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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

        x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

OR

        ¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (918) 574-7000

Securities registered pursuant to Section 12(b) of the Act:

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

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

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.   ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).   x

The aggregate market value of the registrant’s voting and non-voting common units held by non-affiliates computed by reference to the price at which the common units were last sold as of June 30, 2003, was $595.7 million.

As of March 1, 2004, there were outstanding 23,130,541 common units and 4,259,771 subordinated units.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the 2004 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.

MAGELLAN MIDSTREAM PARTNERS, L.P.

FORM 10-K

PART I

(a) General Development of Business

We were formed as a limited partnership under the laws of the State of Delaware in August 2000. On September 1, 2003, our name changed from Williams Energy Partners L.P. (NYSE:WEG) to Magellan Midstream Partners, L.P. (NYSE:MMP). We were formed when The Williams Companies, Inc. (“Williams”) contributed certain entities, which included terminal and ammonia pipeline assets to us. The principal executive offices of Magellan GP, LLC, our general partner, are located at One Williams Center, Tulsa, Oklahoma 74172 (telephone (918) 574-7000).

A discussion of our acquisition of Magellan Pipeline Company, LLC (“Magellan Pipeline”) is included under the caption “Introduction” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. In addition, a brief description of all the acquisitions completed by the Partnership since our initial public offering can be found under the caption “Acquisition History” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

During 2003, Williams agreed to sell their approximate 54.6% interest in us to Magellan Midstream Holdings, L.P. (“MMH”), formerly known as WEG Acquisitions, L.P., a Delaware limited partnership formed by Madison Dearborn Capital Partners IV, L.P. and Carlyle/Riverstone MLP Holdings, L.P. On June 17, 2003, Williams’ sale was consummated and MMH purchased all of the limited partner interests in us owned by Williams through its subsidiaries and all of the membership interests in our general partner. These limited partner interests consisted of 1,079,694 common units, 5,679,694 subordinated units and 7,830,924 class B common units. Through its purchase of all of the membership interests in our general partner, MMH also became the indirect owner of a 2% general partner interest in us and all of our incentive distribution rights, which entitle the holder to an increasing percentage of our cash distributions as we increase distributions to our common unitholders.

In connection with the sale of Williams’ interests in us, six of the seven directors resigned from our general partner’s board of directors and four directors affiliated with MMH were appointed to our general partner’s board. Mr. Don R. Wellendorf, our general partner’s Chief Executive Officer and President, is the Chairman of the Board and continued to serve in these capacities. Prior to December 31, 2003, our general partner’s board increased the size of the board to eight and appointed three directors that meet the independence and financial literacy requirements of the New York Stock Exchange (“NYSE”) and the Securities and Exchange Commission (“SEC”).

In November 2003, our common unitholders approved the conversion of each outstanding class B common unit into one common unit, and the resulting issuance of an aggregate of 7,830,924 common units upon the request by MMH, the holder of those units, for the conversion and cancellation of the 7,830,924 class B common units. On December 1, 2003, MMH requested the conversion of all of the class B common units and the units were then converted into common units. In late December 2003 and early January 2004, MMH sold 4,975,000 common units and we sold 200,000 common units in an underwritten public offering. On February 7, 2004, pursuant to Section 5.8(a) of our Second Amended and Restated Agreement of Limited Partnership, 1,419,923 of the 5,679,694 subordinated units held by MMH converted into common units on a one-for-one basis. As of the date of this annual report on Form 10-K, MMH’s limited partner interests in us consist of 5,355,541 common units and 4,259,771 subordinated units, which represents an approximate 36.4% ownership interest in us, including MMH’s 2% general partner interest.

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(b) Financial Information About Segments

See Part II, Item 8—Financial Statements and Supplementary Data

(c) Narrative Description of Business

We are principally engaged in the storage, transportation and distribution of refined petroleum products and ammonia. Our asset portfolio currently consists of:

Petroleum Products Transportation and Distribution

The United States petroleum products transportation and distribution system links oil refineries to end-users of gasoline and other petroleum products and is comprised of a network of pipelines, terminals, storage facilities, tankers, barges, rail cars and trucks. For transportation of petroleum products, pipelines are generally the lowest-cost alternative for intermediate and long-haul movements between different markets. Throughout the distribution system, terminals play a key role in moving products to the end-user market by providing storage, distribution, blending and other ancillary services. Petroleum products transported, stored and distributed through our petroleum products pipeline system and petroleum products terminals include:

PETROLEUM PRODUCTS PIPELINE SYSTEM

Our petroleum products pipeline system covers an 11-state area, extending from Oklahoma through the Midwest to North Dakota, Minnesota and Illinois. Our pipeline system transports petroleum products and LPGs and includes a common carrier pipeline and 39 terminals that provide transportation and terminals services. The products transported on our pipeline system are largely transportation fuels, and in 2003 were comprised of 58%

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gasoline, 33% distillates (which includes diesel fuels and heating oil) and 9% LPGs and aviation fuel. Product originates on our pipeline system from direct connections to refineries and interconnections with other interstate pipelines for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end-users. See Note 16—Segment Disclosures in the accompanying consolidated financial statements.

Our petroleum products pipeline system is dependent on the ability of refiners and marketers to meet the demand for refined petroleum products and LPGs in the markets it serves through their shipments on our pipeline system. According to statistics provided by the Energy Information Administration, the demand for refined petroleum products in the market area served by our petroleum products pipeline system, known as Petroleum Administration for Defense District (“PADD”) II, is expected to grow at an average rate of approximately 1.7% per year over the next 10 years. The total production of refined petroleum products from refineries located in PADD II is currently insufficient to meet the demand for refined petroleum products in PADD II. The excess PADD II demand has been and is expected to be met largely by imports of refined petroleum products via pipelines from Gulf Coast refineries that are located in PADD III.

Our petroleum products pipeline system is well connected to Gulf Coast refineries through interconnections with the Explorer, Shell, CITGO and Seaway/ConocoPhillips pipelines. These connections to Gulf Coast refineries, together with our pipeline’s extensive network throughout PADD II and connections to PADD II refineries, should allow it to accommodate not only demand growth, but also major supply shifts that may occur.

Our petroleum products pipeline system has experienced increased shipments over each of the last three years, with total shipments increasing by 1.4% from 2001 to 2003. The volume increases have come through a combination of overall market demand growth, development projects on our system and from incentive agreements with shippers utilizing our system. The operating statistics below reflect our petroleum products pipeline system’s operations for the periods indicated:

The maximum number of barrels that our petroleum products pipeline system can transport per day depends upon the operating balance achieved at a given time between various segments on our pipeline system. This balance is dependent upon the mix of petroleum products to be shipped and the demand levels at the various delivery points. We believe that we will be able to accommodate anticipated demand increases in the markets we serve through expansions or modifications of our petroleum products pipeline system, if necessary.

Operations

Our petroleum products pipeline system is the largest common carrier pipeline of refined petroleum products and LPGs in the United States in terms of pipeline miles and the fifth largest based on deliveries. Through direct refinery connections and interconnections with other interstate pipelines, our system can access approximately 41% of the refinery capacity in the continental United States. In general, we do not take title to the petroleum products we transport.

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Our petroleum products pipeline system generates approximately 81% of its revenue, excluding product sales revenue, through transportation tariffs on volumes shipped. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All interstate transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”). Included as a part of these tariffs are charges for terminalling and storage of products at our pipeline system’s 39 terminals. Currently, the tariffs we charge to shippers for transportation of products generally do not vary according to the type of products transported. Published tariffs serve as contracts and shippers nominate the volume to be shipped up to a month in advance. In addition, we enter into supplemental agreements with shippers that commonly result in volume and/or term commitments by shippers in exchange for reduced tariff rates or capital expansion commitments on our part. These agreements have terms ranging from one to ten years. Approximately 53% of the shipments in 2003 were subject to these supplemental agreements. While many of these agreements do not represent guaranteed volumes, they do reflect a significant level of shipper commitment to our petroleum products pipeline system.

Our petroleum products pipeline system generates the remaining 19% of its revenues, excluding product sales revenues, from leasing pipeline and storage tank capacity to shippers and from providing product and other services such as ethanol unloading and loading, additive injection, laboratory testing and data services to shippers. Product services such as ethanol unloading and loading, additive injection, custom blending and laboratory testing are performed under a mix of “as needed” monthly and long-term agreements. In addition, we began operating the Rio Grande pipeline system in 2003 and on January 1, 2004 began serving as a subcontractor to an affiliate of Williams for the interim operations of Longhorn Partners Pipeline, L.P. until its anticipated start-up in the second quarter of 2004. We are receiving a monthly fee for both of these services.

