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Index to Financial Statements

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

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.  x

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

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, 2004, was $1,072,882,421.

As of March 1, 2005, there were outstanding 30,340,464 common units and 2,839,848 subordinated units.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the 2005 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.

Index to Financial Statements

MAGELLAN MIDSTREAM PARTNERS, L.P.

FORM 10-K

PART I

ITEM 1. Business

(a) General Development of Business

We were formed as a limited partnership under the laws of the State of Delaware in August 2000. Our general partner is Magellan GP, LLC, which is a Delaware limited liability company. On September 1, 2003, our name changed from Williams Energy Partners L.P. (NYSE: WEG) to Magellan Midstream Partners, L.P. (NYSE: MMP). Magellan Midstream Holdings, L.P. (“MMH”) has been the owner of our general partner since June 2003. Prior to June 2003, the owner of our general partner was The Williams Companies, Inc. (“Williams”).

On January 29, 2004, we acquired ownership in 14 petroleum products terminals located in the southeastern United States. We paid $24.8 million for these facilities, incurred $0.6 million of closing costs and assumed $3.8 million of environmental liabilities. We previously owned a 79% interest in eight of these terminals and purchased the remaining ownership interest from Murphy Oil USA, Inc. In addition, the acquisition included sole ownership of six terminals that were previously jointly owned by Murphy Oil USA, Inc. and Colonial Pipeline Company.

On March 2, 2004, we acquired a 50% ownership in Osage Pipeline Company, LLC (“Osage Pipeline”) for $25.0 million from National Cooperative Refining 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 Osage Pipeline is owned by NCRA.

On October 1, 2004, we acquired more than 2,000 miles of petroleum products pipeline system assets from Shell Pipeline Company LP and Equilon Enterprises LLC, which had operated these assets under the name Shell Oil Products US (“Shell”) for approximately $487.4 million. In addition, we paid approximately $30.0 million for inventory related to a third-party supply agreement for which we received $14.0 million of cash collateral, assumed approximately $29.6 million of existing liabilities and expect to incur approximately $9.6 million for transaction costs, of which $6.3 million had been incurred as of December 31, 2004. These assets are located in Colorado, Kansas, Oklahoma and Texas and primarily comprise four refined petroleum products pipeline systems with related terminalling and storage facilities that have a combined storage capacity of approximately 5.8 million barrels.

(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 transportation, storage and distribution of refined petroleum products and ammonia. Our asset portfolio currently consists of:

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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 markets 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:

The Gulf Coast region is a significant supply source for our facilities and is a major hub for petroleum refining. According to the Energy Information Administration’s “Petroleum Supply Report for 2003”, the Gulf Coast region accounted for approximately 43% of total U.S. daily refining capacity and 67% of U.S. refining capacity expansion from 1999 to 2003. 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. According to the Energy Information Administration’s “Petroleum Supply Report for 2003”, the amount of petroleum products exported from the Gulf Coast region increased by approximately 28%, or 299 million barrels from 1990 to 2003. The growth in refining capacity and increased product flow attributable to the Gulf Coast region has increased demand for transportation, storage and distribution facilities.

PETROLEUM PRODUCTS PIPELINE SYSTEM

During October 2004, we acquired a 2,000-mile petroleum products pipeline system from affiliates of Shell. This strategic acquisition extended the reach of our existing pipeline system into key markets in Colorado and western and northern Texas. This pipeline system was already interconnected with our existing petroleum products pipeline in Oklahoma, thereby providing us with a direct connection to the U.S. Gulf Coast, which is the primary refining region of the United States and a major point of entry for foreign imports of refined petroleum products. As a result, our common carrier petroleum products pipeline system now extends 8,500 miles and covers a 13-state area, extending from Texas through the Midwest to Colorado, North Dakota, Minnesota and Illinois. Our pipeline system transports petroleum products and LPGs and includes 43 terminals. The products transported on our pipeline system are largely transportation fuels, and in 2004 were comprised of 55% gasoline, 35% distillates (which includes diesel fuels and heating oil) and 10% 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 18—Segment Disclosures in the accompanying consolidated financial statements for financial information about the petroleum products pipeline system segment. The petroleum products pipeline system segment accounted for 83%, 80% and 79% of our consolidated total revenues in 2004, 2003 and 2002, respectively.

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Index to 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 primary market areas 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 1.5% 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, which represents the Gulf Coast region.

