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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

(Mark One)

|ý | Annual Report pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
|- | -------------------------------------------------------------------------------------

For the fiscal year ended December 31, 2001
or

|o | Transition Report pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
|- | -----------------------------------------------------------------------------------------

For the transition period from  to

Commission file number: 1-16315

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AQUILA MERCHANT SERVICES, INC.
(FORMERLY AQUILA, INC.)

(Exact name of registrant as specified in its charter)

Delaware

47-0683480(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification No.)1100 Walnut Street, Suite 3300, Kansas City, Missouri 64106(Address of principal executive offices)Registrant's telephone number, including area code (816) 527-1000Securities registered pursuant to Section 12(b) of the Act: NoneSecurities 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 III of this Form 10-K or any amendment to this Form
10-K. ý

Subsequent
to a recombination and merger on January 7, 2002, the Registrant became a wholly-owned subsidiary of Aquila, Inc., formerly UtiliCorp United Inc.

As
of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form with the reduced
disclosure format.

|Title                                   |  | Outstanding (at April 4, 2002)
|--------------------------------------- |  | ------------------------------
|Common Stock, par value $1.00 per share |  | 1,000                         

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INDEX

|                  |  |                                                                                       |  | Page
|----------------- |  | ------------------------------------------------------------------------------------- |  | ----
|Part 1            |  |                                                                                       |  |     
|Item 1            |  | Business                                                                              |  | 3   
|Item 2            |  | Properties                                                                            |  | 17  
|Item 3            |  | Legal Proceedings                                                                     |  | 17  
|Item 4            |  | Submission of Matters to a Vote of Security Holders                                   |  | 17  
|Part 2            |  |                                                                                       |  |     
|Item 5            |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 17  
|Item 6            |  | Selected Financial Data                                                               |  | 17  
|Item 7            |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 18  
|Item 7a           |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 20  
|Item 8            |  | Financial Statements and Supplementary Data                                           |  | 22  
|Item 9            |  | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure  |  | 49  
|Part 3            |  |                                                                                       |  |     
|Item 10           |  | Directors and Executive Officers of the Company                                       |  | 49  
|Item 11           |  | Executive Compensation                                                                |  | 49  
|Item 12           |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 49  
|Item 13           |  | Certain Relationships and Related Transactions                                        |  | 49  
|Part 4            |  |                                                                                       |  |     
|Item 14           |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                      |  | 49  
|Index to Exhibits |  | 53                                                                                   
|Signatures        |  | 54                                                                                   

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Part 1

Item 1. Business

Name Change

In March, 2002 we changed our name from Aquila, Inc. to Aquila Merchant Services, Inc. In conjunction with our name change, our parent, UtiliCorp
United Inc. changed its name to Aquila, Inc.

Organization and History

Aquila Merchant Services, Inc. ("Aquila Merchant" or the "Company", which may be referred to as we, us, or our) is a wholly-owned subsidiary of
Aquila, Inc. (NYSE:ILA) (the Parent or Aquila) whose headquarters is located in Kansas City, Missouri. We began in 1986 as a wholly owned subsidiary of Aquila. On April 27, 2001, we
completed an initial public offering of our common stock. Upon completion of the offering, Aquila owned approximately 80% of our common shares outstanding. On January 7, 2002, Aquila completed
an offer to acquire all of our outstanding publicly held shares in exchange for shares of Aquila common stock and we became once again a wholly owned subsidiary of Aquila. As of December 31,
2001, we had 1,248 employees, including 1,055 in the United States, with the remaining employees located primarily in Canada and the United Kingdom. We market and trade natural gas, electricity and
other commodities throughout North America, and we market natural gas and electricity in the United Kingdom and Western Europe. We conduct our business mainly through two segments: Wholesale Services
and Capacity Services.



Our Competitive Strengths

We believe we have developed substantial competitive strengths that will enable us to continue to successfully execute our strategy. We believe our competitive
strengths are reflected in our demonstrated track record of consistently achieving above industry average earnings growth. These strengths include:



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Mergers, Acquisitions & Divestitures

Purchase of Gas Storage Interest

On August 23, 2001, we and a partner agreed to acquire a 12 Bcf gas storage facility under construction near Lodi, California, for $105 million.
Further expenditures to complete construction will increase the total project cost to $220 million. We expect this acquisition to close in the second quarter of 2002 after regulatory approval.

Equity Offering

An initial public offering of 19,975,000 of our Class A common shares, including an over-allotment of 2,475,000 shares, closed on
April 27, 2001. The offering price was $24.00 per share and we received approximately $315.4 million in net proceeds. Of the 19,975,000 shares, we sold 14,225,000 new shares and Aquila
sold 5,750,000 previously issued shares. We did not receive any of the proceeds from the shares of stock sold by Aquila. Upon completion of the offering, Aquila owned approximately 80% of our
outstanding shares.

On
January 7, 2002, Aquila, completed an offer to acquire all of our outstanding publicly held shares in exchange for shares of Aquila common stock and subsequently merged us with
another subsidiary of Aquila. Our public shareholders were offered .6896 shares of Aquila common stock in a tax-free exchange for each outstanding share of our Class A common stock.
Approximately 76% of the outstanding public shares of our Class A shares were tendered in the offer. In a subsequent merger, each remaining share of our Class A stock was converted into
shares of Aquila common stock at the same ratio as paid in the exchange offer. Shareholders holding approximately 1.8 million shares of our Class A shares exercised dissenters' rights
with respect to the merger.

Business Group Summary

Segment information for the three years ended December 31, 2001 is provided in Note 15 of the Combined Financial Statements.

Wholesale Services

Our Wholesale Services business provides wholesale marketing and trading services, as well as risk management products and services, to our clients in North
America, and Western Europe. We market and trade natural gas, electricity, weather derivatives, coal, emission allowances and other related commodities in these regions.

Our
Wholesale Services business segment is functionally aligned as follows:



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Commodity Services

Power.We purchase electric power from electric generation facilities and sell it primarily to electric utilities,
municipalities, cooperatives and other marketing companies. During the year ended December 31, 2001, we sold approximately 350 MMWhs of power.

Our
electric power marketing and trading activities include trading electricity at various points of receipt, aggregating power supplies and arranging for transmission and delivery. We
make 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. Power marketing and trading transactions occur across various time periods depending on the needs of our clients. Through an hourly trading function, we
have the ability to offer our clients a variety of services that include coverage of power curtailments, clearing of any existing hourly positions, distributing market information and capturing
arbitrage opportunities within the hourly physical market. We provide capacity for power curtailments by being active in all regions of the country, establishing a
rapport with clients, both major and minor, having trained hourly traders working around the clock, and having a staff that can solve problems and make decisions quickly.

Within
the power marketing and trading group, we focus on developing and providing clients with long-term complex products, which we refer to as "power origination." These
products are designed and negotiated on a case-by-case basis to meet the specific energy or risk mitigation requirements of our clients. Our efforts to sell power origination
products from our power generation assets have been focused on longer-term forward sales to municipalities, utilities, cooperatives and other companies that serve end-users, as
well as selling near-term products that are not widely traded. Our power origination products that combine or repackage third party products are generally highly structured and therefore
require the application of all our commercial capabilities (e.g., power trading, risk management and asset positions).

Natural Gas.We purchase natural gas from a variety of suppliers under daily, monthly, variable load, base load and term
contracts that include either market sensitive or fixed price terms. We sell natural gas under sales agreements that have varying terms and conditions, most of which are intended to match seasonal and
other changes in demand. During the year ended December 31, 2001, we sold approximately 13.5 Bcf/d of natural gas.

Our
natural gas marketing activities include contracting to buy natural gas from suppliers at various points of receipt, aggregating natural gas supplies and arranging for their
transportation, negotiating the sale of natural gas and matching natural gas receipts and deliveries based on volumes required by clients. We make 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 utilize
our natural gas storage facilities and enter 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
focus on developing and providing clients with complex products, which we refer to as "natural gas origination." These products are designed to help the client mitigate both physical
and financial risk. Each transaction is created and negotiated independently and changes according to each client's specific needs.

Client Services

We offer products to help our clients manage multiple risks including price, liquidity, credit, performance, volatility and weather. We use 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 to manage the risks of our

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clients. As a risk manager, we take the principal risk in all activities, bringing our client's risk into our inventory and redistributing the unwanted risk to the broader market. These lines of
products include:



Other Energy-Related Commodities.For the year ended December 31, 2001, we executed 1,850 client transactions,
including 826 weather derivative transactions. In 2001, we marketed and traded
approximately 22.7 million tons of coal and approximately 1.1 million emission allowances. An emission allowance permits the holder to emit a finite amount of pollutants, such as sulfur
dioxide or nitrogen oxide.

Capital Services

Our Capital Services group provides capital structuring services to our clients by bundling structured financing with our commodity and capacity capabilities. Our
structuring alternatives typically include traditional asset based lending, revolving facilities, convertible preferred stock, pre-pays and volumetric production payments. In each case, we
attempt to fit the structure and terms of a transaction to the individual financial needs of the client. Our ability to provide a bundled structured financing solution enables us to provide our
clients with more capital than they could otherwise obtain through separate commodity financing transactions.

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Our
Capital Services earnings are derived from the spread between the price we charge our clients for funding and our cost of these funds. In addition, incremental value is created when
we complete transactions that we might not have otherwise captured without our financing product. For example, we may be able to enhance the utilization of our existing pipeline capacity or provide
other commodity sources for our marketing activities by completing these financing transactions.

For
the year ended December 31, 2001, we have provided or committed approximately $455 million of capital to our clients. Most of our transactions are valued at between $10
and $40 million with a term of 24 to 60 months.

The
majority of our Capital Services clients fall into four categories:



We
also engage in municipal pre-pay transactions. In these transactions, we have agreed to provide physical delivery of natural gas to municipalities for an extended period
of time (generally 10 to 12 years) at a fixed cost, and the municipalities paid us in advance for the commodity. Between 1997 and 2000, we closed five of these transactions with an aggregate
pre-payment amount of approximately $1 billion.

Capacity Services

Our Capacity Services business segment owns, controls, develops and operates energy-related assets. Our energy assets complement our Wholesale Services business
segment by providing power, natural gas and coal supplies and an enhanced ability to structure innovative new products and services for clients. Part of our strategy is to diversify our capacity
assets into various regions to geographically balance our portfolio, reducing our concentration risk. Our physical energy assets include power generation assets; natural gas pipeline, gathering and
processing assets; natural gas storage; and a coal terminal and handling facility.

Power Generation Assets

We own or control 4,721 MW of power generation capacity, including capacity in construction and under development. Generally, we seek to sell a portion of the
capacity from our domestic facilities to the wholesale electricity grid and large industrial customers under fixed-price purchase contracts, fixed-capacity payments or contracts to purchase generation
at a predetermined multiple of either natural gas or oil prices. This provides us with greater cash flow certainty for the capacity sold while allowing us flexibility with respect to the rest of our
generation output. To determine our long-term sales strategy, we evaluate the regional forward power market together with our own region-by-region analysis of
projected future prices. We also take operational constraints and operating risk into consideration in making this determination. We often seek to hedge a portion of our fuel costs, which are
generally linked to our power sales.

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Information regarding our generating plants is set forth below.

|Plant & Location                              |  | Type of
Investment        |  | Percent
Owned |  | Gross
Capacity
(MW) |  | Net
Capacity
(MW) |  | Fuel                |  | Date in Service               
|--------------------------------------------- |  | ------------------------- |  | ------------- |  | ------------------- |  | ----------------- |  | ------------------- |  | ------------------------------
|Topsham Hydro Partners, Maine                 |  | Leveraged lease           |  | 50.00         |  | 14                  |  | 7                 |  | Hydro               |  | October 1987                  
|Stockton CoGen Company, California            |  | General partnership       |  | 50.00         |  | 60                  |  | 30                |  | Coal                |  | March 1988                    
|BAF Energy L.P., California                   |  | Limited partnership       |  | 23.10         |  | 120                 |  | 28                |  | Natural Gas         |  | May 1989                      
|Rumford Cogeneration Company L.P., Maine      |  | Limited partnership       |  | 24.30         |  | 85                  |  | 20                |  | Coal and Waste coal |  | May 1990                      
|Mega Renewable G.P., 4 projects in California |  | Limited partnership       |  | 49.75         |  | 12                  |  | 6                 |  | Hydro               |  | Spring 1987                   
|Koma Kulshan Associates, Washington           |  | Limited partnership       |  | 49.75         |  | 14                  |  | 7                 |  | Hydro               |  | October 1990                  
|Badger Creek Limited, California              |  | Limited partnership       |  | 48.75         |  | 50                  |  | 24                |  | Natural Gas         |  | April 1991                    
|Lockport Energy Associates, L.P.,
New York    |  | Limited partnership       |  | 16.58         |  | 180                 |  | 30                |  | Natural Gas         |  | December 1992                 
|Orlando Cogen Limited, L.P., Florida          |  | Limited partnership       |  | 50.00         |  | 126                 |  | 63                |  | Natural Gas         |  | September 1993                
|Jamaica Private Power Company, Jamaica        |  | Limited liability company |  | 24.09         |  | 60                  |  | 14                |  | Diesel              |  | January 1997                  
|Batesville Unit No. 3, Mississippi            |  | Contracted                |  |              |  | 279                 |  | 279               |  | Natural Gas         |  | June 2000                     
|Lake Cogen Ltd., Florida                      |  | Limited partnership       |  | 99.90         |  | 110                 |  | 110               |  | Natural Gas         |  | July 1993 (a)                 
|Mid-Georgia Cogen, L.P., Georgia              |  | Limited partnership       |  | 50.00         |  | 305                 |  | 148               |  | Natural Gas         |  | June 1998 (a)                 
|Onondaga Cogen. Ltd. Partnership,
New York    |  | Limited partnership       |  | 100.00        |  | 91                  |  | 75                |  | Natural Gas         |  | December 1993 (a)             
|Pasco Cogen Ltd., Florida                     |  | Limited partnership       |  | 49.90         |  | 109                 |  | 54                |  | Natural Gas         |  | July 1993 (a)                 
|Prime Energy Limited Partnership,
New Jersey  |  | Limited partnership       |  | 50.00         |  | 65                  |  | 33                |  | Natural Gas         |  | December 1989 (a)             
|Selkirk Cogen. Partners, L.P., New Jersey     |  | Limited partnership       |  | 19.90         |  | 345                 |  | 69                |  | Natural Gas         |  | March 1992/ September 1994 (a)
|Aries L.L.C., Missouri                        |  | Limited liability company |  | 50.00         |  | 580                 |  | 290               |  | Natural Gas         |  | June 2001/ February 2002      
|Elwood Energy L.L.C., Illinois                |  | Contracted                |  |              |  | 604                 |  | 604               |  | Natural Gas         |  | July 2001 (b)                 
|Acadia Power Plant, Louisiana                 |  | Contracted                |  |              |  | 580                 |  | 580               |  | Natural Gas         |  | July 2002*(c)                 
|Coahoma Power Plant, Mississippi              |  | Contracted                |  |              |  | 340                 |  | 340               |  | Natural Gas         |  | September 2002*               
|Raccoon Creek Power Plant, Illinois           |  | Leased                    |  |              |  | 340                 |  | 340               |  | Natural Gas         |  | June 2002*                    
|Goose Creek Power Plant, Illinois             |  | Leased                    |  |              |  | 510                 |  | 510               |  | Natural Gas         |  | December 2002*                
|Three projects in development                 |  | Owned                     |  | 100.00        |  | 1,060               |  | 1,060             |  | Natural Gas         |  | 2003/2004*                    
|                                              |  |                           |  |               |  |                     |  |                   |  |                     |  |                               
|Total Capacity (MW)                           |  |                           |  |               |  | 6,039               |  | 4,721             |  |                     |  |                               
|                                              |  |                           |  |               |  |                     |  |                   |  |                     |  |                               