Product sales revenues result from the sale of products that are produced from fractionating transmix and from our petroleum products management operation. We take title to the products related to these activities. While the revenues generated from these activities were over $108.0 million in 2003, margins from these sales were only $9.7 million. Revenues and margins from these activities increased in 2003 over 2002 by $38.5 million and $4.5 million, respectively, primarily as a result of our purchase of the petroleum products management operation from Williams in July 2003.

Facilities

Our petroleum products pipeline system consists of a 6,700-mile pipeline and includes 22.5 million barrels of aggregate usable storage capacity at terminals and various pump stations. The terminals deliver petroleum products primarily into tank trucks, although two terminals can load into tank rail cars.

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The following table contains information regarding our owned terminal facilities:

In addition, we have an agreement with ConocoPhillips, which provides us the right to use their terminal facility at Wichita, Kansas.

Petroleum Products Supply

Petroleum products originate from both refining and pipeline interconnection points along our pipeline system. In 2003, 55% of the petroleum products transported on our petroleum products pipeline system originated from 10 direct refinery connections and 45% originated from 12 interconnections with other pipelines. As set forth in the table below, our system is directly connected to, and receives product from, 10 operating refineries.

Major Origins—Refineries (Listed Alphabetically)

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The most significant of our pipeline connections is to Explorer Pipeline in Glenpool, Oklahoma, which transports product from the large refining complexes located on the Texas and Louisiana Gulf Coast. Product from Explorer can be transferred into our pipeline system for delivery into the mid-continent and northern-tier states. Our pipeline system is also connected to all Chicago area refineries through the West Shore Pipe Line.

Major Origins—Pipeline Connections (Listed Alphabetically)

Customers and Contracts

We ship petroleum products for several different types of customers, including independent and integrated oil companies, wholesalers, retailers, railroads, airlines and regional farm cooperatives. End markets for these deliveries are primarily retail gasoline stations, truck stops, farm cooperatives, railroad fueling depots and military and commercial jet fuel users. Propane shippers include wholesalers and retailers who, in turn, sell to commercial, industrial, agricultural and residential heating customers, as well as utilities who use propane as a fuel source.

For the year ended December 31, 2003, our petroleum products pipeline system had approximately 50 transportation customers. The top 10 shippers included several independent refining companies, integrated oil companies and one farm cooperative, and revenues attributable to these top 10 shippers for the year ended December 31, 2003, represented 49% of total revenues for our petroleum products pipeline system and 64% of revenues excluding product sales.

Markets and Competition

In certain markets, barge, truck or rail provide an alternative source for transporting refined products; however, pipelines are generally the lowest-cost alternative for petroleum product movements between different markets. As a result, our pipeline system’s most significant competitors are other pipelines that serve the same markets.

Competition with other pipeline systems is based primarily on transportation charges, quality of customer service, proximity to end-users and longstanding customer relationships. However, given the different supply sources on each pipeline, pricing at either the origin or terminal point on a pipeline may outweigh transportation costs when customers choose which line to use.

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Another form of competition for all pipelines is the use of exchange agreements among shippers. Under these arrangements, a shipper will agree to supply a market near its refinery or terminal in exchange for receiving supply from another refinery or terminal in a more distant market. These agreements allow the two parties to reduce the volumes transported and the average transportation rate paid to us. We have been able to compete with these alternatives through price incentives and through long-term commercial arrangements with potential exchange partners. Nevertheless, a significant amount of exchange activity has occurred historically and is likely to continue.

PETROLEUM PRODUCTS TERMINALS

Within our petroleum products terminals network, we operate two types of terminals: marine terminals and inland terminals. Our marine terminal facilities are located in close proximity to refineries and are large storage and distribution facilities that handle refined petroleum products, blendstocks, heavy oils, feedstocks, crude oil and condensate. Our inland terminals are primarily located in the southeastern United States along third-party pipelines such as Colonial, Explorer, Plantation and TEPPCO. Our facilities receive products from pipelines and distribute them to third parties at the terminals, which in turn deliver them to end-users such as retail outlets. Because these terminals are unregulated, the marketplace determines the prices we can charge for our services.

In 2003, Williams and its affiliates significantly reduced their storage and throughput volumes at our petroleum products terminals. As a result, affiliate revenues with Williams and its affiliates accounted for only 7% of petroleum products terminals’ 2003 revenues as compared to 21% in 2002. Please read Note 11 – Related Party Transactions in the accompanying consolidated financial statements.

Marine Terminal Facilities

The Gulf Coast region is a major hub for petroleum refining, representing approximately 43% of total U.S. daily refining capacity and 67% of U.S. refining capacity expansion from 1990 to 2002. The growth in Gulf Coast refining capacity has resulted in part from consolidation in the petroleum industry to take advantage of economies of scale from operating larger, concentrated refineries. We expect this trend to continue in order to meet growing domestic and international demand. From 1990 to 2002, the amount of petroleum products exported from the Gulf Coast region increased by approximately 18%, or 195 million barrels. The growth in refining capacity and increased product flow attributable to the Gulf Coast region has created a need for additional transportation, storage and distribution facilities. In the future, competition resulting from the consolidation trend, combined with continued environmental pressures, continuation of imports, governmental regulations and market conditions, could result in the closing of smaller, less economical inland refiners, creating even greater demand for petroleum products refined in the Gulf Coast region.

We own and operate five marine terminal facilities, including four marine terminal facilities located along the Gulf Coast and one terminal facility located in Connecticut near the New York harbor. Our marine terminals are large storage and distribution facilities, with an aggregate storage capacity of approximately 16.6 million barrels, that provide inventory management, storage and distribution services for refiners and other large end-users of petroleum products.

Our marine terminal facilities primarily receive petroleum products by ship and barge, short-haul pipeline connections from neighboring refineries and common carrier pipelines. We distribute petroleum products from our marine terminals by all of those means as well as by truck and railcar. Once the product has reached our marine terminal facilities, we store the product for a period of time ranging from a few days to several months. Products that we store include petroleum products, blendstocks, heavy oils and feedstocks.

In addition to providing storage and distribution services, our marine terminal facilities provide ancillary services including heating, blending and mixing of stored products and injection services. Many heavy oils

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require heating to keep them in a liquid state. Further, in order to meet government specifications, products often must be combined with other products through the blending and mixing process. Blending is the combining of products from different storage tanks. Once the products are blended together, the mixing process circulates the blended product through mixing lines and nozzles to further combine the products. Injection is the process of injecting refined petroleum products with additives and dyes to comply with governmental regulations and to meet our customers’ marketing initiatives.

Our marine terminals generate fees primarily through providing long-term or spot demand storage services and inventory management for a variety of customers. In general, we do not take title to the products that are stored in or distributed from our facilities. Refiners and chemical companies will typically use our marine terminal facilities because their facilities are inadequate, either because of size constraints or the specialized handling requirements of the stored product. We also provide storage services and inventory management to various industrial end-users, marketers and traders that require access to large storage capacity.

The following table outlines our marine terminal facilities’ usable storage capacities, primary products handled and the connections to and from these terminals:

Customers and Contracts

We have long-standing relationships with oil refiners, suppliers and traders at our facilities, and most of our customers have consistently renewed their short-term contracts. During 2003, approximately 93% of our marine terminal capacity was utilized. As of December 31, 2003, approximately 59% of our usable storage capacity is under long-term contracts with remaining terms in excess of one year or that renew on an annual basis. Our long-term contract with Williams Energy Marketing & Trading, LLC (“WEM&T”), which represented approximately 19% of revenues at our marine terminal facilities for the year ended December 31, 2002, was terminated during the first quarter of 2003. We received $3.0 million from WEM&T to cancel this contract and recognized that amount as revenue during the first quarter of 2003. As a result, WEM&T accounted for 8% of our total marine revenues for 2003. However, excluding this settlement payment from revenues would have resulted in WEM&T accounting for only 4% of our total marine revenues for 2003. For a further discussion of revenues from major customers, refer to Note 9 – Major Customers and Concentration of Risk in the accompanying consolidated financial statements. Also, please read Note 11 – Related Party Transactions in the accompanying consolidated financial statements for additional information regarding affiliate revenues.

