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

FORM 10-K

(Mark One)

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.    ý

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

        The aggregate market value of the voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on June 30, 2003 as reported on the New York Stock Exchange, was approximately $497,887,123. Shares of Common Stock held by each officer and director and by each person who owns 5% or more of the outstanding Common Stock have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

INDEX

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Part 1

Item 1.    Business

History and Organization

        Aquila, Inc. (the Company, which may be referred to as "we," "us" or "our") is an energy provider headquartered in Kansas City, Missouri. We began as Missouri Public Service Company in 1917 and reincorporated in Delaware as UtiliCorp United Inc. in 1985. In March 2002, we changed our name to Aquila, Inc. We operate regulated and non-regulated businesses in the United States and Canada. As of December 31, 2003, we had 3,235 employees in the United States and 1,202 employees in Canada. Our business is organized into two groups: our Global Networks Group and Merchant Services. Through our Global Networks Group, we operate electric and natural gas distribution networks serving more than 1.8 million customers in seven mid-continent states and two Canadian provinces. Through Merchant Services, we own, operate and contractually control non-regulated electric generation assets in the United States. See Management's Discussion and Analysis for further discussion of recent events.

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

Business Group Summary

        Segment information for the three years ended December 31, 2003 is included in Note 20 to the Consolidated Financial Statements.

I.    Global Networks Group

        Our Global Networks Group is divided into two business segments: Domestic Networks and International Networks.

Domestic Networks

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

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Properties

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

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

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

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

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

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Seasonal Variations of Business

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

Competition

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

Regulation

State Regulation

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

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

•

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

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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 (e.g., through stock or debt issuance or other securitization arrangement) in our assets, 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 following summarizes our recent rate case activity:

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

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

        In August 2002, we filed for a $14.3 million general rate increase in Michigan. We received approval to place an interim increase of $8.2 million into effect in December 2002. We reached a settlement with the Michigan Commission staff and other intervening parties for an increase of $9.1 million. This settlement was approved by the Michigan Commission and the new rates went into effect in March 2003. This increase was partially offset within a separate depreciation case docket which reduced our annual rates by $.7 million. That decrease relates to our depreciation rates and reduced cash flow with little impact on earnings.

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

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

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

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

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

        Our domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute natural gas in seven states. All of our gas distribution utilities have Purchased Gas Cost Adjustment (PGA) provisions that allow them to pass the cost of the gas to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to "true-up" billed amounts to match the actual cost we incurred.

        In our regulated electric business, we generate approximately 60% of the power that we sell and we purchase the remaining 40% through long-term contracts or in the open market. The regulatory provisions for recovering power costs vary by state. In Kansas, we have an Energy Cost Adjustment that serves a purpose similar to the gas utility's PGAs. To the extent that our fuel and purchased power energy costs vary from the energy cost built into our tariffs, the difference is passed through to the customer. In Colorado, we have an Incentive Clause Adjustment that provides for recovery from the customer of 75% of the variability in energy costs. In Missouri, we do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our electric earnings can fluctuate more in Missouri than in our other electric rate jurisdictions.

Federal Regulation

        Under the Federal Power Act (FPA), our wholesale transmission and sale of electric energy in interstate commerce and our generation facilities are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale, the issuance of stock, and long- and short-term debt, the sale, lease or other disposition of such facilities, and accounting matters.

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

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

Environmental Matters

General

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

•

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 Federal Clean Water Act controls effluent and intake requirements and generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency or the U.S. Environmental Protection Agency (EPA).

        In April 2002, the EPA proposed new rules for cooling water intake structures. The final action originally expected in 2003 did not take place but is expected in the first quarter of 2004. The final action may require environmental impact studies as a condition of permit renewals. At this time it is not known what impact, if any, this may have on our operations.

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

Air Emissions

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

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

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

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

Past Operations

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

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

International Networks

        The following discussion describes our International Networks businesses.

Canada

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

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

(a)

As the result of the diversion of water upstream from our plants by another hydroelectric utility, we are entitled to receive power to compensate us for power we otherwise would have been able to generate. In 2003, we received 696,067 MWh of power under this entitlement.

