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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.    o

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

        The aggregate market value of the voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on June 30, 2002 as reported on the New York Stock Exchange, was approximately $1,020,976,000. 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 a multinational 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 four countries. As of December 31, 2002, we had 4,710 employees, with 3,496 of them in the United States and the remaining 1,214 in Canada. Our business is organized into two groups: Global Networks Group, which consists of Domestic Networks and International Networks, and Merchant Services, which consists of Capacity Services and Wholesale Services:

•

Global Networks Group—Our Domestic Networks business owns and operates regulated electric and natural gas operations in the United States, where we provide natural gas and/or electricity to approximately 1.3 million customers in Colorado, Iowa, Kansas, Michigan, Minnesota, Missouri and Nebraska. Domestic Networks also includes Everest Connections, our 96% owned domestic communications business. Our International Networks business owns and manages interests in electric, gas, and communications networks in Australia and the United Kingdom serving approximately 4.0 million customers. It also includes our wholly-owned electric generation, transmission and distribution properties serving approximately 483,000 customers in two Canadian provinces.



•

Merchant Services—Merchant Services consists of Capacity Services, which owns, operates, and contractually controls our non-regulated electric power generation assets, and Wholesale Services, our North American and European commodity client and capital businesses.

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

Strategic and Financial Repositioning

There have been significant changes in the energy industry during the two years ending December 31, 2002. These changes were primarily a result of lower prices in the power markets as new generation capacity continues 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 continue 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 ourselves from the majority of our related activities and assets during 2002. Separately, we restructured our Domestic Networks Group to more closely align it with its regulatory service areas. Staff reductions due to the restructuring, 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. With our exit from wholesale trading, we began to transition to a business comprised primarily of

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our regulated utility business and our non-regulated power plants. As part of this transition, we took the following actions:

•

The wind down of our Merchant Services trading portfolio in North America and Europe.



•

The sale of our natural gas storage facilities in both North America and the United Kingdom.



•

The sale of our notes receivable loan portfolio.



•

The sale of our gas gathering and processing business located primarily in Texas and Oklahoma.



•

The sale of 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%. We sold the remaining shares during the first quarter of 2003.



•

The sale of our equity investment in our regulated utility operations in New Zealand.



•

The initiation of negotiations to sell our Australian and United Kingdom investments.

        Proceeds from these asset sales were used to pay down debt, fund restructuring charges and support our continuing operations. As part of our ongoing transition plan, our Board of Directors has suspended the payment of dividends on our common stock indefinitely. We now plan to operate primarily as a regulated utility with various investments in non-regulated power generation facilities.

        We have experienced significant net losses and negative cash flows from operations in 2002. We have also experienced a number of credit downgrades and are currently rated as non-investment grade. This has caused us to post a substantial amount of cash or letters of credit as collateral on a number of our contractual agreements. As shown in our Consolidated Financial Statements, we had a retained deficit of $1.7 billion as of December 31, 2002. In addition, as discussed in Notes 12 and 13 to the Consolidated Financial Statements, as a result of these losses, we were in violation of an interest coverage ratio covenant and a covenant that requires us to maintain a maximum debt to capitalization ratio.

        On April 11, 2003, we closed on a three-year senior secured financing of $430.0 million and a 364-day senior secured financing of $100.0 million. The 364-day financing also includes an option under which we can during a 30-day period following closing, at our discretion, increase the size of the financing by up to $100.0 million. Proceeds from the financings will be used to retire debt and support existing and future letters of credit. The secured financings will eliminate the covenant violations stated above. With the above financings, we believe we will have sufficient liquidity to cover our operational needs through June 2004. Our next significant need for outside capital relates to our need to retire senior notes maturing in 2004. We anticipate retiring these notes with proceeds from additional asset sales. In the event we are not successful in closing the asset sales, we would need to obtain a bridge loan to meet these obligations. Although no assurance can be given on the above actions, we expect to be successful in their execution.

