Item 5. Other Events

Subject to completion dated May 17, 2004

The information in this prospectus supplement and the accompanying prospectus is not complete and may be changed. This prospectus supplement and accompanying prospectus are not an offer to sell these securities and are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Prospectus supplement
(To prospectus dated May 16, 2002)

$250,000,000
         % Senior Notes due 2014

Interest payable             and

Issue price:                           %

The notes will bear interest at the rate of    % per year. Interest on the notes will accrue from                           , 2004. Interest on the notes is payable on                            and                            of each year, beginning                           , 2004. The notes will mature on                           , 2014.

We may redeem some or all of the notes at any time at a redemption price that includes a make-whole premium, as described under the caption "Description of notes—Optional redemption."

Investing in the notes involves risk. See "Risk factors" beginning on page S-16 of this prospectus supplement and on page 2 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The notes will not be listed on any securities exchange. Currently, there is no public market for the notes.

We expect to deliver the notes to investors in registered book-entry form only through the facilities of The Depository Trust Company on or about                           , 2004.

Summary

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. You should read the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read "Risk factors" beginning on page S-16 of this prospectus supplement and page 2 of the accompanying prospectus for more information about important factors that you should consider before buying the notes in this offering. Unless we indicate otherwise, the information we present in this prospectus supplement assumes that we will consummate the common unit offering described below in "—Overview of our refinancing plan." As used in this prospectus supplement and the accompanying prospectus, unless we indicate otherwise, the terms "our," "we," "us" and similar terms refer to Magellan Midstream Partners, L.P., together with our subsidiaries.

Magellan Midstream Partners, L.P.

We are a publicly traded Delaware limited partnership that owns and operates a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products and ammonia. For the year ended December 31, 2003, we had revenues of $485.2 million, EBITDA of $161.6 million and net income of $88.2 million. For the three months ended March 31, 2004, we had revenues of $133.1 million, EBITDA of $44.1 million and net income of $25.8 million. For a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please see "—Summary selected financial and operating data."

We completed the initial public offering of our common units in February 2001 at an initial offering price of $21.50 per common unit. Since our initial public offering, we have increased our quarterly cash distribution for 12 consecutive quarters, resulting in an aggregate increase of approximately 62% from $0.525 per unit, or $2.10 per unit on an annualized basis, to $0.85 per unit, or $3.40 per unit on an annualized basis. Since February 2001, we have completed eight acquisitions for an aggregate purchase price of approximately $1.1 billion, and we intend to continue pursuing an asset acquisition strategy.

Our asset portfolio currently consists of:

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a 6,700-mile petroleum products pipeline system, including 39 petroleum products terminals, serving the mid-continent region of the United States;



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five petroleum products terminal facilities located along the Gulf Coast and near the New York harbor, referred to as "marine terminal facilities";



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29 petroleum products terminals (three of which we partially own) located principally in the southeastern United States, referred to as "inland terminals"; and



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an 1,100-mile ammonia pipeline system, including six ammonia terminals, serving the mid-continent region of the United States.

Petroleum products pipeline system.     Our petroleum products pipeline system is a common carrier pipeline that provides transportation, storage and distribution services for petroleum

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products and liquefied petroleum gases, or LPGs, in 11 states from Oklahoma through the Midwest to North Dakota, Minnesota and Illinois. Our petroleum products pipeline system generates revenues from:

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tariffs charged on volumes shipped;



•

leasing pipeline and storage tank capacity to shippers;



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providing product and other services such as ethanol loading and unloading, additive injection, laboratory testing and data services; and



•

product sales.

For each of the year ended December 31, 2003 and the three months ended March 31, 2004, our petroleum products pipeline system generated approximately 80% of our total revenues.

Our petroleum products pipeline system is the largest common carrier pipeline of refined petroleum products and LPGs in the United States in terms of pipeline miles. The products we transport on our pipeline system are largely transportation fuels, and during 2003 volumes consisted of 58% gasoline, 33% distillates (which includes diesel fuels and heating oil) and 9% LPGs and aviation fuel.

Through direct refinery connections and interconnections with other pipelines, our petroleum products pipeline system can access approximately 41% of the refinery capacity in the United States and is well-positioned to adapt to shifts in product supply or demand. According to statistics provided by the Energy Information Administration, the demand for refined petroleum products in the Midwest market area served by our petroleum products pipeline system, known as Petroleum Administration for Defense District II, or PADD II, is expected to grow at an average rate of approximately 1.7% per year over the next ten 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 continue to be met largely by imports of refined petroleum products via pipelines from Gulf Coast refineries that are located in PADD III. Our petroleum products pipeline system is well connected to Gulf Coast refineries through interconnections with the Explorer, Shell, CITGO and Seaway/ConocoPhillips pipelines. These connections to Gulf Coast refineries, together with our pipeline's extensive network throughout PADD II and connections to PADD II refineries, should allow us to accommodate not only demand growth, but also major supply shifts that may occur.

For the year ended December 31, 2003, our petroleum products pipeline system generated $228.6 million of revenues from transportation tariffs on volumes shipped. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All interstate transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission, or FERC. Part of these tariffs include charges for terminalling and storage of products at our pipeline system's 39 terminals. In addition, we enter into supplemental agreements with shippers that commonly result in volume commitments, term commitments or both by shippers in exchange for reduced tariff rates or capital expansion commitments on our part. During 2003, approximately 53% of the volumes were subject to these supplemental agreements, which have terms ranging from one

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to ten years. 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.

For the year ended December 31, 2003, our petroleum products pipeline system generated $52.8 million of 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. We perform product services such as ethanol unloading and loading, additive injection, custom blending and laboratory testing under a mix of "as needed" monthly and long-term agreements. In addition, we began operating the Rio Grande pipeline system in 2003 and on January 1, 2004 began serving as a subcontractor to an affiliate of The Williams Companies, Inc., or Williams, for the interim operations of Longhorn Partners Pipeline, L.P. until its anticipated start-up in the second quarter of 2004.

For the year ended December 31, 2003, we generated $112.3 million of product sales revenues, substantially all of which was attributable to our petroleum products pipeline system, resulting in $12.4 million of operating margin. For a reconciliation of operating margin to operating profit and a discussion of operating margin as a performance measure, please see "—Summary selected financial and operating data" beginning on page S-12. We generate our product sales revenues from the sale of products that we produce from fractionating transmix, from overages on our pipeline system and from our petroleum products management operation. These activities involve the purchase of raw materials, such as butane, natural gasoline, and pipeline transmix, and as a result we hold title to the products that are sold. However, we limit our commodity price risk exposure related to these activities by utilizing hedging strategies, including entering into forward sales transactions.

Petroleum products terminals.     We own and operate five marine terminal facilities, including four marine terminal facilities located along the Gulf Coast and one marine terminal facility located in Connecticut near the New York harbor. For each of the year ended December 31, 2003 and the three months ended March 31, 2004, our marine terminal facilities and inland terminals generated approximately 17% of our total revenues.

The marine terminal facilities have an aggregate storage capacity of approximately 16.6 million barrels. Our marine terminal facilities primarily receive petroleum products by ship and barge, short-haul pipeline connections from neighboring refineries and common carrier pipelines. We distribute petroleum products from our marine terminal facilities by all of those means as well as by truck and railcar. Once the product has reached the marine terminal facilities, we store the product for a period of time ranging from a few days to several months. Products that we store include petroleum products, blendstocks, heavy oils and feedstocks.

We have long-standing relationships with oil refiners, suppliers and traders at our marine terminal facilities, and most of our customers have consistently renewed their short-term contracts. For the year ended December 31, 2003, approximately 93% of our marine terminal capacity was utilized and approximately 59% of our usable storage capacity was under long-term contracts with remaining terms in excess of one year or that renew on an annual basis.

Our marine terminal facilities generate revenues primarily through providing long-term or spot demand storage services and inventory management for a variety of customers. We charge competitive rates for the services at our marine terminal facilities that are not subject to

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regulation. In most cases, we do not take title to the products that are stored in or distributed from our facilities. Refiners and chemical companies will typically use our marine terminal facilities because their facilities are inadequate, either because of size constraints or the specialized handling requirements of the stored product. We also provide storage services and inventory management to various industrial end-users, marketers and traders that require access to large storage capacity.

Our inland terminals are part of a distribution network of 29 refined petroleum products terminals located throughout the southeastern United States used by retail suppliers, wholesalers and marketers to receive gasoline and other petroleum products from large, interstate pipelines and to transfer these products to trucks, railcars or barges for delivery to their final destination. Our inland terminal facilities typically consist of multiple storage tanks that are connected to a third-party pipeline system and have a combined storage capacity of 5.4 million barrels. 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 the storage tanks to a truck or railcar loading rack.

The majority of our inland terminals connect to the Colonial, Explorer, Plantation or TEPPCO pipelines and some terminals have multiple pipeline connections. In addition, our Dallas terminal connects to Dallas Love Field airport. For the year ended December 31, 2003, gasoline represented approximately 56% of the product volume distributed through our inland terminals, with the remaining 44% consisting of distillates, including diesel fuel, kerosene and heating oil.

We generate revenues by charging our customers a fee based on the amount of product that we deliver through the inland terminals. In addition to throughput fees, we generate revenues by charging our customers a fee for injecting additives into gasoline, diesel and jet fuel, and for filtering jet fuel.

Ammonia pipeline system.     We own an 1,100-mile ammonia pipeline system with a maximum annual delivery capacity of approximately 900,000 tons that transports and distributes ammonia from production facilities in Texas and Oklahoma to terminals in the Midwest for ultimate distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska, Oklahoma and South Dakota. For each of the year ended December 31, 2003 and the three months ended March 31, 2004, our ammonia pipeline system generated approximately 3% of our total revenues.

The ammonia pipeline system originates at production facilities in Borger, Texas, Verdigris, Oklahoma and Enid, Oklahoma and terminates in Mankato, Minnesota. The ammonia we transport is primarily used as a nitrogen fertilizer. It is also the primary feedstock for the production of upgraded nitrogen fertilizers and chemicals. We transport ammonia to 13 delivery points along the ammonia pipeline system, including six facilities that we own.