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

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Australia

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

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

United Kingdom

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

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

Seasonal Variations of Business

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

Regulation

        Our investments in electric distribution businesses in Canada are subject to regulation by government-appointed agencies. In general, formal approvals are required to amend customer rate tariffs, issue long-term debt, undertake major capital construction or asset dispositions, establish property valuations, or change accounting policies.

        Electric distribution businesses in British Columbia and Alberta, Canada are regulated by the British Columbia Utilities Commission (BCUC) and the Alberta Energy Utilities Board (AEUB), respectively. Customer rates are generally set for one- or two-year periods based on a forecast cost of service. The BCUC has approved the use of an incentive-based ratemaking mechanism for the past several years. In British Columbia, only wholesale customers have the right of open access to transmission and alternate suppliers. Since January 2001, all customers in Alberta had access to alternate suppliers. We sold our Alberta retail supply business to an unaffiliated company in December 2000.

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        The following highlights our recent rate case activity in Canada:

        Our Alberta electric utility operated on interim tariff rates during the period January 1, 2002 through July 31, 2003 pending a regulatory decision. In its decision rendered in early 2003, and through subsequent filings and reviews during 2003, the AEUB rendered a decision on 2002 and 2003 distribution tariff rates and ordered final revised rates for the period August 1 through December 31, 2003 to adjust interim rates to final rates. The decision resulted in a decrease in rates of $21.0 million for 2002, and no increase in rates in 2003 (2002 rates carried forward to 2003). Almost all of the reduction in rates related to depreciation on distribution assets (average asset lives were extended) and the related income tax effect. Because the decision did not adjust the allowed rate of return we earn, we don't expect net income to be materially impacted by this decision. However, we expect the decision to reduce annual cash flow from operations by approximately $27.2 million for 2004 and beyond. With regard to 2003, cash flow from operations was reduced by approximately $46.2 million, which includes the effect of both the 2002 and 2003 reductions.

        In November 2002, we filed a request for a $4.9 million interim rate increase effective in January 2003 in British Columbia. Following a review process, the BCUC issued a final order in February 2003 approving a $4.2 million rate increase. In late 2003, we filed an application with the BCUC to extend the existing settlement agreement and performance-based rate-setting mechanism for 2004. Although 2004 was supposed to be a rebasing year for the performance-based rate-setting mechanism, we decided to seek an extension of the existing rate arrangements due to ANCBC's proposed change of ownership. Negotiations were held on February 24 and 25, 2004. A negotiated settlement was reached in principle and remains pending while the BCUC completes the process of writing the documentation that will be circulated for sign-off by the participants to the settlement.

Environmental Matters

        Our Canadian operations are governed by environmental laws and regulations similar to those in the United States. In addition, the operation and maintenance of our hydroelectric generation facilities are governed by the Canadian Fisheries Act and provincial water permits and licenses. The Department of Fisheries and Oceans is moving towards stricter regulations under the Fisheries Act, which might lead to higher compliance costs in the future.

II.    Merchant Services

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

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Exchange Offer

        In January 2002, we completed an exchange offer and merger in which we acquired all the outstanding publicly held shares of Aquila Merchant in exchange for shares of Aquila common stock. The public shareholders of Aquila Merchant received .6896 shares of Aquila common stock in a tax-free exchange for each outstanding share of Aquila Merchant Class A common stock. Aquila Merchant shareholders holding approximately 1.7 million shares of Aquila Merchant Class A shares exercised their dissenters' rights to request an appraisal of the fair value of their shares with respect to the merger.

Capacity Services

        Our Capacity Services business owns, controls and operates energy-related assets. These assets historically complemented our Wholesale Services business by providing power, natural gas and coal supplies and an enhanced ability to structure innovative new products and services for clients. Following the implementation of our restructuring plan (including the asset sales discussed below), our remaining Capacity Services assets are non-regulated power generation assets.

Acquisitions and Divestitures

        See Notes 5, 6 and 13 to the Consolidated Financial Statements for a more detailed discussion of the following acquisitions and divestitures.

Piatt County Power Plant

        In February 2002, we agreed to lease from a special-purpose entity (SPE) a 510-megawatt power plant being constructed in Piatt County, Illinois. The plant became operational in June 2003. In the fourth quarter of 2002, we repaid $30.0 million of debt related to this project. Because of the debt repayment and the redemption of a portion of the SPE's equity, we consolidated the assets and related debt of the SPE onto our balance sheet in December 2002. Concurrent with the financings described in Notes 12 and 13 to the Consolidated Financial Statements, this debt was repaid in full during the second quarter of 2003.

