, Inc.

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Aquila, Inc. Chief Accounting Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002