Markets and Competition

We believe that the strong demand for our marine terminal facilities from our refining and chemical customers, resulting from our cost-effective distribution services and key transportation links will continue. We

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experience the greatest demand at our marine terminal facilities in a “contango” market. A contango market condition exists when customers expect prices for petroleum products to be higher in the future. Under those conditions, customers tend to store more product to take advantage of the favorable pricing conditions expected in the future. When the opposite market condition “known as backwardation” exists, some companies choose not to store product or are less willing to enter into long-term storage contracts. The additional heating and blending services that we provide at our marine terminals attract additional demand for our storage services and result in increased revenue opportunities.

Several major and integrated oil companies have their own proprietary storage terminals along the Gulf Coast that are currently being used in their refining operations. If these companies choose to shut down their refining operations and elect to store and distribute refined petroleum products through their proprietary terminals, we would experience increased competition for the services that we provide. In addition, several companies have facilities in the Gulf Coast region and offer competing storage and distribution services.

Inland Terminals

We own and operate a network of 29 refined petroleum products terminals located primarily in the southeastern United States. We acquired 6 of these terminals in January 2004 and also acquired the remaining 21% ownership interest in 8 terminals in which we previously had a 79% ownership interest. As a result, we now wholly own 26 of the 29 terminals in our portfolio. Our terminals have a combined storage capacity of 5.4 million barrels. Our customers utilize these facilities to take delivery of refined petroleum products transported on major common carrier interstate pipelines. The majority of our inland terminals connect to the Colonial, Plantation, TEPPCO or Explorer pipelines and some facilities have multiple pipeline connections. In addition, our Dallas terminal connects to Dallas Love Field airport via a 6-inch pipeline we purchased in April 2001. During 2003, gasoline represented approximately 56% of the product volume distributed through our inland terminals, with the remaining 44% consisting of distillates.

Our inland terminal facilities typically consist of multiple storage tanks that are connected to a third-party pipeline system. We load and unload products through an automated system that allows products to move directly from the common carrier pipeline to our storage tanks and directly from our storage tanks to a truck or rail car loading rack.

We are an independent provider of storage and distribution services. Because we do not own the products moving through our terminals, we are not exposed to the risks of product ownership. We operate our inland terminals as distribution terminals and we primarily serve the retail, industrial and commercial sales markets. We provide inventory and supply management, distribution and other services such as injection of gasoline additives at our inland terminals.

We generate revenues by charging our customers a fee based on the amount of product that we deliver through our inland terminals. We charge these fees when we deliver the product to our customers and load it into a truck or rail car. In addition to throughput fees, we generate revenues by charging our customers a fee for injecting additives into gasoline, diesel and jet fuel, and for filtering jet fuel. Our inland terminals are equipped with automated loading facilities that are available 24 hours a day.

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In January 2004, we increased the number of terminals we wholly own from 12 to 26. Additionally, we have ownership interests in 3 inland terminals that range from 50% to 60%. The following table sets forth our inland terminal locations, percentage ownership, usable storage capacities and methods of supply:

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Customers and Contracts

When we acquire terminals, we generally enter into long-term throughput contracts with the sellers under which they agree to continue to use the facilities. In addition to these agreements, we enter into separate contracts with new customers that typically last for one year with a continuing one-year renewal provision. Most of these contracts contain a minimum throughput provision that obligates the customer to move a minimum amount of product through our terminals or pay for terminal capacity reserved but not used. Our customers include:

Due to the change in our relationship with Williams and the sales of its Memphis, Tennessee refinery and travel center operations, Williams and its affiliates accounted for only 3% of our 2003 inland terminal revenues as compared to 25% in 2002. See Note 11 – Related Party Transactions in the accompanying consolidated financial statements.

Markets and Competition

We compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location and versatility, services provided and price. Our competition from independent operators primarily comes from distribution companies with marketing and trading arms, independent terminal operators and refining and marketing companies.

AMMONIA PIPELINE SYSTEM

We own a 1,100-mile ammonia pipeline system. Our pipeline system transports ammonia from production facilities in Texas and Oklahoma to terminals in the Midwest for ultimate distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska, Oklahoma and South Dakota. The ammonia we transport is primarily used as a nitrogen fertilizer. Nitrogen is an essential nutrient for plant growth and is the single most important element for maintenance of high crop yields for all grains. Unlike other primary nutrients, however, nitrogen must be applied each year because virtually all of its nutritional value is consumed during the growing season. Ammonia is the most cost-effective source of nitrogen and the simplest nitrogen fertilizer. It is also the primary feedstock for the production of upgraded nitrogen fertilizers and chemicals.

Ammonia is produced by reacting natural gas with air at high temperatures and pressures in the presence of catalysts. Because natural gas is the primary feedstock for the production of ammonia, ammonia is typically produced near abundant sources of natural gas. Natural gas prices exhibited strong volatility in late 2002 and early 2003, increasing to unprecedented high levels. This caused the shippers to substantially curtail production at their facilities and shipments on our pipeline system during early 2003. Although natural gas prices remain above historical levels, they dropped below these unprecedented high levels during the latter part of the first quarter of 2003 and our shippers resumed shipments at close to historical levels.

Operations

We are a common carrier transportation pipeline and terminals company. We earn revenue from transportation tariffs for the use of our pipeline capacity and throughput fees at our six ammonia terminals. We do not produce or trade ammonia, and we do not take title to the ammonia we transport.

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We generate approximately 93% of our revenue through transportation tariffs. These tariffs are “postage stamp” tariffs, which means that each shipper pays a defined rate per ton of ammonia shipped regardless of the distance that ton of ammonia travels on our pipeline. In addition to transportation tariffs, we also earn revenue by charging our customers for services at the six terminals we own, including unloading ammonia from our customers’ trucks to inject it into our pipeline for shipment and removing ammonia from our pipeline to load it into our customers’ trucks.

Beginning in February 2003, a third-party pipeline company began providing the operating and general and administrative services for our ammonia pipeline system under an operating agreement with us.

Facilities

Our ammonia pipeline was the world’s first common carrier pipeline for ammonia. The main trunk line was completed in 1968. Today, it represents one of two ammonia pipelines operating in the United States and has a maximum annual delivery capacity of approximately 900,000 tons. Our ammonia pipeline system originates at production facilities in Borger, Texas, Verdigris, Oklahoma and Enid, Oklahoma and terminates in Mankato, Minnesota.

We transport ammonia to 13 delivery points along our ammonia pipeline system, including 6 facilities which we own. The facilities at these points provide our customers with the ability to deliver ammonia to distributors who sell the ammonia to farmers and to store ammonia for future use. These facilities also provide our customers with the ability to remove ammonia from our pipeline for distribution to upgrade facilities that produce complex nitrogen compounds such as urea, ammonium nitrate, ammonium phosphate and ammonium sulfate.

Customers and Contracts

We ship ammonia for three customers. Each of these customers has an ammonia production facility as well as related storage and distribution facilities connected to our ammonia pipeline. The transportation contracts with our customers extend through June 2005. Our customers are obligated to ship an aggregate minimum of 450,000 tons per year but can commit to a higher annual volume to receive a lower tariff rate (see Farmland/Koch discussion below). Our customers, or their predecessors, have been shipping ammonia through our pipeline for an average of more than 20 years.

Each transportation contract contains a ship or pay mechanism whereby each customer must ship a specific minimum tonnage per year and an aggregate minimum tonnage over the life of the contract. On July 1 of each contract year, each of our customers nominates a tonnage that it expects to ship during the upcoming year. This annual commitment may be equal to or greater than the contractual minimum tonnage. Our customers’ aggregate annual commitments for the period July 1, 2003 through June 30, 2004 are 550,000 tons. If a customer fails to ship its annual commitment, that customer must pay for the pipeline capacity it did not use (see Farmland/Koch discussion below). We allow our customers to bank any ammonia shipped in excess of their annual commitments. If a customer has previously shipped an amount in excess of its annual commitment, the shipper may offset subsequent annual shipment shortfalls against the excess tonnage in its bank. There are approximately 185,000 tons in this combined bank that may be used to offset future ship or pay obligations. We have the right to adjust our tariff schedule on an annual basis pursuant to a formula contained in the contracts. Any annual adjustment is limited to a maximum increase or decrease of 5% measured against the rate previously in effect.