We generate revenues on our ammonia pipeline system from transportation tariffs for the use of the pipeline capacity and throughput fees at our six ammonia terminals. We do not produce or trade ammonia, and we do not take title to the ammonia we transport. For the year ended December 31, 2003, we generated approximately 93% of the revenues on our ammonia pipeline system through transportation tariffs. In addition to transportation tariffs, we also earn revenues by charging our customers for services at the six terminals we own, including

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unloading ammonia from our customers' trucks to inject it into the pipeline for shipment and removing ammonia from the pipeline to load it into our customers' trucks.

Business strategies

Our primary business strategies are to:

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grow through strategic acquisitions and expansion projects that increase per unit cash flow;



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generate stable cash flows to make quarterly cash distributions; and



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conduct safe and efficient operations.

Competitive strengths

We believe we are well-positioned to execute our business strategies successfully because of the following competitive strengths:

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our assets are strategically located in areas with high demand for our services;



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we have little direct commodity price exposure;



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we have long-term relationships with many of our customers that utilize our pipeline and terminal assets;



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we have a strong financial position with additional borrowing capacity and cash reserves available for making acquisitions and completing expansion projects; and



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our senior management has extensive industry experience.

Overview of our refinancing plan

This offering is one component of a refinancing plan that we are undertaking in an effort to improve our credit profile and increase our financial flexibility by removing all of the secured debt from our capital structure. We will fund this refinancing plan through:

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the issuance of $250.0 million of senior notes; and



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our proposed offering of 1.0 million common units with expected net proceeds of approximately $48.7 million (based upon the last reported sales price of our common units on the New York Stock Exchange on May 14, 2004 of $50.03 per common unit), including our general partner's related capital contribution.

The combined net proceeds to us from our senior notes and proposed common unit offerings are expected to be approximately $296.2 million (after deducting underwriting discounts and estimated offering expenses), and we will use them principally to:

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repay $178.0 million of Series A notes of our Magellan Pipeline Company, LLC subsidiary, plus the related prepayment premium; and



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repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility.

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Concurrently with the repayment of the Series A notes and the term loan, we will:

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replace our existing $85.0 million secured revolving credit facility with a new five year, $125.0 million unsecured revolving credit facility; and



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amend the terms of the Series B notes of Magellan Pipeline Company to release the collateral securing those notes.

Our senior notes offering is not conditioned upon the consummation of our proposed common unit offering. If we do not consummate our proposed common unit offering, we may elect to increase the principal amount of our senior notes offering or borrow funds under our new revolving credit facility in order to complete our refinancing plan. For more information about our refinancing plan, please read "Use of proceeds," "Capitalization" and "Our refinancing plan" on pages S-20, S-21 and S-22, respectively.

Although not part of our refinancing plan, Magellan Midstream Holdings, L.P. proposes to sell 2.0 million common units together with our proposed offering of 1.0 million common units. We will not receive any proceeds from Magellan Midstream Holdings' sale of common units.

Recent developments

Distribution increase.     On April 22, 2004, the board of directors of our general partner declared a quarterly cash distribution of $0.85 per common and subordinated unit for the period of January 1 through March 31, 2004. This first quarter distribution represents a 13% increase over the first quarter of 2003 distribution of $0.75 per unit and an approximate 62% increase since our initial public offering in February 2001. We paid this cash distribution on May 14, 2004 to unitholders of record at the close of business on May 3, 2004.

Acquisition of 50% interest in Osage pipeline.     On March 2, 2004, we acquired a 50% ownership interest in Osage Pipe Line Company, LLC for $25.0 million from National Cooperative Refinery Association, or NCRA. Osage Pipe Line Company, which owns the Osage pipeline, is in the process of obtaining record title to the Osage pipeline assets. The 135-mile Osage pipeline is regulated by FERC and 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 Pipe Line Company continues to be owned by NCRA. We operate the Osage pipeline.

Conversion of subordinated units.     On February 7, 2004, pursuant to our partnership agreement, 1,419,923 of the 5,679,694 subordinated units held by Magellan Midstream Holdings, L.P. converted into an equal number of common units.

Acquisition of petroleum terminals.     On January 29, 2004, we acquired ownership interests in 14 inland terminals located in the southeastern United States for $24.8 million and the assumption of $3.8 million of environmental liabilities. We previously owned an approximate 79% interest in eight of these terminals and acquired the remaining 21% ownership interest in these eight terminals from Murphy Oil USA, Inc. In addition, we acquired sole ownership of six terminals that were previously jointly owned by Murphy Oil USA, Inc. and Colonial Pipeline Company.

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Partnership structure and management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. Upon the consummation of the common unit offering described above:

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There will be 20,775,000 publicly held common units outstanding, representing a 71.7% limited partner interest in us;



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Magellan Midstream Holdings will own 3,355,541 common units and 4,259,771 subordinated units, representing an aggregate 26.3% limited partner interest in us; and



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Magellan GP, LLC, our general partner, will continue to own a 2.0% general partner interest in us and all of the incentive distribution rights.

In June 2003, Williams sold its membership interest in our general partner and the common and subordinated units it owned to a new entity owned by affiliates of Madison Dearborn Partners, LLC and Carlyle/Riverstone Global Energy and Power Fund II, L.P. In September 2003, we changed our name to Magellan Midstream Partners, L.P. from Williams Energy Partners L.P.

Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for direct and indirect expenses incurred on our behalf.

The chart on the following page depicts our organizational and ownership structure after giving effect to our refinancing plan and the proposed offering of 2.0 million common units by Magellan Midstream Holdings. The percentages reflected in the organizational chart represent the approximate ownership interests in us and our operating subsidiaries.

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Summary selected financial and operating data

We have derived the summary selected historical financial data as of and for the years ended December 31, 2001, 2002 and 2003 from our audited consolidated financial statements and related notes. We have derived the summary selected historical financial data as of and for the three months ended March 31, 2003 and 2004 from our unaudited financial statements, which, in the opinion of our management, include all adjustments necessary for a fair presentation of the data. This financial data is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto, which are incorporated by reference and have been filed with the Securities and Exchange Commission, or SEC. You should read these notes for additional information regarding the acquisition of our general partner and certain of our common, Class B common and subordinated units in June 2003. 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" beginning on page S-24 of this prospectus supplement.

The non-generally accepted accounting principle financial measures of EBITDA and operating margin are presented in the summary selected historical financial data. We have presented these financial measures because we believe that investors benefit from having access to the same financial measures utilized by management.

EBITDA is defined as net income plus provision for income taxes, debt placement fees amortization, interest expense (net of interest income) and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with generally accepted accounting principles, or GAAP. EBITDA is not intended to represent cash flow. Because EBITDA excludes some but not all items that affect net income and these measures 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. We believe investors can use EBITDA as a simplified means of measuring cash generated by operations before maintenance capital and fluctuations in working capital. The reconciliation of EBITDA to net income, which is its nearest comparable GAAP measure, is included under the heading "Other data" presented on page S-14.

The components of operating margin are computed by using amounts that are determined in accordance with GAAP. The reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included under the heading "Income statement data" presented on the following page. Operating profit includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and amortization and general and administrative expenses. Our management believes that operating margin is an important performance measure of the economic success of our core operations and individual asset locations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments.

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Footnotes continue on following page.

(a)

Represents a partial quarter of equity earnings related to our 50% ownership interest in Osage Pipe Line Company.

(b)

Prior to our initial public offering on February 9, 2001, our petroleum products terminals and ammonia pipeline system operations were subject to income taxes. Prior to our acquisition of Magellan Pipeline Company, which primarily comprises our "petroleum products pipeline system," on April 11, 2002, Magellan Pipeline Company was also subject to income taxes. Because we are a partnership, the petroleum products terminals and ammonia pipeline system were no longer subject to income taxes after our initial public offering, and Magellan Pipeline Company was no longer subject to income taxes following our acquisition of it.

(c)

At the time of our initial public offering, the affiliate note payable associated with the petroleum products terminals operations was contributed to us as a capital contribution by an affiliate of Williams. At the closing of our acquisition of Magellan Pipeline Company, its affiliate note payable was contributed to us as a capital contribution by an affiliate of Williams.

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(d)

Represents cash distributions declared associated with each respective calendar year. Cash distributions were declared and paid within 45 days following the close of each quarter. Cash distributions declared for 2001 include a prorated distribution for the first quarter, which included the period from February 10, 2001 through March 31, 2001.

(e)

Includes $5.9 million and $1.1 million of reimbursable general and administrative expenses and $10.8 million and $0.6 million of transition costs for the year ended December 31, 2003 and the three months ended March 31, 2004, respectively.

(f)

For the year ended December 31, 2001, represents a full year of activity for the New Haven facility (9.3 million barrels) and two months of activity at the Gibson facility (2.2 million barrels), which was acquired in October 2001.

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Risk factors

An investment in our notes involves various material risks. You should carefully read the risk factors set forth below, the risk factors included under the caption "Risk factors" beginning on page 2 of the accompanying prospectus, and those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, which is incorporated by reference.

Restrictions related to the debt securities of Magellan Pipeline Company, LLC may limit our financial flexibility.

Magellan Pipeline Company is subject to restrictions with respect to its debt that may limit our flexibility in structuring or refinancing existing or future debt. These restrictions include the following:

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before October 7, 2007, we may repay Magellan Pipeline Company's senior notes only by paying the related prepayment premium; and



•

in the note purchase agreement relating to the Magellan Pipeline Company's senior notes, we agreed to maintain a leverage ratio that limits our debt to EBITDA ratio, as defined in the note purchase agreement, to 4.5 to 1.0, thereby limiting our ability to incur additional debt.

Your ability to transfer the notes at a time or price you desire may be limited by the absence of an active trading market, which may not develop.

The notes are a new issue of securities for which there is no established public market. Although we have registered the notes under the Securities Act of 1933, we do not intend to apply for listing of the notes on any securities exchange or for quotation of the notes in any automated dealer quotation system. In addition, although the underwriters have informed us that they intend to make a market in the notes, as permitted by applicable laws and regulations, they are not obliged to make a market in the notes, and they may discontinue their market-making activities at any time without notice. An active market for the notes may not develop or, if developed, may not continue. In the absence of an active trading market, you may not be able to transfer the notes within the time or at the price you desire.

The notes will be senior unsecured obligations. As such, the notes will be effectively junior to any secured debt we may have, to the existing and future debt and other liabilities of our subsidiaries that do not guarantee the notes and to the existing and future secured debt of any subsidiaries that guarantee the notes.