Our petroleum products pipeline system is well connected to Gulf Coast refineries. In addition to our own pipeline that originates in the Gulf Coast region, we also have interconnections with the Explorer, 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 7.2% from 2002 to 2004. The volume increases have come through a combination of acquisitions, 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 for refined petroleum products and LPGs in the United States in terms of pipeline miles. Through direct refinery connections and interconnections with other interstate pipelines, our system can access approximately 43% of the refinery capacity in the continental United States. In general, we do not take title to the petroleum products we transport except with respect to a specific product supply agreement that we assumed in October 2004 and our petroleum products management operation.

Our petroleum products pipeline system generates approximately 80% of its revenue, excluding product sales revenues, through transportation tariffs on volumes shipped. These transportation tariffs vary depending

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Index to Financial Statements

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 38 of our pipeline system’s 43 terminals. Revenues from terminalling and storage at five of our terminals are at privately negotiated rates. 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 54% of the shipments in 2004 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 20% 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. We began operating the Rio Grande pipeline system in 2003. In January 2004 we began serving as a subcontractor to an affiliate of Williams for the operations of Longhorn Partners Pipeline, L.P. (“Longhorn”) and during March 2004 we began operating the Osage Pipeline system. We receive fees for performing these services. Effective April 1, 2005, we have resigned as the operator of the Rio Grande pipeline system.

Product sales revenues primarily result from: (i) a third-party supply agreement assumed as part of the assets acquired from Shell; (ii) the sale of products that are produced from fractionating transmix; and (iii) our petroleum products management operation. We take title to the products related to these activities. Although the revenues generated from these activities were $267.7 million and $107.6 million in 2004 and 2003, respectively, the difference between product sales and product purchases was only $18.5 million and $9.7 million in 2004 and 2003, respectively, as product purchases were $249.2 million in 2004 and $97.9 million in 2003. Revenues increased in 2004 over 2003 by $160.1 million primarily as a result of our third-party supply agreement assumed with the assets acquired from Shell.

Facilities

Our petroleum products pipeline system consists of an 8,500-mile pipeline and includes 26.4 million barrels of aggregate usable storage capacity at terminals and various storage facilities along the system. The terminals deliver petroleum products primarily into tank trucks.

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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. As part of the assets acquired from Shell, we purchased an additional terminal in Oklahoma City, Oklahoma which the Federal Trade Commission is requiring us to sell.

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Petroleum Products Supply

Petroleum products originate from both refining and pipeline interconnection points along our pipeline system. In 2004, 59% of the petroleum products transported on our petroleum products pipeline system originated from 10 direct refinery connections and 41% originated from 11 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)

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. 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.

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Index to Financial Statements

For the year ended December 31, 2004, 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, 2004, represented 54% of total revenues for our petroleum products pipeline system and 63% of revenues excluding product sales.

Product sales primarily relate to the third-party supply agreement we assumed in connection with the assets acquired from Shell, sales of transmix and other petroleum products to trading and marketing companies.

See “Related Party Transactions” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report for a discussion of our affiliate relationship with SemGroup, L.P. and its affiliates.

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.

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 terminals are located in close proximity to refineries and are large storage and distribution facilities that handle refined petroleum products, blendstocks, ethanol, 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. See Note 18—Segment Disclosures in the accompanying consolidated financial statements for financial information about the petroleum products terminals segment. The petroleum products terminals segment accounted for 15%, 17% and 18% of our consolidated total revenues in 2004, 2003 and 2002, respectively.

Marine Terminals

We own and operate six marine terminals, including five marine terminals located along the Gulf Coast and one terminal located in Connecticut near the New York harbor. We acquired one of these terminals in October 2004 as a part of the assets acquired from Shell. Our marine terminals are large storage and distribution facilities, with an aggregate storage capacity of approximately 18.8 million barrels, that provide inventory management, storage and distribution services for refiners and other large end-users of petroleum products.

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Index to Financial Statements

Our marine terminals 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 rail. Once the product has reached our marine terminals, 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, crude oils, heavy oils and feedstocks. In addition to providing storage and distribution services, our marine terminals provide ancillary services including heating, blending and mixing of stored products and additive injection services.

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 terminals. Refiners and chemical companies will typically use our marine terminals 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 terminals’ 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. During 2004, approximately 98% of our marine terminal capacity was utilized. As of December 31, 2004, approximately 60% 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.

