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

FORM 10-K

For the transition period from                            to                           

Commission file number: 1-03562

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

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:

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

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

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

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

        The aggregate market value of the voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on June 30, 2004 as reported on the New York Stock Exchange, was approximately $654,409,600. Shares of Common Stock held by each officer and director and by each person who owns 5% or more of the outstanding Common Stock have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

INDEX

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Glossary of Terms and Abbreviations

APB—Accounting Principles Board.

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

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

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

CFTC—Commodity Futures Trading Commission.

CO₂—Carbon Dioxide.

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

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

Energy Act—Energy Policy Act of 1992.

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

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

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

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

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

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

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

Fitch—Fitch Ratings, a leading global rating agency.

FPA—Federal Power Act.

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

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GWh—Gigawatt-hour.

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

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

kWh—Kilowatt-hour.

LIBOR—London Inter-Bank Offering Rate.

Mcf—One thousand cubic feet.

MGP—Manufactured Gas Plant.

MMBtu—One million Btu's.

MMcf—One million cubic feet.

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

MW—Megawatt, one thousand Kilowatts.

Mwh—Megawatt-hour.

NOx—Nitrogen oxide.

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

NYMEX—New York Mercantile Exchange.

NYSE—New York Stock Exchange.

NYSEG—New York State Electric and Gas Corp.

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

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

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

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

RTO—Regional Transmission Organization.

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

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

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

SO₂—Sulfur dioxide.

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Part I

Item 1.    Business

History and Organization

        Aquila, Inc. (Aquila or the company, which may be referred to as "we," "us" or "our") is primarily an integrated electric and natural gas utility headquartered in Kansas City, Missouri. We began as Missouri Public Service Company in 1917 and reincorporated in Delaware as UtiliCorp United Inc. in 1985. In March 2002, we changed our name to Aquila, Inc. As of December 31, 2004, we had 3,192 employees in the United States. Our business is organized into two groups: Domestic Utilities, which comprises our regulated utility operations, and Merchant Services, which comprises our unregulated energy activities. All other operations are included in Corporate and Other, including costs that are not allocated to our operating businesses; our controlling investment in a broadband company operating in Kansas City, Everest Connections; and our former investments in Australia, New Zealand and the United Kingdom. Substantially all of our revenues are generated by the Domestic Utilities group.

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

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

Access to Company Information and Officer Certifications

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

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

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Business Group Summary

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

I.    Domestic Utilities

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

Electric Generating Facilities

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

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

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

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

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

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

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Seasonal Variations of Business

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

Competition

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

Regulation and Rates

State Regulation

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

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

•

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



•

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

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•

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:

(1)

This rate increase had been collected on an interim basis since October 2000. We refunded over-collected interim rates to our Minnesota customers in February 2004.



(2)

An interim increase of $5.6 million went into effect in September 2002 and we completed a refund to our Iowa gas customers of over-collected amounts in May 2003.



(3)

The new Michigan rates went into effect in March 2003. This increase was net of a separate depreciation case docket, which reduced our annual rates by $.7 million. That decrease relates to our depreciation rates and reduced cash flow and had little impact on earnings.



(4)

The new Colorado rates went into effect in June 2003.



(5)

We have been collecting interim rates in Nebraska since October 2003 based on an interim rate increase of $9.9 million. In April 2004, we refunded the difference between the interim rate increase implemented in October 2003 and the final settlement amount to our Nebraska customers.



(6)

The Missouri electric settlement included a two-year Interim Energy Charge (IEC) that allows us to recover variable generation and purchased power costs up to a specified amount per Mwh specific to each of our Missouri regulatory jurisdictions. The IEC rate per unit sold is $13.98/Mwh for St. Joseph Light & Power and $19.71/Mwh for Missouri Public Service. If the amounts collected under the IEC exceed our average cost incurred for the two-year period, we will refund the excess to our customers with interest. This fuel and purchased power cost recovery mechanism represents $18.5 million of the

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$37.5 million rate increase. Also, as part of the settlement we agreed not to seek a general increase in our Missouri electric rates that would be effective in less than two years from the current rate increase, unless certain significant events occur that impact our operations. The rate increase went into effect April 22, 2004.

(7)

The Missouri gas rate increase went into effect May 3, 2004 for our Missouri Public Service operations and July 1, 2004 for our St. Joseph Light & Power operations.



(8)

The Colorado electric settlement included the modification of our Incentive Clause Adjustment to provide for the recovery of 100% of the variability of energy costs from our electric customers in Colorado, which is an increase from 75% recovery.