The notes will be our senior unsecured debt and will rank equally in right of payment with all of our other existing and future unsubordinated debt. The notes will be effectively junior to all our future secured debt, to the existing and future debt of our subsidiaries that do not guarantee the notes and to the secured debt of any subsidiaries that guarantee the notes. As of March 31, 2004, our subsidiaries had $480.0 million of debt outstanding and $22.8 million of outstanding trade payables, of which $178.0 will be repaid from the proceeds of this offering. Initially, there will be no subsidiary guarantors, and there may be none in the future. Since Magellan Pipeline Company will not guarantee the notes offered by us in this prospectus supplement, the notes will be effectively subordinated to all debt of Magellan Pipeline Company. In addition, the terms of Magellan Pipeline Company's Series B senior notes due October 2007 would not permit it to guarantee the notes in the future until it has repaid those senior notes.

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If we are involved in any dissolution, liquidation or reorganization, our secured debt holders would be paid before you receive any amounts due under the notes to the extent of the value of the assets securing their debt and creditors of our subsidiaries may also be paid before you receive any amounts due under the notes. In that event, you may not be able to recover any principal or interest you are due under the notes.

A guarantee could be voided if the guarantor fraudulently transferred the guarantee at the time it incurred the indebtedness, which could result in the noteholders being able to rely only on us to satisfy claims.

Initially, there will be no subsidiary guarantors. In the future, however, if our subsidiaries become guarantors or co-obligors of our funded debt, then these subsidiaries will guarantee our payment obligations under the notes. Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under a guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:

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intended to hinder, delay or defraud any present or future creditor or received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee;



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was insolvent or rendered insolvent by reason of such incurrence;



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was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or



•

intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

In addition, any payment by that guarantor under a guarantee could be voided and required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor.

We do not have the same flexibility as other types of organizations to accumulate cash which may limit cash available to service the notes or to repay them at maturity.

Our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner, subject to reasonable reserves as described below. As a result, we do not have the same flexibility as corporations or other entities that do not pay dividends or have complete flexibility regarding the amounts they will distribute to their equity holders. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. The timing and amount of our distributions could significantly reduce the cash available to pay the principal, premium (if any) and interest on the notes. The board of directors of our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries as it determines are necessary or appropriate.

Although our payment obligations to our unitholders are subordinate to our payment obligations to you, the value of our units will decrease in correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.

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Our general partner and its affiliates may have conflicts with our partnership.

The directors and officers of our general partner and its affiliates have duties to manage the general partner in a manner that is beneficial to its members. At the same time, the general partner has duties to manage us in a manner that is beneficial to us. Therefore, the general partner's duties to us may conflict with the duties of its officers and directors to its members.

Such conflicts may include, among others, the following:

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decisions of our general partner regarding the amount and timing of cash expenditures, borrowings and issuances of additional limited partnership units or other securities can affect the amount of incentive distribution payments we make to our general partner;



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under our partnership agreement, we reimburse the general partner for the costs of managing and operating us; and



•

under our partnership agreement, it is not a breach of our general partner's fiduciary duties for affiliates of our general partner to engage in activities that compete with us. For example, an affiliate of our general partner also owns the general partner of another publicly traded limited partnership that engages in businesses similar to ours and may compete with us in the future to acquire assets that we may also wish to acquire.

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Use of proceeds

We expect the net proceeds of this offering to be approximately $247.5 million, after deducting underwriting discounts and the estimated offering expenses. We expect to receive net proceeds of approximately $48.7 million from our proposed 1.0 million common unit offering (based upon the last reported sales price of our common units on the New York Stock Exchange on May 14, 2004 of $50.03 per common unit) and our general partner's related capital contribution, after deducting underwriting discounts and the estimated offering expenses payable by us.

We intend to use the net proceeds from this offering, together with the net proceeds from our proposed 1.0 million common unit offering and our general partner's related capital contribution, to:

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repay all of the outstanding $178.0 million principal amount of Series A senior notes issued by Magellan Pipeline Company and pay the related prepayment premium of approximately $12.7 million;



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repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility;



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pay $1.9 million to Magellan Pipeline Company's Series B noteholders to release the collateral held by them;



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replenish cash used to fund our recent acquisitions; and



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pay various fees and expenses in connection with our refinancing plan.

As of March 31, 2004, the term loan under our existing credit facility had an interest rate of 3.1% and matures on August 6, 2008. We used borrowings under our term loan to refinance outstanding indebtedness under a former credit facility. As of March 31, 2004, the Series A notes had an interest rate of 5.4% and mature on October 7, 2007.

Our senior notes offering is not conditioned upon the consummation of our proposed common unit offering. If we do not consummate our proposed common unit offering, we may elect to increase the principal amount of our senior notes offering or borrow funds under our new revolving credit facility in order to complete our refinancing plan.

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Capitalization

The following table sets forth our capitalization as of March 31, 2004:

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on a historical basis;



•

as adjusted to give effect to the notes offered by us and the application of the net proceeds therefrom in the manner described under "Use of proceeds"; and



•

as further adjusted to give effect to our proposed 1.0 million common unit offering, our general partners' related capital contribution and the application of the net proceeds therefrom.

We expect the net proceeds from this offering to be approximately $247.5 million, after deducting underwriting discounts and the estimated offering expenses. We expect the net proceeds of our proposed 1.0 million common unit offering and our general partner's related capital contribution to be approximately $48.7 million (based upon the last reported sales price of our common units on the New York Stock Exchange on May 14, 2004 of $50.03 per common unit), after deducting underwriting discounts and the estimated offering expenses payable by us. Please read "Use of proceeds."

(a)

This table assumes that we will use the net proceeds from this offering to repay all of the outstanding $178.0 million principal amount of Series A senior notes issued by Magellan Pipeline Company and repay approximately $41.3 million of the $90.0 million outstanding principal balance under our exisiting term loan. We will repay the remaining outstanding indebtedness under our existing term loan using the net proceeds from our proposed common unit offering and our general partner's related capital contribution. If we do not consummate our proposed common unit offering, we may elect to increase the principal amount of our senior notes offering or borrow funds under our new revolving credit facility in order to complete our refinancing plan.

(b)

Total partners' capital was reduced to reflect the prepayment of the Series A senior notes and certain write-offs associated with prepaid debt fees.

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Our refinancing plan

This offering is one component of a refinancing plan that we are undertaking in an effort to improve our credit profile and increase our financial flexibility by removing all of the secured debt from our capital structure. We will fund this refinancing plan through:

•

the issuance of $250.0 million of senior notes; and



•

our proposed offering of 1.0 million common units with expected net proceeds of approximately $48.7 million, including our general partner's related capital contribution.

The combined net proceeds to us from our senior notes and proposed common unit offerings are expected to be approximately $296.2 million (after deducting underwriting discounts and estimated offering expenses), and we will use them principally to:

•

repay $178.0 million of Series A notes of our Magellan Pipeline Company subsidiary, plus the related prepayment premium; and



•

repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility.

Concurrently with the repayment of the Series A notes and the term loan, we will:

•

replace our existing $85.0 million secured revolving credit facility with a new five year, $125.0 million unsecured revolving credit facility; and



•

amend the terms of the Series B notes of Magellan Pipeline Company to release the collateral securing those notes.

Our senior notes offering is not conditioned upon the consummation of our proposed common unit offering. If we do not consummate our proposed common unit offering, we may elect to increase the principal amount of our senior notes offering or borrow funds under our new revolving credit facility in order to complete our refinancing plan.

Our new revolving credit facility

As part of our refinancing plan, we expect to enter into a new five-year $125.0 million revolving credit facility with a syndicate of banks. Up to $50.0 million of the revolving credit facility will be available for the issuance of letters of credit. Borrowings under the revolving credit facility will be unsecured.

Borrowings under the revolving credit facility will bear interest, at our election, at an annual rate equal to:

•

the highest of (1) the rate of interest publicly announced by JPMorgan Chase Bank as its prime rate in effect at its principal office in New York City; (2) the secondary market rate for three-month certificates of deposit plus 1.0%; and (3) the federal funds effective rate plus 0.5%; or



•

LIBOR, as adjusted for statutory reserve requirements for eurocurrency liabilities, plus a spread ranging from 0.625% to 1.500%, based upon our credit rating.

The revolving credit facility will require that we maintain specified ratios of:

•

consolidated debt to EBITDA of no greater than 4.50 to 1.00; and



•

consolidated EBITDA to interest expense of at least 2.50 to 1.00.

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In addition, the revolving credit facility will contain covenants that limit our ability to, among other things:

•

incur additional indebtedness or modify our other debt instruments;



•

encumber our assets;



•

make debt or equity investments;



•

make loans or advances;



•

engage in certain transactions with affiliates;



•

engage in sale or leaseback transactions;



•

merge, consolidate, liquidate or dissolve;



•

sell or lease all or substantially all of our assets; and



•

change the nature of our business.

Magellan Pipeline Company senior notes

In connection with the long-term financing of our April 2002 acquisition of Magellan Pipeline Company, we and our subsidiary, Magellan Pipeline Company, entered into a note purchase agreement on October 1, 2002. Magellan Pipeline Company issued two series of notes under the note purchase agreement consisting of $178.0 million of Series A notes that bear interest at a floating rate based on the six-month Eurodollar rate plus 4.25% and $302.0 million of Series B notes that bear interest at a weighted average fixed rate of 7.77%.

The note purchase agreement requires that we and Magellan Pipeline Company maintain specified ratios of:

•

consolidated debt to EBITDA of no greater than 4.50 to 1.00; and



•

consolidated EBITDA to interest expense of at least 2.50 to 1.00.

In addition, the note purchase agreement contains additional covenants that limit Magellan Pipeline Company's ability to, among other things:

•

incur additional indebtedness;



•

encumber its assets;



•

make debt or equity investments;



•

make loans or advances;



•

engage in transactions with affiliates;



•

merge, consolidate, liquidate or dissolve;



•

sell or lease a material portion of its assets;



•

engage in sale and leaseback transactions; and



•

change the nature of its business.

In connection with our repaying the $178.0 million in outstanding Series A senior notes from the proceeds of this offering and our proposed 1.0 million common unit offering, we expect to amend the note purchase agreement to release the collateral held by the Series B noteholders and change certain other covenants, including decreasing the debt to EBITDA ratio for Magellan Pipeline Company to 3.50 to 1.00.