Markets and Competition

We believe that the continued strong demand for our marine terminals results from our cost-effective distribution services and key transportation links. We experience the greatest demand at our marine terminals 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

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Index to Financial Statements

“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, other companies have facilities in the Gulf Coast region that 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 six of these terminals in January 2004 and also acquired the remaining 21% ownership interest in eight 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 capacity of 5.5 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, Explorer, Plantation or TEPPCO pipelines and some facilities have multiple pipeline connections. During 2004, gasoline represented approximately 60% of the product volume distributed through our inland terminals, with the remaining 40% consisting of distillates.

Our inland terminals 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 generally 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 aviation fuel, and for filtering jet fuel.

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The following table sets forth our inland terminal locations, percentage ownership and usable storage capacities:

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 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 retailers, wholesalers, exchange transaction customers and traders.

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 primarily comes from distribution companies with marketing and trading arms, independent terminal operators and refining and marketing companies.

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AMMONIA PIPELINE SYSTEM

We own an 1,100-mile common carrier ammonia pipeline system. Our pipeline system transports ammonia from production facilities in Texas and Oklahoma to terminals in the Midwest. The ammonia we transport is primarily used as a nitrogen fertilizer, an important element for maintenance of high crop yields. 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. See Note 18—Segment Disclosures in the accompanying consolidated financial statements for financial information about the ammonia pipeline system segment. The ammonia pipeline system segment accounted for 2% of our consolidated total revenues in 2004 and 3% in 2003 and 2002.

Operations

We generate more than 90% 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. We do not produce or trade ammonia, and we do not take title to the ammonia we transport.

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

Facilities

Our ammonia pipeline is 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.

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. Our customers are currently 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. The transportation contracts with our customers extend through June 2005. We are currently negotiating the terms of new transportation contracts to be effective in July 2005.

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. Each of our customers nominates a tonnage that it expects to ship during the contract year. Our customers’ aggregate annual commitments for the period July 1, 2004 through June 30, 2005 are 650,000 tons. If a customer fails to ship its annual commitment, that customer must pay for the pipeline capacity it did not use. 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 275,000 tons in this combined bank that may be used to offset future ship or pay obligations.

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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 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. 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 Pipe Line Partners, L.P.’s ammonia pipeline, which originates on the Gulf Coast and transports domestically produced and imported ammonia.

Major Customers

The percentage of revenues derived by customers that accounted for 10% or more of our consolidated total revenues is provided in the table below. Customer A is a customer of both our petroleum products pipeline system and petroleum products terminals segments. Customer B is a customer of our petroleum products pipeline system segment.

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 for finished goods (“PPI-FG”) 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-FG, 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-FG. Approximately one-third of our petroleum products pipeline system is subject to this 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

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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 filed appeals of the FERC’s orders with the United States Court of Appeals. On July 20, 2004, the United States Court of Appeals for the District of Columbia issued its opinion relative to these appeals in BP West Coast Products, LLC v. FERC, which vacated the FERC’s application of its Lakehead policy, with the result that no income tax allowance can be claimed by pipeline owners that are limited partnerships. Because the Court’s ruling appears to focus on the facts and record presented to it in that specific case, it is not clear what impact, if any, the opinion will have on our indexed rates. On December 2, 2004, the FERC issued a Notice of Inquiry that seeks comments regarding whether BP West Coast applies only to the specific facts of that case, or whether it applies more broadly, and, if the latter, what effect that ruling might have on energy infrastructure investments. It is not clear what action the FERC will ultimately take in response to the Court’s ruling and the comments received regarding the Notice of Inquiry, and to what extent such action will be challenged and, if so, whether such action will withstand further judicial review. Nevertheless, a shipper might rely on this decision to challenge our indexed rates based on a changed circumstance argument. If the FERC disallowed our income tax allowance, it may be more difficult to justify our rates on a cost of service basis. However, because of the relatively small percentage of our unitholders that are corporations, we include only a small income tax allowance in our cost of service based on the current Lakehead policy, and so we do not believe that a challenge to our indexed rates based solely on the changed circumstance of the elimination of our income tax allowance would likely succeed.

The Surface Transportation Board (“STB”), a part of the United States Department of Transportation, has jurisdiction over interstate pipeline transportation and rate regulations of ammonia. 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 we may be required to show that our rates are reasonable.