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Business Group Summary

Segment information for the three years ended December 31, 2002 is included in Note 22 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 are engaged in the generation, transmission, distribution and sale of electricity to approximately 438,000 customers in Missouri, Kansas, and Colorado. Our electric generation facilities supply electricity to our own distribution systems. We also sell excess power to other utilities and marketing companies. We also distribute natural gas to approximately 891,000 customers in Missouri, Kansas, Colorado, Nebraska, Iowa, Minnesota, and Michigan. Domestic Networks also includes (a) our equity interest in Quanta Services, Inc., and (b) Everest Connections, our 96% owned domestic communications business which provides local and long-distance telephone, cable television, high-speed internet and data services to areas of greater Kansas City.

Divestitures

See Notes 5 and 20 to the Consolidated Financial Statements for a more detailed discussion of our divestitures described below.

Pipeline Operations

In January 2002, we completed the sale of an intrastate pipeline system in Missouri.

Quanta Services

During 2002, we sold approximately 17.6 million shares of Quanta Services, reducing our ownership percentage from 38% to approximately 10%. We sold our remaining 11.6 million shares during the first quarter of 2003.

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Properties

As of December 31, 2002, our domestic electric generation plants included the following:

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

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        At December 31, 2002, we had electric transmission and distribution lines as follows:

        At December 31, 2002, our gas utility operations had 1,518 miles of gas gathering and transmission pipelines and 18,867 miles of distribution mains and service lines located throughout our service territories.

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

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

        We also had non-regulated commercial and industrial gas, appliance services and other sales (in millions) of $378.9, $570.0 and $514.0 in the years ended December 31, 2002, 2001 and 2000, respectively.

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 peak seasons for our Domestic Networks businesses.

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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, however, 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

Our domestic utility operations are subject to the jurisdiction of the public service commissions in the states in which they operate with respect to services and facilities, rates and charges, accounting, valuation of property, depreciation and various other matters. Certain commissions have jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. 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, long and short-term debt, the sale, lease or other disposition of such facilities, and accounting matters. The FPA and activities of the FERC are described more fully under the regulation discussion of our Merchant Services group.

        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. The case is pending before the Minnesota Utilities Commission with an interim rate increase of approximately $5.2 million granted in October 2000. We expect a final settlement to be approved by the Commission in early summer 2003.

        In June 2001, we filed for a $49.4 million increase in our Missouri electric rates. Approximately $39.0 million of the request related to anticipated increased fuel and purchased power costs that did not materialize. In February 2002, we reached a negotiated settlement with the Commission staff and all intervenors that resulted in a $4.3 million annual rate reduction. The rate reduction was driven primarily by a $16.0 million reduction in depreciation which reduced our cash flow but had little impact on earnings.

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

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        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 as of December 2002. We reached a settlement with the Commission staff and other intervening parties for an increase of $9.1 million. This settlement was approved by the Commission in March 2003 and the new rates have gone into effect. This increase was partially offset within a separate depreciation case docket whereby our annual rates were reduced by $.7 million. This decrease relates to our depreciation rates, which reduced cash flow but had little impact on earnings.

        In October 2002, we filed for a $23.4 million increase in our Colorado electric rates. A hearing will be held in April 2003 and new rates are expected to become effective in June.

        Our domestic regulated businesses produce, purchase and distribute power in three states and purchase and distribute 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 commodity to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to "true-up" billed amounts to actual cost incurred.

        In our regulated electric business, we generate approximately 56% of the power that we sell and purchase the remaining 44% 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 (ECA) that serves a similar purpose as the PGAs in place for the gas utility. 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. For Colorado, we have an Incentive Clause Adjustment (ICA) that provides for an equal sharing of the variability of energy costs between us and the customer. In Missouri, we do not have the ability to adjust the rates we charge for electric service to offset all or part of any increase or decrease in prices we pay for natural gas, coal or other fuel we use in generating electricity (i.e., a fuel adjustment mechanism). As a result, our electric earnings can fluctuate more in Missouri than in our other electric rate jurisdictions. In January 2003, legislation to provide a fuel adjustment clause was introduced in both the Missouri House and Senate. This legislation has now passed both the House and Senate Committees and has been submitted to the respective legislative chambers for passage. If passed and signed by the Governor, we will be able to file periodic fuel and purchase power adjustments.