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Management's discussion and analysis
of financial condition and results of operations

Management's discussion and analysis of financial condition and results of operations should be read in conjunction with the consolidated financial statements and notes contained in our Annual Report on Form 10-K for the year ended December 31, 2003 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2004, each of which is incorporated by reference into this prospectus supplement. We are a publicly traded limited partnership formed to own and operate a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products.

Overview

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

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

Petroleum products pipeline system.     Our petroleum products pipeline system is a common carrier transportation pipeline and terminals network. The system generates approximately 81% 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 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. In July 2003, we purchased a petroleum products management operation from Williams and we now take title to the associated inventories and resulting products. From April 2002 through June 2003, we did not purchase and take title to the inventories or resulting products associated with this operation but performed services related to this operation for an annual fee of approximately $4 million. We also purchase and fractionate transmix and sell the resulting separated products.

Operating costs and expenses incurred by the petroleum products pipeline system are principally fixed costs related to routine maintenance and system integrity as well as field and support personnel. Other costs, including power, fluctuate with volumes transported and stored on the system. Expenses resulting from environmental remediation projects have historically included costs from projects relating both to current and past events. In connection with our acquisition of this pipeline system, an affiliate of Williams agreed to indemnify us for costs and

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expenses relating to environmental remediation for events that occurred before April 11, 2002 and are discovered within six years from that date.

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

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

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

Results of operations

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

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

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Three months ended March 31, 2003 compared to three months ended March 31, 2004

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Transportation and terminals revenues for the three months ended March 31, 2004 were $88.9 million compared to $87.7 million for the three months ended March 31, 2003, an increase of $1.2 million, or 1%. This increase was the result of:

•

a decrease in petroleum products pipeline system revenues of $0.1 million, or less than 1%. Slightly lower transportation revenue per barrel shipped exceeded slightly higher transportation volumes during the current period. Further, additional revenue associated with our operation of the Longhorn Pipeline beginning in 2004 exceeded revenue declines related to data service fees;



•

a decline in petroleum products terminals revenues of $0.6 million, or 3%, primarily due to the first-quarter 2003 settlement received from a former customer associated with the early termination of its storage contract at our Galena Park facility. Increased throughput at our inland terminals resulting primarily from our acquisition of ownership interests in 14 terminals during January 2004 principally offset a decline in marine terminal revenue; and



•

an increase in ammonia pipeline system revenues of $2.0 million, or 125%, primarily due to significantly increased transportation volumes during the current year. Volumes increased in the current quarter due to slightly lower natural gas prices, higher farm commodity prices and the implementation of a proportional credit program during late 2003.

Operating expenses, environmental expenses and environmental reimbursements combined were $37.8 million for the three months ended March 31, 2004 compared to $34.0 million for the three months ended March 31, 2003, an increase of $3.8 million, or 11%. By business segment, this increase was principally the result of:

•

an increase in petroleum products pipeline system expenses of $4.0 million, or 16%, primarily attributable to higher insurance costs, asset retirements principally resulting from improvements to a leased terminal that are no longer utilized and less favorable product loss allowances; and



•

an increase in petroleum products terminals expenses of $0.6 million, or 8%, primarily due to operating costs associated with our newly acquired ownership interest in 14 inland terminals. Partially offsetting this increase was a reduction in costs at our Marrero marine facility resulting from the 2003 demolition of smaller, inefficient storage tanks at this location.

Revenues from product sales were $44.2 million for the three months ended March 31, 2004, while product purchases were $38.5 million, resulting in a net margin of $5.7 million in 2004. The 2004 net margin represents an increase of $1.5 million compared to a net margin in 2003 of $4.2 million resulting from product sales for the three months ended March 31, 2003 of $32.0 million and product purchases of $27.8 million. The increase in 2004 primarily reflects the margin results from our acquisition of the petroleum products management operation during July 2003. This increase was partially offset by lower product margin for the petroleum products terminals due to the sale of additional product overages in the 2003 period during a high pricing environment. Product sales and margins from our petroleum products management business historically have been realized primarily during the first and fourth quarters of each year. Product sales and margins from this business typically are lower during the second and third quarters of each year.

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Affiliate general and administrative expenses for the three months ended March 31, 2004 were $12.9 million compared to $10.4 million for the three months ended March 31, 2003, an increase of $2.5 million, or 24%. This increase was primarily attributable to the following:

•

$0.6 million of reimbursable transition costs associated with the separation of our general and administrative functions from Williams, which principally included expenses during the current year related to the creation of our technology systems. These cumulative transition costs have exceeded the $5.9 million cash amount for which we are responsible. As a result, the amounts in excess of $5.9 million represent a non-cash charge to us and have been recorded as a capital contribution by our general partner;



•

$1.1 million of general and administrative costs that will be reimbursed by our general partner. Our general partner provides general and administrative services to us for an established amount, which was $10.1 million for first quarter 2004. The owner of our general partner is responsible for general and administrative expenses in excess of this cap up to a certain amount. We record total general and administrative costs, including those costs above the cap amount that are reimbursed by the owner of our general partner, as an expense, and we record this amount in excess of the cap for which we are reimbursed as a capital contribution by our general partner. When our general partner was owned by Williams, we were unable to identify specific costs required to support our operations. As a result, we recorded as expense only the general and administrative costs under the cap, which reflected our actual cash costs. As a result of the change in our organization structure following Magellan Midstream Holdings' acquisition of our general partner's membership interests from Williams in June 2003, we are now able to clearly identify all general and administrative costs required to support ourselves. The actual cash general and administrative costs we incur continue to be limited to the general and administrative cap; and



•

$0.7 million of incremental general and administrative costs associated with an annual escalation factor and costs associated with completed acquisitions. As agreed with our general partner, the amount of general and administrative costs we incur will increase on an annual basis by 7% until we are fully funding our general and administrative cost. In addition, we are responsible for incurring incremental general and administrative costs associated with completed acquisitions.

Net interest expense for the three months ended March 31, 2004 was $8.1 million compared to $8.5 million for the three months ended March 31, 2003. The weighted-average interest rate on our borrowings decreased slightly from 6.3% in the first quarter of 2003 to 6.2% in the first quarter of 2004 with the average debt outstanding unchanged at $570.0 million for both periods.

Net income for the three months ended March 31, 2004 was $25.8 million compared to $29.1 million for the three months ended March 31, 2003, a decrease of $3.3 million, or 11%. Operating margin decreased by $1.0 million, or 2%, primarily due to increased costs on the petroleum products pipeline system, partially offset by increased ammonia pipeline system revenues and improved net margin from product sales. General and administrative costs increased by $2.5 million, primarily related to $1.1 million of reimbursable costs and $0.6 million of reimbursable transition costs. Net interest expense declined by $0.4 million between periods.

S-28

Year ended December 31, 2002 compared to year ended December 31, 2003

S-29

Transportation and terminals revenues for the year ended December 31, 2003 were $372.9 million compared to $363.7 million for the year ended December 31, 2002, an increase of $9.2 million, or 3%. This increase was a result of:

•

an increase in petroleum products pipeline system revenues of $8.9 million, or 3%, primarily attributable to a higher weighted-average tariff and increased volumes during the current period. The higher transportation rates per barrel principally resulted from tariff increases during July 2002 and April 2003. Tariff adjustments generally occur during July of each year, as allowed by FERC. However, the April 2003 increase was allowed by FERC due to a change to the mid-year FERC-defined tariff calculation. The incremental volume resulted from the short-term refinery production decreases in the mid-continent region of the U.S. These production decreases resulted in substitute volumes from alternative sources moving through our pipeline system. Further, increased revenues from higher data service fees as well as greater capacity lease utilization and other ancillary revenues benefited the current year;



•

an increase in petroleum products terminals revenues of $0.8 million, or 1%, primarily due to increased throughput at our inland terminals as volumes of a former affiliate were more than replaced with higher volumes from third-party customers. Utilization at the Gulf Coast marine facilities was lower between the two periods due to the termination of a former affiliate's storage agreement at our Galena Park, Texas facility during the first quarter of 2003. Increased revenues from the $3.0 million settlement we received were more than offset by the resulting reduced storage utilization; and



•

a decrease in ammonia pipeline system revenues of $0.5 million, or 4%, primarily due to significantly reduced transportation volumes during the first quarter of 2003 resulting from extremely high prices for natural gas, the primary component in the production of ammonia. Partially offsetting this volume decline was a higher weighted-average tariff in 2003.

Operating expenses, environmental expenses and environmental reimbursements combined were $166.9 million for the year ended December 31, 2003 compared to $155.1 million for the year ended December 31, 2002, an increase of $11.8 million, or 8%. Of this increase, $3.4 million was associated with the affiliate paid-time off benefits liability associated with operations employees and was recorded in conjunction with the change in ownership of our general partner. By business segment, this increase was the result of:

•

an increase in petroleum products pipeline system expenses of $13.8 million, or 12%, in part due to a $2.6 million affiliate paid-time off benefits accrual. Operating expenses further increased due to the retirement of assets and increased costs for tank maintenance and pipeline testing associated with the ongoing implementation of our system integrity program. Increased power costs resulting from higher transportation volumes and power rates as well as higher ad valorem taxes also resulted in greater costs during 2003;



•

a decrease in petroleum products terminals expenses of $0.8 million, or 2%, primarily due to reduced maintenance expenses resulting from efficiency projects that lowered contract labor and repair costs. Timing of tank inspection and cleaning further resulted in reduced maintenance expenses during 2003. These positive variances were partially

S-30

offset by a charge associated with the retirement of an asset, a $0.8 million affiliate paid-time off benefits accrual and increased ad valorem taxes; and

•

a decrease in ammonia pipeline system expenses of $0.4 million, or 8%, primarily due to the purchase in 2002 of right-of-way easements that have historically been leased.

Revenues from product sales were $112.3 million for the year ended December 31, 2003, while product purchases were $99.9 million, resulting in a net margin of $12.4 million in 2003. The 2003 net margin represents an increase of $5.8 million compared to a net margin in 2002 of $6.6 million resulting from product sales for the year ended December 31, 2002 of $70.6 million and product purchases of $64.0 million. The increase in 2003 primarily reflects the margin results from our acquisition of the petroleum products management operation during July 2003. From April 2002 through June 2003, we provided services related to this operation for an affiliate of Williams for an annual fee rather than generating a commodity margin.