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 Colorado, Illinois, Kansas, Oklahoma and Texas. 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.

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Maintenance and Safety Regulations

We believe our assets are operated and maintained in material compliance with applicable federal, state and local laws and regulations, and in accordance with other generally accepted industry standards and practices.

Our assets are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard 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. 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.

Our pipeline systems are also 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 our pipeline facilities. HLPSA covers petroleum, petroleum products and anhydrous ammonia 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, commercially navigable waterways and ecologically sensitive resource areas. Segments of our pipeline systems have the potential to impact high consequence areas. We have spent approximately $32.0 million relative to integrity assessments and anticipate spending approximately $45.0 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.

In 2003, Shell entered into a consent decree with the EPA which, among other things, included testing, maintenance, monitoring and reporting requirements for two of the pipelines we acquired from Shell. The consent decree extends until 2008. Under our purchase agreement with Shell, we agreed, at our own expense, to complete any remaining corrective action(s) required under the consent decree with respect to these pipelines and accordingly recognized a liability of approximately $8.6 million. Shell retains responsibility to the EPA for compliance with the terms of the consent decree.

Our marine terminals are subject to United States Coast Guard regulations and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of these assets.

Environmental

General

The operation of our pipeline systems, terminals and associated facilities is subject to strict and complex laws and regulations relating to the protection of the environment. This body of laws and regulations regulates many aspects of our business including the generation and disposal of waste, discharge of process and storm water, air emissions, remediation requirements as well as facility design requirements to protect against releases into the environment. As an owner or lessee and operator of these facilities, we comply with federal, state and local laws and regulations.

Estimates provided below for remediation costs assume that we will be able to use traditionally acceptable remedial and monitoring methods, as well as associated engineering or institutional controls to comply with applicable regulatory requirements. These estimates include the cost of performing environmental assessments,

15

Index to Financial Statements

remediation and monitoring of the impacted environment such as soils, groundwater and surface water conditions. Remediation costs are estimates only and we cannot predetermine whether the actual total remediation costs will exceed estimated amounts. We are not aware of any potential claims by third parties that could be materially adverse to our operations, financial position or cash flow.

We may experience future releases of regulated materials into the environment or discover historical releases that were previously unidentified or not assessed. While an asset integrity and maintenance program designed to prevent and promptly detect and address releases is an integral part of our operations, damages and liabilities arising out of any future environmental release from our assets have the potential to have a material adverse effect on our financial position, cash flow and results of operations.

Former Williams Indemnities—Prior to May 27, 2004, we had three separate indemnification agreements with Williams and its affiliates. These three agreements are described below:

IPO Indemnity Agreement—Williams and certain of its affiliates indemnified us for covered environmental losses up to $15.0 million related to assets operated by us at the time of our initial public offering date (February 9, 2001) that became known by August 9, 2004 and that exceed amounts recovered or recoverable under our contractual indemnities from third persons or under any applicable insurance policies. We refer to this indemnity as the “IPO Indemnity”. Covered environmental losses included those non-contingent terminal and ammonia system environmental losses, costs, damages and expenses suffered or incurred by us arising from correction of violations or performance of remediation required by environmental laws in effect at February 9, 2001, due to events and conditions associated with the operation of the assets and occurring before February 9, 2001. In addition, Williams and certain of its affiliates indemnified us for right-of-way defects or failures in the ammonia pipeline easements for 15 years after February 9, 2001. Williams and certain of its affiliates also indemnified us for right-of-way defects or failures associated with the marine facilities at Galena Park and Corpus Christi, Texas and Marrero, Louisiana for 15 years after February 9, 2001.

Magellan Pipeline Indemnity Agreement—In conjunction with the acquisition of Magellan Pipeline Company, L.P. (“Magellan Pipeline”) in April 2002, Williams agreed to indemnify us for any breaches of representations or warranties, environmental liabilities and failures to comply with environmental laws as described below. Williams’ liability under this indemnity was capped at $125.0 million. We refer to this indemnity as the “Magellan Pipeline Indemnity”. In addition to environmental liabilities, this indemnity included matters relating to employees and employee benefits and real property, including asset titles. Also, this indemnity provided that we were indemnified for an unlimited amount of losses and damages related to tax liabilities. The environmental liability indemnity included any losses and damages related to environmental liabilities caused by events that occurred prior to the acquisition. Covered environmental losses included those losses arising from the correction of violations of, or performance of remediation required by, environmental laws in effect at April 11, 2002.