(9)

This increase is effective March 1, 2005. We have filed for reconsideration of certain items included in the Commission's order.



(10)

This application is primarily to recover infrastructure improvements and increased operating and maintenance costs. We expect hearings to be held by May 2005 with rates effective in August 2005.

        Our domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute natural gas in seven states. All of our gas distribution utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to "true-up" billed amounts to match the actual cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions.

        In our regulated electric business in 2004, we generated approximately 57% of the power that we sold and we purchased the remaining 43% through long-term contracts or in the open market. The regulatory provisions for recovering power costs vary by state. In Kansas and Colorado, we have an Energy Cost Adjustment and an Incentive Clause Adjustment, respectively, that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Missouri, we do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our electric earnings can fluctuate more in Missouri than in our other electric rate jurisdictions. As described more fully above, the Missouri Commission approved a settlement agreement in April 2004 for our electric operations that establishes our right to recover costs up to $13.98/Mwh in our St. Joseph Light & Power operations and $19.71/Mwh in our Missouri Public Service operations for a two-year period. If our actual costs are higher than those allowed costs, then we cannot recover the excess costs through rates. If our actual costs are less than those allowed costs, then we must refund the difference to our customers, except to the extent actual costs are below $12.64/Mwh for our St. Joseph Light & Power operations and $16.65/Mwh for our Missouri Public Service operations. Since the rate increase went into effect pursuant to the settlement agreement, our actual costs have exceeded the allowed costs by approximately $1.8 million through December 31, 2004.

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Federal Regulation

        Under the FPA, our wholesale transmission and sale of electricity in interstate commerce and our generation facilities are subject to the jurisdiction of the FERC. That jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale, the issuance of stock and long- and short-term debt, the sale, lease or other disposition of such facilities, and accounting matters.

        In December 1999, the FERC issued Order 2000 addressing some significant regional electricity transmission issues. Among other things, Order 2000 required transmission-owning utilities, including Aquila, that did not already participate in an independent system operator (ISO) to file plans detailing their participation in an organization that will control the transmission facilities within a region. We have made the filings required by Order 2000, and are otherwise in compliance with the order, but our transmission facilities are not yet controlled by a regional transmission organization.

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

Environmental Matters

General

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

•

the protection of the environment; and



•

the safety and health of personnel and the public.

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

•

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



•

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 controls water discharge and intake requirements and generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in

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

316(b) Fish Impingement Requirements

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

Missouri River Levels

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

Air Emissions

        Our facilities are subject to the Clean Air Act and many state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, SO₂, NOx and particulate matter. In addition, CO₂ is also included as a potential emission that may be regulated. Fossil-fueled power generating facilities emit each of the foregoing pollutants and, accordingly, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Clean Air Act

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

Multi-pollutant regulations

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

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

New Source Review

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

        In January 2004, Westar Energy, Inc. received a notification from the EPA that it had violated the EPA's NSR requirements and Kansas environmental regulations by making modifications to the Jeffrey Energy Center without obtaining the proper permits. The Jeffrey Energy Center is a large coal-fired power plant located in Kansas that is 84% owned by Westar and operated exclusively by Westar. We have a 16% interest in the Jeffrey Energy Center and are generally responsible for this portion of its operating costs and capital expenditures. The electric generation plants we own or lease are described in the table at Item 1, page 6. It is possible that Westar could be subject to an enforcement action by the EPA and required to make significant capital expenditures to install additional pollution controls at the Jeffrey Energy Center. Aquila would potentially be responsible for 16% of those costs.

Global Climate

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

Solid Waste

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

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Past Operations

        Some federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. We are named as a potentially responsible party at two disposal sites for PCBs. In addition, we retain some environmental liability for several operations and investments that we no longer own.

        We also own or have acquired liabilities from companies that once owned or operated former MGP sites, which are subject to the supervision of the EPA and various state environmental agencies.

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

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

II.   Merchant Services

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

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

(a)

We had a toll contract ending in February 2021, including an anticipated extension at our option, for 281 MW of the output of the Batesville plant. We sold all of this capacity to South Mississippi Electric Power Association (SMEPA) under a power sales contract. In February 2005, we terminated our power sales contract and assigned our rights and obligations under the toll contract to SMEPA. We received approximately $16.3 million in connection with this agreement.