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:

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the discharge of pollutants into the air and water;



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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, associated with our operations;

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•

the protection of animals and minimization of noise emissions; and



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safety and health standards, practices and procedures that apply to the workplace and to 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 Environmental Protection Agency (EPA). All of our facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are lawfully operating under the prior permit.

        In April 2002, the EPA proposed new rules for cooling water intake structures. The final action, expected by August 2003, 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 operations.

        In July 2000, the EPA issued final rules for the implementation of the Total Maximum Daily Load (TMDL) program of the Clean Water Act. While the EPA issued a proposed rule to withdraw the TMDL rules, their goal was to establish over the next 15 years, the maximum amounts of various pollutants that can be discharged into waterways while keeping those waterways in compliance with water quality standards. The establishment of TMDL values may eventually result in more stringent discharge limits in each facility's wastewater discharge permit. We will not know the future impact of the rule until the change is finalized.

Air Emissions.    Our facilities are subject to the Federal Clean Air Act and many state laws and regulations relating to air pollution. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxides (NOx) and particulate matter. Our facilities generally emit these pollutants at levels within regulatory requirements. Fossil-fuel power generating facilities typically are major sources of air pollutants and are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies. The Bush administration has introduced a Clear Skies Initiative that would require further reductions in sulfur dioxide, nitrogen oxides and mercury emissions from power plants. Until the legislation is developed and passed, we cannot determine the impact this action will have on our power plants. In 2003, several of our power plants will come under a NOx budget requirement. However, this will not significantly impact the business.

Carbon Dioxide.    In November 1998, the United States became a signatory to the Kyoto Protocol to the United Nations Framework Convention on Climate Change. The Kyoto Protocol calls for developed nations to reduce their emissions of greenhouse gases, which are believed to contribute to global climate change. Carbon dioxide, a major byproduct of the combustion of fossil fuel, is considered to be a greenhouse gas. The Kyoto Protocol, however, will not become law in the United States until the U.S. Senate ratifies it. Aside from the Kyoto Protocol, the current administration has indicated it will not pursue limitations on carbon dioxide emissions. Nevertheless, bills continue to be introduced in Congress that include carbon dioxide emission limitations. Similarly, a number of states, primarily in the Northeast, are poised to include carbon dioxide limitations in state law. At this time there is no enforceable standard for carbon dioxide emissions, and it is unclear what effect, if any, current federal and state efforts to impose such a standard will have on our facilities.

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Mercury.    In December 2000, the EPA announced that it would regulate mercury emissions from coal- and oil-fired power plants. The EPA is expected to propose regulations by December 2003 and issue final regulations by December 2004. The impact of this action on our power plants cannot be determined until final regulations are issued.

Past Operations.    Some federal and state laws authorize the EPA and other agencies to issue orders and compel responsible parties to clean up sites that are determined to present actual or potential threat to human health or the environment. We are named as a potentially responsible party at two disposal sites for Polychlorinated Biphenyls (PCBs). In addition, we have retained some environmental liability for several operations and investments we no longer own. We also own or have acquired liabilities from companies that once owned or operated 29 former manufactured gas plant sites. We estimate our ongoing program to remediate these sites will cost $8.7 million.

        In EPA Region VII, we and several other gas utilities were requested to provide information on past use of mercury regulators. We responded to the EPA's request and do not expect this inquiry to result in a material cost to us.

International Networks

The following discussion describes our International Networks businesses.

Australia

We have a 33.8% ownership interest in United Energy Limited (UEL), an electricity distribution utility serving 578,000 customers in Melbourne, Victoria. Under an operating services agreement with UEL, we manage the utility for a fee. UEL distributes and sells electricity, with the majority of its sales originating from the regulated distribution network business. We also have a 25.5% equity interest in Multinet Gas, a gas distribution business in Melbourne that serves approximately 630,000 accounts. In addition, we own a 50% interest in WA Gas Holdings Pty Ltd (WA Gas), which in turn owns 45% of AlintaGas Limited, the principal gas distribution and retail business in Western Australia. UEL owns the other 50% interest in WA Gas. AlintaGas serves approximately 463,000 customers. WA Gas has an operating services agreement with AlintaGas and receives a fee for management services provided under the agreement.