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Natural Gas Assets

Pipeline, Gathering & Processing. We gather, process, treat and transport natural gas and natural gas
liquids (NGLs). As a part of this business, we own or have an interest in nine natural gas gathering systems, three natural gas processing plants, and nine natural gas treating plants, all within
Texas and Oklahoma. One of our gas gathering systems is comprised of the Oasis pipeline, a 600-mile, 36-inch diameter intrastate natural gas pipeline system running from Waha,
Texas, a major marketing hub in the Permian Basin of Texas, to Katy, Texas, a major Gulf Coast marketing hub with connections to most pipelines in the Gulf Coast area. The Oasis pipeline has one Bcf/d
of throughput capacity. We have an interest in the Oasis pipeline through our ownership of 50% of the Oasis Pipe Line Company. We also provide essential services to natural gas producers by connecting
producers' wells to our gathering systems, compressing and treating natural gas, gathering natural gas for delivery to our processing plants, processing the natural gas to remove NGLs, and providing
access for the natural gas and NGLs to be transported to various markets.

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We
owned, operated or had interests in nine active natural gas pipeline systems with an aggregate length of approximately 3,824 miles. These pipelines do not form an interconnected
system. Set forth below is information with respect to our pipeline systems as of December 31, 2001:

|Gathering Systems                    |  | Location       |  | Miles of
Pipeline (a) |  | Gas Throughput
Capacity(a)
(MMcf/d)
|------------------------------------ |  | -------------- |  | --------------------- |  | -----------------------------------
|Southeast Texas/Katy Pipeline System |  | Texas          |  | 2,439                 |  | 732                                
|Oasis Pipe Line (b)                  |  | Texas          |  | 600                   |  | 1,000                              
|Elk City Gathering System            |  | Oklahoma       |  | 277                   |  | 130                                
|Others                               |  | Texas/Oklahoma |  | 508                   |  | 280                                
|                                     |  |                |  |                       |  |                                    
|Total                                |  |                |  | 3,824                 |  | 2,142                              
|                                     |  |                |  |                       |  |                                    

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Our
natural gas gathering and processing activities include locating and contracting to purchase natural gas supplies, operating and maintaining systems of gathering
pipelines that connect these natural gas supplies to transport lines and natural gas processing plants, and operating and maintaining processing plants linked to our gathering systems.

At
December 31, 2001, we owned and/or operated an interest in three natural gas processing plants listed. Set forth below is information with respect to our processing plants as
of December 31, 2001:

|Processing Plants             |  | Gas
Throughput
Capacity(a)
(MMcf/d) |  | 2001
Gas
Throughput
(a), (b)
(MMcf/d) |  | 2001
NGLs
Production
(a), (b)
(MBbls/d)(c)
|----------------------------- |  | ----------------------------------- |  | ------------------------------------- |  | ------------------------------------------
|La Grange, Texas              |  | 230                                 |  | 129                                   |  | 13.2                                      
|Elk City, Oklahoma            |  | 130                                 |  | 103                                   |  | 5.4                                       
|Benedum, Texas (20% interest) |  | 100                                 |  | 10                                    |  | 1.5                                       
|                              |  |                                     |  |                                       |  |                                           
|Total owned plants            |  | 460                                 |  | 242                                   |  | 20.1                                      
|Katy, Texas (d)(e)            |  |                                    |  | 139                                   |  |                                          
|                              |  |                                     |  |                                       |  |                                           
|Total                         |  | 460                                 |  | 381                                   |  | 20.1                                      
|                              |  |                                     |  |                                       |  |                                           

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We also own or have an interest in nine natural gas treatment plants with a natural gas throughput capacity of approximately 480 MMcf/d, all of
which are located on, or adjacent to, our pipeline systems. To optimize the flow of natural gas through our pipeline systems, we own or have an interest in a total of 58 field compressor stations
comprised of 85 compressor units with an aggregate of approximately 63,000 horsepower.

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Natural Gas Storage.We own and operate, or are in the process of acquiring, six natural gas storage
facilities listed below:

Storage Facilities

Location

Net Working Gas
Capacity (Bcf)Katy(a)

Texas

21.0Hole House(b)

U.K.

1.0Houston Energy Center(c)

Texas

12.0Chapparal(d)

Texas

4.5Lodi(e)

California

12.0Red Lake(f)

Arizona

12.0Total



62.5


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Coal Terminal and Handling Facility

We own and operate a full service coal dock and material handling facility strategically located on the Big Sandy River in West Virginia. This facility is able to
receive coal by truck, rail, and barge and to load coal to barge and rail. It has the capacity to move 5 million tons of coal and related products annually and more than 450,000 tons of coal
storage capacity. The dock also supports our marketing and trading business by enabling physical settlement.

Competition

All of our businesses are highly competitive. We encounter strong competition from companies of all sizes and levels of financial and personnel resources.

Our
Wholesale Services business segment competes with major national and international full service energy providers, energy merchants, producers and pipelines for sales based on our
ability to aggregate competitively priced commodities from a variety of sources and locations and to utilize

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efficient transportation. We believe our financial condition and our access to capital markets will play an increasing role in distinguishing us from many of our competitors. In addition, we believe
that new methods for mitigating risk and technological advances in executing transactions will differentiate the competition in the near term. Operationally, we believe our ability as an energy
merchant to effectively manage costs, along with our proven capability to effectively combine competitively priced commodities and value-added risk management products and services, are critical to
our success in our Wholesale Services business.

The
demand for power may be met by generation capacity based on several competing technologies, such as natural gas-fired or coal-fired cogeneration and power
generating facilities fueled by alternative energy sources including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat, solid waste and nuclear sources. Our power generation
business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities and other energy service companies in the development and
operation of energy-producing projects. The trend towards deregulation in the United States wholesale electric power industry has resulted in a highly competitive market for acquisition and
development of domestic power generating facilities.

Natural
gas competes with other forms of energy including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas
and other forms of energy, the level of business activity, conservation, legislation and regulations, the ability to convert to alternative fuels and other factors, including weather, affect demand
for natural gas and the level of business of natural gas assets. Our natural gas marketing business faces significant competition from a variety of competitors including major integrated oil
companies, major pipeline companies and their marketing affiliates and national and local natural gas gatherers, processors, brokers, marketers and distributors of varying sizes and experience. The
principal areas of competition include obtaining natural gas supplies for gathering and processing operations, marketing natural gas, offering flexible and tailored pricing structures to meet changing
needs and aggregating customers. Competition typically arises as a result of the location and operating efficiency of facilities, the reliability of services and price and delivery capabilities.

Our
natural gas gathering, processing, pipeline and storage business faces significant competition from a variety of competitors including major integrated oil competitors, major
pipeline companies and national and local natural gas gatherers, processors and distributors of varying sizes and experience. Competition typically arises as a result of the location and operating
efficiency of the facilities, the abilities to connect wells promptly, to efficiently operate pipelines and to ensure reliable gas deliveries, and price.

Regulation

International.Our international operations are subject to the jurisdiction of numerous governmental agencies in the
countries in which our businesses operate. Generally, many of the countries in which we do and will do business have recently developed or are in the process of developing new regulatory and legal
structures to accommodate private and foreign-owned businesses. These regulatory and legal structures and their interpretation and application by administrative agencies are relatively new and
sometimes limited. Many detailed rules and procedures are yet to be issued. The interpretation of existing rules can also be expected to evolve over time. We believe that our operations are in
compliance in all material respects with all applicable laws and regulations in the applicable foreign jurisdictions.

Natural Gas Federal Regulation.The interstate transportation and sale for resale of natural gas is subject to regulation by
the Federal Energy Regulatory Commission, or "FERC," under the Natural Gas Act of 1938, or "NGA," and, to a lesser extent, the Natural Gas Policy Act of 1978, or "NGPA."

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Specifically,
the rates, terms and conditions for the transportation or sale of natural gas in interstate commerce are subject to FERC regulation. The NGA requires that those rates be
just and reasonable. Moreover, the NGA gives the FERC jurisdiction over the construction of natural gas pipeline and storage facilities that are used to transport or store natural gas in interstate
commerce. Before commencing with the construction of such facilities, an entity must obtain from the FERC a certificate of public convenience and necessity. There are numerous requirements applicable
to the FERC's issuance of certificates; among other things, a detailed review must be conducted of the potential environmental impacts of the proposed construction activity. We do not currently own or
operate any natural gas facilities that are subject to regulation under the NGA, and we do not own or operate any facilities that have received or are required to have received a certificate under the
NGA.

The
NGPA authorizes certain types of natural gas transportation services. Among other things, section 311 of the NGPA allows the FERC to authorize intrastate pipelines to
transport natural gas on behalf of interstate pipelines and local distribution companies. The FERC regulations provide that intrastate pipelines providing these services must charge fair and equitable
rates. The regulations further provide various methods for determining whether rates being charged are fair and equitable. We own natural gas storage facilities and a portion of an intrastate
pipeline, that provide section 311 services. These facilities are, therefore, subject to applicable federal and state regulations concerning the services they may provide and the rates they may
charge.

Natural Gas State Regulation.Certain of our activities are subject to regulation by the Railroad Commission of Texas, or
"RCT," pursuant to its jurisdiction over common purchasers and natural gas utilities. We are subject to the common purchaser statutes and regulations, and are also subject to regulation as an
intrastate gas utility.

The
RCT has authority to regulate the volumes of natural gas purchased by common purchasers and the rates charged for the intrastate transportation and sale of natural gas by gas
utilities in Texas. Under the Texas Utilities Code and other Texas statutes, the RCT has the duty to ensure that rates for the transportation and sale of natural gas are just and reasonable and gas
utilities are prohibited from charging rates that are unreasonably preferential, prejudicial or discriminatory. We believe that our RCT jurisdictional activities and tariffs are in compliance with
applicable laws and regulations.

Our
Oklahoma operations are subject to regulation by the State of Oklahoma. The majority of these regulations are administered by the Oklahoma Corporation Commission, or "OCC." Any
entity engaged in the business of carrying or transporting natural gas by pipeline is declared to be a common carrier under Oklahoma law and is prohibited from any unjust or unlawful discrimination in
the carriage, transportation or delivery of gas. Although Oklahoma law may be sufficiently broad to permit the OCC to set rates and terms of service for the transportation and delivery of natural gas
involving our Oklahoma assets, the OCC has not done so to date. Oklahoma legislation prohibits entities that gather gas for hire from charging any fee that is unjustly or unlawfully discriminatory. We
do not expect this legislation to have a significant impact on our operations.

An
entity carrying or transporting natural gas by pipeline which is engaged in the business of purchasing natural gas is declared to be a common purchaser under Oklahoma law and is
required to purchase without discrimination in favor of persons or price all natural gas in the vicinity of its lines. Ratable purchase is required if a purchaser is unable to purchase all gas
offered. To date, such legislation has not had a significant effect on our Oklahoma operations.

The
OCC regulates the amount of gas that producers can sell or deliver to us. Currently, substantially all gas received by us through our Oklahoma operations is produced from wells for
which the OCC establishes allowable production rates at quarterly hearings based upon the OCC's determination of the market demand.

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Natural Gas Marketing.The FERC has promulgated regulations concerning the transportation and marketing natural gas that are
intended to induce interstate pipeline companies to provide nondiscriminatory 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 resulted in 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.

In
Canada, certain federal and provincial regulatory authorities require parties to hold export or removal permits for transactions pursuant to 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 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 for such purposes.

Natural Gas Processing.The primary function of our natural gas processing plants is the extraction of NGLs and the
conditioning of natural gas for marketing, and not natural gas transportation. The FERC has traditionally maintained that a processing plant is not a facility for transportation or sale for resale of
natural gas in interstate commerce and therefore is not subject to jurisdiction under the NGA. Even though the FERC has made no specific declaration as to the jurisdictional status of our natural gas
processing operations or facilities, we believe our natural gas processing plants are primarily involved in removing NGLs and therefore exempt from FERC jurisdiction.