Farmland/Koch. On May 31, 2002, Farmland Industries, Inc. (“Farmland”) and several of its subsidiaries filed for Chapter 11 bankruptcy protection. In December 2002, Farmland, the largest customer on the ammonia pipeline system, announced its intent to sell its ammonia production facility connected to our pipeline to Koch Nitrogen Company (“Koch”) and elected to exercise its rights under our ammonia pipeline agreement to terminate its shipment obligation by submitting 12-month written notice to us. Farmland’s notification was to be

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effective December 23, 2002. Farmland was expected to incur a deficiency of approximately $2.0 million to $2.5 million under its shipment obligation for the contract year beginning July 1, 2002 and ending June 30, 2003. On February 18, 2003, we entered into a settlement agreement with Farmland to resolve the deficiency and provide the basis for assignment of its shipment obligation to the ultimate purchaser of its ammonia assets pursuant to bankruptcy procedures. Under the settlement agreement, Farmland paid us $0.8 million for the deficiency it would have incurred under its shipment obligation for the contract year ending June 30, 2003. On May 19, 2003, Koch Nitrogen Company purchased, with approval from the bankruptcy court, selected U.S. fertilizer assets from Farmland including the Enid production facility and other facilities along our pipeline system. As part of this transaction, Farmland withdrew its termination notice and assigned its shipment obligation with the revised requirements of 200,000 tons annually versus the previous requirement of 450,000 tons annually per the settlement agreement. The revised shipment obligation of Koch has reduced the aggregate minimum shipment obligations on the pipeline system from 700,000 tons annually to 450,000 tons annually.

Markets and Competition

Demand for nitrogen fertilizer has typically followed a combination of weather patterns and growth in population, acres planted and fertilizer application rates. Because natural gas is the primary feedstock for the production of ammonia, the profitability of our customers is impacted by high natural gas prices. To the extent our customers are unable to pass on higher costs to their customers, they may reduce shipments through our ammonia pipeline system.

We compete primarily with ammonia shipped by rail carriers, but we believe we have a distinct advantage over rail carriers because ammonia is a gas under normal atmospheric conditions and must be placed under pressure or cooled to -33 degrees Celsius to be shipped or stored. Because the transportation and storage of ammonia requires specialized handling, we believe that pipeline transportation is the safest and most cost-effective method for transporting bulk quantities of ammonia.

We also compete to a limited extent in the areas served by the far northern segment of our ammonia pipeline system with Kaneb’s ammonia pipeline, which originates on the Gulf Coast and transports domestically produced and imported ammonia.

Tariff Regulation

Interstate Regulation

Our petroleum products pipeline system’s interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and nondiscriminatory. Rates of interstate oil pipeline companies, like those charged for our petroleum products pipeline system, are currently regulated by FERC primarily through an index methodology, which in its initial form allowed a pipeline to change its rates based on the annual change in the producer price index, or PPI, for finished goods less 1%. As required by its own regulations, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing rate indexing methodology. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the U.S. Court of Appeals for the Washington D.C. Circuit, the FERC changed the rate indexing methodology to the PPI for finished goods, but without the subtraction of 1% as had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2001. Under the indexing regulations, a pipeline can request a rate increase that exceeds index levels for indexed rates using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rate resulting from application of the PPI. Approximately one-third of the petroleum products pipeline system is subject to this

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indexing methodology. In addition to rate indexing and cost-of-service filings, interstate oil pipeline companies may elect to support rate filings by obtaining authority to charge market-based rates or through an agreement between a shipper and the oil pipeline company that a rate is acceptable. Two-thirds of our petroleum products pipeline system’s markets are deemed competitive by the FERC, and we are allowed to charge market-based rates in these markets.

In a June 1996 decision, the FERC disallowed the inclusion of a full income tax allowance in the cost-of-service tariff filing of Lakehead Pipe Line Company, L.P. (“Lakehead”), an unrelated oil pipeline limited partnership. The FERC held that Lakehead was entitled to include an income tax allowance in its cost-of-service for income attributable to corporate partners but not on income attributable to individual partners. In 1997, Lakehead reached an agreement with its shippers on all contested rates, so there was no judicial review of the FERC’s decision. In January 1999, in a FERC proceeding involving SFPP, L.P. (“SFPP”), another unrelated oil pipeline limited partnership, the FERC followed its decision in Lakehead and held that SFPP may not claim an income tax allowance with respect to income attributable to non-corporate limited partners. Several parties sought rehearing of the FERC’s decision in SFPP and of several FERC orders issued on rehearing in the SFPP case. Several parties have also filed appeals of the FERC’s orders, which are currently being held in abeyance by the court of appeals pending resolution by the FERC of the remaining requests for rehearing. The FERC’s decision in the Lakehead and SFPP proceedings should have no effect on the market-based rates we charge in competitive markets. However, the Lakehead and SFPP decisions might become relevant to our petroleum products pipeline system should we (1) elect in the future to raise our indexed rates using the cost-of-service methodology, (2) be required to use a cost-of-service methodology to defend our indexed rates against a shipper protest alleging that an indexed rate increase substantially exceeds actual cost increases, or (3) be required to defend our indexed rates against a shipper complaint alleging that the pipeline’s rates are not just and reasonable. In such case, a complainant or protestant could assert that, in light of the decisions regarding Lakehead and SFPP and our ownership of the petroleum products pipeline system, we should be allowed to collect an income tax allowance only with respect to the portion of our partnership units held by corporations. We believe that most if not all of the indexed rates can be supported on a cost-of-service basis, even assuming a reduction in the income tax allowance. Nevertheless, if the indexed rates were challenged, we cannot give assurance that some or all of the indexed rates may not be reduced. If indexed rates were reduced, the amount of cash generated from our operations could be materially reduced.

The Surface Transportation Board (“STB”), a part of the United States Department of Transportation, has jurisdiction over interstate pipeline transportation of ammonia. The STB succeeded the Interstate Commerce Commission which previously regulated pipeline transportation of ammonia.

The STB is responsible for rate regulation of pipeline transportation of commodities other than water, gas or oil. These transportation rates must be reasonable and a pipeline carrier may not unreasonably discriminate among its shippers. If the STB finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives.

The STB does not need to provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and a pipeline holds market power, then it must determine whether the pipeline rates are reasonable. The Board generally applies constrained market pricing principles in its economic analysis. Constrained market pricing provides two alternative methodologies for examining the reasonableness of a carrier’s rates. The first approach examines a carrier’s existing system to determine whether the carrier is already earning sufficient funds to cover its costs and provide a sufficient return on investment, or would earn sufficient funds after eliminating unnecessary costs from specifically identified inefficiencies and cross-subsidies in its operations. The second approach calculates the revenue requirements that a hypothetical, new and optimally efficient carrier would need to meet in order to serve the complaining shippers.

Customers that protest rates in STB proceedings may use any methodology they choose that is consistent with constrained market pricing principles. When addressing revenue adequacy, a complainant must provide

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more than a single period snapshot of a carrier’s costs and revenues. The complainant must measure whether a carrier earns adequate revenues over a period of time, as measured by a multi-period discounted cash flow analysis.

The STB has held that unreasonable discrimination occurs when (1) there is a disparity in rates, (2) the complaining party is competitively injured, (3) the carrier is the common source of both the allegedly prejudicial and preferential treatment and (4) the disparity in rates is not justified by transportation conditions.

Intrastate Regulation

Some shipments on our petroleum products pipeline system move within a single state and thus are considered to be intrastate commerce. Our petroleum products pipeline system is subject to certain regulation with respect to such intrastate transportation by state regulatory authorities in the states of Illinois, Kansas and Oklahoma. However, in most instances, the state commissions have not initiated investigations of the rates or practices of petroleum products pipelines.

Because in some instances we transport ammonia between two terminals in the same state, our ammonia pipeline operations are subject to regulation by the state regulatory authorities in Iowa, Nebraska, Oklahoma and Texas. Although the Oklahoma Corporation Commission and the Texas Railroad Commission have the authority to regulate our rates, the state commissions have generally not investigated the rates or practices of ammonia pipelines in the absence of shipper complaints.

Maintenance and Safety Regulations

Our pipeline systems have been constructed, operated, maintained, repaired, tested and used in general compliance with applicable federal, state and local laws and regulations, American Petroleum Institute standards and other generally accepted industry standards and practices. These pipeline systems will continue to be operated, maintained and inspected in accordance with governing regulations and industry practices.