        Although we have exited the wholesale energy trading business, in the late 1990s and early 2000s, we were one of the largest marketers and traders of wholesale natural gas, electricity and other commodities in North America and Western Europe. We stopped wholesale energy trading during the third quarter of 2002, and subsequent activity has focused on limiting our credit risk to counterparties and liquidating our trading positions. However, we still have certain contracts that remain in the trading portfolio because we were unable to liquidate or terminate them. Many, but not all, of our positions have been hedged to limit our exposure to price movements, and these contracts will continue to be our assets and liabilities until the contracts are settled or assigned.

Competition

        Our merchant power plants compete with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies in the development and operation of energy-producing projects. There is an oversupply of power in the geographic areas in which our merchant power generation plants are located, resulting in strong price competition for electric power. Often our marginal cost of producing power exceeds the marginal costs of other generators or normal market prices. Our merchant power plants are therefore generally dependent on outages and transmission difficulties occurring at generation facilities and distribution networks of others or short-term spikes in demand for power resulting from extreme weather. Those events, if they occur, can create short-term opportunities for our merchant power plants to produce and sell power at very favorable prices. Although we continue to work in the marketplace to mitigate our costs, if such events do not occur, or the spread between the cost of gas and the price of power does not increase, we will incur significant losses related to these plants, including the capacity payments on our Elwood tolling contracts and continued operating and maintenance costs on our other merchant power plants.

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Regulation

Natural Gas Marketing Regulation

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

Power Marketing Regulation

        The FPA and rules of the FERC regulate the transmission of electricity in interstate commerce and sales for resale of electric power. As a result, portions of our operations are under the jurisdiction of the FPA and the FERC.

Power Generation Regulation

        In 1992, Congress passed the Energy Act to promote further competition in the development of new wholesale power generation sources by encouraging the development of independent power projects that are certified by the FERC as EWGs. Our owned and contractually controlled merchant power plants are certified by the FERC as EWGs. The owners or operators of EWGs are exempt from the provisions of PUHCA, but not from the FPA. The Energy Act also provided the FERC with extensive new authority to order electric utilities to provide other electric utilities and independent power projects with access to their transmission systems.

        The FPA grants the FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. The FPA provides the FERC with ongoing as well as initial jurisdiction, enabling the FERC to modify previously approved rates. Such rates may be based on a cost-of-service approach or through competitive bidding or negotiation on a market basis. Independent power projects (including EWGs) must obtain FERC acceptance of their rates under FPA Section 205. Our EWGs have been granted market-based rate authority and comply with the FPA requirements governing the approval of wholesale rates.

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Our Executive Team

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

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

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

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

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

        Rick joined Aquila Merchant in 1989 as Vice President and Controller. In 1995, he left Aquila to serve as Vice President and Controller for ProEnergy in Houston, Texas. He rejoined Aquila Merchant in 1997 and served as Vice President Financial Management until November 2002, when he was appointed Interim Chief Financial Officer of Aquila, Inc. In May 2003, Rick was appointed Senior Vice President and Chief Financial Officer of Aquila. Prior to joining our company, Rick served in a management position with Arthur Andersen LLP.

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

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

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

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

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

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

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

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

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

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

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

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

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Item 2.  Properties

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

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

Item 3.  Legal Proceedings

Litigation

AMS Shareholder Lawsuit

        A consolidated lawsuit was filed against us in federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange offer completed in January 2002. The suit raised allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange offer on behalf of the public shareholders of Aquila Merchant. This lawsuit is scheduled for trial in May 2005. We believe we have strong defenses and will defend this case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Price Reporting Litigation

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

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

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

20

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

Enron Bankruptcy Litigation

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

Lender Litigation

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

ERISA Litigation

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

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

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

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

        There were no matters submitted to a vote of security holders in the fourth quarter of 2004.

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Part II

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

        Our common stock (par $1) is listed on the NYSE under the symbol ILA. Through March 15, 2002, the symbol was UCU. At March 7, 2005, we had approximately 34,000 common shareholders of record. Information relating to market prices of common stock on the NYSE and cash dividends on common stock is set forth below. On March 7, 2005, the reported last sale price of the common stock on the NYSE was $4.06 per share.

Market Price Per Share

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

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Item 6.  Selected Financial Data

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

        (a)   Depreciation and amortization expense included (in millions) $13.1 and $8.1 of goodwill amortization for the years ended December 31, 2001 and 2000, respectively. Goodwill amortization was not recorded in the years ended December 31, 2004, 2003 and 2002 as a result of the implementation of a new accounting standard that discontinued the amortization of goodwill beginning January 1, 2002. Additionally, included in earnings from equity method investments for those periods was approximately (in millions) $17.6 and $10.5, respectively, of goodwill amortization.

