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Aquila Merchant Service Inc – ‘10-K’ for 12/31/01

On:  Monday, 4/8/02   ·   For:  12/31/01   ·   Accession #:  912057-2-14005   ·   File #:  1-16315

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 4/08/02  Aquila Merchant Service Inc       10-K       12/31/01    5:620K                                   Merrill Corp/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML    544K 
 2: EX-3.1      Certificate of Incorporation                           2      9K 
 3: EX-3.2      Bylaws                                                10     37K 
 4: EX-10.16    Amendments to Amended and Restated Rev. Cred. Agmt     8     30K 
 5: EX-99.1     Letter Regarding Repres. of Arthur Andersen, LLP       1      7K 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2001
or

For the transition period from                              to                             

Commission file number: 1-16315

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

(Exact name of registrant as specified in its charter)

        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.

INDEX

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.

•

Wholesale Services—provides commodity risk management and financing services, primarily to the energy industry. We are one of the largest-volume energy wholesalers in North America, marketing power, natural gas, natural gas liquids, crude oil, coal and other related commodities. We partner with clients to identify, assess and measure risks, then create solutions to mitigate energy portfolio risks of all kinds. In addition, we provide a broad line of weather-derivative risk management products, which enable clients to reduce financial risks related to variations in the weather. We also structure energy asset financing for clients in innovative ways, providing a competitive alternative to traditional project financing.



•

Capacity Services—owns or has contractual control of power generation, gas storage, pipeline, gathering, processing and coal terminal assets. This business segment provides complementary assets to the Wholesale Services segment and seeks to develop power and gas capacity assets through the development and expansion of existing assets and acquisitions. We own or control approximately 4,721 megawatts of non-regulated power generation capacity, including capacity under development. We have 26 projects in 12 states and Jamaica. Each facility uses traditional fuels and proven technology. We gather natural gas from the wellhead, treat it, process it to extract the natural gas liquids, and deliver the gas and gas liquids to various markets. We own about 3,800 miles of pipeline and are the 14^th largest producer of natural gas liquids in the United States. We also own and operate a coal terminal in West Virginia with an annual capacity of about 5 million tons that provides throughput, blending and storage 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:

•

Leading position as a wholesale marketer of power and natural gas in North America.



•

Proven risk management policies, procedures and systems to limit exposure to commodity market positions and counterparty risk.

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•

Ability to develop and market innovative custom products and services to existing customer base.



•

Superior market knowledge that allows us to recognize and pursue strategic opportunities.



•

Experience in trading commodities and successfully operating a competitive non-regulated business since our formation in 1986.

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:

•

Commodity Services—Marketing and trading of commodities;



•

Client Services—Customized products and services; and



•

Capital Services—Structured financing to energy-related businesses.

4

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

5

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:

•

GuaranteedWeather®. Our GuaranteedWeather line of risk management products is typically used by clients to protect against the adverse effect of weather on earnings. Over the last three years, we have entered into weather derivative contracts covering time periods from as short as one week to as long as five years.



•

Weather-to-Commodity. We offer a line of weather-to-commodity products that effectively removes the combined risks of variable volumes of energy production and fluctuating market prices. This line of products is particularly suited to weather-dependent energy producers, such as hydroelectric or wind farm producers. For example, our Power-for-Precipitation products can compensate a hydroelectric generating facility for power shortfalls resulting from low rainfall.



•

Generation Fixed-for-Floating Swap. A generation facility often is required to purchase wholesale power to fulfill its own power requirements. To mitigate the risk that the price of power might dramatically increase, we agree to provide power to the facility at a fixed price when certain conditions are met. We then use our trading, marketing and risk management expertise to manage the generation system output against volatile weather and market conditions while allowing the customer to focus on its core competency.



•

GuaranteedGeneration^sm. These products help buyers and sellers manage the risks associated with a forced outage of a generating unit by providing fixed-price power until the unit is operational or the agreement expires. For example, a GuaranteedGeneration contract with a strike price of $100 would give a client the right, but not the obligation, to purchase a fixed volume of power from us at $100/MWh, whenever the covered unit was in forced outage status. We offer GuaranteedGeneration for individual units or groups of units, for constant production or variable production at high demand time units, and to unit owners, unit operators or purchasers of reliable back-up power.



•

GuaranteedPeaking^sm. This line of products allows a client to buy or sell an energy commodity based on the commodity price and a weather trigger. For example, our GuaranteedPeaking for Gas Call product allows a client to purchase natural gas from us at an indexed price if the forecasted temperature for any day is below a specified temperature. We also have a GuaranteedPeaking for Gas Put product that requires us to purchase a fixed volume of natural gas from our client at an indexed price if the forecasted temperature for any day is above a specified temperature.



•

GuaranteedCapacity^sm. Our GuaranteedCapacity products provide replacement transportation or transmission capability where capacity is inoperable or is cut due to system emergencies.

        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.

6

        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:

•

independent oil and natural gas producers looking for funding for acquisitions or to develop proven reserves;



•

independent power generators that are required to invest capital as part of their supply commitment;



•

energy asset owners and developers that trade capacity rights in storage and other projects to finance new projects; and



•

industrial clients desiring off balance sheet financing for energy assets.

        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.

*

Estimated

a)

Interest acquired in GPU International acquisition in December 2000.

b)

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

c)

We have a 20-year contract to supply natural gas necessary to generate 580 MW of power and will own and market the power produced.