Our pipeline systems are subject to regulation by the United States Department of Transportation under the Hazardous Liquid Pipeline Safety Act (“HLPSA”) of 1979, as amended, and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of its pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to make certain reports and provide information as required by the Department of Transportation.

In December 2000, the Department of Transportation adopted new regulations requiring operators of hazardous liquid interstate pipelines to develop and follow an integrity management program that provides for assessment of the integrity of all pipeline segments that could affect designated “high consequence areas,” including high population areas, drinking water and ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. Segments of our pipeline systems are located in high consequence areas and/or have the ability to impact high consequence areas. We believe we are in material compliance with HLPSA requirements. Since this rule went into effect, we have spent approximately $25 million relative to integrity assessment and anticipate spending approximately $36 million during the next five years associated with system integrity assessments. These cost estimates could increase in the future if additional safety measures are required or if existing safety standards are raised that exceed the current pipeline capabilities.

Our pipeline systems are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposures. The OSHA hazard communication standard, the Environmental Protection Agency (“EPA”)

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community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request. In general, we expect to increase our expenditures during the next decade to comply with more strigent industry and regulatory safety standards such as those described above. At qualifying facilities, we are subject to OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We believe we are in material compliance with the OSHA Process Safety Management regulations.

Environmental

General

The operation of our pipeline systems, terminals and associated facilities in connection with the transportation, storage and distribution of refined petroleum products, crude oil and other liquid hydrocarbons and ammonia is subject to stringent and complex laws and regulations governing the discharge of materials into the environment or otherwise related to environmental protection. As an owner or lessee and operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. Compliance with existing and anticipated laws and regulations increases the cost of planning, constructing and operating pipelines, terminals and other facilities. Included in our construction and operating costs are capital cost items necessary to maintain or upgrade our equipment and facilities to comply with existing environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, imposition of remedial actions and the issuance of injunctions, or construction bans or delays on ongoing operations. Except as described below under Environmental Liabilities Associated with Magellan Terminal Holdings and the Ammonia Pipeline System and Environmental Liabilities Associated with the Petroleum Products Pipeline System, we believe that our operations are in material compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change, and we cannot give assurance that the cost to comply with these laws and regulations in the future will not have a material adverse effect on our financial position or results of operations.

Estimates provided below for remediation costs assume that we will be able to use common remedial and monitoring methods or associated engineering or institutional controls to demonstrate compliance with applicable regulatory requirements. These estimates cover the cost of performing assessment, remediation and/or monitoring of impacted soils, groundwater and surface water conditions, but do not include any costs for potential claims by others with respect to these sites. While we do not expect any such potential claims by others to be materially adverse to our operations, financial position, or cash flows, we cannot give assurance that the actual remediation costs or associated remediation liabilities will not exceed estimated amounts.

We may experience future releases of refined petroleum products into the environment from the operation of our pipeline systems, terminals and associated facilities in connection with the transportation, storage and distribution of refined petroleum products, crude oil and other liquid hydrocarbons or discover historical releases that were previously unidentified or not assessed. While we maintain an extensive asset inspection and maintenance program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets nevertheless have the potential to substantially affect our business.

Environmental Indemnification from Williams and its Affiliates

Williams, certain of its affiliates and MMH, will indemnify us against certain environmental liabilities. Williams has guaranteed the obligations of its affiliates. The terms and limitations of these indemnification agreements are summarized below.

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For assets transferred to us from Williams at the time of our initial public offering in February 2001, Williams agreed to indemnify us for up to $15.0 million for environmental liabilities that exceed the amounts covered by the indemnities we received from the sellers of those assets as described below. The indemnity applies to environmental liabilities arising from conduct prior to the closing of the initial public offering (February 9, 2001) and discovered within three years of closing of the initial public offering; however, the discovery period has been extended to August 9, 2004.

In connection with our April 2002 acquisition of Magellan Pipeline, which comprises the majority of our petroleum products pipeline system, Williams has agreed to indemnify us for losses and damages related to breaches of representations and warranties, including environmental representations and warranties and the violation or liabilities arising under any environmental laws prior to the acquisition. This indemnity covers losses in excess of $2.0 million up to a maximum of $125.0 million. Claims related to this environmental indemnity must be made prior to April 2008 and must be related to events that occurred prior to April 11, 2002.

In addition to these two agreements, the purchase and sale agreement (“June 2003 PSA”) entered into in connection with Williams’ sale of its interests in us provides us with two additional indemnities related to environmental liabilities.

First, MMH (the buyer under the June 2003 PSA) assumed Williams’ obligations to indemnify us for $21.9 million of known environmental liabilities, of which $19.0 million was associated with known liabilities at Magellan Pipeline facilities, $2.7 million was associated with known liabilities at our petroleum products terminal facilities and $0.2 million was associated with known liabilities on the ammonia pipeline system.

Second, in the June 2003 PSA, Williams agreed to indemnify us for environmental liabilities arising prior to June 17, 2003 related to all of our facilities to the extent not already indemnified under Williams’ two preexisting indemnification obligations described above. This additional indemnification includes those liabilities related to our petroleum products terminals and the ammonia pipeline system arising after the initial public offering (February 9, 2001) through June 17, 2003 and those liabilities related to Magellan Pipeline arising after our acquisition of it on April 11, 2002 through June 17, 2003. This indemnification covers environmental as well as other liabilities and is capped at $175.0 million.

A summary of the indemnities we have with Williams and the liabilities and receivables associated with these indemnities is provided in Note 17 – Commitments and Contingencies to the accompanying consolidated financial statements.

Environmental Indemnifications From Third Parties

Described below are environmental indemnifications provided by outside entities when we acquired certain of our petroleum product pipeline terminals. Most of the liabilities we assumed in those acquisitions are covered by our indemnities with Williams.

In connection with the acquisition of the Dallas terminal in December 1997, Mobil Oil Corporation retained liability for ongoing remediation activities until agency closure is granted; however, if closure has not been received by December 29, 2013, we will assume any remaining liability.

In connection with the terminal assets purchased from Amoco Oil Company (“Amoco”) in January 1999, Amoco retained liability for all known remediation actions until agency closure is granted; however, if closure has not been received by January 7, 2014, we will assume any remaining liability.

In connection with the three Gulf Coast marine terminal facilities acquired from Amerada Hess Corporation (“Hess”) in August 1999, Hess has obligations to conduct and pay for the clean up of certain hazardous

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substances known to be present or have been released prior to August 1999 and has indemnified us for claims and losses arising out of these remediation obligations. These obligations and indemnifications include:

In addition to these obligations and indemnities, Hess retained liability for the performance of corrective actions associated with hydrocarbon recovery from ground water and a cooling tower at the Corpus Christi, Texas terminal and a process safety management compliance matter at the Galena Park, Texas terminal facility.

In connection with our acquisition of the New Haven, Connecticut marine terminal from Wyatt Energy, Inc., in August 2000 the seller indemnified us against liabilities related to PCB’s. We assumed all other environmental liabilities.

In connection with the acquisition of our two Little Rock, Arkansas terminals in June 2001, TransMontainge Inc. retained liability for ongoing remediation activities until the site receives written completion or a closure order.

We acquired 100% ownership in 6 petroleum products terminals in the Southeast through a series of 4 transactions: (1) a 45.5% interest in the terminals was acquired from Conoco, Inc. in 1996; (2) a 23.5% interest was acquired from Conoco, Inc. in 1998; (3) a 10.0% interest was acquired from Murphy Oil USA, Inc. in 1999; and (4) a 21.0% interest was acquired from Murphy Oil USA, Inc. in 2004. Under the 1996 agreement, Conoco, Inc. retained liability for 45.5% of known environmental liabilities until agency closure is granted. Under the 1998 agreement, TOC Terminals, Inc. retained liability for 23.5% of known environmental liabilities until agency closure is granted, subject to a maximum aggregate liability of $500,000. Under the 2004 agreement, we assumed liability for 31.0% of known environmental liabilities. We have also assumed liability for all unknown environmental liabilities.

Environmental Liabilities Associated with Magellan Terminal Holdings and the Ammonia Pipeline System

The Partnership has insurance policies which provide coverage for environmental matters associated with sudden and accidental releases of petroleum products. As of December 31, 2003, we had no other site-specific environmental insurance policies. Previously existing site-specific policies were retained by Williams at the time MMH acquired Williams’ interest in us in support of Williams’ indemnities to us.