        We are exploring the sale of our interest in the above properties and anticipate a sale being completed in 2003, however, there can be no assurance that this will occur.

New Zealand

In October 2002, through a public tender offer in New Zealand, VECTOR Limited acquired all of the outstanding shares of UnitedNetworks Limited (UNL), in which we had a 70.2% indirect interest. This tender resulted in an after tax gain of $28.0 million. See Note 10 to the Consolidated Financial Statements for a more detailed discussion of this divestiture.

Canada

We own Aquila Networks Canada (British Columbia) Ltd. (ANCBC), a hydroelectric utility in British Columbia, Canada. ANCBC has four hydroelectric generation facilities with a capacity of 212 megawatts and approximately 4,243 miles of distribution and transmission lines that serve approximately 93,000 customers in south central British Columbia. ANCBC generates about half

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of its power needs and acquires the rest through power purchase contracts. We also own Aquila Networks Canada (Alberta) Ltd. (ANCA). ANCA serves approximately 390,000 electric customers through 58,894 miles of low-voltage distribution lines representing 50% of Alberta's distribution network. As part of our restructuring initiatives, we plan to explore the possible sale of our Canadian operations.

        As of December 31, 2002, 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 received another 597,733 MWh of power in 2002 as entitlement generation to compensate us for the power we otherwise would have been able to generate.

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

(a)

Includes a full year of operations from ANCA, offset by the sale of its retail operations in January 2001.



(b)

Includes sales, volumes and customers from ANCA after it was acquired in August 2000.

United Kingdom

In May 2002, we purchased from FirstEnergy Corporation a 79.9% equity interest in Avon Energy Partners Holding Company, the holding company for Midlands Electricity, a United Kingdom electric distribution network. FirstEnergy retained the remaining 20.1% of Avon. Although we have since written off substantially all of our investment, at the time of the

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acquisition, the gross purchase price of the acquisition was valued at approximately $262 million and was comprised of the following:

        Midlands is the fourth-largest regional electricity company in the United Kingdom, serving approximately 2.4 million network customers through a 38,000-mile distribution network. Midlands also owns a combined 884 megawatts of net generation capacity in the United Kingdom, Turkey and Pakistan.

        In connection with the acquisition, FirstEnergy retained substantive participating and protective rights as the minority partner. We and FirstEnergy each have 50% voting power and an equal number of representatives on the Avon board of directors. Although we have the majority economic interest, FirstEnergy's participation in day-to-day business decisions is significant, including approval of executive compensation, additional capital contributions, budgets, and the dissolution of the company.

        Recent downgrades in credit ratings assigned to the public debt in the Midlands ownership chain have called into question the ability of Midlands to pay us management fees and dividends. Additionally, the local regulatory body, the Office of Gas and Electricity Markets (Ofgem), now requires pre-approval of cash payments to the owners in the form of management fees or dividends. Accordingly, in 2003 and beyond, we intend to record equity earnings and management fees only to the extent of cash received.

        In August 2002, Aquila and FirstEnergy initiated a process for the sale of Midlands with final binding bids due in December 2002. We received offers in early December and are currently in negotiations with the prospective buyer.

Seasonal Variations of Business

Our International Networks businesses are weather-sensitive. We have both summer- and winter-peaking assets. The table below shows the peak seasons for these businesses.

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Regulation

Our investments in electric and gas distribution businesses in foreign countries 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 by the Alberta Energy Utilities Board (AEUB), respectively. Customer rates are generally set for one- or two-year periods based on a forecasted 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 have access to alternate suppliers. We sold our Alberta retail supply business to an unaffiliated company in December 2000.

        The electric and gas distribution businesses in Victoria, Australia, are regulated by that state's Essential Services Commission. Customer rates for use of the distribution systems are reset at five year intervals following an examination of the companies' historical and projected costs, return on invested capital, and other aspects of customer service. Those rates are adjusted annually after each reset interval, primarily by the rate of inflation minus a predetermined productivity factor. An efficiency carry-over mechanism provides for a five-year rolling adjustment for actual changes in operating and maintenance cost efficiencies. Gas rates were reset in January 2003 with a reduction of 2%. The next reset for electric rates will occur in January 2006. The final stage of full retail competition for electric customers was implemented in January 2002, and for gas customers in October 2002.