Acquisition Indemnity Agreement—In addition to these two agreements, the purchase and sale agreement entered into in connection with MMH’s acquisition of Williams’ partnership interest in us provided us with two additional indemnities related to environmental liabilities, which we collectively refer to as the “Acquisition Indemnity”.

First, MMH assumed Williams’ obligations to indemnify us for $21.9 million of known environmental liabilities.

Second, Williams agreed to indemnify us for certain environmental liabilities arising prior to June 17, 2003 related to all of our facilities to the extent not already indemnified under the IPO Indemnity and Magellan Pipeline Indemnity agreements described above. This additional indemnification included those liabilities related to the 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

16

Index to Financial Statements

acquisition of it on April 11, 2002 through June 17, 2003. This indemnification covered environmental as well as other liabilities.

Indemnification Settlement—In May 2004, we and our general partner entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release Williams from the environmental indemnifications and certain other indemnifications provided under the IPO Indemnity, Magellan Pipeline Indemnity and Acquisition Indemnity agreements described above. We received $35.0 million from Williams on July 1, 2004 and expect to receive installment payments from Williams of $27.5 million, $20.0 million and $35.0 million on July 1, 2005, 2006 and 2007, respectively.

While the settlement agreement releases Williams from its environmental and certain other indemnifications, certain indemnifications remain in effect. These remaining indemnifications cover:

Known Environmental Liabilities—We have recorded estimated environmental liabilities of $60.8 million at December 31, 2004. These liabilities are provided on an undiscounted basis and have been classified as current or non-current based on estimates regarding the timing of actual payments, which are expected to occur over the next 10 years. Our liabilities include:

Other Environmental Matters—We have notified the Texas Commission on Environmental Quality regarding certain potential air permit non-compliance issues associated with the Galena Park terminal. At this time, we cannot assess the materiality of these notifications. In addition, we have entered into a consent agreement with the Oklahoma Department of Environmental Quality that resolves a prior air emission concern at Magellan Pipeline’s Enid terminal. Under the agreement we have agreed to invest approximately $2.0 million in capital costs and pay a civil penalty of $475,000.

We have evaluated the SPCC regulations for potential deficiencies at our petroleum products terminals and are in the process of implementing corrective actions associated with identified potential deficiencies. We have

17

Index to Financial Statements

estimated the capital liability associated with the corrective actions to be approximately $15.0 million with spending to occur over the next two years.

We are currently assessing the applicability of the EPA’s Prevention of Significant Deterioration regulations to certain of our facilities based on recent EPA guidance. Depending on the outcome of this assessment, we may be required to upgrade air pollution control equipment at certain of these facilities. At this time, we are unable to determine what the outcome of this might be and the impact it will have, if any, on our results of operations, financial position and cash flows.

Environmental Receivables—In June 2003, MMH assumed a $21.9 million obligation from Williams to indemnify us for certain identified environmental liabilities (previously identified under Acquisition Indemnity Agreement above. As of December 31, 2004, we had received $10.4 million from MMH associated with this indemnification, resulting in a remaining associated receivable from MMH of $11.5 million. Environmental receivables from insurance carriers were $7.4 million at December 31, 2004.

Insurance Policies—We have insurance policies which provide coverage for environmental matters associated with liabilities arising from sudden and accidental releases of products applicable to all of our assets. In conjunction with acquisitions, we generally purchase pollution legal liability insurance to cover pre-existing unknown conditions for the acquired assets with deductibles ranging from $0.1 million to $0.3 million.

Environmental Indemnifications From Third Parties—Described below are environmental indemnifications provided by outside entities when we acquired certain of our assets:

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Index to Financial Statements

Outstanding Indemnity Claim—We have filed claims totaling $1.9 million with Hess associated with their indemnifications to us in regards to our 1999 purchase of the Gulf Coast marine terminals. Our claims stated that remediation expenditures beyond our initial $1.9 million claim may be necessary and that our claims would be increased for any expenditures required beyond this amount. We are currently negotiating a settlement of our claims with Hess.

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 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.

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. We have responded to a request from the EPA received in December 2004 seeking additional data regarding one site. We responded that we have found no information regarding the site. The EPA has not responded to the other matter.

Our operations also generate wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“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 can 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, may 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 expenses.