Depreciation and amortization expense for the year ended December 31, 2003 was $36.1 million, representing a $1.0 million increase from 2002 at $35.1 million due to the additional depreciation associated with acquisitions and capital improvements.

General and administrative expenses for the year ended December 31, 2003 were $56.9 million compared to $43.2 million for the year ended December 31, 2002, an increase of $13.7 million, or 32%.

•

$7.4 million of this increase was associated with one-time costs resulting from the change in ownership of our general partner during 2003 as follows:



•

$3.7 million was associated with the separation of our general and administrative functions from Williams, which primarily included the creation of our information technology systems and benefits programs;



•

$2.1 million was related to recording an affiliate paid-time off benefits liability associated with general and administrative employees; and



•

$1.6 million was associated with the early vesting of units granted under our 2001 and 2002 equity-based incentive compensation plan resulting from the change in control of our general partner.



•

$5.9 million was associated with general and administrative costs in excess of the general and administrative cap that will be reimbursed by our general partner. As a result of the change in our organizational structure we are now able to clearly identify all general and administrative costs required to support ourselves and total general and administrative costs, including those costs above the cap amount that will be reimbursed by our general partner, are recorded as our expense. Under the previous structure, we were unable to identify specific costs required to support our operations; consequently, we recorded as expense only the general and administrative costs under the cap, which reflected our actual cash cost. The actual cash general and administrative costs we incur will continue to be limited to the general and administrative cap and the amount of costs above the cap will be recorded as a capital contribution by our general partner.

S-31

Net interest expense for the year ended December 31, 2003 was $34.5 million compared to $21.8 million for the year ended December 31, 2002. The increase in interest expense was primarily related to the replacement during the fourth quarter of 2002 of short-term debt financing associated with the acquisition of our petroleum products pipeline system with long-term debt at higher interest rates. The weighted-average interest rate on our borrowings increased from 4.6% in 2002 to 6.3% in 2003 with the average debt outstanding increasing from $522.0 million in 2002 to $570.0 million in 2003.

Debt placement fee amortization declined from $9.9 million in 2002 to $2.8 million in 2003. During the 2002 period, the short-term debt associated with our acquisition of the petroleum products pipeline system was outstanding with related debt costs amortized over the seven-month period that the debt was outstanding. Our subsequent long-term debt financing costs are amortized over the five-year life of the notes.

We do not pay income taxes because we are a partnership. However, earnings from the petroleum products pipeline system were subject to income taxes prior to our acquisition of it in April 2002. Taxes on these earnings were at income tax rates of 37% for the year ended December 31, 2002, based on the effective income tax rate for Williams as a result of Williams' tax-sharing arrangement with its subsidiaries. The effective income tax rate exceeds the U.S. federal statutory income tax rate primarily due to state income taxes.

Net income for the year ended December 31, 2003 was $88.2 million compared to $99.2 million for the year ended December 31, 2002, a decrease of $11.0 million, or 11%, primarily due to $10.8 million of one-time costs associated with the 2003 change in ownership of our general partner, of which $3.4 million was operating expense and $7.4 was general and administrative expense. Our net income further declined due to an additional $5.9 million of reimbursable general and administrative costs. Our operating margin increased by $3.0 million over the prior year despite the $3.4 million of one-time operating expense items, largely as a result of increased transportation volumes and rates on our petroleum products pipeline system, increased product margin associated with the purchase of our petroleum products management operation in July 2003 and reduced operating expenses associated with the petroleum products terminals. Depreciation and net interest expense increased by $1.0 million and $12.7 million, respectively, while debt placement fee amortization expense decreased $7.1 million. Other income declined $2.0 million primarily due to a gain on the sale of assets during 2002. Income taxes decreased $8.3 million due to our partnership structure.

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Year ended December 31, 2001 compared to year ended December 31, 2002

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Transportation and terminals revenues for the year ended December 31, 2002 were $363.7 million compared to $339.4 million for the year ended December 31, 2001, an increase of $24.3 million, or 7%. This increase was the result of:

•

an increase in petroleum products pipeline system revenues of $17.6 million, or 7%. Transportation revenues increased between periods due to higher weighted-average tariffs that more than offset slightly lower shipments. The tariffs were higher due to a mid-year rate increase and our customers' transporting products longer distances. These longer hauls resulted primarily from supply shifts within our pipeline system during the latter part of 2002 caused by temporary reductions of refinery production on our system. Further, increased rates for data services as well as higher ethanol loading and storage volumes resulted in additional revenue;



•

an increase in petroleum products terminals revenues of $8.1 million, or 12%, primarily due to the acquisitions of our Gibson marine terminal facility in October 2001 and two Little Rock inland terminals in June 2001. An improved marketing environment resulted in higher utilization and rates at our Gulf Coast facilities, further increasing revenues during 2002; and



•

a decrease in ammonia pipeline system revenues of $1.4 million, or 10%, primarily due to a throughput deficiency billing in the prior year that resulted from a shipper's inability to meet its minimum annual throughput commitment for the contract year ended June 2001. In addition, revenue also declined due to significantly reduced volumes from one of our shippers following its filing for Chapter 11 bankruptcy during May 2002. Partially offsetting these decreases was a higher weighted-average tariff in 2002.

Operating expenses, environmental expenses and environmental reimbursements combined were $155.1 million for the year ended December 31, 2002, compared to $160.9 million for the year ended December 31, 2001, a decrease of $5.8 million, or 4%. This decrease was the result of:

•

a decrease in petroleum products pipeline system expenses of $8.9 million, or 7%, primarily due to lower environmental and maintenance expenses and reduced power costs. Environmental costs were lower due to the indemnification from an affiliate of Williams for environmental issues resulting from operations prior to our ownership of the pipeline. Maintenance expenses declined due to improved cost controls as a result of the implementation of improved operating practices. Reduced power costs resulted from lower volumes transported coupled with reduced power rates. Partially offsetting these reductions was an increase in pipeline lease expenses, which represent tariffs paid on connecting pipelines to move a customer's product to its ultimate destination;



•

an increase in petroleum products terminals expenses of $2.2 million, or 7%, primarily due to the addition of the Gibson marine facility and the Little Rock inland terminals and increased maintenance expenses resulting from timing of tank cleaning and inspections at the inland terminals; and



•

an increase in ammonia pipeline system expenses of $0.9 million, or 23%, primarily due to the purchase in the current year of right-of-way easements that have historically been leased and higher property taxes.

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Revenues from product sales were $70.6 million for the year ended December 31, 2002, while product purchases were $64.0 million, resulting in a net margin of $6.6 million in 2002. The 2002 net margin represents a decrease of $6.3 million compared to a net margin in 2001 of $12.9 million resulting from product sales for the year ended December 31, 2001 of $108.2 million and product purchases of $95.3 million. The margin decline in 2002 reflects our agreement with an affiliate of Williams to provide blending services for them for an annual fee rather than generating a commodity margin in relation to this activity from April 2002 through December 2002.

Affiliate management fee revenues for the year ended December 31, 2002 were $0.2 million compared to $1.0 million for the year ended December 31, 2001. Historically, the petroleum products pipeline system received a fee to manage an affiliate pipeline.

Depreciation and amortization expense for the year ended December 31, 2002 was $35.1 million, representing a $0.7 million decrease from 2001 at $35.8 million. Additional depreciation associated with acquisitions and capital improvements was more than offset by the elimination of depreciation associated with assets that previously were a part of Magellan Pipeline Company but were excluded from the assets transferred to us when we acquired the petroleum products pipeline system.

General and administrative expenses for the year ended December 31, 2002 were $43.2 million compared to $47.3 million for the year ended December 31, 2001, a decrease of $4.1 million, or 9%. Prior to our acquisition of the petroleum products pipeline system, this operating unit was allocated general and administrative costs from Williams based on a multi-factor formula. Following the acquisition, general and administrative expenses that we paid to Williams for this pipeline system were subject to an expense limitation, which resulted in a lower general and administrative costs to us. Incentive compensation costs associated with our long-term incentive plan were specifically excluded from the expense limitation and were $3.7 million during 2002 and $2.0 million during 2001. The 2002 incentive compensation costs included $2.1 million associated with the early vesting of the restricted units issued to key employees at the time of our initial public offering. The early vesting was triggered as a result of meeting targets for our growth in cash distributions paid to unitholders.

Net interest expense for the year ended December 31, 2002 was $21.8 million compared to $12.1 million for the year ended December 31, 2001. The increase in interest expense was primarily related to the debt financing of the petroleum products pipeline system. Although the weighted-average interest rates decreased from 5.0% in 2001 to 4.6% in 2002, the weighted-average debt outstanding increased from $113.3 million in 2001 to $522.0 million in 2002.

We do not pay income taxes because we are a partnership. However, earnings from the petroleum products pipeline system were subject to income taxes prior to our acquisition of it in April 2002, and our pre-initial public offering earnings in 2001 were also taxable. Taxes on these earnings were at income tax rates of 37% and 39% for the year ended December 31, 2002 and 2001, respectively, based on the effective income tax rate for Williams as a result of Williams' tax-sharing arrangement with its subsidiaries. The effective income tax rate exceeds the U.S. federal statutory income tax rate primarily due to state income taxes.

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Net income for the year ended December 31, 2002 was $99.2 million compared to $67.9 million for the year ended December 31, 2001, an increase of $31.3 million, or 46%. The operating margin increased by $23.0 million during the period, largely as a result of increased revenues and reduced operating expenses including environmental expenses net of reimbursements for the petroleum products pipeline system, earnings from the acquisitions of the Little Rock and Gibson terminal facilities and increased utilization and rates at our Gulf Coast marine facilities. Depreciation expense and general and administrative expenses decreased by $0.7 million and $4.1 million, respectively, while net interest expense increased by $9.7 million. Debt placement fee amortization expense increased $9.7 million primarily due to costs from debt financing associated with the petroleum products pipeline system acquisition. Other income increased $1.7 million primarily due to a gain on the sale of assets during 2002 and an impairment charge recorded during 2001 related to the inactive refinery site at Augusta, Kansas, the assets and liabilities of which were not transferred to us as part of our acquisition of the petroleum products pipeline system. Income taxes decreased $21.2 million due to our partnership structure.