        The gas distribution business in Western Australia is regulated by the Office of Gas Access Regulation. Refinement of the regulatory regime is in progress, following the privatization of the formerly government-owned gas utility in November 2000. The regulatory process for review of customer rates will likely reflect a number of the features of the Victoria model. The proportion of gas volumes used by industrial and large commercial customers compared to residential customers is very high. Because the company's franchise is not exclusive, other companies can construct pipelines that by-pass the incumbent network. The implementation of full retail gas competition is expected during 2003.

        Electric distribution businesses in the United Kingdom are regulated by Ofgem. Full retail competition is in effect in the U.K. However, we do not participate in the retail supply business. Customer rates for use of the distribution systems are reset at five year intervals following an examination of the companies' historical costs, industry benchmark costs, return on invested capital, and customer service levels. Those rates are adjusted annually after each reset interval, primarily by the rate of inflation minus a predetermined productivity factor. The next reset for our electricity rates will be in April 2005.

        The following highlights our recent rate case activity:

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        In December 2001, we filed for an annual rate increase in Alberta of about $30 million along with an application for a performance-based rate-setting mechanism. We subsequently modified that request and sought a $12.7 million increase for 2002 and a $6.0 million increase for 2003. In July 2002, an interim rate increase of approximately $9.6 million was approved. Hearings were held in September and October 2002 and a final order was issued in February 2003, resulting 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. The decision did not adjust the allowed rate of return earned by the company and therefore, net income is not expected to be materially impacted by this decision. However, the decision is estimated to reduce annual cash flow from operations by approximately $17.0 million for 2004 and beyond. With regard to 2003, cash flow from operations will be reduced by approximately $33.0 million, which includes the effect of both the 2002 and 2003 reduction.

        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.

Environmental Matters

Canada.    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 is governed by the Canadian Fisheries Act and provincial water permits and licenses. The Department of Fisheries and Oceans is moving towards stricter enforcement of the Fisheries Act, which might lead to higher compliance costs in the future.

II.  Merchant Services

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

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 1.8 million shares of Aquila Merchant Class A shares exercised dissenters' rights 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 asset sales discussed below, our remaining Capacity Services assets are comprised of non-regulated power generation assets.

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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.

Power Plant Construction

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. We expect construction to be completed 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, as it no longer qualified for off-balance sheet treatment. Concurrent with our new 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, as it no longer qualified for off-balance sheet treatment. Concurrent with our new financings described in Notes 12 and 13 to the Consolidated Financial Statements, this debt was repaid in full during the second quarter of 2003.

Coahoma Power Plant.    In September 2002, construction was completed on a 340-megawatt power plant that we own and operate in Clarksdale, Mississippi.

Termination of Cogentrix Acquisition

In August 2002, we agreed to terminate the purchase agreement we signed in April 2002 to acquire Cogentrix Energy, Inc., an independent power producer. We agreed with Cogentrix that due to the current uncertainty of the electric power market, the deterioration of the creditworthiness of some of Cogentrix's customers and our exit from the wholesale energy trading business, proceeding with the transaction was impractical and not in either company's interest.

Sale of Lockport Energy

In September 2002, we sold our 16.58% interest in the Lockport Energy facility, a 180-megawatt gas-fired power plant located approximately 30 miles north of Buffalo, New York.

Sale of Gas Gathering and Pipeline Assets

In October 2002, we sold our Texas and Oklahoma natural gas pipeline systems, including our natural gas and natural gas liquids processing assets, and our 50% ownership interest in the Oasis Pipe Line Company.

Sale of U.K. Gas Storage Assets

In October 2002, we sold our Hole House natural gas storage assets in the United Kingdom. The assets consisted principally of a natural gas storage facility in Cheshire, England.

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Sale of Lodi Gas Storage

In October 2002, we sold our investment in the Lodi gas storage project in California. We owned 50% of WHP Acquisition Company LLC, a company jointly established in 2001 with an affiliate of ArcLight Energy Partners Fund I, L.P., to purchase Western Hub Properties LLC, the developer of the Lodi gas storage project.