We 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 remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination. Although potential costs associated with the removal or remediation of previously disposed wastes is unknown, we do not expect these potential costs to have a material adverse effect on our financial condition or results of operations.

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Index to Financial Statements

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 American Petroleum Institute Standard No. 653 to regulate above ground tanks subject to their jurisdiction. 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.

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 significant 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, as well as 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. While we have exceeded permit discharges 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. 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.

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Index to Financial Statements

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. 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 in February 2001 and (2) title defects related to the portion of our petroleum products pipeline system acquired from Williams in April 2002 that arise within ten years from the 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.

Employees

To conduct our operations, MMH employs approximately 955 employees, of whom 506 conduct the operations of our petroleum products pipeline system, 209 conduct the operations of our petroleum products terminals and 240 provide general and administrative services.

(d) Financial Information About Geographical Areas

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

(e) Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the Securities and Exchange Commission (“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 (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings.

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Index to Financial Statements

You can also obtain information about us at the offices of the New York Stock Exchange (“NYSE”), 20 Broad Street, New York, New York 10005 or at the NYSE’s Internet site (www.nyse.com). The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The chief executive officer of our general partner submitted an unqualified annual written certification to the NYSE during 2004 as required.

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.

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

During 2001, the EPA, pursuant to Section 308 of the Clean Water Act (the “Act”), preliminarily determined that Williams may have systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received the EPA’s reply, which indicated that the EPA intends to fine us for as much as $22.0 million for violations under Section 311(b) of the Act associated with spills identified in the EPA’s reply that occurred from March 1999 through January 2004. The EPA further indicated that some of those spills may have also violated the SPCC requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We have verbally agreed to a response schedule for the releases that occurred from March 1999 through January 2004 and have submitted a response in accordance to that schedule. We have met with the EPA and the DOJ and anticipate negotiating a final settlement with the EPA and the DOJ by the end of 2005. We have evaluated this issue and have accrued a liability based on our best estimates that is less than $22.0 million.

On March 22, 2004, we received a Corrective Action Order from the Department of Transportation Southwest Region Office of Pipeline Safety (“OPS”) as a result of the OPS’ May 2003 inspection of a former affiliates’ Integrity Management Program applicable to our assets. The Corrective Action Order focused on timing of repairs and temporary pressure reductions upon discovery of anomalies. The OPS preliminarily assessed us with a civil penalty of $105,000. Supplemental information was presented to the OPS in September 2004. We are awaiting the OPS’ response on this matter.

The Oklahoma Department of Environmental Quality (“ODEQ”) has alleged in a Notice of Violation dated June 14, 2002 that a terminal on our petroleum products pipeline system located in Enid, Oklahoma was subject to the Maximum Achievable Control Technology (“MACT”) standards at 40 C.F.R 63.420-429, National Emission Standard for Gasoline Distribution Facilities. During July 2004, we reached a verbal agreement with ODEQ to comply with the MACT requirements and to pay a penalty of $475,000.

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.

None

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Index to Financial Statements

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”. Since our name change to Magellan Midstream Partners, L.P. on September 1, 2003, our common units have been listed on the New York Stock Exchange under the ticker symbol “MMP”. At the close of business on March 1, 2005, we had 184 registered holders and approximately 37,500 beneficial holders of record of our common units. The high and low closing sales price ranges and distributions paid by quarter for 2003 and 2004 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. In accordance with the early conversion criteria described below, 2,839,846 of these units have converted to common units, leaving 2,839,848 subordinated units outstanding as of March 1, 2005. There is no established public trading market for these units. All of the subordinated units are held by MMH, and MMH receives a quarterly distribution on these units only after sufficient funds have been paid to the common units, as also described below. In addition, the subordinated units generally have reduced voting rights equal to one-half vote for each unit owned.

During the subordination period, the holders of our common units are entitled to receive 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 were eligible to convert to common units on a one-for-one basis after December 31, 2003 and one-quarter of the subordinated units were eligible to convert to common units on a one-for-one basis after December 31, 2004 if we met 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. We also met the second early conversion test effective February 2005, with another 1,419,923 subordinated units converted to common units at that time. Following this second early conversion, we have 2,839,848 subordinated units outstanding. Because of these conversions, the common units have less protection with respect to distributions and the subordinated units that converted into common units have 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

23

Index to Financial Statements

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:

In conjunction with our acquisition of petroleum products pipeline assets during October 2004, our general partner agreed to reduce the amount of its incentive distributions by $1.25 million per quarter for distributions associated with fourth-quarter 2004 and all quarters of 2005 and by $0.75 million for all quarters of 2006.