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

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

        (d)   Included in earnings (loss) from continuing operations for the year ended December 31, 2002, are (a) a $696.1 million impairment charge on our investment in Quanta Services; (b) a $247.5 million impairment charge on our investment in Midlands Electricity; (c) a $127.2 million impairment charge on our investment in Multinet Gas and AlintaGas; (d) a $227.6 million impairment charge related to our 96% investment in Everest Connections; (e) a $181.2 million write-down of Merchant Services' goodwill; (f) other impairment charges and losses on sale of assets of $91.9 million, primarily as a result of our decision to sell non-core assets to improve our

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

        (e)   In the year ended December 31, 2001, we (a) recorded a $110.8 million gain on the sale of 5.75 million shares of Aquila Merchant Services, Inc. Class A common stock (net income reflects our 80% ownership of Aquila Merchant from April 27, 2001 to December 31, 2001); (b) wrote off exposure related to the Enron bankruptcy of $35.0 million in Merchant Services and $31.8 million in Domestic Utilities; (c) recorded charges of $16.5 million in our communications business; and (d) recorded charges of $11.5 million in our Australian networks related to valuation allowances on certain deferred taxes and collectibility of certain receivables.

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

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

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

Strategic and Financial Repositioning Overview

Overview

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

•

Maintain synergies of an integrated, multi-state utility.



•

Significantly reduce our debt levels.



•

Continue to improve operational efficiency and lower earnings variability.



•

Gain access to the capital markets on improved terms, allowing the company to more cost-effectively fund investments in its rate base to meet customer needs.



•

Actively work with regulators and legislators to address rate and fuel cost issues.



•

Selectively divest regulated utility assets.



•

Efficiently divest of our interest in remaining three Merchant peaking facilities and Everest Connections and exit our Elwood tolling obligation.

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

Asset Divestures and Strengthen Credit Profile

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

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

26

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

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

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

Historical Review of Repositioning Efforts

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

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

•

Began the wind-down of our Merchant Services trading portfolio in North America and Europe;



•

Sold our natural gas storage facilities in both North America and the United Kingdom;



•

Sold substantially all of our merchant loan portfolio;



•

Sold our gas gathering and processing business located primarily in Texas and Oklahoma;



•

Reduced our investment in Quanta Services, Inc. (which builds and maintains networks that carry energy and telecommunications) from 38% to 10.2%;



•

Sold our equity investment in regulated utility operations in New Zealand; and



•

Eliminated our quarterly dividend.

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

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

•

Sold our remaining 10.2% investment in Quanta Services, Inc.;



•

Sold our Australian investments;



•

Signed an agreement to sell our United Kingdom utility investment, which we completed in January 2004;



•

Entered into a $430 million three-year secured term loan;



•

Terminated our capacity payment obligations under our Acadia tolling agreement;



•

Signed agreements to sell our Canadian utility businesses, which we completed in the second quarter of 2004;



•

Signed agreements to sell our equity investment in 13 independent power plants, which we completed in the first half of 2004;



•

Pursued rate increases for certain of our gas and electric operations; and



•

Continued the wind-down of our wholesale energy trading businesses in North America and Europe.

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

•

Sold our investment in a merchant power plant development project in the United Kingdom;



•

Settled rate cases relating to our Missouri and Colorado electric and Missouri and Nebraska gas utility operations and pursued rate relief for our Kansas electric and gas utility operations;



•

Terminated our capacity payment obligations under our Aries tolling agreement and exited our investment in the Aries merchant power plant;



•

Received a distribution on our investment in the BAF Energy cogeneration project;



•

Renewed our 364-day letter of credit facility;



•

Sold a non-strategic natural gas system located in eastern Missouri;



•

Terminated four long-term natural gas supply contracts;



•

Issued 46.0 million shares of common stock and $345 million of mandatorily convertible senior notes, raising $446.6 million in net proceeds;

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•

Retired the $430 million three-year secured term loan due in April 2006;



•

Entered into a $220 million five-year unsecured term loan and a $110 million five-year revolving credit facility; and



•

Entered into a $150 million six-month revolving credit facility secured by the accounts receivable of our regulated operations.

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

LIQUIDITY AND CAPITAL RESOURCES

Working Capital Requirements

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

Cash Flows

Cash Flows from Operating Activities

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

•

We had a net loss from continuing operations of $562.5 million before income tax benefits, including a $156.2 million loss related to the termination of four long-term gas contracts.