Natural Gas Gathering.The NGA exempts natural gas-gathering facilities from the jurisdiction of the FERC.
Interstate transmission facilities, on the other hand, remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities on a fact-specific
basis. We believe our gathering facilities and operations meet the current tests used by the FERC, and that they constitute nonjurisdictional gathering facilities. The FERC's articulation and
application of the tests used to distinguish between jurisdictional pipelines and nonjurisdictional gathering facilities have varied over time. While we believe our gathering facilities are not FERC
jurisdictional, the possibility exists that the rates, terms and conditions of the services rendered by those facilities, and the operation of the facilities, will be subject to regulation by the FERC
or by the various states in the absence of FERC regulation.

Other Natural Gas Regulatory Issues.Our natural gas purchases and sales are generally not regulated by the FERC or other
regulatory authorities; however, as a natural gas merchant, 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. Additionally, certain of our other pipeline activities and facilities are involved in intrastate
transportation and storage services and are subject to various federal and state regulations which generally regulate the rates, terms and conditions of service.

Power Marketing Regulation.The Federal Power Act, or "FPA", and rules promulgated by the FERC regulate the transmission of
electric power 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-jurisdictional
interstate transmission grid in the continental United States to all qualified persons that seek transmission services. Owners of FERC-jurisdictional 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

13

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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, or "ISO," to file plans by October 2000, to detail their participation in an organization that will control the transmission
facilities within a region, while those utilities that already participate in an ISO must submit filings in January 2001. Filings by many utilities and regional transmission entities are now on
file and pending review at the FERC. 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 and thus their impact on our power marketing business cannot be predicted.

Power Generation Regulation.Historically in the United States, regulated and government-owned utilities have been the only
significant producers of electric power for sale to third parties. The enactment of The Public Utility Regulatory Policies Act, or "PURPA", in 1978 encouraged companies other than utilities 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 facilities and
small power production facilities by requiring utilities to purchase electric power generated by such facilities that meet certain requirements, referred to as "qualifying facilities." As a result of
PURPA, a significant market for electric power produced by independent power producers developed in the United States. The benefits and exemptions afforded by PURPA to qualifying facilities are
important to our competitors and us.

In
1992, Congress enacted the Energy Act, which amended the FPA, and The Public Utility Holding Company Act, or "PUHCA." Among other things, the Energy Act created new exemptions from
PUHCA for independent power producers selling electric energy at wholesale, increased electricity transmission access for independent power producers and certain other entities and reduced the burdens
of complying with PUHCA's restrictions on corporate structures for owning or operating generation or transmission facilities in the United States or abroad. The Energy Act has enhanced the development
of independent power projects and has further accelerated the changes in the electric utility industry that were initiated by PURPA.

The
enactment in 1978 of PURPA and the adoption of regulations thereunder by the FERC and individual states provide incentives for the development of small power production facilities
and cogeneration facilities meeting criteria established by the FERC 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 oil or natural gas is used as a fuel source and (iii) not be more than 50 percent 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 power production capacity of no more than 80MW, unless the primary energy source of the facility is solar, wind, waste or the facility qualifies under FPA
Section 3(17)(E), in which case there is no maximum size for the facility. 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 under PURPA 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

14

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by qualifying facilities at a price equal to the incremental cost that it would have cost the utility 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, 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.

The
Congress passed the Energy Act to promote further competition in the development of new wholesale power generation sources. Through amendments to PUHCA, the Energy Act encourages the
development of independent power projects that are certified by the FERC as exempt wholesale generators, or "EWGs." The owners or operators of EWGs are exempt from the provisions of PUHCA, but not
from the FPA. The Energy Act also provides 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 and wholesale sales of electric power pursuant 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.

State Regulatory Reforms.Legislation is currently under review in various states that could affect natural gas and electric
power marketing, power generation and the introduction of competition for retail electric power customers. This legislation, as well as other state regulatory reforms impacting our processing and
gathering operations and other businesses, could likely impact us in the near term.

With
respect to the deregulation of the electric power industry on the state level, some states such as California and Pennsylvania already have opened substantial portions of their
retail electric power markets to competition. Other states are considering doing so, or have implemented pilot programs to test the implementation of retail competition programs. However, the push for
retail competition has slowed somewhat in light of the dramatic price swings for supplies of electric power in certain areas, such as occurred in the California market during the second half of 2000,
and the public opposition that has arisen to the price swings that have occurred in some deregulated markets. It is uncertain at this time which states will implement fully operational retail
competition programs or the schedule pursuant to which they will do so. While the ultimate impact of this type of state legislation on our businesses cannot be predicted with certainty, we do not
believe that the outcome of these matters will have a material adverse effect on our operations or competitiveness.

15

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Environmental Matters

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



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



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 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.

The
EPA has issued for public comment proposed rules that would impose uniform, minimum technology requirements on new cooling water intake structures. It is not known at this time what
requirements the final rules for existing intake structures will impose and whether our existing intake structures will require modification as a result of such requirements.

In
July 2000, the EPA issued final rules for the implementation of the Total Maximum Daily Load, or "TMDL," program of the Clean Water Act. The goal of the TMDL rules is 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. Such limits may require our facilities to install additional
wastewater treatment equipment, modify operational practices or implement other wastewater control measures.

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, or "SO2 and particulate matter. As a
general matter, our facilities emit these pollutants at levels within regulatory requirements. Fossil-fired power generating facilities typically qualify as major sources of air pollutants under
federal and state air pollution laws, and are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

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, which is a major byproduct of the combustion of fossil fuel, is
considered to be a greenhouse gas. The Kyoto Protocol, however, will not become enforceable law in the United States until the U.S. Senate ratifies it. Aside from the Kyoto Protocol, the current
administration has indicated that it will not pursue limitations on carbon dioxide emissions. Nevertheless, bills recently introduced in Congress do include carbon dioxide emissions limitations.
Similarly, a number of states, primarily located in the northeastern United States, are poised to include carbon dioxide limitations into 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.

16

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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.

Item 2.    Properties

Our corporate offices currently occupy approximately 102,000 square feet of leased office space in Kansas City, Missouri with leases expiring in
February 2008 and December 2009, subject to renewal options. 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 generation assets and development activities, our natural gas gathering, transportation, processing and
storage assets and our coal blending, storage and loading facility. Our principal asset facilities are generally described under "BusinessCapacity Services."

Item 3.    Legal Proceedings

On February 19, 2002, we filed suit seeking declaratory judgment in the United States District Court in Lincoln, Nebraska, asking the court to support our
interpretation of the terms of certain indemnity agreements entered into with subsidiaries of the Chubb Insurance Group. These agreements relate to certain surety bonds issued by Chubb to support our
obligations under certain long-term gas supply contracts. The maximum amount that Chubb could be required to pay under the surety bonds is approximately $570 million. Notwithstanding our continued
performance under the gas supply agreements and strong financial position, Chubb has demanded that we replace it as the surety, or alternatively, that we post collateral to secure its obligations. We
believe that there is no merit to Chubb's position and that the court will agree with our interpretation of the indemnity agreements.

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

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

Part 2

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

Information relating to market prices of common stock and cash dividends on common stock is set forth in the table below. We completed our initial public offering
in April 2001, therefore, first quarter 2001 information is not applicable.

Market Price

2001 Quarters

High

Low

Cash
DividendsFirst


N/A


N/A


N/ASecond

$
35.00

$
22.00

$
0.00Third

$
28.35

$
17.75

$
0.00Fourth

$
26.40

$
14.55

$
0.00


Item 6.    Selected Financial Data

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

17

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

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this form with the reduced disclosure format.

Two-year reviewWholesale Services

|                                          |                                       | Year Ended December 31, |         
|----------------------------------------- | ------------------------------------- | ----------------------- | --------
|
|Sales                                     |                                       | $                       | 36,607.1
|Cost of sales                             |                                       |                         | 35,976.7
|Equity in earnings of investments         |                                       |                         | .2      
|                                          |                                       |                         |         
|Gross profit                              |                                       |                         | 630.6   
|                                          |                                       |                         |         
|Operating expenses:                       |                                       |                         |         
|                                          | Administrative expenses               |                         |         
|                                          | Depreciation and amortization expense |                         |         
|                                          | Impairment and other charges          |                         |         
|                                          |                                       |                         |         
|Total operating expenses                  |                                       |                         | 403.6   
|                                          |                                       |                         |         
|Other income                              |                                       |                         | (34.5   
|                                          |                                       |                         |         
|Earnings before interest and taxes (EBIT) |                                       | $                       | 261.5   
|                                          |                                       |                         |         

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales and cost of sales increased 43% in 2001 compared to 2000. Gross profit increased $186.8 million or 42% in 2001 compared to 2000. These increases were
primarily due to the following:



Operating Expenses

Total operating expenses increased $71.4 million due to the write-off of approximately $35.0 million related to our trading exposures
with Enron, the continued expansion of the merchant business and our strong performance resulting in higher incentive compensation expense. Also impacting operating expenses was the allocation of
$10.8 million of expenses from our Parent. While the $35.0 million write-off represents our best estimate of our exposure based on our contracts with Enron, the ultimate
outcome is subject to review by the bankruptcy courts.

18

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Two-year reviewCapacity Services

|                                          |                                       | Year Ended December 31, |        
|----------------------------------------- | ------------------------------------- | ----------------------- | -------
|
|Sales                                     |                                       | $                       | 1,162.9
|Cost of sales                             |                                       |                         | 952.7  
|Equity in earnings of investments         |                                       |                         | 32.4   
|                                          |                                       |                         |        
|Gross profit                              |                                       |                         | 242.6  
|                                          |                                       |                         |        
|Operating expenses:                       |                                       |                         |        
|                                          | Administrative expenses               |                         |        
|                                          | Depreciation and amortization expense |                         |        
|                                          | Impairment and other charges          |                         |        
|                                          |                                       |                         |        
|Total operating expenses                  |                                       |                         | 131.8  
|                                          |                                       |                         |        
|Other income                              |                                       |                         | (2.9   
|                                          |                                       |                         |        
|Earnings before interest and taxes (EBIT) |                                       | $                       | 113.7  
|                                          |                                       |                         |        

2001 versus 2000

Sales, Cost of Sales and Gross Profit

Sales and cost of sales increased 43% and 40%, respectively, in 2001 compared to 2000. Gross profit increased $90.2 million. These increases were primarily
the result of the following factors:



Operating Expenses

Total operating expenses increased $25.0 million in 2001 compared to 2000, primarily as the results of our GPU International acquisition in
December 2000. In 2000, impairment charges of $7.8 million were recorded on certain pipeline related assets.

Two-year reviewCorporate & Other

We generally make decisions on finance, dividends and taxes at the corporate level. We discuss those topics separately on a combined basis below.

Interest Expense

Interest expense decreased $13.1 million during 2001 compared to 2000. This was due primarily to decreased long-term debt payable to parent.

19

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Provision for Income Taxes

The provision for income taxes increased $85.1 million during 2001 compared to 2000. This was primarily due to the increased earnings before income taxes
in 2001 resulting from the factors discussed previously. Our overall effective tax rate decreased from 45.1% in 2000 to 44.4% in 2001.

Item 7a.    Quantitative and Qualitative Disclosures about Market Risk

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this form with the reduced disclosure format.

Market RiskTrading

We are exposed to market risk, including changes in commodity prices, interest rates and currency exchange rates. To manage the volatility relating to these
exposures, we enter into various derivative transactions in accordance with our policy approved by the board of directors. Our trading portfolios consist of natural gas, electricity, coal, global
liquids, weather derivatives and interest rate contracts that are settled by the delivery of the commodity or cash. These contracts take many forms, including futures, forwards, swaps and options.

We
measure the risk in our trading portfolio using value-at-risk methodologies, to simulate forward price curves in the energy markets and estimate the size of
future potential losses. Value-at-risk measures the potential loss in a portfolio's value with a specific degree of probability. The quantification of market risk using
value-at-risk methodologies provides a consistent measure of risk across diverse energy markets and products. The use of this method requires a number of key assumptions, such
as:



The
average value at risk for all commodities during 2001 was $11.3 million. Our total value at risk as approved by the board of directors is limited to $15.0 million. We also use
additional risk control mechanisms such as stress testing, daily loss limits and commodity position limits, as well as daily monitoring of the trading activities which is performed by an independent
function.

All
interest and foreign currency risks are monitored within the commodity portfolios and value-at-risk calculation. The value of our commodity portfolios is
impacted by interest rates as the portfolio is valued using an estimated interest discount factor to December 31, 2001. We often sell Canadian source natural gas into the U.S. markets accepting
U.S. dollars from customers, but paying Canadian dollars to suppliers. This exposes our portfolio to currency risk and we generally hedge this exposure.