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 $0.9125 per limited partner unit, which, including the impact of the reductions in our general partners’ incentive distributions as discussed above, entitles our general partner to receive approximately 15% of 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.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management” contained herein.

ITEM 6.

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 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

24

Index to Financial Statements

principally included Magellan Pipeline’s interest in and agreement related to 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 Williams and us, operating results from Magellan Pipeline’s petroleum products management operation, other than an annual fee of approximately $4.0 million, were not included in our financial results subsequent to April 2002. In addition, general and administrative expenses related to the petroleum products pipeline system for which we had been reimbursing our general partner, were subject to a cap under our operating agreement (see Reimbursement of G&A Expense under Note 12—Related Party Transactions in the accompanying consolidated financial statements). The ATLAS 2000 software system assets were contributed to us on June 17, 2003 in conjunction with the sale by Williams of its interests in us (see Change in Ownership of General Partner under Note 1—Organization and Basis of Presentation in the accompanying consolidated financial statements), and the depreciation expense associated with those assets has been included in our results since that date. Also, we acquired Williams’ interest in the petroleum products management operation in July 2003 (see Note 6—Acquisitions in the accompanying consolidated financial statements), and the results of this operation have been included in our results subsequent to that date.

In October 2004, we acquired certain assets from Shell for a total purchase price of $553.3 million (see Note 6—Acquisitions in the accompanying consolidated financial statements), which had a significant impact on our operating results, financial position and cash flows during the fourth quarter of 2004.

Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not be indicative of our future financial conditions or results of operations. A discussion of our critical accounting estimates is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this report. In addition, a discussion of our environmental liabilities and indemnifications can be found in Item 1. Business—Environmental, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 19—Commitments and Contingencies in the accompanying consolidated financial statements.

We define EBITDA, a non-generally accepted accounting principles measure presented in the following schedules as net income plus provision for income taxes, debt prepayment premiums, write-off of unamortized debt placement fees, 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 profit, 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.

In addition to EBITDA, the non-GAAP measure of operating margin (in the aggregate and by segment) is presented in the following table. We compute the components of operating margin 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 following tables (see Note 18—Segment Disclosures in the accompanying consolidated financial statements for a reconciliation of segment operating margin to segment operating profit). We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performance of our core operations. This measure forms the basis of our internal financial reporting and is used by our management in deciding how to allocate capital resources between segments. Operating profit, alternatively,

25

Index to Financial Statements

includes expense items such as depreciation and amortization and general and administrative costs, that management does not consider when evaluating the core profitability of an operation.

26

Index to Financial Statements

27

Index to Financial Statements

ITEM 7.

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. 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 three operating segments include:

During April 2002, we acquired Magellan Pipeline Company, L.P. (“Magellan Pipeline”) 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 interests. 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

Indemnification settlement—During May 2004, we entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release them from certain indemnifications. The indemnifications primarily related to environmental items for periods during which Williams was the owner of assets we purchased from them. We received $35.0 million from Williams on July 1, 2004 and expect to receive the remaining balance in annual installments of $27.5 million, $20.0 million and $35.0 million in July of 2005, 2006 and 2007, respectively. See the Environmental section below for further discussion of this matter.

Refinancing—Also in May 2004, we took steps to increase our financial flexibility, which included the issuance of one million common units and $250.0 million of 10-year senior unsecured notes. We used the proceeds from these offerings primarily to refinance $268.0 million of existing secured debt. Further, we amended our remaining secured debt instruments to release the collateral, resulting in our current unsecured capital structure. See the Liquidity section below for further discussion of our new debt structure.

Pipeline acquisition—During June 2004, we announced our intention to acquire more than 2,000 miles of petroleum products pipeline system assets from affiliates of Shell Oil Products US (“Shell”). In anticipation of the transaction closing, we sold 1.8 million common units during August 2004 to assist with the acquisition

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Index to Financial Statements

funding. Net proceeds from this sale were $87.1 million, including our general partner’s $1.8 million contribution to maintain its 2% general partner interest. We closed the acquisition on October 1, 2004, and paid approximately $487.4 million for the pipeline systems. In addition, we paid approximately $30.0 million for inventory related to a third-party supply agreement for which we received $14.0 million of cash collateral. Further, we assumed approximately $29.6 million of existing liabilities and expect to incur $9.6 million of transaction costs. We have incurred approximately $6.3 million of transaction costs through December 31, 2004.