Liquidity and capital resources

Cash flows and capital expenditures

Three months ended March 31, 2004.     During the three months ended March 31, 2004, distributions paid and maintenance capital requirements exceeded net cash provided by operating activities by $12.4 million. Working capital needs, described below, significantly reduced our net cash provided by operating activities in the current quarter. We do not expect this situation to continue for the remainder of 2004. Our current cash distributions exceeded the minimum quarterly distribution of $0.525 per unit by $12.2 million.

Net cash provided by operating activities was $15.6 million for the three months ended March 31, 2004 and $40.2 million for the three months ended March 31, 2003. Lower net income and changes in components of operating assets and liabilities during 2004 resulted in decreased cash from operations. Significant changes in working capital included:

•

a decrease in accrued affiliate payroll and benefits of $8.0 million in 2004 compared to an increase of $0.8 million in 2003. The decrease in 2004 was primarily the result of the payment of larger bonuses related to 2003 in the first quarter of 2004, while smaller bonuses related to 2002 were paid partially in March of 2003 and partially in August of 2003;



•

a decrease in accrued product purchases in 2004 of $3.7 million, compared to an increase of $4.9 million in 2003. The decrease in accrued product purchases in 2004 was primarily the result of seasonal fluctuations related to our petroleum products management operation, which we purchased in July 2003. This decrease was partially offset by a decrease in inventories of $3.3 million in 2004 versus a decrease of only $0.3 million in 2003;



•

an increase in current and noncurrent environmental liabilities in 2004 of $20.1 million, compared to an increase of $0.5 million in 2003. The increase in 2004 was primarily the result of indemnified environmental liabilities for which we recorded offsetting receivables; and

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•

an increase in accounts receivable and other accounts receivable in 2004 of $25.6 million, compared to an increase of $3.0 million in 2003. The majority of the increase in 2004 was related to indemnified environmental liabilities, which largely offset the increase in accounts receivable and other accounts receivable. The remaining increase in 2004 was attributable primarily to receivables from insurers related to environmental remediation performed during 2004, and to higher trade receivables related to our petroleum products management business as a result of favorable market conditions.

Net cash used by investing activities for the three months ended March 31, 2004 and 2003 was $59.7 million and $4.5 million, respectively. During 2004, we acquired ownership in 14 petroleum products terminals and a 50% interest in Osage Pipe Line Company, LLC. We also invested capital to maintain our existing assets. Total maintenance capital spending before reimbursements was $2.7 million and $2.6 million in 2004 and 2003, respectively. Please see "—Capital requirements" below for a further discussion of capital expenditures as well as maintenance capital amounts net of reimbursements.

During the first quarter of 2004, we paid $25.8 million in cash distributions to our unitholders and general partner. The quarterly distribution amount associated with the first quarter of 2004 that will be paid during the second quarter of 2004 was $0.85 per unit, which equates to a total payment of $26.9 million. If we continue to pay cash distributions at this level and the number of outstanding units remains the same, we will pay total cash distributions of $107.6 million to our unitholders on an annual basis. Of this amount, $14.5 million, or 13%, is related to our general partner's 2% ownership interest and incentive distribution rights held by our general partner.

Net cash used by financing activities for the three months ended March 31, 2004 and 2003 was $23.3 million and $17.4 million, respectively, consisting primarily of the payment of cash distributions to our unitholders during both periods.

Years Ended December 31, 2001, 2002 and 2003.     During 2003, net cash provided by operating activities exceeded distributions paid and maintenance capital requirements by $32.6 million. Our cash distributions exceeded the minimum quarterly distribution of $0.525 per unit by $38.2 million.

Net cash provided by operating activities was $144.0 million for the year ended December 31, 2003, $161.0 million for 2002 and $135.3 million for 2001.

•

The $17.0 million decrease from 2002 to 2003 was primarily attributable to:



•

reduced net income of $11.0 million principally resulting from the one-time costs related to the 2003 change in control of our general partner that impacted the current year;



•

an increase in inventory of $12.1 million during 2003 resulting from our July 2003 purchase of a petroleum products management operation. The corresponding increase in accrued product purchases of $8.5 million partially offset the inventory change; and



•

non-cash one-time expenses associated with the change of control of our general partner in 2003 were generally offset by changes in our affiliate assets and liabilities.

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•

The $25.7 million increase in cash from operating activities from 2001 to 2002 was primarily attributable to an increase in net income of $31.3 million and changes in operating assets and liabilities. Changes in operating assets and liabilities reduced net cash from operating activities by $7.2 million and were principally attributable to:



•

an increase in accounts receivable and other accounts receivable of $15.4 million. As part of our acquisition of the petroleum products pipeline system in April 2002, Williams retained $15.0 million of receivables resulting in a significant increase in receivables during 2002 as the receivables retained by Williams were replaced in the ordinary course of business;



•

a reduction in inventory of $18.3 million due to the elimination of inventories associated with the petroleum products management operation retained by Williams at the time of our acquisition of the petroleum products pipeline system; and



•

net affiliate assets and liabilities increased $17.6 million. However, $5.0 million of the increase was offset by related increases in environmental liabilities indemnified by affiliates. The remaining increase of $12.6 million was due primarily to establishing affiliate receivables for environmental liabilities indemnified at the time of our acquisition of the petroleum products pipeline system.

Net cash used by investing activities for the years ended December 31, 2001, 2002 and 2003 was $87.5 million, $727.0 million and $45.9 million, respectively. During 2003, we acquired our petroleum products management operation. During 2002, we acquired our petroleum products pipeline system and the Aux Sable natural gas liquids pipeline. During 2001, we acquired our two Little Rock inland terminals and the Gibson marine facility. We also invested capital to maintain our existing assets. Total maintenance capital spending before reimbursements was $24.4 million, $26.4 million and $20.9 million in 2001, 2002 and 2003, respectively. Please see "—Capital requirements" below for further discussion of capital expenditures as well as maintenance capital amounts net of reimbursements.

Net cash provided (used) by financing activities for the years ended December 31, 2001, 2002 and 2003 was $(34.0) million, $627.3 million and $(61.8) million, respectively. Cash was used during 2003 primarily to pay cash distributions to our unitholders. Cash provided during 2002 principally included the debt and equity funding that were completed in conjunction with our acquisition of the petroleum products pipeline system. Cash was used in 2001 to repay affiliate notes associated with the assets held at the time of our initial public offering assets as well as payments made by our petroleum products pipeline system to decrease its affiliate note balance, partially offset by proceeds from debt borrowings and equity issued in our initial public offering and subsequent debt borrowings for acquisitions.

During 2003, we paid $90.5 million in cash distributions to our unitholders.

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Capital requirements

The transportation, storage and distribution business requires continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. The capital requirements of our businesses consist primarily of:

•

maintenance capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental regulations; and



•

payout capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, referred to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

Williams agreed to reimburse us for maintenance capital expenditures incurred in 2001 and 2002 in excess of $4.9 million per year related to the assets held at the time of our initial public offering. This reimbursement obligation was subject to a maximum combined reimbursement for both years of $15.0 million. During 2001 and 2002, we recorded reimbursements from Williams associated with these assets of $3.9 million and $11.0 million, respectively.

In connection with our acquisition of Magellan Pipeline Company, Williams agreed to reimburse us for maintenance capital expenditures incurred in 2002, 2003 and 2004 in excess of $19.0 million per year related to this pipeline system, subject to a maximum combined reimbursement for all years of $15.0 million. Our maintenance capital expenditures related to the petroleum products pipeline system for 2002 and 2003 were less than $19.0 million per year and we expect that they will be less than $19.0 million in 2004. Therefore, we do not anticipate reimbursement by Williams associated with this agreement.

During first-quarter 2004, we spent maintenance capital of $2.2 million on our operations. Further, we spent an additional $0.5 million of capital associated with our separation from Williams, all of which was reimbursed by our general partner. For 2004, we expect to incur maintenance capital expenditures net of reimbursable projects for all of our businesses of approximately $18.5 million.

During 2003, our maintenance capital spending net of environmental reimbursements was $12.2 million. Reimbursable environmental projects were $3.6 million during 2003. Further, we spent an additional $5.0 million of capital associated with our separation from Williams, or $3.4 million net of reimbursements.

In addition to maintenance capital expenditures, we also incur payout capital expenditures at our existing facilities. During first-quarter 2004, we spent $6.6 million for these organic growth opportunities with an additional $50.4 million spent for acquisitions. Based on projects currently in process, we plan to spend an additional $13.0 million on organic growth capital in 2004, exclusive of future acquisition opportunities. During 2003, we spent $29.0 million of payout capital, including acquisitions. We expect to fund our payout capital expenditures, including any acquisitions, from:

•

cash provided by operations;

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•

borrowings under the revolving credit facility discussed below and other borrowings; and



•

the issuance of additional common units.

If capital markets do not permit us to issue additional debt and equity, our business may be adversely affected and we may not be able to acquire additional assets and businesses.

Liquidity

As of March 31, 2004, we had $570.0 million of total debt outstanding, with $0.9 million of this amount classified as a current liability.

Magellan Pipeline Company senior notes.     In connection with the long-term financing of our April 2002 acquisition of Magellan Pipeline Company, we and our subsidiary, Magellan Pipeline Company, entered into a note purchase agreement on October 1, 2002.

The $480.0 million borrowed under this note purchase agreement included Series A and Series B notes. The maturity date of these notes is October 7, 2007, with scheduled prepayments equal to 5% of the outstanding balance due on both October 7, 2005 and October 7, 2006. The debt is secured by our membership interests in and the assets of Magellan Pipeline Company. Payment of interest and principal is guaranteed by us.

The Series A notes include $178.0 million of borrowings that incur interest based on the six-month Eurodollar rate plus 4.25%. The Series B notes include $302.0 million of borrowings that incur interest at a weighted-average fixed rate of 7.77%.

In the event of a change in control of our general partner, each holder of the notes has 30 days within which it could exercise a right to put its notes to Magellan Pipeline Company unless the new owner of our general partner has: (i) a net worth of at least $500.0 million and (ii) long-term unsecured debt rated as investment grade by both Moody's Investor Service Inc. and Standard & Poor's Rating Service. For these notes, a change in control is defined as the acquisition by any person of 50% or more of the interest in our general partner. The holders of these notes waived their put rights with respect to the change in control of our general partner.