The
table below shows the expected cash flows associated with the interest rate financial instruments at December 31, 2001.

|(Dollars in Millions)  |  | 2002 |     | 2003 |   | 2004 |   | 2005 |    
|---------------------- |  | ---- | --- | ---- | - | ---- | - | ---- | ---
|Fixed to variable rate |  | $    | (.8 | )    | $ | (2.1 | ) | $    | (.1
|Average rate paid      |  |      | 6.7 | %    |   | 6.8  | % |      | 6.7
|Average rate received  |  |      | 4.8 | %    |   | 5.2  | % |      | 4.8
|                       | 

20

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Market RiskNon-Trading

We are also exposed to commodity price changes outside of price risk management activities. The following table summarizes these exposures on an EBIT basis as if
our positions were completely unhedged:

|                                        |  | Commodity
Price Change |          | EBIT
Impact(a)
|--------------------------------------- |  | ---------------------- | -------- | --------------
|Natural gas liquids price per gallon(b) |  | +- $                   | .01      |               
|Natural gas price per MCF               |  |                        | +-  1.00 |               
|                                       

---

Certain Trading Activities

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading
activities are accounted for under the mark-to-market method of accounting. Under this method, our energy commodity trading contracts, including physical transactions
(mainly gas and power) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of
counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market
prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. When market prices are not readily available or
determinable, certain contracts are valued at fair value using an alternative approach such as model pricing. The market prices or fair values used in determining the value of the portfolio are our
best estimates utilizing information such as closing exchange rates, over-the-counter (OTC) quotes, volatility, time value, counterparty credit and the potential impact on
market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. The changes in fair value of our trading contracts for 2001 are
summarized below:

|(Dollars in millions)                                                     |  | Trading
Contracts |        | Long-term
Gas Contracts |   | Total  |  
|------------------------------------------------------------------------- |  | ----------------- | ------ | ----------------------- | - | ------ | -
|Fair value of contracts outstanding at the beginning of the year          |  | $                 | 567.1  |                         | $ | (912.9 | )
|Fair value generated during the year                                      |  |                   | 623.2  |                         |   |       |  
|Contracts realized or settled during the yearentered into in 2001        |  |                   | (429.0 | )                       |   |       |  
|Contracts realized or settled during the yearentered into in prior
years |  |                   | (191.3 | )                       |   | 80.4   |  
|Other, net                                                                |  |                   | 19.1   |                         |   |       |  
|                                                                          |  |                   |        |                         |   |        |  
|Fair value of contracts outstanding at the end of the year                |  | $                 | 589.1  |                         | $ | (832.5 | )
|                                                                          |  |                   |        |                         |   |        |  

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

|(Dollars in millions)                                  |  | 2002 |       | 2003 |   | 2004  |   | 2005 |       | Thereafter(a) |   | Total |  
|------------------------------------------------------ |  | ---- | ----- | ---- | - | ----- | - | ---- | ----- | ------------- | - | ----- | -
|Prices actively quoted                                 |  | $    | 296.1 |      | $ | 90.7  |   | $    |      |               | $ |      |  
|Prices provided by other external sources              |  |      |      |      |   |      |   |      | 71.1  |               |   | 28.2  |  
|Prices based on models and other valuation
    methods |  |      | 10.4  |      |   | 1.1   |   |      | 1.9   |               |   |      |  
|                                                       |  |      |       |      |   |       |   |      |       |               |   |       |  
|Fair value of contracts                                |  |      | 306.5 |      |   | 91.8  |   |      | 73.0  |               |   | 28.2  |  
|Long-term gas contracts                                |  |      | (79.7 | )    |   | (81.5 | ) |      | (85.1 | )             |   | (87.8 | )
|                                                       |  |      |       |      |   |       |   |      |       |               |   |       |  
|Total price risk management assets (liabilities)       |  | $    | 226.8 |      | $ | 10.3  |   | $    | (12.1 | )             | $ | (59.6 | )
|                                                       |  |      |       |      |   |       |   |      |       |               |   |       |  

---

21

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Item 8.    Financial Statements and Supplementary Data

Aquila Merchant Services, Inc. and Subsidiaries  Combined Statements of Income

|                                                   |                                       | Year Ended December 31, |         
|-------------------------------------------------- | ------------------------------------- | ----------------------- | --------
|
|
|Sales                                              |                                       | $                       | 37,770.0
|Cost of sales                                      |                                       |                         | 36,929.4
|Equity in earnings of investments and partnerships |                                       |                         | 32.6    
|                                                   |                                       |                         |         
|Gross profit                                       |                                       |                         | 873.2   
|                                                   |                                       |                         |         
|Operating expenses:                                |                                       |                         |         
|                                                   | Administrative expenses               |                         |         
|                                                   | Depreciation and amortization expense |                         |         
|                                                   | Impairments and other charges         |                         |         
|                                                   |                                       |                         |         
|Total operating expenses                           |                                       |                         | 535.4   
|                                                   |                                       |                         |         
|Other income                                       |                                       |                         | (37.4   
|                                                   |                                       |                         |         
|Earnings before interest and taxes                 |                                       |                         | 375.2   
|Interest expense, net                              |                                       |                         | 1.9     
|Interest expense to Parent                         |                                       |                         | 1.0     
|                                                   |                                       |                         |         
|Earnings before income taxes                       |                                       |                         | 372.3   
|Provision for income taxes                         |                                       |                         | 165.2   
|                                                   |                                       |                         |         
|Net income                                         |                                       | $                       | 207.1   
|                                                   |                                       |                         |         
|Weighted average common shares outstanding:        |                                       |                         |         
|                                                   | Basic                                 |                         |         
|                                                   | Diluted                               |                         |         
|                                                   |                                       |                         |         
|Earnings per common share:                         |                                       |                         |         
|                                                   | Basic                                 |                         | $       
|                                                   | Diluted                               |                         |         
|                                                   |                                       |                         |         

See
accompanying notes to combined financial statements.

22

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Aquila Merchant Services, Inc. and Subsidiaries    Combined Balance Sheets

|                                                                                                                                    |                                               | December 31, |        
|----------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------- | ------------ | -------
|
|
|ASSETS                                                                                                                              |                                               |              |        
|Current Assets:                                                                                                                     |                                               |              |        
|                                                                                                                                    | Cash and cash equivalents                     |              | $      
|                                                                                                                                    | Funds on deposit                              |              |        
|                                                                                                                                    | Accounts receivable, net                      |              |        
|                                                                                                                                    | Accounts and notes receivable from Parent     |              |        
|                                                                                                                                    | Inventories                                   |              |        
|                                                                                                                                    | Price risk management assets                  |              |        
|                                                                                                                                    | Other                                         |              |        
|                                                                                                                                    |                                               |              |        
|Total current assets                                                                                                                |                                               |              | 4,130.5
|                                                                                                                                    |                                               |              |        
|Property, plant and equipment, net                                                                                                  |                                               |              | 707.5  
|Investments in partnerships                                                                                                         |                                               |              | 457.5  
|Price risk management assets                                                                                                        |                                               |              | 436.5  
|Notes receivable                                                                                                                    |                                               |              | 415.6  
|Other                                                                                                                               |                                               |              | 112.6  
|                                                                                                                                    |                                               |              |        
|Total Assets                                                                                                                        |                                               | $            | 6,260.2
|                                                                                                                                    |                                               |              |        
|LIABILITIES AND SHAREHOLDERS' EQUITY                                                                                                |                                               |              |        
|Current Liabilities:                                                                                                                |                                               |              |        
|                                                                                                                                    | Current maturities of long-term debt          |              | $      
|                                                                                                                                    | Short-term debt                               |              |        
|                                                                                                                                    | Accounts payable                              |              |        
|                                                                                                                                    | Accrued liabilities                           |              |        
|                                                                                                                                    | Accounts and line of credit payable to Parent |              |        
|                                                                                                                                    | Price risk management liabilities             |              |        
|                                                                                                                                    | Customer deposits                             |              |        
|                                                                                                                                    |                                               |              |        
|Total current liabilities                                                                                                           |                                               |              | 4,374.7
|                                                                                                                                    |                                               |              |        
|Long-term debt, net                                                                                                                 |                                               |              | 12.5   
|Notes payable to Parent                                                                                                             |                                               |              |       
|Price risk management liabilities                                                                                                   |                                               |              | 929.3  
|Deferred income taxes and credits                                                                                                   |                                               |              | 54.8   
|Other deferred credits                                                                                                              |                                               |              | 92.2   
|                                                                                                                                    |                                               |              |        
|Total liabilities                                                                                                                   |                                               |              | 5,463.5
|                                                                                                                                    |                                               |              |        
|Shareholders' Equity:                                                                                                               |                                               |              |        
|Preference stock, $.68 par value; 200,000,000 shares authorized, 28,380,000 and 8,000,000 issued and outstanding, respectively      |                                               |              | 19.3   
|Class A common stock, $.01 par value; 550,000,000 shares authorized, 19,975,000 and none issued and outstanding, respectively       |                                               |              | .2     
|Class B common stock, $.01 par value; 250,000,000 shares authorized, 80,025,000 and 85,775,000 issued and outstanding, respectively |                                               |              | .8     
|Additional paid-in capital                                                                                                          |                                               |              | 566.6  
|Retained earnings                                                                                                                   |                                               |              | 216.7  
|Accumulated other comprehensive losses                                                                                              |                                               |              | (6.9   
|                                                                                                                                    |                                               |              |        
|Total shareholders' equity                                                                                                          |                                               |              | 796.7  
|                                                                                                                                    |                                               |              |        
|Total Liabilities and Shareholders' Equity                                                                                          |                                               | $            | 6,260.2
|                                                                                                                                    |                                               |              |        

See accompanying notes to combined financial statements.

23

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Aquila Merchant Services, Inc. and Subsidiaries    Combined Statements of Shareholders' Equity

|                                       |                                                     | Year Ended December 31, |      
|-------------------------------------- | --------------------------------------------------- | ----------------------- | -----
|
|
|Preference Stock:                      |                                                     |                         |      
|                                       | Balance beginning of year                           |                         | $    
|                                       | Issuance of preference stock                        |                         |      
|                                       |                                                     |                         |      
|Balance end of year                    |                                                     |                         | 19.3 
|                                       |                                                     |                         |      
|Class A common stock:                  |                                                     |                         |      
|                                       | Balance beginning of year                           |                         |      
|                                       | Issuance of class A common stock                    |                         |      
|                                       |                                                     |                         |      
|Balance end of year                    |                                                     |                         | .2   
|                                       |                                                     |                         |      
|Class B common stock:                  |                                                     |                         |      
|                                       | Balance beginning of year                           |                         |      
|                                       | Conversion to Class A common stock                  |                         |      
|                                       |                                                     |                         |      
|Balance end of year                    |                                                     |                         | .8   
|                                       |                                                     |                         |      
|Additional Paid-In Capital:            |                                                     |                         |      
|                                       | Balance beginning of year                           |                         |      
|                                       | Proceeds from sale of common stock, net of expenses |                         |      
|                                       | Sale of related party investments                   |                         |      
|                                       | Repurchase of common stock                          |                         |      
|                                       | Capital contributions by Parent                     |                         |      
|                                       |                                                     |                         |      
|Balance end of year                    |                                                     |                         | 566.6
|                                       |                                                     |                         |      
|Retained Earnings:                     |                                                     |                         |      
|                                       | Balance beginning of year                           |                         |      
|                                       | Net income                                          |                         |      
|                                       | Dividends on common stock                           |                         |      
|                                       |                                                     |                         |      
|Balance end of year                    |                                                     |                         | 216.7
|                                       |                                                     |                         |      
|Accumulated other comprehensive losses |                                                     |                         | (6.9 
|                                       |                                                     |                         |      
|Total Shareholders' Equity             |                                                     | $                       | 796.7
|                                       |                                                     |                         |      

Combined Statements of Comprehensive Income

|                                   |  | Year Ended December 31, |      
|---------------------------------- |  | ----------------------- | -----
|
|
|Net Income                         |  | $                       | 207.1
|Unrealized translation adjustments |  |                         | (6.1 
|Unrealized cash flow hedges        |  |                         | 0.9  
|                                   |  |                         |      
|Comprehensive Income               |  | $                       | 201.9
|                                   |  |                         |      

See
accompanying notes to combined financial statements.

24

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Aquila Merchant Services, Inc. and Subsidiaries    Combined Statements of Cash Flows

|                                                     |                                                                                             | Year Ended December 31,                             |          
|---------------------------------------------------- | ------------------------------------------------------------------------------------------- | --------------------------------------------------- | ---------
|
|
|Cash Flows From Operating Activities:                |                                                                                             |                                                     |          
|                                                     | Net income                                                                                  |                                                     | $        
|                                                     | Adjustments to reconcile net income to net cash (used in) provided by operating activities: |                                                     |          
|                                                     | Depreciation and amortization expense                                                       |                                                     |          
|                                                     | Impairments and other charges                                                               |                                                     |          
|                                                     | Net change in price risk management assets and liabilities                                  |                                                     |          
|                                                     | Deferred income taxes and credits                                                           |                                                     |          
|                                                     | Equity in earnings of investments and partnerships                                          |                                                     |          
|                                                     | Dividends from investments and partnerships                                                 |                                                     |          
|                                                     | Changes in operating assets and liabilities:                                                |                                                     |          
|                                                     |                                                                                             | Accounts receivable                                 |          
|                                                     |                                                                                             | Accounts payable and receivable to/from Parent, net |          
|                                                     |                                                                                             | Inventories                                         |          
|                                                     |                                                                                             | Accounts payable and accrued liabilities            |          
|                                                     |                                                                                             | Other                                               |          
|                                                     |                                                                                             |                                                     |          
|                                                     |                                                                                             |                                                     | Sub-total
|                                                     |                                                                                             | Funds on deposit, net                               |          
|                                                     |                                                                                             |                                                     |          
|Net cash (used in) provided by operating activities  |                                                                                             |                                                     | (134.7   
|Cash Flows From Investing Activities:                |                                                                                             |                                                     |          
|                                                     | Capital expenditures                                                                        |                                                     |          
|                                                     | Investments in partnerships                                                                 |                                                     |          
|                                                     | Additions to notes receivable, net                                                          |                                                     |          
|                                                     | Assets acquired                                                                             |                                                     |          
|                                                     | Cash received on sale of related party investments                                          |                                                     |          
|                                                     | Proceeds from asset dispositions                                                            |                                                     |          
|                                                     | Purchase of minority interest                                                               |                                                     |          
|                                                     | Other                                                                                       |                                                     |          
|                                                     |                                                                                             |                                                     |          
|Net cash used in investing activities                |                                                                                             |                                                     | (354.5   
|                                                     |                                                                                             |                                                     |          
|Cash Flows From Financing Activities:                |                                                                                             |                                                     |          
|                                                     | Short-term borrowings, net                                                                  |                                                     |          
|                                                     | Long term borrowings                                                                        |                                                     |          
|                                                     | Line of credit with Parent, net                                                             |                                                     |          
|                                                     | Issuances (repayment) of notes payable to Parent, net                                       |                                                     |          
|                                                     | Retirement of long-term debt                                                                |                                                     |          
|                                                     | Issuance (repurchase) of common stock, net                                                  |                                                     |          
|                                                     | Capital contribution by Parent                                                              |                                                     |          
|                                                     | Cash dividends paid                                                                         |                                                     |          
|                                                     |                                                                                             |                                                     |          
|Net cash provided by (used in) financing activities  |                                                                                             |                                                     | 628.1    
|                                                     |                                                                                             |                                                     |          
|Net increase (decrease) in cash and cash equivalents |                                                                                             |                                                     | 138.9    
|Cash and cash equivalents at beginning of period     |                                                                                             |                                                     | 9.0      
|                                                     |                                                                                             |                                                     |          
|Cash and cash equivalents at end of period           |                                                                                             | $                                                   | 147.9    
|                                                     |                                                                                             |                                                     |          
|Supplemental cash flow information:                  |                                                                                             |                                                     |          
|Interest paid, net of amount capitalized             |                                                                                             | $                                                   | 4.9      
|Income taxes paid                                    |                                                                                             |                                                     | 241.5    
|                                                     |                                                                                             |                                                     |          

See accompanying notes to combined financial statements.