At the closing, we financed the acquisition with: (i) cash on hand of approximately $173.7 million, including net proceeds of approximately $87.1 million from our August 2004 equity offering and net of an escrow payment of approximately $24.6 million to Shell in June 2004; (ii) $300.0 million of borrowings under a short-term acquisition facility; and (iii) $50.0 million of borrowings under our revolving credit facility. During October 2004, we issued and sold an additional 2.6 million common units for net proceeds of approximately $138.3 million, including our general partner’s $2.9 million contribution to maintain its 2% general partner interest, and $250.0 million of unsecured notes for net proceeds of approximately $247.6 million. The proceeds from the equity and debt offerings were used primarily to repay the borrowings under our short-term acquisition facility and revolving credit facility. The underwriters exercised their over-allotment option associated with the October 2004 equity offering and on November 1, 2004, we issued and sold an additional 0.4 million common units. The net proceeds from this sale were approximately $20.8 million, including our general partner’s $0.4 million contribution to maintain its 2% general partner interest, which replaced cash we used to pay for other investments.

We have accounted for the assets we acquired from Shell as an acquisition of assets for the following reasons: (i) the assets we acquired were not operated historically as a separate division or subsidiary. Shell operated these assets as part of its more extensive transportation and terminalling and crude oil and refined products operations. As a result, Shell did not maintain complete and separate financial statements for these assets as an independent business unit; (ii) we intend to make significant changes to the assets in the future, including construction of additional connections between the acquired assets and our existing infrastructure, which may result in significant operating differences and revenues generated; and (iii) differences in our operating approach may result in our obtaining different revenues and results of operations than those historically achieved by Shell. Beginning with fourth-quarter 2004, financial results from the majority of the acquired assets have been reported as part of our petroleum products pipeline system segment.

Recent Developments

On January 26, 2005, the board of directors of our general partner declared a quarterly cash distribution of $0.9125 per unit for the period of October 1 through December 31, 2004. Including this declaration, we paid distributions equal to $3.5225 per unit related to 2004 compared to $3.17 per unit related to 2003, an increase in excess of 11%. In addition, the $0.9125 per unit distribution represented a 74% increase compared to our $0.525 per unit distribution at the time of our initial public offering in February 2001. The quarterly distribution was paid on February 14, 2005 to unitholders of record on February 8, 2005.

In January 2005, Magellan Midstream Holdings (“MMH”), the owner of our general partner interest, sold 2,735,541 of our common units it held in a privately negotiated transaction. Further, in February 2005, MMH sold an additional 225,144 common units. Following these sales and the February 2005 conversion of a portion of our subordinated units, MMH owned 1,194,779 common units, 2,839,848 subordinated units and all of the ownership interests in our general partner, for a combined 14% ownership interest in us.

Overview

In 2004, our net cash from operating activities significantly exceeded our debt service obligations and cash distributions to our unitholders. Our petroleum products pipeline system generates a substantial portion of our cash flows. 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. Operating expenses 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

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Index to Financial Statements

from environmental remediation projects have historically included costs from projects relating both to current and past events. For further discussion of indemnified environmental matters, see “Business—Environmental” under Item 1 of this 10-K report.

We expect to maintain or grow the cash flows of our 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. (See “Risks Related to our Business” for other factors which could impact our operations and cash flows).

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 and we also purchase transmix which we then fractionate and sell. Additionally, we purchased a petroleum products management operation from Williams in July 2003, and we take title to the associated inventories and resulting products from that operation. 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. In October 2004, as part of our acquisition of assets from Shell, we assumed a third-party supply agreement which requires us to buy and sell significant quantities of petroleum products. We routinely take title to these products under this agreement.

Petroleum Products Terminals. Within our terminals network, we operate two types of terminals: marine terminal facilities and inland terminals. The marine terminals 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 aviation fuel and filtering aviation fuel.

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 significantly increased our operations over the past three years through the following acquisitions:

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Index to Financial Statements

Results of Operations

We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure used by management to evaluate the economic performance 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, such as depreciation and amortization and general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of an operation.

Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but 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 tables below.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2004