Sale of Gas Storage Facility

In December 2002, we sold our Texas natural gas storage facility in Katy, Texas, one of the largest operating storage facilities in the Southwest.

Sale of Coal Terminal

In February 2003, we sold our coal terminal in West Virginia that provides blending and storage services, with annual capacity of approximately 5 million tons.

Properties

Contracted Power Plants

We own interests in a number of "qualifying facilities" (QFs) and "exempt wholesale generators" (EWGs) which 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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        The table below shows information about our contracted power plants:

Merchant Power Plants

We own or control 2,664 MW of net power generation capacity from merchant facilities, including capacity under construction. 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 they 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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        The table below shows information about our merchant power plants:

*

Estimated.



(a)

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



(b)

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



(c)

We have a 20-year contract for 580 MW of the output of the Acadia plant.



(d)

The measure of efficiency of converting fuel to electricity, expressed as BTU's of fuel per kilowatt-hour. The lower the heat rate, the more efficient the plant.

Natural Gas Assets

We owned significant natural gas gathering, transportation, processing and storage facilities located in Texas, Oklahoma and California. These assets were sold as part of our restructuring in the second half of 2002.

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

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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. We continue to work in the market place to mitigate our costs, however, if significant events do not occur, we will incur significant losses related to these plants.

Wholesale Services

Although we are winding down the activities related to Wholesale Services, this business historically has represented a substantial portion of our income, expense, assets and liabilities. Because of the increased capital required to operate Wholesale Services, we began scaling back its activities during the second quarter of 2002. We stopped entering into new transactions and began liquidating our assets and liabilities related to this business during the third quarter. Nevertheless, because of the significance of this business to our historical operations and the continuing impact of the remaining obligations and risks associated with Wholesale Services, an understanding of these historical operations continues to be relevant.

        Wholesale Services was functionally aligned as follows:

•

Commodity Services—Marketing and trading of commodities;



•

Client Services—Structured products and services; and



•

Capital Services—Structured financing for energy-related businesses.

Commodity Services

We stopped growing our wholesale trading portfolio during the third quarter of 2002. 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. These positions have been hedged to mitigate the exposure of price movements and will continue to be our assets and liabilities until the contracts are settled.

Power.    We purchased electric 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 made 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.

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        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 made transportation arrangements with affiliated and 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, 2002, we had obligations of $752.7 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

We offered products to help our clients manage multiple risks, including price, liquidity, credit, performance, 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.

Capital Services

Our Capital Services group 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 facilities, convertible preferred stock and volumetric production payments.

        Our Capital Services earnings were derived from the spread between the price we charged our 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 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. Regulations in Canada have created a similar business environment in that country. The sale for resale of natural gas in North America has substantially completed its evolution to an open access market.

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        In Canada, certain federal and provincial regulatory authorities require parties to hold export or removal permits for transactions by which natural gas is to be exported from the jurisdiction in which it is produced. These requirements apply whether the natural gas is moved from one province to another or from a province to the United States. We hold permits for such purposes from the provinces of Alberta, British Columbia, Manitoba, Saskatchewan, Ontario and Quebec, and from the Canadian National Energy Board and the United States Department of Energy.

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 put out by 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 that the owner imposes on itself. Second generation implementation issues arising out of Order 888 abound. These include issues relating to power pool structures and transmission pricing.

        In December 1999, the FERC issued Order 2000 addressing some of the significant regional transmission issues. Among other things, Order 2000 required transmission-owning utilities that do 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. Utilities that already participated in an ISO had to submit filings in January 2001. Filings by many utilities and regional transmission entities are now on file and pending FERC review. Our electric marketing transactions may be impacted by the functioning of these new regional transmission organizations. Order 2000 allows significant flexibility in the structure and operation of these new organizations. We therefore cannot predict their impact on our power marketing business.

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

23

(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 not 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, qualifying facilities are exempt from otherwise applicable requirements of PUHCA, the FPA and state laws respecting rate and 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.