25

---

NOTE 1:    Summary of Significant Accounting Policies

Nature of Operations

Aquila Merchant Services, Inc., formerly Aquila, Inc., markets natural gas, electricity and other commodities throughout North America and Western
Europe through its Wholesale Services business segment, which also includes our Capital Services business. It also gathers, transports, stores and processes natural gas and gas liquids and owns,
operates or controls power plants through its Capacity Services business segment. In 1999, 2000 and through April 2001, we were 100% owned by Aquila, Inc., formerly UtiliCorp
United Inc., (the "Parent" or "Aquila"). In April 2001, approximately 20% of our ownership was sold to the public. In January 2002, Aquila acquired our outstanding public shares
in an exchange offer and merger.

In
March, 2002 we changed our name from Aquila, Inc. to Aquila Merchant Services, Inc. In conjunction with our name change, our parent, UtiliCorp United Inc. changed
its name to Aquila, Inc.

Use of Estimates

We prepared these financial statements in conformity with accounting principles generally accepted in the United States. We made certain estimates and assumptions
that affect the reported amounts of assets and liabilities. Our estimates and assumptions affect the disclosure of contingent assets and liabilities in this report and reported amounts of sales and
expenses during the reporting period. Actual results could differ from those estimates.

Background and Basis of Presentation

The accompanying combined financial statements include Aquila Merchant Services, Inc. and its subsidiaries and Aquila Canada Corp. (ACC), a wholly owned
subsidiary of Aquila. The combination of these entities is referred to as the "Company".

Historically,
we have managed ACC for Aquila as it has similar trading operations to us. We have also performed administrative functions on behalf of ACC. We purchased the workforce of
ACC in the second quarter of 2001 for $4.3 million. As ACC is included in the combined financial statement, this transaction has been eliminated. ACC has entered into new power contracts
subsequent to this date. All natural gas sales are now transacted by our wholly owned subsidiary.

The
combined statements of income include all revenues and costs directly attributable to the Company. All significant intercompany transactions and balances have been eliminated in the
combined financial statements. Generally, we use the equity accounting method for investments in which we own between 20% to 50%.

Property, Plant and Equipment

We show property, plant and equipment at cost. We expense repair and maintenance costs as incurred. Depreciation is provided on a straight-line basis
over the estimated lives of the assets which range from 5 to 30 years.

Goodwill

We have recorded goodwill representing the excess of the cost of acquisitions over the fair value of the related net assets at the dates of acquisition of
$115.1 million, less accumulated amortization of $16.1 million as of December 31, 2001. We amortize goodwill on the straight-line method over periods of
40 years or less. Amortization expense for the years ended December 31, 2001, 2000 and 1999 was (in millions) $4.4, $3.3 and $3.3, respectively.

26

---

Sales Recognition

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading
activities are accounted for under the mark-to-market method of accounting. Under this method, our energy commodity trading contracts, including both physical transactions and
financial instruments, are recorded at fair value and shown on the combined balance sheets as "Price Risk Management Assets" and "Price Risk Management Liabilities." As part of the valuation of our
portfolio, we value our credit risks associated with the financial condition of counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable
transactions in liquid markets to value our contracts. If actively quoted market prices are not readily available, we contact brokers or other external sources or use comparable transactions to obtain
current values of our contracts. When market prices are not readily available or determinable, certain contracts are valued at fair value using an alternate approach such as model pricing. The market
prices or fair values used in determining the value of our portfolio are our best estimates utilizing information such as closing exchange rates, over-the-counter quotes,
historical volatility and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When the portfolio
market value changes (primarily due to the effect of price changes, newly originated transactions and the settlement of existing transactions), the change is recognized as a gain or loss in the period
of change. We record the resulting unrealized gains or losses as price risk management assets and liabilities.

Funds on Deposit

We have funds on deposit with counterparties that consist primarily of margin requirements related to commodity swap and futures contracts. Pursuant to individual
contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors. Interest is earned on most funds on deposit. We also hold
funds on deposit from counterparties in the same manner.

Inventories

Our inventories consist primarily of natural gas in storage, coal and materials and supplies valued at the lower of weighted average cost or market.

Development Activity

We incur project-related development costs. These include costs of feasibility studies, bid preparation, permitting, licensing and contract negotiations that are
expensed as incurred until the project is deemed to be probable. At that point, we expense or capitalize the costs based on their nature. These costs may be recoverable through partners in the
projects or other third parties, or classified as investment and
recovered through future project cash flows. Accumulated capitalized costs for project development are expensed during the period in which we determine it is probable the costs will not be recovered.

Income Taxes

We are included in the consolidated tax returns for Aquila. We use the liability method to reflect income taxes on our financial statements. To estimate deferred
tax assets and liabilities, we apply current tax regulations at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported
amounts in the financial statements.

27

---

Cash Equivalents and Cash Flow Information

Cash includes cash in banks and temporary investments with an original maturity of three months or less. As of December 31, 2001, 2000, and 1999, our cash
held in foreign countries was $74.4 million, $8.6 million, and $7.4 million, respectively.

Currency Adjustments

For income statement items, we translate the financial statements of our foreign subsidiaries and operations into U.S. dollars using the average exchange rate
during the period. For balance sheet items, we use the year-end exchange rate. When translating foreign currency-based assets and liabilities to U.S. dollars, we show any differences
between accounts as unrealized translation adjustments in common shareholders' equity. Currency transaction gains or losses on transactions executed in a currency other than the functional currency
are recorded in income.

Reclassifications

Certain prior year amounts in the combined financial statements have been reclassified where necessary to conform to the 2001 presentation.

Earnings Per Common Share

The table below shows how we calculated diluted earnings per share and diluted shares outstanding. Basic earnings per share and basic weighted average shares are
the starting point in calculating the dilutive measures. To calculate basic earnings per share, divide earnings available for common shares by weighted average shares outstanding without adjusting for
dilutive items. Diluted earnings per share is calculated by dividing earnings available for common shares after assumed conversion of dilutive securities by weighted average shares outstanding
adjusted for the effect of dilutive securities.

(In millions, except per share amounts)

2001

2000

1999Earnings available for common shares

$
207.1

$
97.6

$
36.8Dilutive items








Earnings available for common shares after assumed conversion of dilutive items

$
207.1

$
97.6

$
36.8Earnings per share:Basic

$
2.17

$
1.14

$
0.43Diluted


2.17


1.14


0.43Weighted average number of common shares used in basic earnings per share


95.6


85.8


85.8Effect of dilutive securities:Stock options








Weighted number of common shares and dilutive common stock used in diluted earnings per share


95.6


85.8


85.8


28

---

NOTE 2:    Price Risk Management

A. Commodity Trading Activities:
Price Risk Management Activities

We
trade energy commodity contracts daily. Our trading activities attempt to match our portfolio of physical and financial contracts to current or anticipated market conditions. Within
the trading portfolio, we take certain positions to hedge physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We record most energy
contractsboth physical and financialat fair value. Changes in value are reflected in the consolidated statement of income. We use all forms of financial instruments,
including futures, forwards, swaps and options. Each type of financial instrument involves different risks. We believe financial instruments help us manage our contractual commitments, reduce our
exposure to changes in cash market prices and take advantage of selected arbitrage opportunities. We refer to these transactions as price risk management activities.

Market Risk

Our price risk management activities involve offering fixed price commitments into the future. The contractual amounts and terms of these financial instruments at
December 31, 2001 and 2000, are below:

December 31, 2001Fixed Price
Payor

Fixed Price
Receiver

Maximum Term
In YearsEnergy Commodities:Natural gas(trillion Btu's)


6,233


5,350

11Electricity(megawatt-hours)


31,271,408


34,002,676

7Crude oil(barrels)


9,421,662


7,794,800

3Natural gas liquids(barrels)


8,902,000


11,364,000

2Coal(tons)


69,750


153,450

1Financial Products:Interest rate instruments (in millions)

$
2,047

$
4,532

9


December 31, 2000Fixed Price
Payor

Fixed Price
Receiver

Maximum Term
In YearsEnergy Commodities:Natural gas(trillion Btu's)


5,700


4,533

12Electricity(megawatt-hours)


9,820,208


14,068,008

5Crude oil(barrels)


5,200,219


5,219,800

4Financial Products:Interest rate instruments (in millions)

$
1,127

$
4,884

10


Although
we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create
a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio's value. To the extent we have an open position, we are exposed to
fluctuating market prices that may adversely impact our financial position or results from operations.

29

---

Market Valuation

The prices we use to value price risk management activities reflect our best estimate of fair values considering various factors, including closing exchange and
over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating our
position in an orderly manner over a reasonable period of time under present market conditions.

We
consider a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial
condition of counterparties and the time value of money. The value of all forward contracts is discounted to December 31, 2001, using market interest rates for the contract term adjusted for
our credit rating or the credit of the counterparty. We continuously monitor the portfolio and value it daily based on present market conditions. The following table displays the fair values of energy
transactions at December 31, 2001, and the average value for the year ended December 31, 2001:

Price Risk Management Assets

Price Risk Management LiabilitiesAverage Value

December 31, 2001

Average Value

December 31, 2001(Dollars in millions)Natural gas

$
1,237.5

$
984.4

$
1,652.9

$
1,274.5Electricity


357.0


208.3


276.8


197.9Coal


44.0


46.5


33.6


21.1Other


32.5


18.2


17.5


7.3Total

$
1,671.0

$
1,257.4

$
1,980.8

$
1,500.8


Future
changes in our creditworthiness and the creditworthiness of our counterparties change the value of our portfolio. We adjust the value of contracts and set dollar limits with
counter parties based on our assessment of their credit quality.

The
value of price risk management assets is concentrated in five contracts representing 25% of the total asset value of the portfolio. This concentration of customers may impact our
overall exposure to credit risk, either positively or negatively, since the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

In
1997 through 2000, we were paid in advance on certain contracts with natural gas purchasing agents to deliver gas to municipal utilities they represent over the subsequent 10 to
12 years. In 2000 and 1999, we received $444 million and $250 million, respectively. Included in price risk management liabilities is $832.5 million of these advance
payments. These contracts are settled monthly through the physical delivery of gas. We have hedged our exposure to changes in gas prices related to these contracts. These contracts mature as follows
(in millions): $79.7 in 2002, $81.5 in 2003, $85.1 in 2004, $87.8 in 2005, $91.2 in 2006 and $407.2 from 2007 through 2012.

B. Non-Trading Activities

We use derivative financial instruments primarily to reduce our exposure to adverse fluctuations in commodity prices and other market risks. When we enter into a
financial instrument, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge
transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged, fluctuations in the value of the derivative instruments are generally
offset by changes in the value or cash flows of the underlying exposures being hedged. We record derivatives in the combined balance sheets at fair value in either Price Risk Management Assets or
Liabilities and in Other Comprehensive Income (OCI). The fair values of derivatives used to hedge or modify our risks fluctuate over time.

30

---

These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions and the overall reduction in our risk
relating to adverse fluctuations in commodity prices and other market factors. In addition, the net income effect resulting from our derivative instruments is recorded in the same line item within the
combined statements of income as the underlying exposure being hedged. We also formally assess, both at the inception and at least quarterly thereafter, whether the financial instruments that are used
in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposures. Any ineffective portion of a financial instrument's change in
fair value is immediately recognized in net income.

Accounting for Hedging Activities

Effective January 1, 2001, we adopted Statement of Financial Accounting Standard (SFAS) No. 133 as amended, which requires us to recognize all
derivative instruments on the balance sheet at fair value. It also establishes new accounting rules for hedging instruments, which depend on the nature of the hedge relationship. The adoption of
SFAS 133 resulted in our recording transition adjustments to recognize derivative instruments at fair value and to recognize the ineffective portion of the change in fair value of derivatives.
The cumulative effect of these transition adjustments at January 1, 2001, was a reduction to OCI of approximately $3.7 million ($2.2 million net of tax). The reduction in OCI was
related to cash flow hedges of future natural gas liquids production. The effect on net income was not significant.

We
recorded a $3.1 million increase to OCI in 2001, net of both income taxes and reclassifications to earnings. This will generally offset future cash flow losses relating to the
underlying exposures being hedged. We estimate that we will reclassify gains into earnings during the next 12 months approximating $.9 million from the net amount recorded in OCI as of
December 31, 2001. We did not discontinue any fair value or cash flow hedge relationships during the year ended December 31, 2001. As of December 31, 2001, the fair value of cash
flow hedges was $1.5 million, ($.9 million net of tax). The effect on net income was not significant.

NOTE 3:    New Accounting Standards

Business Combinations

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations." SFAS 141 addresses financial
accounting and reporting for business combinations and requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method of accounting. It
prohibits the pooling-of-interests method. SFAS 141 also requires certain additional disclosures regarding material business combinations. The adoption of this standard
is not expected to have a material impact on our financial position or results of operations.

Goodwill and Other Intangible Assets

In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 142 requires that, beginning on January 1,
2002, goodwill no longer be amortized against earnings. Rather, this statement requires that goodwill be tested no less than annually for impairment, and if impaired,
be written off against earnings at that time. We estimate the adoption of this standard will reduce annual amortization by approximately $4.4 million on approximately $99.0 million of
goodwill.