•

During 2004, we paid a $26.5 million civil penalty settlement to the CFTC related to the reporting of natural gas trading information to publications and we paid $38.0 million to settle an appraisal rights lawsuit.



•

Higher gas prices in 2004 resulted in increased cash payments for the purchase of gas inventory, collateral deposits and gas purchase prepayments for our domestic utilities business.



•

We made $25.6 million of net tax payments related to the sale of our consolidated Canadian utility operations and other international investments.



•

Offsetting cash outflows in 2004 were collateral returns resulting from the continued wind-down of our wholesale energy trading positions and contract exits, and depreciation.

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

•

During 2003, we had significant working capital requirements due to our non-investment grade credit rating and the resulting changes in vendor payment terms.



•

We were required to post significant collateral in 2003 due to our non-investment grade credit rating and increased natural gas prices. Some of our collateral from 2002 was returned to us as we continued to exit our energy trading businesses. However, we were required to cash collateralize our letters of credit under our new letter of credit facility.



•

We made a $105.5 million payment to terminate our Acadia tolling contract in connection with our restructuring effort to return to operating as a domestic utility.



•

We made other restructuring payments of $61.3 million in 2003 for severance, retention and other related charges due to our continued exit from the wholesale energy trading business, primarily for severance that had been accrued in 2002 and due to our restructuring of Everest Connections.



•

Higher gas prices in 2003 resulted in increased cash payments for the purchase of gas inventory for our utilities.



•

Offsetting cash outflows was the receipt of approximately $261 million of income tax refunds received during the year and depreciation.

        Our Elwood tolling contracts will have a material negative impact on our operating cash flows for the foreseeable future. We are attempting to restructure or terminate the Elwood tolling contracts. Any cash payment made to exit this obligation would have a negative impact on operating cash flows in the year the payment is made, but would improve operating cash flows in future periods.

        Our significant debt load relative to our overall capitalization and the 14.875% interest rate we pay on $500 million of our long-term debt has substantially increased our interest costs and will continue to negatively impact our operating cash flows. It will be important for us to substantially improve our operating cash flows. We are attempting to do this by improving the efficiency of our remaining businesses, increasing sales through utility rates, retiring debt and completing the wind-down of our Merchant Services business.

Cash Flows from Investing Activities

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

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

Cash Flows from Financing Activities

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

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

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

Current Credit Ratings

        Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and vendor payment terms, including collateral and prepayment requirements. Our financial flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment grade borrowers. As of December 31, 2004, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

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

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

        We do not have any trigger events (e.g., an acceleration of repayment of outstanding indebtedness, an increase in interest costs or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events. If our credit ratings improve to certain levels, the interest rates on $970 million of our long-term debt obligations will be lowered.

Collateral Positions

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

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

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

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

32

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

Contractual Obligations

        Our contractual cash obligations include maturities of long-term debt, cash payments for our two remaining long-term gas contracts, minimum payments on operating leases and regulated power, gas and coal purchase contracts, as well as the Elwood tolling contracts and merchant gas transportation obligations. See Notes 13, 14 and 21 to the Consolidated Financial Statements for further discussion of these obligations.

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

(a)

Long-term debt obligations maturing in 2007 does not include the non-cash, mandatory conversion of $345.0 million of PIES to common stock on September 15, 2007.

Long-Term Gas Contracts

        We accounted for the advance cash payments we received under these contracts as liabilities. We reduce our obligation for these long-term gas contracts as the gas is delivered to the customer under the units of revenue method. If we were to default on these obligations, or were unable to perform on them, we would be required to pay the issuers of the surety bonds or the counterparties on these arrangements approximately $69.6 million. This amount is greater than the long-term gas contract balance on our Consolidated Balance Sheet due to our use of the units of revenue method versus a present value method applied under the default provisions of the contractual agreements. We do not intend to terminate these remaining contracts.

Elwood Tolling Contracts

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

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Off-Balance Sheet Arrangements

        The term "off-balance sheet arrangement" generally means any transaction, agreement or other contractual arrangement to which an entity that we do not consolidate is a party, under which we have (i) any obligation arising under a guarantee contract, derivative instrument or variable interest; or (ii) a retained or contingent interest in assets transferred to such entity or similar arrangement that serves as credit, liquidity or market risk support for such assets. As of December 31, 2004, we have obligations under certain off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that may be material to investors. These are discussed below.