Clay County Power Plant

        In November 2000, we agreed to lease from an SPE a 340-megawatt power plant being constructed in Clay County, Illinois. The plant became operational in November 2002. In the fourth quarter of 2002, we repaid $34.5 million of debt related to this project. Because of the debt repayment and the redemption of a portion of the SPE's equity, we consolidated the assets and related debt of the SPE onto our balance sheet in December 2002. Concurrent with the financings described in Notes 12 and 13 to the Consolidated Financial Statements, this debt was repaid in full during the second quarter of 2003.

Sale of Coal Terminal

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

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Sale of Turbines

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

Acadia Tolling Agreement

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

Sale of Independent Power Plants

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

Properties

Contracted Independent Power Plants

        We own interests in a number of "qualifying facilities" (QFs) and "exempt wholesale generators" (EWGs) that have long-term contracts to sell power. QFs are small power producers or cogenerators (power producers that produce steam as a byproduct of the electricity generating process, for use in a second industrial process) that meet certain operating, efficiency and fuel-use standards set forth by the FERC. Electric utilities are required to purchase generating capacity and electric energy from QFs at a price approved by state regulatory bodies. EWGs are independent power projects that are exempt from the Public Utility Holding Company Act (PUHCA), but must obtain FERC approval for wholesale rates. Our EWGs have been granted market-based rate authority.

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        Our contracted independent power plants, as of December 31, 2003, are described below:

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

Merchant Power Plants

        We own or control 2,084 MW of net power generation capacity from merchant facilities. Our merchant power plants generally do not have dedicated customers, because they are designed to operate only during periods of peak demand in the geographic area in which the plant is located. Generally these plants provide power to utilities when the utilities experience unexpected outages or transmission difficulties or the demands of their customers exceed their regular power supply due to extreme weather.

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        Our merchant power plants are described below:

(a)

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.



(b)

Our Domestic Networks business currently has a contract to purchase up to 500 MW during the summer peak through May 2005.



(c)

We have a 15-year contract for 604 MW of the output of the Elwood plant.

Competition

        Our contracted power plants have agreements to sell all their power under long-dated, fixed-price contracts and therefore generally do not face competition. Generally, the purchasers of this power are regulated utilities with investment grade credit ratings. However, if the purchasers were to become bankrupt or default on the contracts, or if the purchase contracts were to be otherwise terminated, we would need to find replacement purchasers of the power from these facilities. Because our facilities are generally less efficient than the most modern power plants, we would have difficulty competing for new customers.

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

Wholesale Services

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

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

Commodity Services

        Our Commodity Services business was a marketer and trader of wholesale natural gas, electricity and other commodities in North America and Western Europe. We stopped increasing our wholesale trading portfolio during the third quarter of 2002, and subsequent activity has been focused on limiting our credit risk to counterparties and liquidating our trading positions. However, we still have certain contracts that remain in the trading portfolio because we were unable to liquidate or terminate them. Commodity price volatility related to most of our positions has been mitigated to limit our exposure to price movements.

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

*

This measure represents the combined thermal equivalent of all commodities delivered per day.

Power

        We purchased power from generation facilities and sold it primarily to utilities, municipalities, cooperatives and other marketing companies.

        Our power marketing and trading activities included trading electricity at various points of receipt, aggregating power supplies and arranging for transmission and delivery. We entered into transmission arrangements with non-affiliated interstate and intrastate transmission companies through a variety of means, including short-term and long-term firm and interruptible transmission agreements.

Natural Gas

        We purchased natural gas from a variety of suppliers under daily, monthly, variable load, base load and term contracts that included either market-sensitive or fixed-price terms. We sold natural gas under sales agreements that had varying terms and conditions, most of which were intended to match seasonal and other changes in demand.

        Our natural gas marketing activities included contracting to buy natural gas from suppliers at various points of receipt, aggregating natural gas supplies, arranging for their transportation, negotiating the sale of natural gas and matching natural gas receipts and deliveries based on volumes required by clients. We entered into transportation arrangements with affiliated and

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non-affiliated interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. We also utilized our natural gas storage facilities and entered into various short-term and long-term firm and interruptible agreements for natural gas storage in order to offer peak delivery services to satisfy winter heating and summer electric generating demands.