Asset Retirement Obligations

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires companies to record the fair
value of a liability for an asset retirement obligation in the period in which the liability is incurred. When the liability is initially recorded, the entity will

31

---

capitalize the estimated cost by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each subsequent period and the
capitalized cost will be depreciated over the useful life of the related asset. Upon settlement of the liability, the company will record a gain or loss for the difference between the settled
liability and the recorded amount. This standard will become effective for us on January 1, 2003. Earlier application is encouraged. We are in the process of assessing how adopting this
standard will affect our financial position and results of operations.

Impairment or Disposal of Long-Lived Assets

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." This standard retains the provisions of
SFAS 121 regarding the impairment of long-lived assets to be held and used. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of
by sale. It requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued
operations. SFAS 144 is effective for fiscal years beginning after December 15, 2001. The adoption of this standard is not expected to have a material impact on our financial position or
results of operations.

NOTE 4:    Investments in Partnerships

Our combined balance sheets contain various equity investments as shown in the table below. The table below summarizes our investments and related equity
earnings:

|                                       |  |         |   |                |  | Investment
at December 31, |       | Equity-Earnings
Year Ended December 31,
|-------------------------------------- |  | ------- | - | -------------- |  | -------------------------- | ----- | ---------------------------------------
|
|
|
|Independent power project partnerships |  | 17%50  | % | U.S. & Jamaica |  | $                          | 293.7 |                                        
|Oasis Pipe Line Company                |  | 50      | % | United States  |  |                            | 99.4  |                                        
|UtiliCorp Networks Canada Limited      |  |        |   | Canada         |  |                            | 38.9  |                                        
|Western Hub Properties                 |  | 50      | % | United States  |  |                            | 18.8  |                                        
|Other                                  |  | Various |   |                |  |                            | 6.7   |                                        
|                                       |  |         |   |                |  |                            |       |                                        
|Total                                  |  |         |   |                |  | $                          | 457.5 |                                        
|                                       |  |         |   |                |  |                            |       |                                        

We
own interests in 14 independent power projects located in eight states and Jamaica. These investments are aggregated because individual investments are not significant.

We
acquired a 35% interest in Oasis Pipe Line Company, a natural gas pipeline in Texas, in 1996. In December 2000 we obtained an additional 15% interest in Oasis, bringing our
total ownership interest to 50%. At December 31, 2001, the unamortized excess of our Oasis investment over our interest in the underlying net assets of Oasis was approximately
$73.3 million.

During
2001 we purchased 226 shares of UtiliCorp Networks Canada Limited (UNCL) preferred stock for approximately $38.9 million. The preferred shares have no stated par value, are
non-cumulative and pay dividends upon declaration by the board of directors at no set amount. UNCL is a wholly owned subsidiary of Aquila, Inc.

We
formed a partnership, Western Hub Properties, to purchase a gas storage interest near Lodi, California. See Note 14 for further discussion.

32

---

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

Following
is the summarized combined financial information of the unconsolidated material equity investments listed above:

December 31,2001

2000Dollars in millionsAssets:Current assets



$
318.9

$
256.6Non-current assets




1,426.0


1,611.8Total Assets



$
1,744.9

$
1,868.4Liabilities and Equity:Current liabilities



$
225.2

$
164.2Non-current liabilities




1,087.6


1,283.8Equity




432.1


420.4Total Liabilities and Equity



$
1,744.9

$
1,868.4


Year Ended December 31,2001

2000

1999Dollars in millionsOperating Results:Revenues

$
695.6

$
348.4

$
346.9Costs and expenses


572.6


272.8


276.3Net Income

$
123.0

$
75.6

$
70.6


33

---

NOTE 5:    Accounts and Notes Receivable

Our accounts receivable on the combined balance sheets are comprised as follows:

December 31,2001

2000(Dollars in millions)Accounts receivable

$
3,011.5

$
4,265.3Allowance for bad debt


(51.7
)

(30.4
)Accounts receivable sale program


(220.0
)

(275.0
)Total

$
2,739.8

$
3,959.9


We
have an agreement that allows us to periodically transfer undivided ownership interests in a revolving pool of our trade receivables to multi-seller conduits administered by
independent financial institutions. The agreement, which was terminated in January 2002, was for up to $275 million of our receivables.

Under
the terms of the agreement, we transferred trade receivables to a bankruptcy-remote special purpose entity ("SPE"). The percentage ownership interest in receivables purchased by
the SPE
increased or decreased over time, depending on the characteristics of the trade receivables, including delinquency rates and debtor concentrations. We service the receivables transferred to the SPE
and receive a servicing fee, which we have determined approximates market compensation for these services. We have minimal servicing assets and liabilities relative to the receivables sold under these
facilities. Collections on these receivables are reinvested on behalf of the conduits in newly created receivables. We had gross sales of accounts receivable of $3.2 billion,
$3.3 billion and $2.3 billion during 2001, 2000 and 1999, respectively. The selling price of the receivables is tied to short-term commercial paper rates. Our combined
statements of income include the loss on the sale of receivables of $12.1 million, $20.0 million and $8.8 million in 2001, 2000 and 1999, respectively. As a result of the
termination of the agreement, we will not be permitted to reinvest collections of the $220 million of receivables sold under the agreement.

We
provide capital primarily to client energy-related businesses seeking financing to fund energy projects. We have classified these transactions as notes receivable in our combined
balance sheets. Notes receivable consist of notes with terms ranging from two to ten years and interest rates ranging from 5.75% to 13.5%. At December 31, 2001 and 2000, the fair value of these
instruments approximated their carrying value of $415.6 million and $313.2 million, respectively.

NOTE 6:    Property, Plant and Equipment

The components of property, plant and equipment are below:

December 31,2001

2000(Dollars in millions)Gas storage

$
149.2

$
86.3Gas gathering and pipeline systems


573.9


555.9Other


95.5


55.5Construction in process


115.3


50.2933.9


747.9Lessdepreciation


226.4


188.9Property, plant and equipment, net

$
707.5

$
559.0


34

---

NOTE 7:    Impairments and Other Charges

Year Ended December 31,2001

2000

1999(Dollars in millions)Enron exposures

$
35.0

$


$
Pipeline and retail assets





10.8


Total

$
35.0

$
10.8

$



In
connection with the bankruptcy filing of Enron Corporation in December 2001, we evaluated our overall exposure with Enron and wrote off $35.0 million related to trading
activities. While this write-off represents our best estimate of our exposure based on our contracts with Enron, the ultimate outcome is subject to review by the bankruptcy courts.

During
2000, we adjusted the reported value of certain assets to their net realizable value. We recognized asset impairment charges of $7.8 million with respect to our assessment of
certain
underperforming pipeline assets; and $3.0 million related to our investments in certain retail assets in the United Kingdom.

NOTE 8:    Short-Term Debt

We have a $30 million credit facility with a U.S. financial institution that provides overdraft protection and letters of credit support to our European business.
We had $25.9 million committed on this facility at December 31, 2001, comprised of $19.5 million in overdrafts recorded in accounts payable and $6.4 million in letters of credit.

We
also had a $125 million letter of credit facility with a group of banks that is used for trading and other activities with various counterparties. As of December 31, 2001, we
had $49.3 million outstanding against this facility. This facility was not renewed when it expired in December 2001.

We
entered into a $350 million revolving credit agreement and a $100 million line of credit agreement with Aquila, Inc. during 2001. The revolver is a one-year agreement with
borrowing rates based on one month LIBOR plus .4% to 2.725%, depending upon our credit rating and the outstanding balance under the revolver. The line of credit is payable on demand and its borrowing
rate is based on the one month LIBOR plus 3%. At December 31, 2001, $386.0 million was outstanding under these facilities and is included within accounts and line of credit payable to Parent.
As a result of our merger and recombination with Aquila these credit agreements were cancelled. The amount outstanding under the agreements at the date of the merger and recombination of approximately
$384.0 million was converted to an equity infusion by Aquila and recorded by us as additional paid in capital.

NOTE 9:    Long-Term Debt

This table summarizes the company's long-term debt:

December 31,2001

2000(Dollars in millions)Notes payable to Aquila, Inc.

$


$
47.6Variable rate non recourse debt, due December 2004


12.5


8.29% senior notes, due September 15, 2002


12.5


25.0Total Long-Term Debt


25.0


72.6Less current maturities


12.5


12.5Long-term debt, net

$
12.5

$
60.1


35

---

Periodically,
we borrow funds from Aquila to finance acquisitions or working capital needs. We pay interest to Aquila on long-term advances. Interest rates on long-term
advances to affiliates ranged from 2.6% to 5.1% in 2001. Our notes payable to Aquila, Inc. were repaid in April 2001.

In
May 2001, a subsidiary of the company borrowed $12.5 million from a U.S. financial institution. This debt is non-recourse to the company and is secured by the underlying assets
of the subsidiary. Interest is currently being charged at a rate of LIBOR plus 2.75%.

Our
senior notes mature in September 2002. The notes contain various restrictive covenants, including limitations on the incurrence or guarantee of additional indebtedness,
incurrence of liens on assets, the purchase or sale of assets, investments and mergers. The notes also require that one of our wholly owned subsidiaries meet certain financial covenants related to net
worth, debt, cash flow, dividends and other restricted payments and reserve life. Through December 31, 2001, we were in compliance with these covenants. The estimated fair value of these debt
instruments approximated their carrying amount as of December 31, 2001.

NOTE 10:    Preference Stock

In 1997, we issued 8.0 million shares of preference stock to an affiliated company, for approximately $5.4 million. A non-cumulative dividend of 8% of the issued
preference stock could be paid if declared by the board of directors; however, to date, we have not declared any dividends on this preference stock. We also can redeem the preferred stock at our
option at any point in time.

In
1997, ACC issued 20.0 million shares of preference stock to Aquila Merchant Services, Inc. for approximately $13.9 million. This investment and preference stock were eliminated
in our combined financial statements in 2000. In 2001, we sold our investment in the preference stock to Aquila for its original issuance price. Because ACC is included in our combined financial
statements, the preference stock we formerly owned is no longer eliminated. Therefore, this transaction has been reflected as an increase in preference stock in 2001.

NOTE 11:    Capital Stock and Stock Compensation

Equity Offering

An initial public offering of 19,975,000 of our Class A common shares, including an over-allotment of 2,475,000 shares, closed on April 27, 2001.
The offering price was $24.00 per share and we received approximately $315.4 million in net proceeds. Of the 19,975,000 shares, we sold 14,225,000 new shares and Aquila sold 5,750,000 previously
issued shares. We did not receive any of the proceeds from the shares of stock sold by Aquila. Upon completion of the offering, Aquila owned approximately 80% of our outstanding shares.

On
January 7, 2002, Aquila completed an offer to acquire all of our outstanding publicly held shares in exchange for shares of Aquila common stock and subsequently merged us with
another Aquila subsidiary. Our public shareholders were offered .6896 shares of Aquila common stock in a tax-free exchange for each of our outstanding shares of Class A common stock.
Approximately 76% of our outstanding Class A public shares were tendered in the offer. In the subsequent merger, each remaining share of our Class A stock was converted into shares of
Aquila common stock at the same ratio as paid in the exchange offer. Shareholders holding approximately 1.8 million of our shares have advised us they intend to exercise dissenters' rights with
respect to the merger.

36

---

Retirement Investment Plan

We
participate in Aquila's defined contribution plan, the Retirement Investment Plan (Savings Plan), which covers all of our full-time and eligible part-time employees. Participants may
generally elect to contribute up to 15% of their annual pay on a before- or after-tax basis subject to certain limitations. The company generally matches contributions up to 6% of pay. Participants
may direct their contributions into various investment options. All company matching contributions are invested in Aquila common stock. Our portion of Aquila's contributions was $2.8 million, $2.2
million, and $2.0 million during the years ended December 31, 2001, 2000 and 1999, respectively. The Savings Plan also includes a stock contribution fund to which the company contributes Aquila
common stock equal to 3% of base wages for eligible full-time employees. Vesting occurs over five years with distribution upon termination of employment. All dividends are reinvested in Aquila common
stock. Effective in 2002, participants may elect to receive their vested dividends in cash. For 2001, compensation expense of $.5 million was recognized, which approximates 3% of eligible employees'
base wages.

Stock Incentive Plan

Our Stock Incentive Plan enables the company to grant Aquila common shares to certain employees as restricted stock awards and as stock options. The company holds
shares issued as restricted stock awards until certain restrictions lapse, generally on the third award anniversary. Stock options granted under the Plan allow the purchase of common shares at a price
not less than fair market value at the date of grant. Options are generally exercisable commencing with the first anniversary of the grant. They expire 10 years after the date of grant.

Stock Options

This table summarizes all stock options as of December 31, 2001:

Shares

2001Beginning balance


Granted


4,028,800Exercised


Cancelled


(111,400
)Ending balance


3,917,400Weighted average prices:Beginning balance

$
Granted price


24.02Exercised price


Cancelled price


24.01Ending balance

$
24.02


37

---

This table summarizes all outstanding stock options as of December 31, 2001:

Outstanding OptionsAverage Exercise Price Range

Number

Weighted
Average
Remaining
Contractual
Life in Years$24.00

3,871,700

9.33$24.01-29.20

45,700

9.59Total

3,917,400


None
of these options were exercisable as of December 31, 2001. In conjunction with our recombination with Aquila, Inc. all stock options were converted into options to
purchase common stock of Aquila, Inc.

Stock Based Compensation

We issue stock options to employees from time to time and account for these options under Accounting Principles Board Opinion No. 25 (APB 25). All stock
options issued are granted at the common stock's current market price. This means we record no compensation expense related to stock options. We also offer employees a 15% discount from the market
price of common stock.