Under the Oil Pollution Prevention regulations, EPA regulates the requirements for Spill Prevention, Control, and Countermeasure (“SPCC”) plans. Currently, we are evaluating the SPCC plans for potential deficiencies at approximately 34 of our petroleum products terminal facilities and costs associated with complying with the regulations cannot be determined at this time. However, we believe that costs incurred to correct any deficiencies associated with complying with the regulations are covered by Williams’ indemnification obligations described above.

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We have notified the Texas Commission on Environmental Quality regarding certain potential non-compliance issues associated with the Galena Park terminal and its various air permits. At this time, we cannot assess the materiality of these notifications; however, we believe that any corrective action(s) required and/or civil penalty assessed are covered by Williams’ indemnifications obligations described above.

Environmental Liabilities Associated with the Petroleum Products Pipeline System

Potentially significant assessment, monitoring and remediation projects related to events prior to our acquisition of the petroleum products pipeline system are being performed at about 45 sites in Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Oklahoma, South Dakota and Wisconsin. We estimate, that the total cost of performing the currently anticipated assessment, monitoring and remediation at these 45 sites over future years will be approximately $23.4 million, of which at least $20.9 million, and potentially all $23.4 million, is covered by our indemnification agreements with Williams or MMH. The most significant remedial costs at these sites are costs attributed to cleanup at eight terminals and four right-of-way locations where we estimate that $17.3 million of the $23.4 million in costs will be incurred. This estimate assumes that we will be able to use common remedial and monitoring methods or associated engineering or institutional controls to demonstrate compliance with applicable regulatory requirements. This estimate covers the cost of performing assessment, remediation and/or monitoring of impacted soils, groundwater and surface water conditions, but does not include any costs for potential claims by others with respect to these sites.

Under the Oil Pollution Prevention regulations, EPA regulates the requirements for SPCC plans. Currently we are assessing the impact of deficiencies at approximately 70 Magellan Pipeline facilities and the costs associated with complying with the regulations cannot be determined at this time. However, we believe that any costs incurred to correct any associated deficiencies to comply with the regulations are covered by Williams’ indemnification obligations described above.

We are currently negotiating a consent order for Magellan Pipeline’s Enid terminal. Capital costs associated with that order are estimated at approximately $2.0 million and the civil penalty associated with the alleged non-compliance with federal air regulations from December 1997 through December 2001 are estimated to be between $0.5 million and $1.5 million. We believe these costs are covered by Williams’ indemnification obligations described above.

On July 2, 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from Williams and its affiliates’ pipelines, pipeline systems and pipeline facilities used in the movement of oil or petroleum products during the period from July 1, 1998 through July 2, 2001. In November 2001, Williams furnished its response, which related primarily to our petroleum products pipeline system. In September 2003, the EPA notified Williams it was reviewing Williams’ response. To date, neither Williams nor we have received further correspondence from the EPA related to this issue; however, we believe any civil penalty that arises from this matter are covered by Williams’ indemnification obligations described above.

Hazardous Substances and Wastes

In most instances, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into the water or soils, and include measures to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under the Superfund law, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural

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resources and for the costs of certain health studies. The Superfund law also authorizes the EPA, and in some instances third parties, to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within the Superfund law’s definition of a hazardous substance, and as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.

In 2003, the EPA notified Williams that it was a potentially responsible party for two Superfund sites. Williams has responded to both EPA correspondences indicating that neither Williams nor we have any documentation or knowledge of being a potentially responsible party at either site. Responses from the EPA have not been received to date.

Our operations also generate wastes, including hazardous wastes that are subject to the requirements of the RCRA and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations routinely generate only small quantities of hazardous wastes, and we do not hold ourselves out as a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA hazardous waste permit. While RCRA currently exempts a number of wastes, including many oil and gas exploration and production wastes, from being subject to hazardous waste requirements, the EPA from time to time will consider the adoption of stricter disposal standards for non-hazardous wastes. Moreover, it is possible that additional wastes, which could include non-hazardous wastes currently generated during operations, will in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly storage and disposal requirements than are non-hazardous wastes. Changes in the regulations could have a material adverse effect on our capital expenditures or operating expenses.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to the Superfund law, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

Above Ground Storage Tanks

States in which we operate typically have laws and regulations governing above ground tanks containing liquid substances. Generally, these laws and regulations require that these tanks include secondary containment systems or that the operators take alternative precautions to ensure that no contamination results from any leaks or spills from the tanks. The Department of Transportation Office of Pipeline Safety has incorporated API 653 to regulate above ground tanks subject to their jurisdiction. We believe we are in material compliance with all applicable above ground storage tank laws and regulations. As part of our assessment of facility operations we have identified some above ground tanks at our terminals that either are, or are suspected of being, coated with lead-based paints. The removal and disposal of any paints that are found to be lead-based, whenever such activities are conducted in the future as part of our day-to-day maintenance activities, will require increased handling by us. However, we do not expect the costs associated with this increased handling to be significant. We believe that the future implementation of above ground storage tank laws or regulations will not have a material adverse effect on our financial condition or results of operations.

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Water Discharges

Our operations can result in the discharge of pollutants, including oil. The Oil Pollution Act was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 or the Water Pollution Control Act and other statutes as they pertain to prevention and response to oil spills. The Oil Pollution Act subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill such as natural resource damages, where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill from one of our facilities into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations have been or are being developed under the Oil Pollution Act and comparable state laws that may also impose additional regulatory burdens on our operations. Although the costs associated with complying with the amended regulations cannot be determined at this time, we do not expect these expenditures to have a material adverse effect on our financial condition or results of operations.

The Federal Water Pollution Control Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. This law and comparable state laws require that permits be obtained to discharge pollutants into state and federal waters and impose substantial potential liability for the costs of noncompliance and damages. Where required, we hold discharge permits that were issued under the Federal Water Pollution Control Act or a state-delegated program, and we believe that we are in material compliance with the terms of those permits. While we have experienced permit discharge exceedences at some of our terminals we do not expect our non-compliance with existing permits and foreseeable new permit requirements to have a material adverse effect on our financial position or results of operations.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state and local laws. Under such laws, permits are typically required to emit pollutants into the atmosphere. Amendments to the federal Clean Air Act enacted in 1990, as well as recent or soon to be proposed changes to state implementation plans (“SIPs”), for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the amendments include an operating permit for major sources of volatile organic compounds, which applies to some of our facilities. We believe that we currently hold or have applied for all necessary air permits and that we are in material compliance with applicable air laws and regulations. Although we can give no assurances, we believe implementation of the 1990 federal Clean Air Act amendments and any changes to the SIPs pertaining to air quality in regional non-attainment areas will not have a material adverse effect on our financial condition or results of operations.

Employee Safety

We are subject to the requirements of the federal OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in material compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

Title to Properties

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property, and in some instances, these rights-of-way are revocable at the election of the grantor. Several rights-of-way for our pipelines and other real property assets are shared with other pipelines and by third parties.

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In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some cases, property for pipeline purposes was purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our pipelines. The previous owners of the applicable pipelines may not have commenced or concluded eminent domain proceedings for some rights-of-way.

Some of the leases, easements, rights-of-way, permits and licenses that have been transferred to us will require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. We believe that a failure to obtain all consents, permits or authorizations will not have a material adverse effect on the operation of our business.

We believe that we have satisfactory title to all of our assets or are entitled to indemnification from affiliates of Williams for (1) title defects to the ammonia pipeline that arise within 15 years after the closing of our initial public offering and (2) title defects related to the petroleum products pipeline system that arise within ten years from its acquisition. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us or our predecessor, we believe that none of these burdens should materially detract from the value of our properties or from our interest in them or should materially interfere with their use in the operation of our business.

The assets of our petroleum products pipeline system have been pledged as collateral to secure the Series A and Series B notes issued by Magellan Pipeline (see Note 13—Debt to the accompanying consolidated financial statements for further information).

Employees

To conduct our operations, an affiliate of our general partner employs approximately 823 employees, of whom 435 conduct the operations of our petroleum products pipeline system, 174 conduct the operations of our petroleum products terminals and 214 provide general and administrative services. From June 18, 2003 through December 31, 2003, an affiliate of our general partner contracted with Williams for these services.