        We also entered into long-term gas transactions with municipalities, agreeing to deliver natural gas to them for an extended period of time (generally 10 to 12 years) at a fixed cost. The municipalities paid us in advance for the commodity. Between 1997 and 2000, we closed five of these transactions with an aggregate payment amount of approximately $1 billion. Our obligation to deliver gas under these contracts has not changed and we are committed to meeting those obligations. As of December 31, 2003, we had obligations of $671.1 million on the balance sheet related to these contracts. We have substantially hedged our risk of changes in the price of natural gas to be delivered under these contracts.

Client Services

        Our Client Services business offered products to help our clients manage multiple risks, including price, liquidity, credit, volatility and weather risks. We used our access to current market information, trends, opportunities and threats, as well as the quantitative analytical and practical skills we developed in our marketing and trading business, to develop innovative products and services in order to better manage the risks of our clients. We exited this business in 2002.

Capital Services

        Our Capital Services business provided capital structuring services to our clients by bundling structured financing with our commodity and capacity capabilities. Our structuring alternatives typically included traditional asset-based lending, revolving credit facilities, convertible preferred stock and volumetric production payments.

        Our Capital Services earnings were derived from the spread between the price we charged clients for funding and our cost for these funds. In addition, incremental value was created when we completed transactions that we otherwise might not have captured without our commodity capabilities. In December 2002, we sold substantially all our notes receivable in the merchant loan portfolio as we exited from this business. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of this divestiture.

Regulation

Natural Gas Marketing

        The FERC has implemented regulations on the transportation and marketing of natural gas that are intended to induce interstate pipeline companies to provide non-discriminatory transportation services to producers, distributors and other shippers. The effect of the regulations has been the creation of an open access market for natural gas purchases and sales and the creation of a business environment that has fostered the evolution of various privately negotiated natural gas sales, purchase and transportation arrangements. The sale for resale of natural gas in North America has substantially completed its evolution to an open access market.

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Other Natural Gas Regulatory Issues

        Our natural gas purchases and sales are generally not regulated by the FERC or other regulatory authorities. However, we depend on the natural gas transportation and storage services offered by various pipeline companies that are regulated by the FERC and state regulatory authorities to enable the sale and delivery of our natural gas supplies.

Power Marketing Regulation

        The Federal Power Act (FPA) and rules of the FERC regulate the transmission of electricity in interstate commerce and sales for resale of electric power. As a result, portions of our operations are under the jurisdiction of the FPA and the FERC. In April 1996, the FERC adopted Order 888 to expand transmission service and access and to provide alternative methods of pricing for transmission services. Order 888 was intended to open the FERC-regulated interstate transmission grid in the continental United States to all qualified persons seeking transmission services. Owners of FERC-regulated transmission facilities are required to provide non-discriminatory open access to those facilities with rates, terms and conditions that are materially comparable to those the owner imposes on itself.

Power Generation Regulation

        Historically in the United States, regulated and government-owned utilities have been the only significant producers of electricity for sale to third parties. The enactment of the Public Utility Regulatory Policies Act (PURPA) in 1978 encouraged non-utility companies to enter the electric power business by reducing their regulatory burdens. In addition, PURPA and its implementing regulations created unique opportunities for the development of cogeneration and small power production facilities by requiring utilities to purchase electricity generated by such facilities that meet certain requirements, referred to as "qualifying facilities." As a result of PURPA, a significant market for electricity produced by independent power producers developed in the United States. The benefits and exemptions afforded by PURPA to qualifying facilities are important to us and our competitors.

        The enactment in 1978 of PURPA and the adoption of regulations by the FERC and individual states provide incentives for the development of small power production and cogeneration facilities meeting FERC criteria concerning the facility's size, fuel use, ownership and operating standards. In order to be a qualifying facility, a cogeneration facility must (i) produce not only electricity but also a FERC-mandated quantity of useful thermal output, (ii) meet FERC-mandated operating and efficiency standards when using oil or natural gas as a fuel source and (iii) be no more than 50% owned by an electric utility or electric utility holding company, or any combination thereof. In order to be a qualifying facility, a small power production facility must meet the same ownership criteria as qualifying cogeneration facilities and must have as its primary energy source biomass, waste, renewable resources, geothermal resources or some combination thereof. Small power production facilities must have a capacity of no more than 80 MW, unless the primary energy source of the facility is solar, wind or waste, or the facility qualifies under FPA Section 3(17)(E), in which case there is no maximum plant size. Hydroelectric small power production facilities also may be PURPA qualifying facilities if, among other things, they impound or direct water by means of a new dam or diversion and meet FERC-specified environmental regulations.