Merchant Loan Portfolio

        In connection with our former portfolio of merchant loans to energy-related businesses, we entered into commodity and interest rate swaps with the borrowers. Because of increases in natural gas prices and declines in interest rates, these swaps have increased in market value. When we sold substantially all of the portfolio of loans, we retained these swaps. As part of the sale agreement, we agreed that in the event these borrowers fail to meet their note obligations to the buyer of the portfolio, we could be required to share a portion of any proceeds we receive on these swaps with the buyer. In 2004, we paid $6.0 million to the buyer of the portfolio out of $10.7 million of swap proceeds collected. As of December 31, 2004, we have collected $28.0 million related to the remaining swaps, of which we have reserved $5.0 million to cover this obligation. The value of the unsettled portion of these swaps, which expire by December 2006, was $28.5 million at December 31, 2004.

Equity Put Rights

        Certain minority owners of Everest Connections had the option to sell their ownership units to us if Everest Connections did not meet certain financial and operational performance measures as of December 31, 2004 (target-based put rights). If the target-based put rights were exercised, we would have been obligated to purchase up to 4.0 million and 4.75 million ownership units at a price of $1.00 and $1.10 per unit, respectively, for a total potential cost of $9.2 million. As a result of our reduced funding of this business, management assessed the likelihood of achieving these metrics and during 2002 recorded a probability-weighted expense of $7.1 million. In 2004, we achieved the operating targets related to 4.0 million and 1.5 million of ownership units at a price of $1.00 and $1.10 per unit, respectively. Therefore, we reversed $4.5 million of this reserve. We did not achieve the targets related to 3.25 million of ownership units at a price of $1.10 per unit. The holders of these target-based put rights exercised their options and were paid $3.6 million for their ownership units in February 2005. As of December 31, 2004, we had fully reserved for this obligation. The minority owners of 9.5 million ownership units also have the option to sell their ownership units to us at fair market value (market-based put rights). The market-based put rights expire on December 31, 2005. We have not provided for this potential obligation as the exercise would represent an equity transaction at fair value. We do not believe based on current estimates of fair value that these market-based put rights are a material contingent obligation.

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Capital Expenditures

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

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

Iatan 2

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

Regulatory Approvals Required for Financing

        We are required to obtain the prior approval of the FERC, Kansas Corporation Commission and Colorado Public Utilities Commission prior to issuing long-term debt or stock. We currently have approval from the FERC, Kansas Commission and Colorado Commission to issue up to $238 million of securities in the form of any combination of common stock and long-term debt that is mandatorily convertible into our common stock. We do not have approvals to incur additional long-term debt.

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

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

Restriction on Ability to Issue Common Stock

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

FINANCIAL REVIEW

        This review of performance is organized by business segment, reflecting the way we managed our business during the periods covered by this report. Each business group leader is responsible for operating results down to earnings before interest and taxes (EBIT). We use EBIT as a performance measure as it captures the income and expenses within the management control of our segment business leaders. Because financing for the various business segments is generally completed at the parent company level, EBIT provides our management and third parties an indication of how well individual business segments are performing. Therefore, each segment discussion focuses on the factors affecting EBIT, while financing and income taxes are separately discussed at the corporate level.

        The use of EBIT as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with GAAP. In addition, our use of EBIT may not be comparable to similarly titled measures used by other entities.

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        See page 65 for cautionary statements and risk factors concerning forward-looking statements contained in this analysis.

Key Factors Impacting Continuing Operating Results

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

•

Domestic Utilities EBIT decreased $16.0 million primarily due to increased cost of natural gas used for fuel, higher purchased power cost and unfavorable weather for both the electric utility and the gas utility, partially offset by rate increases in Nebraska, Colorado and Missouri.



•

The continued wind-down of our energy trading businesses resulted in a $23.2 million increase in losses before interest and taxes from Merchant Services, driven primarily by the losses associated with the termination of four long-term gas contracts.



•

In Corporate and Other, we recorded $42.1 million of foreign currency gains in 2003 related to favorable movements in the Australian and New Zealand dollar against the U.S. dollar. We recorded $11.9 million of foreign currency gains in 2004 related to the wind-down of our Canadian merchant subsidiaries.

Cumulative Effect of Accounting Change

        In October 2002, the EITF reached a consensus to rescind EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." By rescinding EITF 98-10, all contracts that would have otherwise been accounted for under EITF 98-10 and that do not fall within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging

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Activities" (SFAS 133), should no longer be marked-to-market through earnings. We elected to adopt this requirement in October 2002 and thus reversed $37.5 million (or $22.7 million on an after-tax basis) of earnings previously recognized.

Restructuring Charges

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

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Net Loss on Sale of Assets and Other Charges

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