        Congress passed the Energy Act to promote further competition in the development of new wholesale power generation sources by encouraging the development of independent power projects that are certified by the FERC as 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 ratemaking 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 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, Jr. (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 College)

        Keith joined our company in 1983 as a staff engineer at our 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, a 33.8% owned foreign traded Australian company and currently serves as its Chairman. From January 2000 to November 2001, he served as Chief Executive Officer of Aquila Merchant Services, Inc. In November 2001, he was appointed President and Chief Operating Officer of our Global Networks Group. He also serves on the board of AlintaGas Limited, a 22.5% owned foreign traded Australian company. 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 Services 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 Services in 1997 and served as Vice President Financial Management until November 2002 when he was appointed Interim 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

25

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., 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.

C. E. Payne Jr. (B.S., Portland State University)

        Cal joined our company in December 1995 as our first Trading Control Officer. In 2000, he was appointed Vice President and Chief Risk Officer, and in March 2001 he became Senior Vice President and Chief Risk Officer. Prior to joining our company, Cal held executive and management positions for 11 years at Transco Energy Company in Houston, Texas.

Michael G. Jonagan (B.S. Mechanical Engineering and B.S. Petroleum Engineering, University of Missouri—Rolla; M.S. Engineering Management, University of Kansas)

        Mike joined our company in 1986 as a staff engineer at our Sibley Generating Station. Between 1986 and 1999 he held various operating positions. In 1999, he was named Vice President, Origination at Aquila Merchant Services and in 2000 he became Vice President, Regulated Power Generation. In October 2000, Mike became Chief Operating Officer of UEL and he presently serves on its board of directors. From July 2002 until October 2002, Mike was the Chief Executive Officer of our domestic regulated utility business and in October 2002 he became Senior Vice President, Capacity Services.

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 our Consolidated Financial Statements for a description of the liens.

Item 3. Legal Proceedings

On February 19, 2002, we filed a suit 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 $540 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

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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 Delaware Chancery Court in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange offer completed in January 2002. The suit raises 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. The plaintiffs' claims for equitable relief were denied by the Delaware Chancery Court in January 2002, and there has been no further activity with the lawsuit. Securities fraud complaints seeking damages based on the same conduct were also filed against us in federal court in Missouri. Persons holding certificates formerly representing approximately 1.8 million shares of Aquila Merchant common stock are also pursuing their appraisal rights in connection with the recombination. We do not believe that any of these actions will have an outcome materially adverse to us.

        A number of companies that have engaged in energy trading activities, including us, have received requests from various regulatory agencies to furnish data and answer questions relating to the possible inaccurate reporting of gas trade information to various industry publications in 2000 and 2001. In response to such inquiries, we initiated a review of our reported information relative to recorded data and are fully cooperating with these investigations. Additionally, we have reported to the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission that we have been unable to reconcile all of the gas trade data reported to various trade publications with the gas trade data in our internal records and that our former traders may have reported inaccurate information. A lawsuit was filed against us and numerous other energy trading companies in November 2002 by the Lieutenant Governor of the State of California alleging that we misreported gas trade data that, in turn, affected the market price of electricity in California.

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 2002.

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 under the symbol ILA. Through March 15, 2002, the symbol was UCU. At March 14, 2003, we had approximately 40,000 common shareholders of record. Information relating to market prices of common stock on the New York Stock Exchange and cash dividends on common stock is set forth below.

Market Price

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Item 6. Selected Financial Data

The following notes reflect the pre-tax effect of items affecting the comparability of the Selected Financial Data above:

        (1)  Depreciation and amortization expense included (in millions) $19.1, $10.9, $2.7 and $1.2 of goodwill amortization for the years ended December 31, 2001, 2000, 1999 and 1998, respectively. Goodwill amortization was not recorded in the year ended December 31, 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, $6.6 and $7.3, respectively, of goodwill amortization.