        PURPA provides two primary benefits to qualifying facilities. First, the facilities are exempt from otherwise applicable requirements of PUHCA, the FPA and state laws respecting rate and

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financial regulation, except for state laws pertaining to sales of energy to a qualifying facility for the setting of avoided cost rates for purchases from the qualifying facility and establishing reliability procedures and standards. Second, PURPA requires that electric utilities purchase electricity generated by qualifying facilities at a price equal to the incremental cost the utility would have incurred to generate or purchase the power from another source (i.e., the utility's "avoided cost"). PURPA also requires the utility to sell back-up power to the qualifying facility on a non-discriminatory basis. The FERC regulations permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at rates other than the purchasing utility's avoided cost. If Congress amends PURPA, the statutory requirement that an electric utility purchase electricity from a qualifying facility could be eliminated and even the validity and effect of existing contracts could be adversely affected. Moreover, although current legislative proposals specify the honoring of existing contracts, a repeal of the statutory purchase requirements of PURPA going forward could increase pressure to renegotiate existing contracts. Any changes that result in lower contract prices for qualifying facilities could have an adverse effect on our results of operations and financial position.

        In 1992, Congress passed the Energy Policy Act (Energy Act) to promote further competition in the development of new wholesale power generation sources by encouraging the development of independent power projects that are certified by the FERC as exempt wholesale generators (EWGs). The owners or operators of EWGs are exempt from the provisions of PUHCA, but not from the FPA. The Energy Act also provided the FERC with extensive new authority to order electric utilities to provide other electric utilities, qualifying facilities and independent power projects with access to their transmission systems. However, the Energy Act does preclude the FERC from ordering transmission services to retail customers and prohibits "sham" wholesale energy transactions which appear to provide wholesale service, but actually are providing service to retail customers.

        The FPA grants the FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. The FPA provides the FERC with ongoing as well as initial jurisdiction, enabling the FERC to modify previously approved rates. Such rates may be based on a cost-of-service approach or through competitive bidding or negotiation on a market basis. Although "qualifying facilities" under the Public Utility Regulatory Policies Act (PURPA) are exempt from the FPA's rate-making and rate approval requirements, independent power projects (including EWGs) must obtain FERC acceptance of their rates under FPA Section 205. Wholesale electricity sales related to power marketing activities are also subject to FERC acceptance on the basis that the rates either are cost-justified or are market-based. Independent power projects in which we have an interest and that are not qualifying facilities have been granted market-based rate authority and comply with the FPA requirements governing approval of wholesale rates.

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Our Executive Team

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

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

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

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

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

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

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

        Leo joined our company in 1994 as Vice President, Performance Management. He was appointed Senior Vice President in 1995 and Senior Vice President, Human Resources and Operations Support in 1997. In 2000, he was named Senior Vice President and Chief

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

Leslie J. Parrette, Jr. (A.B., Sociology; Harvard College; J.D., Harvard Law School)

        Les joined our company in July 2000 as Senior Vice President and General Counsel. In September 2001, he was also appointed Corporate Secretary of Aquila. Prior to joining our company, Les was a partner in the law firm of Blackwell Sanders Peper Martin LLP from 1992 through June 2000.

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

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

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

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

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

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

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

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

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Item 2.  Properties

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

        In addition, we lease or own various real property and facilities relating to our regulated and non-regulated electricity generation assets. Our principal assets are generally described under "Capacity Services," "International Networks—Canada" and "Domestic Networks." Certain of these properties are encumbered by liens securing loans made to us. See Notes 12 and 13 to the Consolidated Financial Statements for a description of the liens.