Approximately 216 of the employees assigned to our petroleum products pipeline system are represented by the Paper, Allied-Industrial, Chemical and Energy Workers International Union (“PACE”). The employees represented by PACE are subject to a contract that extends through January 2006. None of the terminal operations employees are represented by a union. The employees at our Galena Park marine terminal facility were previously represented by a union, but indicated in 2000 their unanimous desire to terminate their union affiliation. Nevertheless, the National Labor Relations Board (“NLRB”) ordered us to bargain with the union as the exclusive collective bargaining representative of the employees at the facility. Subsequently, the NLRB reversed its decision and withdrew its order. Our general partner’s affiliate considers its employee relations to be good.

(d) Financial Information About Geographical Areas

We have no revenue or segment profit or loss attributable to international activities.

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(e) Available Information

We file annual, quarterly and other reports and other information electronically with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

Our Internet address is www.magellanlp.com. We make available, free of charge on or through our Internet website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Our Corporate Governance Guidelines, Audit Committee charter, Compensation Committee charters and Code of Business Conduct, each of which has been approved by our general partner’s board of directors, are available on our website at www.magellanlp.com. Our unitholders may request a written copy of these materials by calling 1-918-574-7000.

See Item 1(c) for a description of the locations and general character of our material properties.

In July 2001, the EPA, pursuant to Section 308 of the Clean Water Act, preliminarily determined that Magellan Pipeline may have systematic problems with discharges from its pipelines and served Williams with an information request. In November 2001, Williams submitted a timely response to the EPA information request. In September 2003, the EPA notified Williams that it was reviewing its response. No further communications have been received from the EPA regarding this matter. If the EPA determines that Magellan Pipeline has systematic problems with discharges from its pipelines, it may result in a fine in excess of $100,000. We believe any fine the EPA may assess in this matter is covered by Williams’ indemnity obligations.

The Oklahoma Department of Environmental Quality (“ODEQ”) alleges in two separate Notice of Violations dated June 14, 2002 and September 30, 2003 that a terminal on our petroleum products pipeline system located in Enid, Oklahoma violated its air permit and applicable regulations by non-compliance with the federal Maximum Achievable Control Technology (“MACT”) standards, which the ODEQ alleges are applicable to the facility. This proceeding is in the preliminary stages. However, if the ODEQ determines that the terminal is subject to the MACT standards, it may result in a monetary fee in excess of $100,000. We believe that any monetary fees and any cost to bring the terminal into compliance with the MACT standards are covered by Williams’ indemnity obligation.

On August 8, 2003, we notified the Texas Commission on Environmental Quality (“TCEQ”) that we were requesting immunity from civil and administrative penalties under the Texas Environmental Health and Safety Audit Privilege Act (“Audit Act”) for potential violations of TCEQ rules, federal rules or permit emission limits arising out of air emissions produced when storage tank floating roofs are landed on their support legs when tanks are emptied. To qualify for immunity under the Audit Act, the violation must have been noted and disclosed as a result of a voluntary environmental audit and must meet the reasonable inquiry standard required under the EPA Clean Air Act Title V regulations. If the TCEQ concludes that our environmental audit that led to the disclosure to TCEQ did not exceed the reasonable inquiry standard, the immunity provided by the Audit Act would not apply, which may result in a fine in excess of $100,000. We believe that any fine the TCEQ may assess in this matter is covered by Williams’ indemnity obligations.

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We are also a party to various legal actions that have arisen in the ordinary course of our business. We do not believe that the resolution of these matters will have a material adverse effect on our financial condition or results of operations.

Our Annual Meeting of Limited Partners was held on November 7 and 21, 2003. At this meeting, two individuals were elected as directors of our general partner’s board of directors and the conversion of each outstanding class B common unit into one common unit, and the resulting issuance of an aggregate of 7,830,924 common units upon the conversion and cancellation of the 7,830,924 class B common units was approved.

A tabulation of the voting with respect to each of the matters voted upon at the meeting follows:

Election of Directors

Conversion of Class B Common Units into Common Units

PART II

We completed our initial public offering in February 2001, and our common units began trading on the New York Stock Exchange under the ticker symbol “WEG”. Subsequent to our name change to Magellan Midstream Partners, L.P. on September 1, 2003, our common units are listed on the New York Stock Exchange under the ticker symbol “MMP”. At the close of business on March 1, 2004, we had 143 registered holders and 24,790 beneficial holders of record of our common units. The high and low closing sales price ranges and distributions paid by quarter for 2001, 2002 and 2003 are as follows:

In addition to common units, we also issued 5,679,694 subordinated units as part of our initial public offering in February 2001. There is no established public trading market for these units. All of the subordinated units are held by an affiliate of our general partner and receive a quarterly distribution only after sufficient funds have been paid to the common units, as described below. In addition, the subordinated units generally have reduced voting rights equal to one-half vote for each unit owned.

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Prior to November 2003, we also had 7,830,924 class B common units outstanding, which were all held by an affiliate of our general partner. These units were issued as partial payment for the April 2002 purchase of our petroleum products pipeline system (see Note 6—Acquisitions and Divestitures in the accompanying consolidated financial statements for additional information on this acquisition). These units were equivalent to common units except they only had voting rights with respect to matters that would have a material impact on the holders of such units. The holder of the class B common units had the right to request conversion of these units into common units on a 1-for-1 basis beginning April 2003. The holder did request that the common unitholders vote to approve the conversion of the class B common units and such approval was granted at the annual meeting of limited partners held during November 2003. These units have converted to common units and are no longer outstanding.

During the subordination period, the holders of our common units are entitled to receive each quarter a minimum quarterly distribution of $0.525 per unit ($2.10 annualized) prior to any distribution of available cash to holders of our subordinated units. The subordination period is defined generally as the period that will end on the first day of any quarter beginning after December 31, 2005 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, during such periods, as defined in our partnership agreement, equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2003 and one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2004 if we meet the tests set forth in our partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units. We met the first early conversion test effective February 2004, and 25%, or 1,419,923, of our 5,679,694 then outstanding subordinated units converted to common units. The impact of this conversion is that the existing common units have less subordinated protection with respect to distributions and the subordinated units that converted into common units received voting rights equivalent to those of the common units.

During the subordination period, our cash is distributed first 98% to the holders of common units and 2% to our general partner until there has been distributed to the holders of common units an amount equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution on the common units for any prior quarter. Any additional cash is distributed 98% to the holders of subordinated units and 2% to our general partner until there has been distributed to the holders of subordinated units an amount equal to the minimum quarterly distribution.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as available cash, which is defined in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution. We currently pay quarterly cash distributions of $0.83 per unit, which entitles our general partner to receive approximately 12% of

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the total cash distributions paid. In general, we intend to continue to increase our cash distributions in the future assuming no adverse change in our operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.

SELECTED FINANCIAL AND OPERATING DATA

We have derived the summary selected historical financial data from our current and historical audited consolidated financial statements and related notes. Due to the April 2002 acquisition of Magellan Pipeline, which comprises the majority of our petroleum products pipeline system, we have restated our consolidated financial statements and notes to reflect the results of operations, financial position and cash flows of Magellan Midstream Partners, L.P. and Magellan Pipeline on a combined basis throughout the periods presented. This financial information is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto. All other amounts have been prepared from our financial records. Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The historical results for Magellan Pipeline included income and expenses and assets and liabilities that were conveyed to and assumed by an affiliate of Magellan Pipeline prior to our acquisition of it. The assets principally included Magellan Pipeline’s interest in and agreement related to Longhorn Partners Pipeline, L.P. (“Longhorn”), an inactive refinery site at Augusta, Kansas, a pipeline construction project, the ATLAS 2000 software system and the pension asset and obligations associated with the non-contributory defined-benefit pension plan that covered employees assigned to Magellan Pipeline’s operations. The liabilities principally included the environmental liabilities associated with an inactive refinery site in Augusta, Kansas and current and deferred income taxes and affiliate note payable. The current and deferred income taxes and the affiliate note payable were contributed to us in the form of a capital contribution by an affiliate of Williams. Also, as agreed between the Partnership and Williams, operating results from Magellan Pipeline’s petroleum products management operation, other than an annual fee of approximately $4.0 million, were not included in the financial results of the Partnership since April 2002. In addition, general and administrative expenses related to the petroleum products pipeline system for which the Partnership had been reimbursing its general partner, were limited to $30.7 million on an annual basis. This cap was increased to $31.0 million on February 1, 2003 when Magellan Pipeline began operating the Rio Grande Pipeline. The ATLAS 2000 software system assets were contributed to the Partnership on June 17, 2003 in conjunction with the sale by Williams of its interests in the Partnership (see Change in Ownership of General Partner under Note 1—Organization and Presentation in the accompanying consolidated financial statements), and the depreciation expense associated with those assets has been included in the Partnership’s results since that date. Also, the Partnership acquired Williams’ interest in the petroleum products management operation in July 2003 (see Note 6—Acquisitions and Divestitures in the accompanying consolidated financial statements), and the results of this operation have been included in the Partnership’s results subsequent to that date.