        (2)  Included in earnings (loss) from continuing operations for the year ended December 31, 2002, is (a) a $696.1 million impairment charge on our investment in Quanta Services due to a continued drop in its share price, the termination of our proxy contest for control of Quanta Services and the decline of the telecommunications industry; (b) a $247.5 million impairment charge on our investment in Midlands Electricity due to the indicated fair value being substantially below our carrying value as suggested by recent sale negotiations and analysis, as well as a corresponding impairment charge being taken at the investment level; (c) a $127.2 million impairment charge on our investment in Multinet and AlintaGas based on the status of negotiations to sell our interest in these businesses, as well as a corresponding impairment charge being taken at the investment level; (d) a $227.6 million impairment charge related to our 96% owned investment in Everest Connections due to our decision to significantly reduce our funding to this business and lower values for certain technology related investments; (e) a $178.6 million write-down of Wholesale Services' goodwill in connection with our exit of the energy trading business; (f) other impairment charges and losses on sale of assets of $106.2 million, primarily as a result of our decision to sell $1 billion in 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 restructure of our utility business.

        (3)  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 (EBIT and net income reflect 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

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$31.8 million in Domestic Networks; (c) recorded charges of $16.5 million in our communications business related to preliminary system design and leases in markets we do not intend to develop; 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.

        (4)  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.

        (5)  In 1998 we recorded (a) asset impairment charges of $13.2 million reflecting a plan to curtail our retail activities, (b) an $8.0 million charge relating to our plan to dissolve the EnergyOne, LLC partnership and (c) a $6.5 million impairment related to our investment in a power plant project.

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

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. Corporate management is responsible for making all financing decisions. 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 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 64 for cautionary statements and risk factors concerning forward looking statements contained in this analysis.

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Key Factors Impacting EBIT

Our total EBIT decreased significantly in 2002 compared to 2001. Key factors affecting 2002 results were as follows:

•

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 the last half of the year that related to our exit. This business contributed EBIT of approximately $25.6 million in the third and fourth quarters of 2001, compared to a loss before interest and taxes of $270.0 million in 2002, before impairments and restructuring charges.



•

Less volatile commodity prices in the first half of 2002 compared to a robust commodity environment in the same period of 2001 resulted in a $139.5 million decrease in EBIT from Wholesale Services, before restructuring and impairment charges.



•

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



•

As a result of asset sales and impairments, we recorded impairment charges and net losses on sale of assets of $1,583.2 million in 2002.



•

Lower power prices and higher natural gas prices in 2002 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 for Capacity Services in 2002 was down $96.9 million when compared to 2001, before impairments and restructuring charges.

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 restructuring charges for the year ended December 31, 2002 that consisted of the following:

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Impairment Charges and Net Loss on Sale of Assets

As further discussed in Note 5 to the Consolidated Financial Statements, we recorded the following impairment charges and net loss on sale of assets for the years ended December 31, 2002, 2001 and 2000:

        During 2002, we also incurred a $426.6 million loss on an impairment charge and net losses on asset sales that are reflected in discontinued operations and is not included in the table above. See the paragraph below for further discussion of these charges.

Discontinued Operations

As further discussed in Note 6 to the Consolidated Financial Statements, in connection with the sales of our gas storage facility, our gas gathering and pipeline assets, our Merchant loan portfolio

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and our coal handling facility, we have reported the results of these businesses in discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Statements of Income.

        Operating results of discontinued operations are as follows:

2002 versus 2001

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $224.2 million, $194.8 million and $29.4 million, respectively, in 2002 compared to 2001. These decreases were primarily due to lower natural gas liquids prices and throughput volumes for the first three quarters of 2002 as compared to the same period in 2001. As a result, sales, cost of sales and gross profit from our gas gathering and pipeline business all decreased by $165.4 million, $149.9 million and $15.5 million, respectively. The sale of these operations on October 1, 2002, as compared to a full fourth quarter of operations in 2001, caused a further reduction in sales, cost of sales and gross profit of $66.0 million, $44.9 million and $21.1 million, respectively.

Impairment Charges and Net Loss on Sale of Assets

In 2002, we incurred a $240.3 million loss on the sale of our gas gathering and pipeline assets, a $184.0 million loss on the sale of our Merchant loan portfolio, a $6.6 million impairment of our coal handling facility and a $4.3 million pretax gain on sale of our gas storage assets.

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Depreciation and Amortization Expense