Item 3.  Legal Proceedings

Litigation

        On February 19, 2002, we filed a suit which is currently pending in the U.S. District Court for the Western District of Missouri against Chubb Insurance Group, the issuer of surety bonds in support of certain of our long-term gas supply contracts. Previously, Chubb had demanded that it be released from its surety obligation of up to $513.0 million or, alternatively, that we post collateral to secure its obligation. We do not believe that Chubb is entitled to be released from its surety obligations or that we are obligated to post collateral to secure its obligations unless it is likely we will default on the contracts. Chubb has not alleged that we are likely to default on the contracts. If Chubb were to prevail, it would have a material adverse impact on our liquidity and financial position. We rely on other sureties in support of long-term gas supply contracts similar to those described above. There can be no assurance that these sureties will not make claims similar to those raised by Chubb. We have performed under these contracts since their inception and intend to continue to fully perform under these contracts.

        A consolidated lawsuit was filed against us in federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange offer completed in January 2002. The suit raised allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange offer on behalf of the public shareholders of Aquila Merchant. On December 9, 2003, the court denied our motion to dismiss this lawsuit. Persons holding certificates formerly representing approximately 1.7 million shares of Aquila Merchant common stock are also pursuing their appraisal rights in connection with the recombination. The dissenters' rights action is scheduled for trial in May 2004. We do not believe that either of these actions will have an outcome materially adverse to us.

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

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

Other Matters

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

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

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

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

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

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

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

There were no matters submitted to a vote of security holders in the fourth quarter of 2003.

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Part 2

Item 5.  Market for Registrant's Common Equity and Related Shareholder Matters

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

Market Price Per Share

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

Item 6.  Selected Financial Data

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

        (a)   Depreciation and amortization expense included (in millions) $13.1, $8.1 and $1.8 of goodwill amortization for the years ended December 31, 2001, 2000 and 1999, respectively. Goodwill amortization was not recorded in the years ended December 31, 2003 and 2002 as a result of the implementation of a new accounting standard that discontinued the amortization of goodwill beginning January 1, 2002. Additionally, included in earnings from equity method investments for those periods was approximately (in millions) $17.6, $10.5 and $6.6, respectively, of goodwill amortization.

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

        (c)   Included in earnings (loss) from continuing operations for the year ended December 31, 2002, are (a) a $696.1 million impairment charge on our investment in Quanta Services; (b) a $247.5 million impairment charge on our investment in Midlands Electricity; (c) a $127.2 million impairment charge on our investment in Multinet Gas and AlintaGas; (d) a $227.6 million impairment charge related to our 96% investment in Everest Connections; (e) a $178.6 million write-down of Wholesale Services' goodwill; (f) other impairment charges and losses on sale of assets of $94.5 million, primarily as a result of our decision to sell non-core assets to improve our liquidity position; and (g) $210.2 million of restructuring charges from our exit from the wholesale energy trading business and the restructuring of our utility business.

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

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

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

Strategic and Financial Repositioning

        There have been significant changes in the energy industry during the three years ended December 31, 2003. These changes were primarily a result of lower prices in the power markets as new generation capacity continued to come online, the stabilization of commodity prices in California, the bankruptcy and near bankruptcy of several energy merchants, the tightening of the credit markets (for energy merchant companies in particular), and the lack of liquidity in forward energy markets as companies continued to exit and/or scale back their energy trading activities. In response to this escalating set of circumstances, we exited from our wholesale energy trading business and divested the majority of our related activities and assets during 2002. We continued to unwind and restructure our remaining merchant contracts and sell non-core assets in 2003. Separately, we restructured Domestic Networks in 2002 to more closely align it with its regulatory service areas. Staff reductions due to our ongoing restructuring efforts, including employees transferred with the sale of various businesses, consisted of approximately 1,205 Merchant Services employees, 75 Corporate employees and 550 Domestic Networks employees in 2002. With our exit from wholesale trading, we began to transition to a business comprised primarily of our domestic regulated utility business and our merchant power plants. We consider our domestic utility assets our core business. As part of this transition, we took the following actions in 2002:

•

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 our merchant loan portfolio;



•

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



•

Reduced our investment in Quanta Services, Inc. (a company specializing in building and maintaining networks used to carry energy and telecommunications) from 38% to 10.2%; and



•

Sold our equity investment in our regulated utility operations in New Zealand.