EBITDA, a non-generally accepted accounting principle measure presented in the following schedules, is defined as net income plus provision for income taxes, debt placement fee amortization, interest expense (net of interest income) and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with generally accepted accounting principles (“GAAP”). Because EBITDA excludes some items that affect net income and these items may vary among other companies, the EBITDA data presented may not be comparable to similarly titled measures of other companies. Our management uses EBITDA as a performance measure to assess the viability of projects and to determine overall rates of return on alternative investment opportunities. A reconciliation of EBITDA to net income, the nearest comparable GAAP measure, is included in the following schedules.

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In addition to EBITDA, the non-GAAP measure of operating margin (in the aggregate and by segment) is presented in the following table. The components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the table (see Note 16—Segment Disclosures in the accompanying consolidated financial statements for a reconciliation of segment operating margin to segment operating profit). The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important performance measure of the economic success of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and general and administrative costs.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and notes thereto. Magellan Midstream Partners, L.P., formerly Williams Energy Partners L.P., is a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. Our current asset portfolio consists of:

During April 2002, we acquired Magellan Pipeline Company, LLC (“Magellan Pipeline”), which comprises the majority of our petroleum products pipeline system, for approximately $1.0 billion from a wholly owned subsidiary of The Williams Companies, Inc. (“Williams”). Because Williams was an affiliate of ours at the time of the acquisition, the transaction was between entities under common control and, as such, was accounted for similar to a pooling of interest. Accordingly, our consolidated financial statements and notes have been restated to reflect the historical results of operations, financial position and cash flows of this pipeline system and us on a combined basis throughout the periods presented.

Significant Events

On June 17, 2003, Williams sold its 54.6% interest in us to Magellan Midstream Holdings, L.P. (“MMH”), a new entity jointly formed by private equity firms Madison Dearborn Capital Partners IV, LLC and Carlyle/Riverstone MLP Holdings, L.P. MMH acquired 1.1 million of our common units, 5.7 million subordinated units, 7.8 million class B common units and 100% of the ownership interest in our general partner.

The change in majority ownership of this transaction resulted in the following items, primarily due to our separation from Williams:

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In late December 2003, MMH sold 4,300,000 common units and we sold 200,000 common units in an underwritten public offering. MMH sold an additional 675,000 common units in January 2004, when the underwriters exercised their over-allotment option. The net proceeds from our sale of the 200,000 units, after transaction costs and underwriting commissions, were $9.5 million. We also received a $0.2 million contribution from MMH to maintain its 2% general partner interest. Proceeds from these transactions will be used for general partnership purposes. Following these transactions, MMH has an approximate 36% ownership interest in us, including its 2% general partner interest.

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Recent Developments

On January 27, 2004, the board of directors of our general partner declared a quarterly cash distribution of $0.83 per unit for the period of October 1 through December 31, 2003. The fourth-quarter distribution represents a 14% increase over the fourth-quarter 2002 distribution of $0.725 per unit and a 58% increase since our initial public offering in February 2001. The distribution was paid on February 13, 2004 to unitholders of record on February 6, 2004.

On January 29, 2004, we announced our acquisition of ownership interests in 14 inland terminals located in the southeastern United States for $24.8 million. We previously owned a 79% interest in eight of these terminals and acquired the remaining 21% ownership interest in these eight terminals from Murphy Oil USA, Inc. In addition, we acquired sole ownership of six terminals that had been jointly owned by Murphy Oil USA, Inc. and Colonial Pipeline Company.

In February 2004, we entered into three separate agreements with two different banks for forward starting interest rate swaps totaling $150.0 million. The swaps begin in October 2007, when we expect to refinance the majority of Magellan Pipeline’s $480.0 million senior secured notes. Under the swap agreements, we will pay fixed interest rates and will receive LIBOR for a ten-year period, which is the assumed tenure of replacement debt. The average fixed rate on the swaps is 5.9%.

On March 2, 2004, we acquired a 50% ownership in Osage Pipe Line Company, LLC, which owns the Osage Pipeline, for $25.0 million from National Cooperative Refinery Association (“NCRA”). The 135-mile Osage pipeline transports crude oil from Cushing, Oklahoma to El Dorado, Kansas and has connections to the NCRA refinery in McPherson, Kansas and the Frontier refinery in El Dorado, Kansas. The remaining 50% interest in the Osage Pipe Line Company, LLC will continue to be owned by NCRA.

Overview

In 2003, our cash flow significantly exceeded our debt service obligations and cash distributions to our unitholders. Our petroleum products pipeline system generates a substantial portion of this cash flow. The revenues generated from the petroleum products pipeline business are significantly influenced by demand for refined petroleum products, which has been growing in the markets we serve. In addition, expenses for this business are principally fixed and relate to routine maintenance and system integrity work as well as field and support personnel cost.

We expect to maintain or grow the cash flow of the petroleum products pipeline system as well as our other businesses in the future. However, a prolonged period of high refined-product prices could lead to a reduction in demand and result in lower shipments on our pipeline system. In addition, increased pipeline maintenance regulations, higher power costs and higher interest rates could decrease the amount of cash we generate.

Petroleum Products Pipeline System. Our petroleum products pipeline system is a common carrier transportation pipeline and terminals network. The system generates approximately 80% of its revenues, excluding the sale of petroleum products, through transportation tariffs for volumes of petroleum products it ships. These tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”). The petroleum products pipeline system also earns revenues from non-tariff based activities, including leasing pipeline and storage tank capacity to shippers on a long-term basis and by providing data services and product services such as ethanol unloading and loading, additive injection, custom blending and laboratory testing.

Our petroleum products pipeline system generally does not produce, trade or take title to the products it transports. However, the system does generate small volumes of product through its fractionation activities.

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In July 2003, we purchased a petroleum products management operation from Williams and we now take title to the associated inventories and resulting products. From April 2002 through June 2003, we did not purchase and take title to the inventories or resulting products associated with this operation but performed services related to this operation for an annual fee of approximately $4 million. We also purchase and fractionate transmix and sell the resulting separated products.

Operating costs and expenses incurred by the petroleum products pipeline system are principally fixed costs related to routine maintenance and system integrity as well as field and support personnel. Other costs, including power, fluctuate with volumes transported and stored on the system. Expenses resulting from environmental remediation projects have historically included costs from projects relating both to current and past events. In connection with our acquisition of this pipeline system, an affiliate of Williams agreed to indemnify us for costs and expenses relating to environmental remediation for events that occurred before April 11, 2002 and are discovered within six years from that date. See “Business—Environmental” under Item 1 of this 10-K report.

Petroleum Products Terminals. Within our terminals network, we operate two types of terminals: marine terminal facilities and inland terminals. The marine terminal facilities are large product storage facilities that generate revenues primarily from fees that we charge customers for storage and throughput services. The inland terminals earn revenues primarily from fees we charge based on the volumes of refined petroleum products distributed from these terminals. The inland terminals also earn ancillary revenues from injecting additives into gasoline and jet fuel and filtering jet fuel.

Operating costs and expenses that we incur in our marine and inland terminals are principally fixed costs related to routine maintenance as well as field and support personnel. Other costs, including power, fluctuate with storage utilization or throughput levels.

Ammonia Pipeline System. The ammonia pipeline system earns the majority of its revenue from transportation tariffs that we charge for transporting ammonia through the pipeline. Effective February 2003, we entered into an agreement with a third-party pipeline company to operate our ammonia pipeline system. Operating costs and expenses charged to us are principally fixed costs related to routine maintenance as well as field personnel. Other costs, including power, fluctuate with volumes transported on the pipeline.

Acquisition History

We have increased our operations through a series of acquisitions:

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Results of Operations

The non-generally accepted accounting principle (“GAAP”) financial measure of operating margin is presented below. The components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the table below.

We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important performance measure of the economic success of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and G&A costs.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2003