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:

a)

All mileage, capacity and volume information is approximate. Capacity figures are management's estimates based on existing facilities without regard to the present availability of natural gas.

b)

At December 31, 2001, we owned 50% of the capital stock of the Oasis Pipe Line Company and the right to reserve transportation capacity of 280 MMcf/d of natural gas on the Oasis pipeline, plus the opportunity to utilize excess capacity on an interruptible basis. We use the equity method of accounting for this investment.

        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:

a)

All capacity and volume information is approximate. Capacity figures are management's estimates based on existing facilities without regard to the present availability of natural gas.

b)

Volumes from joint ventures have been included at our present ownership interest.

c)

Thousands of barrels per day (MBbls/d).

d)

This plant is owned and operated by a third party from which we receive a portion of the NGL's produced from gas we deliver to the plant. This plant is included in this section for informational purposes to show the gas throughout and NGL's production we received utilizing the access to this plant.

e)

In 2001, we elected to bypass the Katy, Texas, plant and receive payment in BTU value due to the depressed NGL's commodity prices.

        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.

9

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

a)

We acquired this facility in 1999. This facility has the ability to inject up to 400 MMcf and withdraw up to 700 MMcf of natural gas per day.

b)

We completed the development of the initial .5 Bcf of capacity in 2001 and expect to complete an additional .5 Bcf in 2002. We expect to develop a total of 2.0 Bcf of storage capacity at this facility. We expect this facility will have the ability to inject up to 100 MMcf and withdraw up to 200 MMcf of natural gas per day.

c)

We are developing this facility and expect it to be in operation in two phases in 2003. We expect this facility will have the ability to inject up to 450 MMcf and withdraw up to 900 MMcf of natural gas per day.

d)

We are developing this facility and expect it to be in operation in three phases in 2003 and 2004. We expect this facility will have the ability to inject up to 200 MMcf and withdraw up to 400 MMcf of natural gas per day.

e)

We expect to complete the acquisition of this facility in second quarter 2002. This facility is currently under construction. The first phase was operational in December 2001 and the second phase is expected to be in operation in 2002. We expect this facility will have the ability to inject up to 200 MMcf and withdraw up to 400 MMcf of natural gas per day.

f)

We acquired the rights to develop this facility in January 2002. This facility is expected to be in operation in two phases in 2003 and 2004. We expect this facility will have the ability to inject up to 450 MMcf and withdraw up to 950 MMcf of natural gas per day.

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

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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

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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.

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Environmental Matters

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

•

protection of the environment; and



•

safety and health of personnel and the public.

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

•

the discharge of pollutants into the air and water;



•

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



•

the protection of animals and noise emissions; and



•

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

        Water Issues.    The Federal Clean Water Act controls effluent and intake requirements and generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency or the 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.

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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

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.

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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

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:

•

A volatile pricing environment for gas and electricity, particularly in early 2001, provided opportunities to execute our strategies and deliver products and services to our clients.



•

Electricity and gas volumes marketed in 2001 increased 84% and 13%, respectively, over 2000, contributing to a combined 34% increase on a total Btu equivalent per day basis. These increases, together with a 27% increase in the number of commodity transactions executed, contributed to the increase in sales, cost of sales and gross profit.



•

A 5% increase in average gas prices also increased our sales and cost of sales.



•

A 28% increase in the number of client transactions in 2001 compared to 2000 contributed to a 34% increase in gross profit from our origination deals and from the more highly customized products we call Client Services. These products included our GuaranteedWeather and GuaranteedGeneration products as well as our longer-duration gas and electric contracts.

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.

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Two-year review—Capacity Services

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:

•

The GPU International acquisition in December 2000 added approximately $54.9 million to gross profit in 2001 while adding $81.6 million and $26.7 million to sales and cost of sales, respectively.



•

We secured power capacity prices on our generation assets above current market prices, improving our margins in 2001. We attempted to optimize asset positions with forward contracts from time to time. When we take these positions with derivative instruments, they are recorded at fair value while the underlying asset position is reflected at historical cost.



•

The additional sales and cost of sales are also the result of additional capacity brought on line.



•

Approximately $11.6 million of this increase relates to the equity investments in four independent power plants that we added to our power capacity as part of our acquisition of GPU international in December 2000.

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.

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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:

•

Selection of a confidence level (we use 95%)



•

Estimated holding period (this is the time needed to liquidate different commodity and term positions; we use holding periods of one to five days depending on the commodity and duration of the position); and



•

Use of historical estimates of volatility and correlation with recent activity more heavily weighted.

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.

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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:

(a)

Assumes the price change occurs for an entire year.

(b)

We have hedged approximately 54% of our forward natural gas liquids production to minimize the effect of price changes.

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:

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

(a)

The fair value of our long-term contracts is composed primarily of fixed price risk that has been significantly hedged.

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Item 8.    Financial Statements and Supplementary Data

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

See accompanying notes to combined financial statements.

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Aquila Merchant Services, Inc. and Subsidiaries

Combined Balance Sheets

See accompanying notes to combined financial statements.

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Aquila Merchant Services, Inc. and Subsidiaries

Combined Statements of Shareholders' Equity

Combined Statements of Comprehensive Income

See accompanying notes to combined financial statements.

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Aquila Merchant Services, Inc. and Subsidiaries

Combined Statements of Cash Flows