The note purchase agreement requires that we and Magellan Pipeline Company maintain specified ratios of:

•

consolidated debt to EBITDA of no greater than 4.50 to 1.00; and



•

consolidated EBITDA to interest expense of at least 2.50 to 1.00.

In addition, the note purchase agreement contains additional covenants that limit Magellan Pipeline Company's ability to, among other things:

•

incur additional indebtedness;



•

encumber its assets;



•

make debt or equity investments;



•

make loans or advances;

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•

engage in transactions with affiliates;



•

merge, consolidate, liquidate or dissolve;



•

sell or lease a material portion of its assets;



•

engage in sale and leaseback transactions; and



•

change the nature of its business.

In connection with our repaying the $178.0 million in outstanding Series A notes from the proceeds of this offering and the proposed common unit offering, we expect to amend the note purchase agreement to release the collateral held by the Series B noteholders and change certain other covenants, including decreasing the debt to EBITDA ratio for Magellan Pipeline Company to 3.50 to 1.00. Please read "Use of proceeds" on page S-20 of this prospectus supplement and "Our refinancing plan" on page S-22 of this prospectus supplement.

Magellan Midstream Partners term loan and revolving credit facility.     We will repay the $90.0 million of indebtedness outstanding under our existing term loan with a portion of the proceeds from this offering and the proposed common unit offering and our general partner's related capital contribution and will enter into a new five-year $125.0 million revolving credit facility with a syndicate of banks. Please read "Use of proceeds" on page S-20 of this prospectus supplement and "Our refinancing plan" on page S-22 of this prospectus supplement.

Other items.     During February 2004, 25% of our subordinated units, or 1,419,923 units, converted to common units. Our partnership agreement provided for this conversion because quarterly distributions equaled or exceeded our minimum quarterly distribution for three consecutive years. This conversion does not impact the amount of cash distributions paid or the total number of units outstanding. If we continue to pay quarterly distributions equal to or exceeding our minimum quarterly distribution, an additional 1,419,923 subordinated units will convert to common units during February 2005.

In April 2004, we entered into three agreements for treasury lock transactions to hedge our exposure against interest rate increases for a portion of the debt we intend to refinance during the second quarter of 2004. The notional amount of the agreements totals $150.0 million. Initially, the weighted average interest rate was 4.4% with a forward date of May 13, 2004. The treasury locks were subsequently amended, resulting in a weighted average interest rate of approximately 4.5% and a forward date of May 20, 2004. We have accounted for these interest rate hedges as cash flow hedges.

During the first quarter of 2004, we received a notice from the Environmental Protection Agency, or EPA, which indicated the EPA intends to fine us for as much as $22.0 million for violations under Section 311(b) of the Clean Water Act associated with spills identified in the EPA's reply that occurred on our petroleum products pipeline system from March 1999 through January 2004. The EPA further indicated that some of those spills may have also violated the Spill Prevention Control and Countermeasure requirements of the Clean Water Act and that additional penalties may be assessed. In addition to these liabilities, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We are in the process of evaluating the EPA's assertions and we anticipate negotiating a final settlement with the EPA during the next 12 months. While we are currently unable to estimate the final settlement amount, we have accrued a liability associated with this issue,

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based on our best estimates, that is less than $22.0 million. We do not believe that the final settlement will materially impact our results of operations, liquidity or cash flows because we believe the EPA's claim is substantially covered by Williams' environmental indemnifications to us.

Debt-to-total capitalization.     The ratio of debt-to-total capitalization is a measure frequently used by the financial community to assess the reasonableness of a company's debt levels compared to its total capitalization, which is calculated by adding total debt and total partners' capital. Based on the figures shown in our balance sheet, debt-to-total capitalization is 53% at March 31, 2004. Because accounting rules required the acquisition of our petroleum products pipeline system to be recorded at historical book value due to the affiliate nature of the transaction, the $474.5 million difference between the purchase price and book value at the time of the acquisition was recorded as a decrease to our general partner's capital account, thus lowering our overall partners' capital by that amount. If this pipeline system had been acquired from a third party at the identical purchase price, the asset would have been recorded at market value, resulting in a debt-to-total capitalization of 37% as our equity would have been $474.5 million higher. This pro forma debt-to-total capitalization ratio is presented in order to provide our investors with an understanding of what our debt-to-total capitalization position would have been had we made a similar acquisition from a third-party entity. We believe this presentation is important in comparing our debt-to-total capitalization ratio to that of other entities.

Off-balance sheet arrangements

We do not have any off-balance sheet arrangements.

Contractual obligations

The following table summarizes certain contractual obligations as of December 31, 2003 (in millions):

(1)

We have an agreement with Magellan Midstream Holdings, an affiliate entity, for operating and general and administrative costs associated with our activities. The agreement requires us to pay for actual operating costs incurred by Magellan Midstream Holdings on our behalf and for general and administrative costs incurred on our behalf up to the expense limitations as imposed by the new Omnibus Agreement. The agreement, which began on June 17, 2003, has a five-year term but has provisions for termination upon 90-day notice by either party. As a result of the termination provision and the agreement's requirement to pay only Magellan Midstream Holdings' costs as they are incurred, we are unable to determine the actual amount of this commitment.

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Environmental

Our operations are subject to environmental laws and regulations, adopted by various governmental authorities, in the jurisdictions in which these operations are conducted. We have accrued liabilities for estimated site restoration costs to be incurred in the future at our facilities and properties, including liabilities for environmental remediation obligations at various sites where we have been identified as a possible responsible party. Under our accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated.

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

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

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

In addition to these two agreements, the purchase and sale agreement, which we refer to as the June 2003 Purchase and Sale Agreement, entered into in connection with Magellan Midstream Holdings' acquisition of our general partner provides us with two additional indemnities related to environmental liabilities, which we cumulatively refer to as the Acquisition Indemnity in the table below.

First, Magellan Midstream Holdings assumed Williams' obligations to indemnify us for $21.9 million of known environmental liabilities, of which $19.0 million was associated with known liabilities at Magellan Pipeline Company facilities, $2.7 million was associated with known liabilities at our petroleum products terminal facilities and $0.2 million was associated with known liabilities on the ammonia pipeline system.

Second, in the June 2003 Purchase and Sale Agreement, 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 Williams' two preexisting indemnification obligations described above. This additional indemnification includes those liabilities related to our petroleum products terminals and the ammonia pipeline system arising after the initial public offering (February 9, 2001) through June 17, 2003 and those liabilities related to Magellan Pipeline Company arising after our acquisition of it on April 11, 2002 through June 17, 2003. This indemnification covers environmental as well as other liabilities and is capped at $175.0 million.

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A summary of the indemnities we have with Williams, the total claims against those indemnities and the amount of those indemnities remaining is provided below.

We have collected $5.5 million from Magellan Midstream Holdings and $14.7 million from Williams associated with their indemnification obligations described above.

We are in the advanced stages of discussions with Williams about entering into a settlement agreement under which we, our general partner and its owner would agree to release Williams and its affiliates from their environmental indemnity obligations described above in exchange for a negotiated cash payment.

Impact of inflation

Although inflation has slowed in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Critical accounting estimates

Goodwill impairment

In January 2002, we began applying the rules promulgated by Statement of Financial Accounting Standards, or SFAS, No. 142, "Goodwill and Other Intangibles", relative to accounting for goodwill and other intangible assets. Under this standard we no longer amortize goodwill because it is an asset with an indefinite useful life but test it for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The first step of the impairment test is to determine if the fair value of our reporting units exceed their carrying amount. If the fair value of the reporting unit is less than its carrying amount then the goodwill may be impaired. The second step compares the implied fair value of goodwill to its carrying amount. If the carrying amount of goodwill exceeds its implied fair value, an impairment loss is recognized equal to that excess. The implied fair value of goodwill should be calculated in the same manner that goodwill is calculated in a business combination.

Goodwill included in our consolidated balance sheet was $22.1 million at December 31, 2003 and $22.3 million at both December 31, 2002 and 2001. The change in goodwill during 2003

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was the result of a purchase price adjustment created by a contingency payment associated with the acquisition of our Little Rock, Arkansas terminal. All of the goodwill and other intangibles recognized by us are associated with the petroleum products terminals segment and were acquired as part of the Gibson, Louisiana and Little Rock, Arkansas terminals acquisitions. We performed our annual testing of goodwill, as required by SFAS No. 142, as of October 1, 2003.

We believe that the accounting estimate related to goodwill impairment is a "critical accounting estimate" of our petroleum products terminals segment because: (1) significant judgment is exercised during the process of determining the petroleum products terminals segment fair value and (2) because different assumptions could result in material charges to our operating results.

For the 2003 test, fair value of the petroleum products terminals was assessed using two approaches: (1) a discounted future cash flows approach, and (2) an EBITDA multiple approach. The discounted future cash flows model assumed a 9.5% discount rate based on an expected 12% return on equity and a 7% cost of debt and a ⁵⁰ / 50 debt-to-equity ratio. Under the EBITDA multiple approach, we applied a multiple of nine times the adjusted EBITDA of the petroleum products terminals segment to determine fair value. We define EBITDA as income before income taxes plus interest expense (net of interest income), depreciation and amortization expense and debt placement fee amortization. EBITDA multiples are used industry-wide in assessing values for business assets similar to those in our petroleum products terminals segment. The EBITDA of the petroleum products terminals segment was adjusted to exclude a portion of the general and administrative expenses to take into consideration expected synergies.

Under both of the methodologies described above the fair value of the petroleum products terminals segment exceeded the carrying value of the segment. Therefore, we did not recognize an impairment in 2003. In reaching the conclusion above, more confidence was placed on the discounted cash flow model because management believes this approach provides a better assessment of the actual value that a willing buyer and willing seller could agree upon.

The critical factors in the discounted cash flow model are the required rate of return on equity and the cost of debt. A chart showing the implied impairments under various assumed changes in the estimates is provided below (in millions):

Based on the table one can determine that, assuming all other factors remain constant, if debt costs increased from our assumed rate of 7% to 11%, combined with an increase in our assumed required rate of return on equity from 12% to 16%, the assets of the petroleum products terminals segment would be impaired. It is likely that under this scenario the entire $22.1 million of goodwill would be impaired. Because we pay no income taxes, the impairment

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would reduce operating profit and net income by $22.1 million, which represents an 18% decrease in operating profit and a 25% decrease in net income for 2003.