Since
we record options and discounts under APB 25, we must disclose the pro forma net income and earnings per share (dilutive method) as if we reflected the estimated fair value of
options and discounts as compensation at the date of grant or issue. For the year ended December 31, 2001, our pro forma net income and diluted earnings per share would have been as follows:

(In million, except per share)

2001Net Income:As reported

$
207.1Pro forma


145.7Diluted earnings per share:As reported

$
2.17Pro forma


1.52


The
fair value of stock options granted in 2001 was estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair values and related assumptions
were as follows:

2001Weighted average fair value per share

$
15.69Expected volatility


45.79
%Risk-free interest rate


5.43
%Expected lives


10 yearsDividend yield


0
%


38

---

NOTE 12:    Income Taxes

We are part of the consolidated federal income tax return of Aquila. Under a joint income tax agreement, we compute current and deferred tax expense on a
stand-alone basis. Under this agreement, we make tax allocation payments to Aquila on a quarterly basis.

Year Ended December 31,2001

2000

1999(Dollars in millions)Currently Payable:Federal

$
146.2

$
96.0

$
25.5Foreign


37.7


23.1


6.2State


16.1


14.4


3.8Deferred:Federal


(18.6
)

(46.7
)

(9.3
)State


(16.2
)

(6.7
)

(1.2
)Total provision for income taxes

$
165.2

$
80.1

$
25.0


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

December 31,2001

2000(Dollars in millions)Deferred Tax Assets:Price Risk Management activities



$


$
15.6Deferred Tax Liabilities and Credits:Depreciation and amortization



$
113.2

$
157.6Allowance for bad debts




(14.9
)

(28.9
)Accrued incentive




(14.6
)

(20.6
)Price risk management activities




(4.8
)

Other, net




(24.1
)

(2.9
)Total deferred tax liabilities and credits



$
54.8

$
105.2


Our
effective income tax rates differed from the statutory federal income tax rates primarily due to the following:

Year Ended December 31,2001

2000

1999Statutory Federal Income Tax Rate

35.0
%
35.0
%
35.0
%Tax effect of:State income taxes, net of federal benefit

5.3

4.3

4.2Difference in tax rate of foreign subsidiaries

1.8

3.6

2.1Other

2.3

2.2

(.8
)Effective income tax rate

44.4
%
45.1
%
40.5
%


39

---

NOTE 13:    Employee Benefits

Pensions

We participate in Aquila's defined benefit pension plans and other benefit plans that cover substantially all of our employees, other than those employed by our
Canadian and European operations. The following table shows the funded status of Aquila's pension plans and the amounts included in the consolidated balance sheets and statements of income of Aquila:

|                                                 |  | Pension Benefits |       | Other Post-retirement Benefits |  
|------------------------------------------------ |  | ---------------- | ----- | ------------------------------ | -
|
|
|Change in Benefit Obligation:                    |  |                  |       |                                |  
|Benefit obligation at start of year              |  | $                | 269.3 |                                | $
|Service cost                                     |  |                  | 9.7   |                                |  
|Interest cost                                    |  |                  | 20.3  |                                |  
|Plan participants' contribution                  |  |                  | .9    |                                |  
|Amendments                                       |  |                  | 19.3  |                                |  
|Net acquisitions                                 |  |                  |      |                                |  
|Actuarial (gain) loss                            |  |                  | 19.3  |                                |  
|Curtailment (gain) loss                          |  |                  | (1.4  | )                              |  
|Benefits paid                                    |  |                  | (17.6 | )                              |  
|Foreign currency exchange changes                |  |                  | (3.0  | )                              |  
|                                                 |  |                  |       |                                |  
|Benefit obligation at end of year                |  | $                | 316.8 |                                | $
|                                                 |  |                  |       |                                |  
|Change in Plan Assets:                           |  |                  |       |                                |  
|Fair value of plan assets at start of year       |  | $                | 387.6 |                                | $
|Actual return on plan assets                     |  |                  | (49.9 | )                              |  
|Employer contribution                            |  |                  | 1.7   |                                |  
|Plan participants' obligation                    |  |                  | 1.0   |                                |  
|Net acquisitions                                 |  |                  |      |                                |  
|Benefits paid                                    |  |                  | (17.6 | )                              |  
|Foreign currency exchange changes                |  |                  | (3.4  | )                              |  
|                                                 |  |                  |       |                                |  
|Fair value of plan assets at end of year         |  | $                | 319.4 |                                | $
|                                                 |  |                  |       |                                |  
|Funded status                                    |  | $                | 2.6   |                                | $
|Unrecognized transition amount                   |  |                  | (5.1  | )                              |  
|Unrecognized net actuarial (gain) loss           |  |                  | 67.5  |                                |  
|Unrecognized prior service cost                  |  |                  | 28.3  |                                |  
|Additional minimum liability                     |  |                  | (12.2 | )                              |  
|Employer contribution                            |  |                  | .7    |                                |  
|                                                 |  |                  |       |                                |  
|Prepaid (accrued) benefit cost                   |  | $                | 81.8  |                                | $
|                                                 |  |                  |       |                                |  
|Weighted Average Assumptions as of September 30: |  |                  |       |                                |  
|Discount rate                                    |  |                  | 7.42  | %                              |  
|Expected return on plan assets                   |  |                  | 9.67  | %                              |  
|Rate of compensation increase                    |  |                  | 5.21  | %                              |  

Our
portion of the benefit obligation at the end of 2001, 2000 and 1999 was $12.0 million, $6.5 million and $5.7 million, respectively. Plan assets currently are not
allocated to business units. We are allocated our respective portion of the prepaid (accrued) benefit costs on an annual basis.

40

---

For
measurement purposes, to calculate the annual rate of increase in the per capita cost of covered health benefits for each future fiscal year, we used a graded rate starting at 12% in
2002 and decreasing 1% annually until the rate levels out at 5% for years 2008 and thereafter.

|                                         |  | Pension Benefits |       | Other Post-retirement Benefits |  
|---------------------------------------- |  | ---------------- | ----- | ------------------------------ | -
|
|
|Components of Net Periodic Benefit Cost: |  |                  |       |                                |  
|Service cost                             |  | $                | 9.7   |                                | $
|Interest cost                            |  |                  | 20.3  |                                |  
|Expected return on plan assets           |  |                  | (36.8 | )                              |  
|Amortization of transition amount        |  |                  | (1.9  | )                              |  
|Amortization of prior service cost       |  |                  | .8    |                                |  
|Recognized net actuarial (gain) loss     |  |                  | (1.0  | )                              |  
|Curtailment (gain) loss                  |  |                  | (.8   | )                              |  
|Regulatory adjustment                    |  |                  | (4.1  | )                              |  
|                                         |  |                  |       |                                |  
|Net Periodic Benefit Cost                |  | $                | (13.8 | )                              | $
|                                         |  |                  |       |                                |  

The
U.S. pension plan was amended effective December 1, 1999 to provide the same pension benefits for almost all participants. The Supplemental Executive Retirement Plan was
amended in 2001 to include certain participants' annual incentive compensation in the calculation of plan benefits. This amendment resulted in an $18.3 million increase in plan benefit
obligation at December 31, 2001.

We
also participate in Aquila's health care plans. These plans are contributory, with participants' contributions adjusted annually. The life insurance plans are
non-contributory. Future cost-sharing changes are assumed in estimating future health care costs.

The
assumed health care cost trends significantly affect the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates
would have the following effects for 2001.

1 Percentage-PointIncrease

Decrease(in millions)Effect on total of service and interest cost components

$
.8

$
(.7
)Effect on post-retirement benefit obligation


7.3


(6.5
)


Our
portion of the 2001 periodic benefit cost would be approximately $.7 million.

NOTE 14:    Mergers, Acquisitions and Divestitures

Purchase of Gas Storage Interest

On August 23, 2001, we agreed with a partner to acquire a 12 Bcf gas storage facility under construction near Lodi, California for $105 million.
Further expenditures to complete construction will increase the total project cost to $220 million. We expect this acquisition to close in the second quarter of 2002 after regulatory approval.

GPU International

On December 22, 2000, we purchased GPU International, a company holding interests in six independent U.S.-based generating plants, for $225 million.
We accounted for the transaction as a purchase.

41

---

Aquila Gas Pipeline Tender Offer

On May 7, 1999, approximately 3.4 million shares of Aquila Gas Pipeline Corporation (AQP) were tendered to us at $8.00. The 3.4 million
shares together with the 24.0 million shares already held represented 93% of AQP's total shares outstanding. All remaining shares not tendered were converted in a "short-form"
merger into a right to receive $8.00 per share. Upon completion of the short-form merger on May 14, 1999, AQP ceased being a publicly traded company and became wholly owned by us.

Natural Gas Storage Facility

On March 29, 1999, we agreed to purchase Western Gas Resources Storage Inc. The $100 million cash transaction increased our ownership and
control of strategically located natural gas storage assets. The 2,400-acre subsurface facility in Katy, Texas has a storage capacity of 20 billion cubic feet. The purchase closed
on May 3, 1999.

Pro Forma Operating Results

The following reflects our results for the two years ended December 31, 2000, assuming significant acquisitions during the year ended December 31,
2000 occurred as of the beginning of each of the respective periods:

Year Ended December 31,2000

1999(Dollars in millions,
(Unaudited))Sales





$
26,550.6

$
16,739.8Net income






125.0


41.0Diluted earnings per share






1.46


.48


The
pro forma results of operations are not necessarily indicative of the actual results that would have been obtained had we made the acquisitions at the beginning of the respective
periods, or of results which may occur in the future. The pro forma operating results do not include adjustments for synergies or other adjustments to the business operations. There were no
significant acquisitions in 2001.

NOTE 15:    Segment Information

We manage our business in two segments, Wholesale Services and Capacity Services. Each segment is managed based on operating results, expressed as earnings before
interest and taxes. Generally, decisions on finance, dividends and taxes are made at the Corporate and other level.

A. Business Lines

Year Ended December 31,2001



2000

1999(Dollars in millions)Sales:Wholesale Services

$
36,607.1

96.9
%
$
25,662.5

$
16,268.0Capacity Services


1,162.9

3.1


815.5


384.8Total

$
37,770.0

100.0
%
$
26,478.0

$
16,652.8


42

---

Year Ended December 31,2001



2000

1999(Dollars in millions)Earnings Before Interest and Taxes:*Wholesale Services

$
261.5

69.7
%
$
156.8

$
61.4Capacity Services


113.7

30.3


36.9


22.2Total

$
375.2

100.0
%
$
193.7

$
83.6


---

Year Ended December 31,2001



2000

1999(Dollars in millions)Depreciation and Amortization Expense:Wholesale Services

$
16.2

29.2
%
$
16.5

$
5.0Capacity Services


39.3

70.8


32.3


30.7Total

$
55.5

100.0
%
$
48.8

$
35.7


December 31,2001



2000(Dollars in millions)Identifiable Assets:Wholesale Services

$
4,665.1

74.5
%
$
6,505.0Capacity Services


1,595.1

25.5


1,382.2Total

$
6,260.2

100.0
%
$
7,887.2


Year Ended December 31,2001



2000

1999(Dollars in millions)Capital Expenditures:Wholesale Services

$
36.1

15.0
%
$
32.2

$
4.7Capacity Services


204.6

85.0


23.9


104.2Total

$
240.7

100.0
%
$
56.1

$
108.9


B. Geographical Information

Year Ended December 31,2001



2000

1999(Dollars in millions)Sales:United States

$
31,444.6

83.2
%
$
20,667.2

$
13,689.4United Kingdom


2,992.5

7.9


1,837.2


669.9Canada


2,690.7

7.1


3,970.1


2,293.5Other international


642.2

1.8


3.5


Total

$
37,770.0

100.0
%
$
26,478.0

$
16,652.8


43

---

December 31,2001



2000(Dollars in millions)Long-Lived Assets:*United States



$
1,079.1

92.6
%
$
922.8United Kingdom




46.5

4.0


42.8Canada




39.3

3.4


1.3Other international




.1




.1Total



$
1,165.0

100.0
%
$
967.0


---

NOTE 16:    Related Party Transactions

We negotiated separation agreements with Aquila to provide transition services following our Stock Offering in the areas of finance, accounting, information
technology, cash management, payroll, employee benefits and insurance, among others. These services are provided at cost plus a 1% administrative fee, which is capped at $200,000 on an annual basis.
We paid $6.6 million to Aquila during 2001 under this agreement.

Prior
to our separation agreement, we had agreements with Aquila under which Aquila or one of its subsidiaries provided the following services to us: finance, accounting, information
technology, cash management, payroll, employee benefits, credit support and insurance. The costs of these services are both directly incurred and allocated on a cost-based formula.
Allocated costs amounted to $5.4 million, $30.5 million, and $23.4 million during 2001, 2000, and 1999, respectively.

Aquila
charges us for any services which are identifiable specifically to us. The remaining non-direct support costs are allocated to certain business units of Aquila, first
using appropriate and specific cost drivers and second using a general allocator. These allocated costs are charged to us at actual (or fully distributed) cost, rather than market. Costs drivers
represent the percentage of support to a business unit in relation to all business units. The general allocator utilized by Aquila is the Massachusetts Formula, which is the arithmetic average of net
plant, net margin and payroll (fully loaded) charged to expense.

We
believe that the allocation methods used were reasonable and reflective of our proportionate share of such expenses and were not materially different from those that would have been
incurred on a stand-alone basis.

We
incurred interest expense on notes payable to affiliates of $1.0 million, $14.2 million, and, $19.0 million during 2001, 2000, and 1999, respectively.

In
February 1999, a wholly owned subsidiary of ours entered into a power supply contract with a subsidiary of Aquila. Under this agreement we will provide up to 580 MW of power
from June 2001 to May 2005. In 2000, we sold a 50% interest in our subsidiary that held the power contract with the Aquila subsidiary. After the sale of the 50% interest in this
subsidiary we account for our 50% ownership interest by the equity method of accounting.

We
transact in a normal course of business with affiliated companies. We supply and purchase gas to and from subsidiaries of Aquila, which generated sales of $30.1 million,
$56.7 million and $147.0 million, and gas costs of $9.4 million, $11.2 million and $20.4 million, respectively for the years ended December 31, 2001, 2000,
and 1999.

44

---

Certain
employee benefits and compensation programs are managed by Aquila on a consolidated basis. The costs are allocated to the Aquila subsidiary which generated the expense or to the
subsidiary which employs the employees that earn the benefit.

Employees
of the Company participate in the following Aquila compensation programs; Dividend Reinvestment Plan, Employee Stock Purchase Plan, and the Long Term Incentive Plan.

NOTE 17:    Commitments and Contingencies

Commitments

We have various commitments relating to power, gas and coal supply commitments and lease commitments as summarized below. As with any estimates, the actual
amounts paid or received could differ materially.

|                              |  | 2002 |      | 2003 |   | 2004  |  | 2005 |       | 2006 |   | Thereafter
|----------------------------- |  | ---- | ---- | ---- | - | ----- |  | ---- | ----- | ---- | - | ----------
|
|Future minimum lease payments |  | $    | 6.3  |      | $ | 7.0   |  | $    | 6.7   |      | $ | 5.8       
|Purchased power obligations   |  |      | 92.8 |      |   | 136.5 |  |      | 137.3 |      |   | 137.9     

Future
minimum lease payments primarily relate to office space. Rent expense for the years 2001, 2000, and 1999 was (in millions) $5.3, $3.5, and $3.2, respectively.

In
1998 we entered into a 15-year agreement to obtain the rights to dispatch 279 megawatts of purchased power from a facility owned by a third party. As part of the agreement
we will provide the natural gas to the power plant and will be able to dispatch the power. This facility became operational in July 2000.

In
October 2000, we announced two agreements, a 15-year agreement and a 20-year agreement, for the power output of two natural gas-fired
peaking facilities. The agreements are expected to provide us with approximately 1,184 megawatts of additional capacity. One of these plants became operational in the summer of 2001 and the other is
expected to be operational in the summer of 2002.

In
January 2000, we formed a joint venture with Calpine Corporation (Calpine) to develop a 580-megawatt, combined-cycle power plant in Missouri. In
September 2000, the joint venture closed on the financing of this project. Prior to completion of construction, the project costs are funded through a project level construction loan facility.
After completion of construction, the joint venture will sell the facility to a group of investors and enter into a 30-year lease of the facility. This is expected to occur in the first
half of 2002. This lease is classified as an operating lease in the partnership financial statements. As such, we have included the annual purchased power above. We manage the plant's fuel supply and
the marketing of the plant's power. Calpine oversees construction, operation and maintenance of the plant.

In
November 2000, we entered into a $145.0 million synthetic lease through a special purpose entity to finance a 340-megawatt power plant, currently under
construction. We expect this plant to be completed by May 2002. The lease has a term of seven years. During construction, we guarantee up to 89.95% of construction costs, and under certain
limited circumstances, we guarantee up to 100% of the construction cost. As of December 31, 2001, approximately $78.9 million had been funded under this lease agreement. We have
guaranteed up to 82% of the power plant's value at the end of the lease under the agreement.

In
May 2001, we entered into a five-year operating lease through a special purpose entity for 10 GE turbines plus related equipment. Lease payments are not required
during the construction period and will commence at date of operation, or, if a site has not been selected, once construction of the turbines is completed. We can lease up to $265 million in
turbines and equipment under this agreement. During construction, we guarantee up to 89.99% of construction costs, and under certain

45

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limited circumstances, we guarantee up to 100% of the construction cost. As of December 31, 2001, approximately $99 million had been spent under the above agreement. Under the terms of
the turbine and equipment lease, we must cash collateralize cumulative borrowings of the lessor above $42.4 million. As of December 31, 2001, our outstanding collateral balance was
approximately $56.2 million, which is included in Other Assets in the combined balance sheets. Upon expiration of the lease, we may either extend the lease if accepted, refinance the agreement
or sell the equipment on behalf of the lessor. We have guaranteed up to 84% of the lessor's unrecovered principal and costs should the sale proceeds not be sufficient.

Purchase of Gas Storage Interest

In August 2001, we, in conjunction with a partner, agreed to purchase a 12 Bcf gas storage facility under development in Lodi, California for
$105 million. Further capital expenditures are expected to bring the total project cost to $220 million. We expect this acquisition to close in the second quarter of 2002 after
regulatory approval. As of December 31, 2001, we have invested approximately $18.8 million. In order to complete construction of the project, interim bank financing of up to
$60 million was put in place and guaranteed by Aquila. As of December 31, 2001, $37.5 million was outstanding under this facility. Once the acquisition closes, the interim
financing will be replaced with $170 million of non-recourse project level debt, in addition to a net investment of $50 million by Aquila and its partner.

Legal

We have a dispute with an insurance company regarding certain indemnity agreements we have with them. These agreements relate to surety bonds issued to support
our obligations under certain long-term gas supply contracts. The maximum amount that the insurance company could be required to pay under the surety bonds is approximately
$570 million. Notwithstanding our continued performance under the gas supply agreements and strong financial position, this company has demanded that we replace it as the surety, or
alternatively, that we post collateral to secure all of their obligations under the agreements. We believe there is no merit to the insurance company's position given our full compliance with the
related gas supply contracts, and that a court would agree with our interpretation of the indemnity agreements.

The
company is subject to various other legal proceedings and claims that arise in the ordinary course of business operations. We do not expect the amount of liability, if any, from
these actions to materially affect our consolidated financial position or results of operations.

Environmental

We are subject to various environmental laws. These include regulations governing air and water quality and the storage and disposal of hazardous or toxic wastes.
We continually assess ways to ensure we comply with laws and regulations on hazardous materials and hazardous waste and remediation activities.

In
December 2000, the U.S. Environmental Protection Agency (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.

We
do not expect final resolution of these environmental matters to have a material adverse affect on our financial position or results of operations.

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Contingencies

The IRS has examined and proposed adjustments to Aquila's consolidated federal income tax returns for 1988 through 1993. The IRS has proposed an adjustment for
fiscal years 1990-1993 to lengthen the depreciable life of certain pipeline assets owned by us. Aquila filed a petition in the U.S. Tax Court contesting the IRS-proposed
adjustments for 1990 and 1991. Aquila intends to vigorously contest the proposed adjustment, and we believe it is reasonably possible that Aquila will prevail. It is expected that additional
assessments for the years 1994 through the present would also be made on the same issue. Under the provisions of the tax-sharing agreement between Aquila and us, we would be liable to
Aquila for additional taxes of approximately $18.9 million for the audit period through the present plus potential interest of approximately $10.1 million. The additional taxes would
result in an adjustment to the deferred tax liability with no effect on net income. We expect that the ultimate resolution of this matter will not have a material adverse effect on our combined
financial position or results of operations.

We
are also subject to other asserted claims and contingent liabilities which arise in the ordinary course of business. In our opinion, such other asserted claims and contingent
liabilities are not anticipated to result in any losses which will materially affect our combined financial position or results of operations.

NOTE 18:    Quarterly Financial Data (Unaudited)

Financial results for interim periods do not necessarily indicate trends for any 12-month period. Quarterly results can be affected by the timing of
acquisitions, the effect of weather on sales, and other factors typical of energy related businesses.

|                            |         | 2001 Quarters |          | 2000 Quarters
|--------------------------- | ------- | ------------- | -------- | -------------
|
|
|Sales                       |         | $             | 10,981.0 |              
|Gross profit                |         |               | 251.2    |              
|Net income                  |         |               | 49.3     |              
|Earnings per common share:* |         |               |          |              
|                            | Basic   |               | $        | .57          
|                            | Diluted |               |          | .57          
|                            |         |               |          |              

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Report of Independent Public Accountants

To the Board of Directors and Shareholders of Aquila Merchant Services, Inc.:

We have audited the accompanying combined balance sheets of Aquila Merchant Services, Inc. (formerly Aquila, Inc.) and subsidiaries as of
December 31, 2001 and 2000 and the related combined statements of income, common shareholders' equity, comprehensive income, and cash flows for each of the three years in the period ended
December 31, 2001. These combined financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our
audits.

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

In
our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of Aquila Merchant Services, Inc. and
subsidiaries as of December 31, 2001 and 2000 and the combined results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States of America.

Arthur
Andersen LLP
Kansas City, Missouri
February 5, 2002

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Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Part 3

Item 10.    Directors and Executive Officers of the Company

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

Item 11.    Executive Compensation

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

Item 12.    Security Ownership of Certain Beneficial Owners and Management

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

Item 13.    Certain Relationships and Related Transactions

As of the date of this filing, we meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form with the reduced disclosure format.

Part 4

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

The following documents are filed as part of this report:

(a)(1)    Financial Statements:

| |                                                                                                | Page No.
| | ---------------------------------------------------------------------------------------------- | --------
| | Combined Statements of Income for the three years ended December 31, 2001                      |         
| | Combined Balance Sheets at December 31, 2001 and 2000                                          |         
| | Combined Statements of Common Shareholders' Equity for the three years ended
December 31, 2001 |         
| | Combined Statements of Comprehensive Income for the three years ended
December 31, 2001        |         
| | Combined Statements of Cash Flows for the three years ended December 31, 2001                  |         
| | Notes to Combined Financial Statements                                                         |         
| | Report of Independent Public Accountants                                                       |         

(a)(2)    Financial Statement Schedule

| | Report of Independent Accountants on Financial Statement Schedule II |  | 51
| | -------------------------------------------------------------------- |  | --
| | Valuation and Qualifying Accounts for the years 2001, 2000 and 1999  |  | 52

All
other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

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(a)(3)    List of Exhibits *

The following exhibits relate to a management contract or compensatory plan or arrangement:

|10.7*  |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Keith Stamm.    
|------ |  | ------------------------------------------------------------------------------------------------------------
|10.8*  |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Dan J. Streek.  
|10.9*  |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Edward K. Mills.
|10.10* |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and John A. Shealy. 
|10.11* |  | Severance Compensation Agreement dated as of March 16, 2001 by and between the Company and Jeffrey D. Ayers.
|10.12* |  | Severance Compensation Agreement dated as of March 16, 2001 by and between the Company and Brock A. Shealy. 
|10.13* |  | 2001 Omnibus Incentive Compensation Plan.                                                                   

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Reports on Form 8-K



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REPORT OF INDEPENDENT ACCOUNTANTS ON  FINANCIAL STATEMENT SCHEDULE

To
the Board of Directors and Shareholders of Aquila Merchant Services, Inc.:

We
have audited, in accordance with auditing standards generally accepted in the United States, the combined financial statements of Aquila Merchant Services Inc. (formerly
Aquila, Inc.) for the years ended December 31, 2001, 2000, and 1999, and have issued our report thereon dated February 5, 2002. Our audits were made for the purpose of forming an
opinion on those statements taken as a whole. The Financial Statement Schedule listed in Item 14(a)2 is the responsibility of the company's management and is presented for the purposes of complying
with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic
combined financial statements, and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic combined financial statements
taken as a whole.

/s/
ARTHUR ANDERSEN LLP

Kansas
City, Missouri
February 5, 2002

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AQUILA MERCHANT SERVICES, INC.  SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2001  (in Millions)

|Column A |  | Column B |      | Column C |   | Column D |  | Column E
|-------- |  | -------- | ---- | -------- | - | -------- |  | --------
|
|
|2001     |  | $        | 30.4 |          | $ | 33.4     |  | $       
|2000     |  | $        | 11.9 |          | $ | 28.9     |  | $       
|1999     |  | $        | 1.7  |          | $ | 10.2     |  | $       

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AQUILA MERCHANT SERVICES, INC.  INDEX TO EXHIBITS

|Exhibit
Number |  | Document Description                                                                                                                                                                       
|-------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1            |  | Certificate of Incorporation.                                                                                                                                                              
|3.2            |  | Bylaws.                                                                                                                                                                                    
|10.7*          |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Keith Stamm. (Exhibit 10.7 to Registration Statement No. 333-51718, filed
April 18, 2001.)     
|10.8*          |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Dan J. Streek. (Exhibit 10.8 to Registration Statement No. 333-51718, filed
April 18, 2001.)   
|10.9*          |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and Edward K. Mills. (Exhibit 10.9 to Registration Statement No. 333-51718, filed April 18, 2001.) 
|10.10*         |  | Severance Compensation Agreement dated as of March 16, 2001, by and between the Company and John A. Shealy. (Exhibit 10.10 to Registration Statement No. 333-51718, filed April 18, 2001.) 
|10.11*         |  | Severance Compensation Agreement dated as of March 16, 2001 by and between the Company and Jeffrey D. Ayers. (Exhibit 10.11 to Registration Statement No. 333-51718, filed April 18, 2001.)
|10.12*         |  | Severance Compensation Agreement dated as of March 16, 2001 by and between the Company and Brock A. Shealy. (Exhibit 10.12 to Registration Statement No. 333-51718, filed April 18, 2001.) 
|10.13*         |  | 2001 Omnibus Incentive Compensation Plan. (Exhibit 10.13 to Registration Statement No. 333-51718, filed April 18, 2001.)                                                                   
|10.14*         |  | Form of 2001 Omnibus Incentive Compensation Plan Non-Qualified Stock Option Award. (Exhibit 10.14 to Registration Statement No. 333-51718, filed April 18, 2001.)                          
|10.15*         |  | Amended & Restated Revolving Credit Agreement with UtiliCorp United Inc. (Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001)            
|10.16          |  | Amendments to the Amended & Restated Revolving Credit Agreement with UtiliCorp United Inc.                                                                                                 
|99.1           |  | Letter Regarding Representation of Arthur Andersen LLP.                                                                                                                                    

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized as of April 4, 2002.

| |  | Aquila Merchant Services, Inc.
| |  | ------------------------------
| |  | By:                           

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on
the dates indicated, as of April 4, 2002.

|By: |  | /s/ROBERT K. GREENRobert K. Green             |  | Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)
|--- |  | --------------------------------------------- |  | --------------------------------------------------------------------------------------------
|By: |  | /s/EDWARD K. MILLSEdward K. Mills             |  | President and Chief Operating Officer and Director                                          
|By: |  | /s/DAN STREEKDan Streek                       |  | Chief Financial Officer (Principal Financial and Accounting Officer)                        
|By: |  | /s/RICHARD C. GREEN, JR.Richard C. Green, Jr. |  | Director                                                                                    

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