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

•

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



•

Sold our Australian investments;



•

Executed a definitive agreement to sell our United Kingdom investment, which we completed in January 2004;



•

Entered into a three year senior secured term-loan facility;



•

Terminated our capacity payment obligations under our Acadia tolling agreement;

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•

Signed definitive agreements to sell our Canadian utility businesses;



•

Signed definitive agreements to sell our investments in 13 independent power plants, which we expect to close in the first quarter of 2004;



•

Pursued (a) appropriate rate increases for certain of our gas and electric operations, and (b) regulatory approvals to pledge our network assets as collateral for the working capital requirements of our utility operations; and



•

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

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

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

•

The improvement of our domestic utility operations, primarily by (a) eliminating cost and operational inefficiencies; (b) improving customer service; (c) continuing to pursue appropriate rate relief; and (d) improving our relationships with the state public service commissions;



•

The reduction of liabilities, which includes attempting to restructure significant contractual liabilities, such as our long-term gas contracts and capacity tolling agreements and pursuing arrangements that will result in the return of collateral posted under contracts with counterparties; and



•

Improving our capital structure by continuing to sell assets and issuing equity or convertible debt securities as market conditions warrant.

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LIQUIDITY AND CAPITAL RESOURCES

Overall

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

(a)

Gross proceeds net of assumed debt obligations.



(b)

This facility is secured by certain future rate collections and will be paid off in March 2004.

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

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

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Pending Asset Sales

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

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

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

Working Capital Requirements

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

Cash Flows

Cash Flows from Operating Activities

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

•

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

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•

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.

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

•

We terminated our accounts receivable sales programs in 2002 resulting in $297.5 million in cash outflows as these receivables were collected and paid to the vendor. However, no additional receivables were sold.



•

Also increasing cash outflows was the payment of higher annual and long-term incentive compensation based on 2001 earnings.



•

We were required to post significant collateral as a result of our credit rating downgrades to non-investment grade. These collateral demands were related to trading contracts as well as certain debt and tolling agreements.



•

We made $95.2 million of restructuring payments in 2002 for severance, retention and other related charges primarily due to our exit from the wholesale energy trading business and for the restructuring of our domestic utilities business to more closely align it with its regulatory service areas.



•

In addition, we made payments of $39.3 million to our defined benefit pension plans to offset declines in plan asset values due to market performance.



•

Partially offsetting cash outflows were cash collections related to price risk management assets and inflows due to the liquidation of our wholesale gas storage inventory.

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

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

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

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

Cash Flows from Investing Activities

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

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

Cash Flows from Financing Activities

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

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

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

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

Current Credit Ratings

        Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and vendor payment terms. Our financial flexibility is limited because of restrictive covenants and other terms that are typically imposed on non-investment grade borrowers. As of December 31, 2003, our senior unsecured long-term debt ratings, as assessed by the three major credit rating agencies, were as follows:

        We do not have any trigger events (e.g., an acceleration of repayment of outstanding indebtedness, an increase in interest costs or the posting of cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events.

Collateral Positions

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

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

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

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

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Contractual Obligations

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

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

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

Long-Term Gas Contracts

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

Merchant Tolling Obligations

        Because it is generally expected that the fuel and start-up costs of operating merchant power plants will exceed the revenues that would be generated from the power sales, during the foreseeable future, we believe that under our merchant tolling agreements our capacity to generate power will largely be unutilized. After including existing forward sales contracts, we expect to incur pretax losses and negative operating cash flows of approximately $38.0 million in 2004 related to these contracts. We are attempting to terminate or restructure these obligations. If our tolling agreements that comprise a substantial portion of our capacity payments are not terminated or restructured on terms acceptable to our counterparties and us, our future earnings and cash flow will be negatively impacted.

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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, 2003, we have obligations under certain off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that may be material to investors as follows:

Merchant Loan Portfolio

        In connection with our former portfolio of merchant loans to energy-related businesses, we entered into commodity and interest rate swaps with the borrowers. Because of increases in natural gas prices and declines in interest rates, these swaps have increased in market value. When we sold the portfolio of loans we retained these swaps. As part of the sale agreement, we agreed that in the event these borrowers fail to meet their note obligations to the buyer of the portfolio, we could be required to share a portion of any proceeds we receive on these swaps with the buyer. As of December 31, 2003 we have collected $27.3 million related to these swaps, of which we have reserved $10.5 million to cover this obligation. The value of the unsettled portion of these swaps was $26.5 million at December 31, 2003.

Guarantees

        We have guaranteed the performance of certain gas aggregators in connection with loans that were made by our wholesale energy trading business. In connection with these agreements, we guarantee to pay the aggregators' counterparties if the aggregators are unable to make their payments for the gas they have purchased. We have terminated all of these agreements as of December 31, 2003. Our exposure is limited to the outstanding payable balances of the aggregators as of the termination dates of these agreements. Our guarantees for these agreements at December 31, 2003 totaled $9.2 million.

Equity Put Rights

        Certain shareholders of Everest Connections have the option to sell their share interests to us if Everest Connections does not meet certain financial and operational performance measures (target-based put rights) as of December 31, 2004. If the target-based put rights were exercised, we would be obligated to purchase up to 4.0 million and 4.75 million share interests at a price of $1.00 and $1.10, respectively, for a total potential cost of $9.2 million. As a result of our reduced funding of this business, management assessed the likelihood of achieving these metrics and during 2002 recorded a probability-weighted expense of $7.1 million. As of December 31, 2003, we reserved $7.8 million for this obligation. Such shareholders also have the option to sell their share interests to us at fair market value (market-based put rights) if they have not exercised their target-based put rights. The market-based put rights expire on December 31, 2005 for 9.5 million shares and do not expire for the remaining 3.25 million shares. We have not provided for this potential obligation as the exercise would represent an equity transaction at fair value.

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Capital Expenditures

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

(a)

Although our Canadian utilities are included in the table above for 2004, we anticipate closing the sale of those businesses in the first half of 2004 and therefore have not included Canada's estimated capital expenditures for 2005 and 2006. Following the sale, future capital expenditures will be the obligation of the buyer.

Regulatory Approvals Required for Financing

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

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

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

FINANCIAL REVIEW

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

        The use of EBIT as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with

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generally accepted accounting principles (GAAP), as an indicator of operating performance or as a measure of liquidity, or other performance measures used under GAAP. In addition, the term may not be comparable to similarly titled measures used by other entities.

        See page 69 for cautionary statements and risk factors concerning forward-looking statements contained in this analysis.

Key Factors Impacting Continuing Operating Results

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

•

As a result of asset sales and impairments, we recorded impairment charges and net losses on sale of assets of $194.7 million in 2003 compared to $1,571.5 million in 2002. These impairments stemmed mainly from our decision to sell non-core, international utility assets in order to return to operating primarily as a domestic electric and gas utility.



•

We exited from the wholesale energy trading business during the third quarter of 2002 and incurred trading and contract losses of $115.8 million during 2002 related to our exit. Our losses in 2003 from this continued wind-down were significantly lower. In addition, our

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operating expenses decreased by approximately $50.1 million from 2002 due to our exit from this business.

•

In 2003, we incurred $28.2 million of restructuring charges versus $210.2 million of restructuring charges in 2002 in connection with the realignment of our Domestic Networks business and the exit from our wholesale energy trading business.



•

Continued lower power prices and higher natural gas prices in 2003 resulted in narrow "spark spreads" (the difference between the price at which electricity is sold and the cost of the fuel used to generate it) which reduced or eliminated the economic benefits of running certain power plants and exercising power generation rights under our tolling contracts. These conditions also negatively impacted our ability to sell additional generation capacity that came on-line. EBIT, before impairments and restructuring charges, for Capacity Services in 2003 was down $80.1 million when compared to 2002.



•

Equity and other earnings for our International Networks segment, including impairment charges and net losses on sale of assets, decreased by $226.4 million in 2003 compared to 2002 primarily due to the sale of its businesses in the fourth quarter of 2002 and in 2003.

Cumulative Effect of Accounting Change

        In October 2002, the Emerging Issues Task Force (EITF) reached a consensus to rescind EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." By rescinding EITF 98-10, all contracts that would have otherwise been accounted for under EITF 98-10 and that do not fall within the scope of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS 133) should no longer be marked-to-market through earnings. We elected to adopt this requirement in October 2002 and thus reversed $37.5 million (or $22.7 million on an after-tax basis) of earnings previously recognized.

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Restructuring Charges

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