Our management has discussed the development and selection of this critical accounting estimate with the audit committee of our general partner's board of directors and the audit committee has reviewed this disclosure.

Environmental liabilities

We estimate the liabilities associated with environmental expenditures based on site-specific project plans for remediation, taking into account prior remediation experience. Experienced remediation project managers evaluate each known case of environmental liability to determine what phases and associated costs can be reasonably estimated and to ensure compliance with all applicable federal and/or state requirements. We believe the accounting estimate relative to environmental remediation costs to be a "critical accounting estimate" because: (1) estimated expenditures, which will generally be made over the next one to ten years, are subject to cost fluctuations and could change materially, (2) unanticipated third-party liabilities may arise, and (3) changes in federal, state and local environmental regulations could also significantly increase the amount of the liability. The estimate for environmental liabilities is a critical accounting estimate for all three of our operating segments.

A defined process for project reviews is integrated into our System Integrity Plan. Specifically, our remediation project managers meet once a year with accounting, operations, legal and other personnel to evaluate, in detail, the known environmental liabilities associated with each of our operating units. The purpose of the annual project review is to assess all aspects of each project, evaluating what will be required to achieve regulatory compliance, estimating the costs associated with executing the regulatory phases that can be reasonably estimated and estimating the timing for those expenditures. During the site-specific evaluations, all known information is utilized in conjunction with professional judgment and experience to determine the appropriate approach to remediation and to assess liabilities. The general remediation process to achieve regulatory compliance consists of: site investigation/delineation, site remediation, and long-term monitoring. Each of these phases can, and often does, include unknown variables that complicate the task of evaluating the estimated costs to complete.

Each quarter, we reevaluate our environmental estimates taking into account any new incidents that have occurred since the last annual meeting of the remediation project managers, any changes in the site situation and additional findings and/or changes in federal or state regulations. The estimated environmental liability accruals are adjusted as necessary.

At December 31, 2001, our environmental liabilities were $16.9 million. During 2002, we spent $6.4 million for environmental remediation but also made significant accrual adjustments to six environmental projects. These adjustments resulted in an increase in our environmental liabilities of $10.5 million. Accruals for all other projects, including five new projects identified during the year, were $1.3 million, resulting in the December 31, 2002 environmental liability of $22.3 million. The $10.5 million increase in our environmental liabilities during 2002 was the result of additional work and reassessments at the six previously mentioned terminals on our petroleum products pipeline system. Williams indemnified these liabilities; consequently, there was no impact to our operating profit or net income from these accrual increases. During 2003, we spent $9.4 million for environmental remediation. During 2003, we experienced a leak on

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our petroleum products pipeline near Kansas City, Kansas, which resulted in an increase to our environmental liabilities of $4.8 million as of December 31, 2003. As of March 31, 2004, we estimated that the total cost associated with this leak was $8.9 million. The recommendations that came from the annual and quarterly review process during 2003 resulted in our increasing the environmental liabilities associated with over 100 separate remediation sites by approximately $9.1 million. These accrual increases did not have a significant impact on our operating profit or net income because Williams indemnified most of the increases. Our liabilities for environmental costs were $26.8 million at December 31, 2003 and $50.7 million at March 31, 2004. This increase was primarily due to liabilities related to spills that occurred on our petroleum products pipeline system from March 1999 through January 2004 as discussed under "—Liquidity—Other items." As of March 31, 2004, we recorded $29.1 million, $16.4 million and $7.2 million as environmental receivables from Williams, Magellan Midstream Holdings and insurance, respectively. In addition to these liabilities, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief.

Environmental receivables

As described above, we have agreements which indemnify us against certain environmental liabilities, the most significant of which are with Williams and Magellan Midstream Holdings. When a site-specific environmental liability is recognized, a determination is made as to whether or not the liability is indemnified. If so, a receivable for the amount of the indemnified liability is also recognized. We do not require payment from the indemnifying party until actual remediation work is performed on the site. At that time, the indemnifying party is billed for the remediation work and the cash received is used to reduce the environmental receivable. Changes in our environmental receivables since December 31, 2001 are as follows (in millions):

We believe that the accounting estimate related to affiliate receivables is a "critical accounting estimate" because: (1) its carrying amount is subject to many of the same estimates as those used to develop the underlying environmental liabilities (see "Critical accounting estimates—Environmental liabilities" above); and (2) given Williams' unfavorable financial status in recent years, it requires our management's estimations involving Williams' ability to pay and our ability to collect the receivable amount.

If Williams is unable to perform on its existing obligations, we may be unable to collect part or all of this environmental account receivable. In preparing our financial statements for the year ended December 31, 2003, management's assumptions were that we would be able to collect the full amount of this receivable from Williams.

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Any change in our estimate of the amount of the receivable we believe we can ultimately collect from Williams would require us to take a charge against income because we have not recorded any allowance for doubtful accounts associated with this receivable. If none of the receivable were collectable, we would have a charge against income of $7.8 million, which represents 6% of our operating profit and 9% of our net income for 2003. The impact of such a charge would likely not have affected our liquidity because, even with the increased expense, we would still comply with the covenants of our long-term debt agreements as discussed above under "Liquidity and capital resources—Liquidity".

Our management has discussed the development and selection of this critical accounting estimate with the audit committee of our general partner's board of directors and the audit committee has reviewed this disclosure.

New accounting pronouncements

In December 2003, the Financial Accounting Standards Board, or FASB, issued a revision to SFAS No. 132 "Employers' Disclosures about Pensions and Other Postretirement Benefits". This revision requires that companies provide more details about their plan assets, benefit obligations, cash flows, benefit costs and other relevant information. A description of investment policies and strategies and target allocation percentages, or target ranges, for these asset categories also are required in financial statements. Cash flows will include projections of future benefit payments and an estimate of contributions to be made in the next year to fund pension and other postretirement benefit plans. In addition to expanded annual disclosures, the FASB is requiring companies to report the various elements of pension and other postretirement benefit costs on a quarterly basis. The guidance is effective for fiscal years ending after December 15, 2003, and for quarters beginning after December 15, 2003.

In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This statement had no impact on our financial position, results of operations or cash flows upon its initial adoption.

In April 2003, the FASB issued SFAS No. 149 "Amendment of Statement 133 on Derivative Instruments and Hedging Activities". This Statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. In addition all provisions of this Statement must be applied prospectively. This Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as "derivatives") and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The initial application of this Statement did not have a material impact on our financial position, results of operations or cash flows.

In December 2002, the FASB issued SFAS No. 148 "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123". This Statement amends

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FASB Statement No. 123, "Accounting for Stock-Based Compensation", to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. This Statement improves the prominence and clarity of the pro forma disclosures required by Statement 123 by prescribing a specific tabular format and by requiring disclosure in the "Summary of Significant Accounting Policies" or its equivalent. The standard is effective for fiscal periods ending after December 15, 2002. Although we account for stock-based compensation for Williams employees assigned to us under provisions of Accounting Principles Board Opinion No. 25, the structure of the awards is such that we fully recognize compensation expense associated with unit awards. Hence, had we adopted this standard, it would not have had a material impact on our operations or financial position.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force, or EITF, Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. We adopted this standard in January 2003 and it did not have a material impact on our results of operations or financial position.

In the second quarter of 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13 and Technical Corrections". The rescission of SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt," and SFAS No. 64, "Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements," requires that gains or losses from extinguishment of debt only be classified as extraordinary items in the event they meet the criteria in Accounting Principle Board Opinion, or APB, No. 30, "Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions". SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers," established accounting requirements for the effects of transition to the Motor Carriers Act of 1980 and is no longer required now that the transitions have been completed. Finally, the amendments to SFAS No. 13 "Accounting for Leases" are effective for transactions occurring after May 15, 2002. All other provisions of this Statement will be effective for financial statements issued on or after May 15, 2002. We adopted this standard in January 2003, and it did not have a material impact on our results of operations or financial position. However, in subsequent reporting periods, any gains and losses from debt extinguishments will not be accounted for as extraordinary items.

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Description of notes

The notes will constitute a new series of debt securities under a senior indenture to be dated as of                  , 2004, between us and SunTrust Bank, as trustee. We will issue the notes under a supplement to the senior indenture setting forth the specific terms applicable to the notes, and references to the "indenture" in this description mean the senior indenture as so supplemented. You can find the definitions of various terms used in this description under "—Certain definitions" beginning on page S-62. The terms of the notes include those set forth in the indenture and those made a part of the indenture by reference to the Trust Indenture Act of 1939.

This description is intended to be an overview of the material provisions of the notes and the indenture. This summary is not complete and is qualified in its entirety by reference to the indenture. You should carefully read the summary below, the description of the general terms and provisions of our debt securities set forth in the accompanying prospectus under "Description of debt securities" and the provisions of the indenture that may be important to you before investing in the notes. This summary supplements, and to the extent inconsistent therewith replaces, the description of the general terms and provisions of our debt securities set forth in the accompanying prospectus. Capitalized terms defined in the accompanying prospectus or in the indenture have the same meanings when used in this prospectus supplement unless updated herein. In this description, all references to "we," "us" or "our" are to Magellan Midstream Partners, L.P. only, and not its subsidiaries, unless otherwise indicated.

The indenture does not limit the amount of debt securities that we may issue. Debt securities may be issued under the indenture from time to time in separate series, each up to the aggregate amount from time to time authorized for such series.

General

The notes.     We will issue notes initially in an aggregate principal amount of $250.0 million. The notes will be in denominations of $1,000 and integral multiples of $1,000. The notes:

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will be our general unsecured, senior obligations;



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will constitute a new series of debt securities issued under the indenture, and such series will be initially limited to an aggregate principal amount of $250.0 million;



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will mature on                           , 2014;



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will not be entitled to the benefit of any sinking fund; and



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initially will be issued only in book-entry form represented by one or more global notes registered in the name of Cede & Co., as nominee of The Depository Trust Company ("DTC"), or such other name as may be requested by an authorized representative of DTC, and deposited with the trustee as custodian for DTC.

Interest.     Interest on the notes will: