Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED): May 16, 2002

MAGELLAN MIDSTREAM PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)

1-16335
(Commission File Number)

73-1599053
(I.R.S. Employer Identification No.)

P.O. Box 22186
Tulsa, Oklahoma
(Address of Principal Executive Offices)

74121-2186
(Zip Code)

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

EXPLANATORY NOTE

On May 16, 2002 and November 3, 2003, respectively, each of Amendment No. 2 to the Registration Statement on Form S-3 (Registration No. 333-83952) of Magellan Midstream Partners, L.P. (the "Partnership") and the Partnership's Registration Statement on Form S-3 (Registration No. 333-109732) (collectively, the "Registration Statements") were declared effective by the Securities and Exchange Commission. Pursuant to Part II, Item 17 of Form S-3 and Item 512(a) of Regulation S-K, the Partnership is generally required to file a post-effective amendment to reflect in the prospectus any facts or events arising after the effective date of the Registration Statements (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the Registration Statements. Since the Registration Statements are filed on Form S-3, Item 512(a) of Regulation S-K also provides that the Partnership is not required to file a post-effective amendment if the information described in the preceding sentence is set forth in periodic reports filed by the Partnership under Section 13 of the Securities Exchange Act of 1934 that are incorporated by reference in the Registration Statements.

On May 17, 2004, the Partnership commenced simultaneous underwritten public offerings of $250,000,000 of senior notes due 2014 and 1,000,000 common units. In addition, on May 17, 2004, Magellan Midstream Holdings, L.P. commenced an underwritten public offering of 2,000,000 of the Partnership's common units owned by it. The offerings of senior notes and common units by the Partnership are part of a refinancing plan that the Partnership is undertaking in an effort to improve its credit profile and increase its financial flexibility by removing all of the secured debt from its capital structure.

The combined net proceeds to the Partnership from its senior notes and common unit offerings are expected to be approximately $296.2 million (after deducting underwriting discounts and estimated offering expenses). The Partnership will use a portion of the net proceeds to:

•: repay $178.0 million of Series A notes of the Partnership's Magellan Pipeline Company subsidiary, plus the related prepayment premium; and
•: repay the $90.0 million outstanding principal balance of the term loan under the Partnership's existing credit facility.

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

•: replace its 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.

The Partnership's senior notes offering is not conditioned upon the consummation of the Partnership's common unit offering. If the Partnership does not consummate its common unit offering, the Partnership may elect to increase the principal amount of its senior notes offering or borrow funds under its new revolving credit facility in order to complete its refinancing plan. If the Partnership does not consummate its senior notes offering, the Partnership will use the net proceeds from the common unit offering to replenish cash used to fund recent acquisitions or repay a portion of the amount outstanding under the Partnership's term loan.

For purposes of fulfilling the Partnership's obligation under Part II, Item 17 of the Registration Statements, the Partnership is filing this Current Report with the Securities and Exchange Commission to incorporate by reference into the Registration Statements the information included under Item 5 of this Current Report.

The information included under Item 5 of this Current Report reflects a series of excerpts from the Partnership's prospectus supplements that are subject to completion dated May 17, 2004 (collectively, the "Prospectus Supplements"). The excerpts retain the pagination of the respective Prospectus Supplements to allow for accurate cross references to other sections of the Prospectus Supplements. The Prospectus Supplements relate to (1) an underwritten public offering by the Partnership of $250,000,000 of senior notes due 2014, (2) an underwritten public offering by the Partnership of 1,000,000 of its common units and (3) a secondary underwritten public offering (with respect to which the Partnership will receive no proceeds) by Magellan Midstream Holdings, L.P., a selling unitholder, of 2,000,000 of the Partnership's common units.

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.

	Price to public	Underwriting discounts	Proceeds to us before expenses


Per note	%	%	%

Total	$	$	$

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.

Joint Book-Running Managers

JPMorgan

Lehman Brothers

Citigroup
Scotia Capital Markets
SunTrust Robinson Humphrey

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:

•: a 6,700-mile petroleum products pipeline system, including 39 petroleum products terminals, serving the mid-continent region of the United States;
•: five petroleum products terminal facilities located along the Gulf Coast and near the New York harbor, referred to as "marine terminal facilities";
•: 29 petroleum products terminals (three of which we partially own) located principally in the southeastern United States, referred to as "inland terminals"; and
•: 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:

•: tariffs charged on volumes shipped;
•: leasing pipeline and storage tank capacity to shippers;
•: 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:

•: grow through strategic acquisitions and expansion projects that increase per unit cash flow;
•: generate stable cash flows to make quarterly cash distributions; and
•: 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:

•: our assets are strategically located in areas with high demand for our services;
•: we have little direct commodity price exposure;
•: we have long-term relationships with many of our customers that utilize our pipeline and terminal assets;
•: we have a strong financial position with additional borrowing capacity and cash reserves available for making acquisitions and completing expansion projects; and
•: 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:

•: 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 (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:

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

•: 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. 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:

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

The issuer		Magellan Midstream Partners, L.P.
Securities offered by us		$250.0 million principal amount of % Senior Notes due 2014. The notes will be issued in denominations of $1,000 and integral multiples of $1,000.
Interest payment dates		and of each year, beginning , 2004.
Maturity date		, 2014.
Use of proceeds		We will use the net proceeds from this offering, together with the net proceeds from our proposed common unit offering and our general partner's related capital contribution, to:
		• 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;
		• repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility;
		• pay $1.9 million to Magellan Pipeline Company's Series B noteholders to release the collateral held by them;
		• replenish cash used to fund our recent acquisitions; and
		• pay various fees and expenses in connection with our refinancing plan.
Ratings		We have obtained the following ratings on the notes: BBB by Standard & Poor's Ratings Services and Ba1 by Moody's Investors Service, Inc.
		A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold the notes. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if the rating agency decides that the circumstances warrant a revision.

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Ranking		The notes will be our senior unsecured obligations and will rank equally with all of our other existing and future senior indebtedness, including indebtedness under our new revolving credit facility.
		We conduct substantially all of our business through our subsidiaries. The notes will be structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of any of our subsidiaries. As of March 31, 2004, our subsidiaries had approximately $480.0 million of outstanding debt to unaffiliated third parties and $22.8 million of outstanding trade payables. We will use a portion of the proceeds of this offering to repay $178.0 million of this debt. See "Description of notes — Ranking."
Subsidiary guarantees		We will cause any of our existing and future subsidiaries that guarantees or becomes a co-obligor in respect of any of our funded debt to equally and ratably guarantee the notes.
Certain covenants and events of default		We will issue the notes under an indenture with SunTrust Bank, as trustee. The indenture does not limit the amount of unsecured debt we may incur. The indenture will contain limitations on, among other things, our ability to:
		• incur indebtedness secured by certain liens;
		• engage in certain sale-leaseback transactions; and
		• consolidate, merge or dispose of all or substantially all of our assets.
		The indenture will provide for certain events of default, including default on certain other indebtedness.
Optional redemption		We may redeem some or all of the notes at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest, if any, to the redemption date, as described in "Description of notes" beginning on page S-50 of this prospectus supplement.

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Risk factors

See "Risk factors" beginning on page S-16 and on page 2 of the accompanying prospectus and "Management's discussion and analysis of financial condition and results of operations" beginning on page S-24 of this prospectus supplement for a discussion of factors you should carefully consider before investing in the notes.

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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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		Year ended December 31,									Three months ended March 31,

($ in thousands, except per unit amounts)			2001			2002			2003			2003			2004

Income statement data:
Transportation and terminals revenues		$	339,412		$	363,740		$	372,848		$	87,714		$	88,930
Product sales revenues			108,169			70,527			112,312			32,001			44,214
Affiliate construction and management fee revenues			1,018			210			–			–			–

	Total revenues		448,599			434,477			485,160			119,715			133,144
Operating expenses including environmental expenses net of indemnifications			160,880			155,146			166,883			33,970			37,790
Product purchases			95,268			63,982			99,907			27,818			38,499
Equity earnings(a)			–			–			–			–			(120	)

	Operating margin		192,451			215,349			218,370			57,927			56,975
Depreciation and amortization			35,767			35,096			36,081			9,379			9,522
General and administrative			47,365			43,182			56,846			10,438			12,887

	Operating profit		109,319			137,071			125,443			38,110			34,566
Interest expense, net			12,113			21,758			34,536			8,505			8,069
Debt placement fees amortization			253			9,950			2,830			547			682
Other income, net			(431	)		(2,112	)		(92	)		—			—

	Income before income taxes		97,384			107,475			88,169			29,058			25,815
Provision for income taxes(b)			29,512			8,322			–			–			–

	Net income	$	67,872		$	99,153		$	88,169		$	29,058		$	25,815
	Basic net income per limited partner unit	$	1.87		$	3.68		$	3.32		$	0.99		$	0.87

	Diluted net income per limited partner unit	$	1.87		$	3.67		$	3.31		$	0.99		$	0.87

Balance sheet data:
Working capital (deficit)		$	(2,211	)	$	47,328		$	77,438		$	(30,479	)	$	32,160
Total assets			1,104,559			1,120,359			1,194,930			1,132,549			1,209,433
Total debt			139,500			570,000			570,000			570,000			570,000
Affiliate long-term note payable(c)			138,172			–			–			–			–
Partners' capital			589,682			451,757			498,149			464,040			497,778
Cash flow data:
Cash distributions declared per unit(d)		$	2.02		$	2.71		$	3.17		$	0.75		$	0.85
(continued on following page)

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Other data:
Operating margin:
	Petroleum products pipeline system		$	143,711	$	163,233	$	162,494	$	41,202	$	40,326
	Petroleum products terminals			38,240		43,844		46,909		16,167		13,381
	Ammonia pipeline system			10,500		8,272		8,094		558		2,613
	Allocated partnership depreciation costs			–		–		873		–		655

		Operating margin	$	192,451	$	215,349	$	218,370	$	57,927	$	56,975
EBITDA:
	Net income		$	67,872	$	99,153	$	88,169	$	29,058	$	25,815
	Income taxes(b)			29,512		8,322		–		–		–
	Debt placement fees amortization			253		9,950		2,830		547		682
	Interest expense, net			12,113		21,758		34,536		8,505		8,069
	Depreciation and amortization			35,767		35,096		36,081		9,379		9,522

		EBITDA(e)	$	145,517	$	174,279	$	161,616	$	47,489	$	44,088
Operating statistics:
Petroleum products pipeline system:
	Transportation revenues per barrel shipped (cents per barrel)			90.8		94.9		96.4		98.0		97.2
	Transportation barrels shipped (millions)			236.1		234.6		237.6		52.7		52.8
	Barrel miles (billions)			70.5		71.0		70.5		15.8		14.9
Petroleum products terminals:
	Marine terminal average storage capacity utilized per month (million barrels)			15.7		16.2		15.2		15.8		15.5
	Marine terminal throughput (million barrels)(f)			11.5		20.5		22.2		5.3		5.5
	Inland terminal throughput (million barrels)			56.7		57.3		61.2		12.6		20.5
Ammonia pipeline system:
	Volume shipped (thousand tons)			763		712		614		47		219

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:

•: 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:

•: 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;
•: was insolvent or rendered insolvent by reason of such incurrence;
•: 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:

•: 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;
•: 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:

•: 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;
•: repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility;
•: pay $1.9 million to Magellan Pipeline Company's Series B noteholders to release the collateral held by them;
•: replenish cash used to fund our recent acquisitions; and
•: 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.

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Capitalization

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

•: 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."

		As of March 31, 2004

(unaudited) ($ in thousands)		Historical		As adjusted for this offering(a)(b)		As further adjusted for our proposed common unit offering

Cash and cash equivalents		$	43,891	$	56,768	$	56,768

Debt:
	Credit facility	$	90,000	$	48,685	$	—
	Magellan Pipeline Company Series A senior notes		178,000		—		—
	Magellan Pipeline Company Series B senior notes due 2007		302,000		302,000		302,000
	% Senior notes due 2014		—		250,000		250,000

Total debt		$	570,000	$	600,685	$	552,000
Total partners' capital			497,778		480,079		528,764

Total capitalization		$	1,067,778	$	1,080,764	$	1,080,764

(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.

S-21

Our refinancing plan

•: 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.

•: 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 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

S-24

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.

S-25

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

				Three months ended March 31,

				2003		2004

Financial highlights (in millions)
Revenues:
	Transportation and terminals revenue:
		Petroleum products pipeline system		$	64.7	$	64.6
		Petroleum products terminals			21.4		20.8
		Ammonia pipeline system			1.6		3.6
		Eliminations			–		(0.1	)

			Total transportation and terminals revenue		87.7		88.9
	Product sales				32.0		44.2

			Total revenues		119.7		133.1
Operating expenses, environmental expenses and environmental reimbursements:
	Petroleum products pipeline system				25.2		29.2
	Petroleum products terminals				7.7		8.3
	Ammonia pipeline system				1.1		1.0
	Eliminations				–		(0.7	)

			Total operating expenses, environmental expenses and environmental reimbursements		34.0		37.8
	Product purchases				27.8		38.5
	Equity earnings				–		(0.1	)

Operating margin					57.9		56.9
Depreciation and amortization					9.4		9.4
Affiliate general and administrative expenses					10.4		12.9

			Operating profit	$	38.1	$	34.6

Operating statistics
Petroleum products pipeline system:
	Transportation revenue per barrel shipped (cents per barrel)				98.0		97.2
	Transportation barrels shipped (million barrels)				52.7		52.8
	Barrel miles (billions)				15.8		14.9
Petroleum products terminals:
	Marine terminal facilities:
		Average storage capacity utilized per month (barrels in millions)			15.8		15.5
		Throughput (barrels in millions)			5.3		5.5
	Inland terminals:
		Throughput (barrels in millions)			12.6		20.5
Ammonia pipeline system:
	Volume shipped (tons in thousands)				47		219

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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.

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

				Year ended December 31,

				2002		2003

Financial highlights (in millions)
Revenues:
	Transportation and terminals revenue:
		Petroleum products pipeline system		$	272.5	$	281.4
		Petroleum products terminals			78.1		78.9
		Ammonia pipeline system			13.1		12.6

			Total transportation and terminals revenue		363.7		372.9
	Product sales				70.6		112.3
	Affiliate management fees				0.2		–

			Total revenues		434.5		485.2
Operating expenses, environmental expenses and environmental reimbursements:
	Petroleum products pipeline system				114.7		128.5
	Petroleum products terminals				35.5		34.7
	Ammonia pipeline system				4.9		4.5
	Eliminations				–		(0.8	)

			Total operating expenses, environmental expenses and environmental reimbursements		155.1		166.9
	Product purchases				64.0		99.9

Operating margin					215.4		218.4
Depreciation and amortization					35.1		36.1
Affiliate general and administrative expenses					43.2		56.9

			Operating profit	$	137.1	$	125.4

Operating statistics
Petroleum products pipeline system:
	Transportation revenue per barrel shipped (cents per barrel)				94.9		96.4
	Transportation barrels shipped (million barrels)				234.6		237.6
	Barrel miles (billions)				71.0		70.5
Petroleum products terminals:
	Marine terminal facilities:
		Average storage capacity utilized per month (barrels in millions)			16.2		15.2
		Throughput (barrels in millions)			20.5		22.2
	Inland terminals:
		Throughput (barrels in millions)			57.3		61.2
Ammonia pipeline system:
	Volume shipped (tons in thousands)				712		614

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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

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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.

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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

				Year ended December 31,

				2001		2002

Financial highlights (in millions)
Revenues:
	Transportation and terminals revenue:
		Petroleum products pipeline system		$	254.9	$	272.5
		Petroleum products terminals			70.0		78.1
		Ammonia pipeline system			14.5		13.1

			Total transportation and terminals revenue		339.4		363.7
	Product sales				108.2		70.6
	Affiliate management fees				1.0		0.2

			Total revenues		448.6		434.5
Operating expenses, environmental expenses and environmental reimbursements:
	Petroleum products pipeline system				123.6		114.7
	Petroleum products terminals				33.3		35.5
	Ammonia pipeline system				4.0		4.9

			Total operating expenses, environmental expenses and environmental reimbursements.		160.9		155.1
	Product purchases				95.3		64.0

Operating margin					192.4		215.4
Depreciation and amortization					35.8		35.1
Affiliate general and administrative expense					47.3		43.2

			Operating profit	$	109.3	$	137.1

Operating statistics
Petroleum products pipeline system:
	Transportation revenue per barrel shipped (cents per barrel)				90.8		94.9
	Transportation barrels shipped (million barrels)				236.1		234.6
	Barrel miles (billions)				70.5		71.0
Petroleum products terminals:
	Marine terminal facilities:
		Average storage capacity utilized per month (barrels in millions)			15.7		16.2
		Throughput (barrels in millions)			11.5		20.5
	Inland terminals:
		Throughput (barrels in millions)			56.7		57.3
Ammonia pipeline system:
	Volume shipped (tons in thousands)				763		712

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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

S-36

•: 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.

S-37

•

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.

S-38

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;

S-39

•: 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):

		Total			< 1 year		1-3 years		3-5 years		> 5 years


Long-term and current debt obligations		$	570.0		$	0.9	$	49.8	$	519.3	$	–
Operating lease obligations		$	18.5		$	2.4	$	4.5	$	3.8	$	7.8
Purchase commitments:
	Affiliate operating and general and administrative		(1	)
	Capital projects	$	28.2		$	28.2	$	–	$	–	$	–
	Petroleum product purchases	$	2.5		$	2.5	$	–	$	–	$	–
	Other	$	4.3		$	1.0	$	1.9	$	1.4	$	–

(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.

		As of March 31, 2004

		(in millions)
		Maximum indemnity amount		Magellan Midstream Holdings' obligations			Claims Against Williams' Indemnifications			Amount of indemnity remaining

IPO Indemnity		$	15.0	$	(2.9	)	$	(4.1	)	$	8.0
Magellan Pipeline Indemnity			125.0		(19.0	)		(37.9	)		68.1
Acquisition Indemnity			175.0		–			(1.8	)		173.2
	Total	$	315.0	$	(21.9	)	$	(43.8	)	$	249.3

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):

	Debt / equity ratio = 50 / 50


Debt cost		7%		8%		9%		10%		11%
Equity cost		12%		13%		14%		15%		16%

Implied impairment	$	–	$	–	$	–	$	–	$	16.9

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):

			2002							2003

	Balance 12/31/01		2002					Balance 12/31/02		2003								Balance 12/31/03
Indemnifying party	Balance 12/31/01		Accruals		Payments			Balance 12/31/02		Accruals		Transfers			Payments			Balance 12/31/03

Williams	$	3.2	$	24.3	$	(4.5	)	$	23.0	$	9.5	$	(21.9	)	$	(2.8	)	$	7.8
Magellan Midstream Holdings		–		–		–			–		–		21.9			(2.9	)		19.0
Other		–		–		–			–		3.1		–			–			3.1
Totals	$	3.2	$	24.3	$	(4.5	)	$	23.0	$	12.6	$	–		$	(5.7	)	$	29.9

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".

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:

•: will be our general unsecured, senior obligations;
•: 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;
•: will mature on , 2014;
•: will not be entitled to the benefit of any sinking fund; and
•: 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:

•: accrue at the rate of % per annum;
•: accrue from , 2004 or the most recent interest payment date;

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•: be payable in cash semi-annually in arrears on and of each year, commencing on , 2004;
•: be payable to holders of record on the and immediately preceding the related interest payment dates;
•: be computed on the basis of a 360-day year consisting of twelve 30-day months; and
•: be payable on overdue interest to the extent permitted by law at the same rate as interest is payable on principal.

Payment and transfer. Initially, the notes will be issued only in global form. Beneficial interests in notes in global form will be shown on, and transfers of interests in notes in global form will be made only through, records maintained by DTC and its participants. Notes in definitive form, if any, may be presented for registration of transfer or exchange at the office or agency maintained by us for such purpose. Initially, this will be the corporate trust office or agency of the trustee located at 767 Third Avenue, 31st Floor, New York, New York 10017 c/o Law Debenture Corporate Trust Services.

Payment of principal of, premium, if any, and interest on notes in global form registered in the name of DTC's nominee will be made in immediately available funds to DTC's nominee, as the registered holder of such global notes. If any of the notes are no longer represented by a global note, payments of interest on notes in definitive form may, at our option, be made at the corporate trust office or agency of the trustee indicated above or by check mailed directly to holders at their respective registered addresses or by wire transfer to an account designated by a holder of at least $1,000,000 of notes. All funds that we provide to the trustee or a paying agent for the payment of principal and any premium or interest on any note that remain unclaimed at the end of two years will (subject to applicable abandoned property laws) be repaid to us, and the holder of such note must thereafter look only to us for payment as a general creditor.

No service charge will be imposed for any registration of transfer or exchange of notes, but we or the trustee may require payment of a sum sufficient to cover any tax or other governmental charge payable upon transfer or exchange of notes. We are not required to register the transfer of or to exchange any note (1) selected or called for redemption or (2) during a period of 15 days before mailing notice of any redemption of notes.

The registered holder of a note will be treated as its owner for all purposes, and all references in this description to "holders" mean holders of record, unless otherwise indicated.

Replacement of securities. We will replace any mutilated, destroyed, lost or stolen notes at the expense of the holder upon surrender of the mutilated notes to the trustee or evidence of destruction, loss or theft of a note satisfactory to us and the trustee. In the case of a destroyed, lost or stolen note, we may require an indemnity satisfactory to the trustee and to us before a replacement note will be issued.

Additional issuances

We may from time to time, without notice or the consent of the holders of the notes, create and issue additional notes of the series ranking equally and ratably with the original notes in all respects (except for the payment of interest accruing prior to the date such additional notes

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are initially issued under the indenture), so that such additional notes form a single series with the original notes and have the same terms as to status, redemption or otherwise as the original notes.

Optional redemption

The notes will be redeemable, at our option, at any time in whole, or from time to time in part, at a price equal to the greater of:

•: 100% of the principal amount of the notes to be redeemed; and
•: the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (exclusive of interest accrued to the date of redemption) discounted to the date of redemption on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus basis points;

plus, in either case, accrued interest to the date of redemption. The actual redemption price, calculated as provided in this description, will be calculated and certified to the trustee and us by the Independent Investment Banker (as defined below).

Notes called for redemption become due on the date fixed for redemption. Notices of redemption will be mailed at least 30 but not more than 60 days before the redemption date to each holder of the notes to be redeemed at its registered address. The notice of redemption for the notes will state, among other things, the amount of notes to be redeemed, if less than all of the outstanding notes are to be redeemed, the redemption date, the redemption price (or the method of calculating it) and each place that payment will be made upon presentation and surrender of notes to be redeemed. Unless we default in payment of the redemption price, interest will cease to accrue on any notes that have been called for redemption on the redemption date. If less than all the notes are redeemed at any time, the trustee will select the notes (or any portion of notes in integral multiples of $1,000) to be redeemed on a pro rata basis or by any other method the trustee deems fair and appropriate, but beneficial interests in notes in global form will be selected for redemption in accordance with DTC's customary practices.

For purposes of determining the optional redemption price, the following definitions are applicable:

"Comparable Treasury Issue" means the United States Treasury security or securities selected by the Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity to the remaining term of the notes to be redeemed.

"Comparable Treasury Price" means, for any redemption date, (1) the average of four Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

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"Independent Investment Banker" means J.P. Morgan Securities Inc. or Lehman Brothers Inc., as specified by us, and any successor firm, or if such firm is unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing appointed by the trustee after consultation with us.

"Reference Treasury Dealer" means J.P. Morgan Securities Inc., Lehman Brothers Inc., plus two other dealers selected by the trustee that are primary U.S. government securities dealers in New York City and their respective successors; provided, if J.P. Morgan Securities Inc., Lehman Brothers Inc. or any other primary U.S. government securities dealer selected by the trustee shall cease to be a primary U.S. government securities dealer, then such other primary U.S. government securities dealers as may be substituted by the trustee.

"Reference Treasury Dealer Quotations" means, for each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by such Reference Treasury Dealer at 3:30 p.m., New York City time, on the third business day preceding such redemption date.

"Treasury Rate" means, with respect to any redemption date, (1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15(519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the remaining term of the notes to be redeemed, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month) or (2) if such release (or any successor release) is not published during the week in which the calculation date falls (or in the immediately preceding week if the calculation date falls on any day prior to the usual publication date for such release) or does not contain such yields, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate shall be calculated on the third business day preceding the redemption date. Any weekly average yields calculated by interpolation or extrapolation will be rounded to the nearest 1/100^th of 1%, with any figure of 1/200^th of 1% or above being rounded upward.

Except as set forth above, the notes will not be redeemable by us prior to maturity, will not be entitled to the benefit of any sinking fund and will not be subject to repurchase by us at the option of the holders.

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Ranking

The notes will be unsecured, unless we are required to secure them as described below under "—Certain covenants—Limitations on liens." The notes will also be our unsubordinated obligations and will rank equally in contractual right of payment with all of our other existing and future unsubordinated indebtedness.

We currently conduct substantially all our operations through our Subsidiaries, and our Subsidiaries generate substantially all our operating income and cash flow. As a result, we depend on distributions or advances from our Subsidiaries for funds to meet our debt service obligations. Contractual provisions or laws, as well as our Subsidiaries' financial condition and operating requirements, may limit our ability to obtain from our Subsidiaries cash that we require to pay our debt service obligations, including payments on the notes. The notes will be structurally subordinated to all obligations of our Subsidiaries, including claims of trade payables, except for any Subsidiary Guarantees as described below under "—Potential guarantee of notes by subsidiaries." This means that you, as a holder of the notes, will have a junior position to the claims of creditors of such Subsidiaries on their assets and earnings. The notes will also be effectively subordinated to any secured debt we may incur, to the extent of the value of the assets securing that debt. The indenture does not limit the amount of debt we or our Subsidiaries may incur; it permits our Subsidiaries to incur indebtedness in addition to the outstanding Series B Senior Notes of Magellan Pipeline Company.

As of March 31, 2004, we had an aggregate of $570.0 million of total debt outstanding. Of such total debt, $90.0 million represents our debt, which would rank equally in right of payment with the notes, and $480.0 million represents debt of our Subsidiaries, which will be effectively senior to the notes. We will use the net proceeds of this offering, together with the net proceeds from our proposed common unit offering and our general partner's related capital contribution, to repay the $90.0 million of our debt and $178.0 million of debt of our Subsidiaries. Our Subsidiaries also had $22.8 million of trade payables outstanding as of March 31, 2004 that will be effectively senior to the notes. See "Capitalization."

Potential guarantee of notes by subsidiaries

Initially, the notes will not be guaranteed by any of our Subsidiaries. In the future, however, if any of our Subsidiaries become guarantors or co-obligors of our Funded Debt, then those Subsidiaries will jointly and severally, fully and unconditionally, guarantee our payment obligations under the notes. We refer to any such Subsidiaries as "Subsidiary Guarantors" and sometimes to such guarantees as "Subsidiary Guarantees." Each Subsidiary Guarantor will execute a supplement to the indenture and a notation of a guarantee as further evidence of its guarantee.

The obligations of each Subsidiary Guarantor under its guarantee of the notes will be limited to the maximum amount that will not result in the obligations of the Subsidiary Guarantor under the guarantee constituting a fraudulent conveyance or fraudulent transfer under federal or state law, after giving effect to:

•: all other contingent and fixed liabilities of the Subsidiary Guarantor; and
•: any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its guarantee.

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Addition and release of subsidiary guarantors

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to the notes as described below under "—Defeasance" or discharge our obligations under the indenture with respect to the notes as described below under "—Satisfaction and discharge," then any Subsidiary Guarantee will be released. Further, if no Default has occurred and is continuing under the indenture, a Subsidiary Guarantor will be unconditionally released and discharged from its guarantee:

•: automatically upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not our affiliate, of all of our direct or indirect limited partnership, limited liability company or other equity interests in the Subsidiary Guarantor;
•: automatically upon the merger of the Subsidiary Guarantor into us or any other Subsidiary Guarantor or the liquidation or dissolution of the Subsidiary Guarantor; or
•: following delivery of a written notice by us to the trustee, upon the release of all guarantees by the Subsidiary Guarantor of any Funded Debt of ours, except the notes.

If at any time following any release of a Subsidiary Guarantor from its initial guarantee of the notes pursuant to the third bullet point in the preceding paragraph, the Subsidiary Guarantor again guarantees any of our Funded Debt (other than our obligations under the indenture), then we will cause the Subsidiary Guarantor to again guarantee the notes in accordance with the indenture.

Certain covenants

The following is a description of certain covenants of the indenture that limit our ability and the ability of our Subsidiaries to take certain actions.

Limitations on liens. We will not, nor will we permit any Subsidiary to, create, assume, incur or suffer to exist any Lien upon any Principal Property or upon any capital stock of any Restricted Subsidiary, whether owned or leased on the date of the indenture or thereafter acquired, to secure any Debt of ours or any other Person (other than debt securities issued under the indenture), without in any such case making effective provision whereby all of the notes and other debt securities then outstanding under the indenture are secured equally and ratably with, or prior to, such Debt so long as such Debt is so secured. This restriction does not apply to or prevent the creation or existence of:

•: any Lien on any property or assets owned by us or any Restricted Subsidiary in existence on the Issue Date or created pursuant to an "after-acquired property" clause or similar term in existence on the Issue Date in any mortgage, pledge agreement, security agreement or other similar instrument applicable to us or any Restricted Subsidiary and in existence on the Issue Date;
•: any Lien on any property or assets created at the time of acquisition of such property or assets by us or any Restricted Subsidiary or within one year after such time to secure all or a portion of the purchase price for such property or assets or Debt incurred to finance such purchase price, whether such Debt was incurred prior to, at the time of or within one year of such acquisition;

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•: any Lien on any property or assets existing thereon at the time of the acquisition thereof by us or any Restricted Subsidiary (whether or not the obligations secured thereby are assumed by us or any Restricted Subsidiary), provided that such Lien only encumbers the property or assets so acquired;
•: any Lien on any property or assets of a Person existing thereon at the time such Person becomes a Restricted Subsidiary by acquisition, merger or otherwise, provided that such Lien is not incurred in anticipation of such Person becoming a Restricted Subsidiary;
•: any Lien on any property or assets to secure all or part of the cost of construction, development, repair or improvements thereon or to secure Debt incurred prior to, at the time of, or within one year after completion of such construction, development, repair or improvements or the commencement of full operations thereof (whichever is later), to provide funds for any such purpose;
•: any Lien in favor of us or any Restricted Subsidiary;
•: any Lien created or assumed by us or any Restricted Subsidiary in connection with the issuance of Debt the interest on which is excludable from gross income of the holder of such Debt pursuant to the Internal Revenue Code of 1986, as amended, or any successor statute, for the purpose of financing, in whole or in part, the acquisition or construction of property or assets to be used by us or any Subsidiary;
•: Permitted Liens;
•: any Lien on any additions, improvements, replacements, repairs, fixtures, appurtenances or component parts thereof attaching to or required to be attached to property or assets pursuant to the terms of any mortgage, pledge agreement, security agreement or other similar instrument, creating a Lien upon such property or assets permitted by the first eight bullet points, inclusive, above; or
•: any extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refundings or replacements) of any Lien, in whole or in part, that is referred to in the first nine bullet points, inclusive, above, or of any Debt secured thereby; provided, however, that the principal amount of Debt secured thereby shall not exceed the greater of (A) the principal amount of Debt so secured at the time of such extension, renewal, refinancing, refunding or replacement (plus the aggregate amount of premiums, other payments, costs and expenses required to be paid or incurred in connection with such extension, renewal, refinancing, refunding or replacement) and (B) the maximum committed principal amount of Debt so secured at such time; provided further, however, that such extension, renewal, refinancing, refunding or replacement shall be limited to all or a part of the property or assets (including improvements, alterations and repairs on such property or assets) subject to the Lien so extended, renewed, refinanced, refunded or replaced (plus improvements, alterations and repairs on such property or assets).

Notwithstanding the preceding, under the indenture, we may, and may permit any Subsidiary to, create, assume, incur or suffer to exist any Lien upon any Principal Property or capital stock of a Restricted Subsidiary to secure our Debt or the Debt of any other Person (other than debt securities issued under the indenture) that is not excepted by bullet points one through ten,

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inclusive, above without securing the notes and other debt securities issued under the indenture, provided that the aggregate principal amount of all Debt then outstanding secured by such Lien and all other Liens not excepted by bullet points one through ten, inclusive, above, together with all net sale proceeds from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by bullet points one through four, inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below), does not exceed at any one time 15% of Consolidated Net Tangible Assets.

Restriction on Sale-Leasebacks. We will not, and will not permit any Restricted Subsidiary to, engage in a Sale-Leaseback Transaction, unless:

•: the Sale-Leaseback Transaction occurs within one year from the date of acquisition of the Principal Property subject thereto or the date of the completion of construction or commencement of full operations on such Principal Property, whichever is later;
•: the Sale-Leaseback Transaction involves a lease for a period, including renewals, of not more than three years;
•: we or such Restricted Subsidiary would be entitled under the limitations on liens covenant described above to incur Debt secured by a Lien on the Principal Property subject to the Sale-Leaseback Transaction in a principal amount equal to or exceeding the net sale proceeds from such Sale-Leaseback Transaction without equally and ratably securing the debt securities issued under the indenture; or
•: we or such Restricted Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the net sale proceeds from such Sale-Leaseback Transaction to (A) the prepayment, repayment, redemption or retirement of any unsubordinated Funded Debt of us or any Funded Debt of a Subsidiary of ours, or (B) investment in another Principal Property.

Notwithstanding the preceding, we may, and may permit any Restricted Subsidiary to, effect any Sale-Leaseback Transaction that is not excepted by bullet points one through four, inclusive, of the above paragraph, provided that the net sale proceeds from such Sale-Leaseback Transaction, together with the aggregate principal amount of then outstanding Debt (other than debt securities issued under the indenture) secured by Liens upon Principal Properties not excepted by bullet points one through ten, inclusive, of the first paragraph of the limitations on liens covenant described above do not exceed at any one time 15% of Consolidated Net Tangible Assets.

Limitation on Amending Partnership Agreement. Except in limited circumstances, we may not amend certain provisions of our partnership agreement, in a manner that is materially adverse to the interests of the holders of the notes, that require us to maintain our separate existence, resolve any conflicts of interest with our general partner and its affiliates in a manner that is fair and reasonable to us, or take certain actions related to our bankruptcy or liquidation without the approval of the conflicts committee of our general partner.

Reports. So long as any notes are outstanding, we will be required to comply with the covenant under the caption "Description of debt securities—Covenants—Reports" on page 15 of the accompanying prospectus. We are also required to furnish to the trustee annually a statement as to our compliance with all covenants under the indenture.

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Merger, amalgamation, consolidation and sale of assets

We will not merge, amalgamate or consolidate with or into any other Person or sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets to any Person, whether in a single transaction or series of related transactions, except in accordance with the provisions of our partnership agreement, and unless:

•

we are the surviving Person in the case of a merger, or the surviving or transferee Person if other than us:

•: is a partnership, limited liability company or corporation organized under the laws of the United States, a state thereof or the District of Columbia; and
•: expressly assumes by supplemental indenture satisfactory to the trustee all of our obligations under the indenture and the debt securities issued under the indenture;

•

immediately after giving effect to the transaction or series of transactions, no Default or Event of Default has occurred or is continuing;

•

if we are not the surviving Person, then each Subsidiary Guarantor, unless it is the Person with which we have consummated a transaction under this provision, has confirmed that its guarantee of the notes will continue to apply to the obligations under the notes and the indenture; and

•

we have delivered to the trustee an officers' certificate and opinion of counsel, each stating that the merger, amalgamation, consolidation, sale, conveyance, transfer, lease or other disposition, and if a supplemental indenture is required, the supplemental indenture, comply with the conditions set forth above and any other applicable provisions of the indenture.

Thereafter, if we are not the surviving Person, the surviving or transferee Person will be substituted for us under the indenture. If we sell or otherwise dispose of (except by lease) all or substantially all of our assets and the above stated requirements are satisfied, we will be released from all of our liabilities and obligations under the indenture and the notes. If we lease all or substantially all of our assets, we will not be so released from our obligations under the indenture and the notes.

Events of default

Events of default. In addition to the "Events of Default" described under the caption "Description of debt securities—Events of default, remedies and notice—Events of default" on pages 15 and 16 of the accompanying prospectus, "Events of Default" under the indenture with respect to the notes will also include:

•: default by us or any of our Subsidiaries in the payment at the stated maturity, after the expiration of any applicable grace period, of principal of, premium, if any, or interest on any Debt then outstanding having a principal amount in excess of $50.0 million or acceleration of any Debt having a principal amount in excess of such amount so that it becomes due and payable prior to its stated maturity and such acceleration is not rescinded within 30 days after notice;

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•: a final judgment or order for the payment of money in excess of $50.0 million (net of applicable insurance coverage) having been rendered against us or any Subsidiary and such judgment or order shall continue unsatisfied and unstayed for a period of 30 days; and
•: except in limited circumstances, the amendment by our general partner of certain provisions of its limited liability company agreement, in a manner that is materially adverse to the interests of the holders of the notes, that require it to maintain its and our separate existence, or take certain actions related to its and our bankruptcy or liquidation without the approval of the conflicts committee of our general partner.

Exercise of remedies. If an Event of Default, other than an Event of Default described in the fifth bullet point under the caption "Description of debt securities—Events of default, remedies and notice—Events of default" on pages 15 and 16 of the accompanying prospectus, occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the outstanding notes may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the notes to be due and payable immediately. If an Event of Default described in such fifth bullet point occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all debt securities outstanding under the indenture, including the notes, will become immediately due and payable without any declaration of acceleration or other act on the part of the trustee or any holders.

The holders of a majority in principal amount of the outstanding notes may rescind any declaration of acceleration by the trustee or the holders, but only if:

•: rescinding the declaration of acceleration would not conflict with any judgment or decree of a court of competent jurisdiction; and
•: all existing Events of Default with respect to the notes have been cured or waived, other than the nonpayment of principal, premium or interest on the notes that have become due solely by the declaration of acceleration.

The trustee will not be obligated, except as otherwise provided in the indenture, to exercise any of the rights or powers under the indenture at the request or direction of any of the holders of notes, unless such holders have offered to the trustee reasonable indemnity or security against any costs, liability or expense that may be incurred in exercising such rights or powers. No holder of notes may pursue any remedy with respect to the indenture or the notes, unless:

•: such holder has previously given the trustee notice that an Event of Default with respect to the notes is continuing;
•: holders of at least 25% in principal amount of the outstanding notes have requested that the trustee pursue the remedy;
•: such holders have offered the trustee reasonable indemnity or security against any cost, liability or expense to be incurred in pursuit of the remedy;
•: the trustee has not complied with such request within 60 days after the receipt of the request and the offer of indemnity or security; and

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•: the holders of a majority in principal amount of the outstanding notes have not given the trustee a direction that is inconsistent with such request within such 60-day period.

This provision does not, however, affect the right of a holder of a note to sue for enforcement of any overdue payment. The holders of a majority in principal amount of the notes have the right, subject to certain restrictions, to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or of exercising any right or power conferred on the trustee with respect to the notes. The trustee, however, may refuse to follow any direction that:

•: conflicts with law;
•: is inconsistent with any provision of the indenture;
•: the trustee determines is unduly prejudicial to the rights of any holder of notes not taking part in such direction; or
•: would involve the trustee in personal liability.

Notice of default. Within 30 days after the occurrence of any Default or Event of Default, we are required to give written notice to the trustee and indicate the status of the Default or Event of Default and what action we are taking or propose to take to cure it, as further described under the caption "Description of debt securities—Events of default, remedies and notice—Notice of event of default" on page 17 of the accompanying prospectus.

Defeasance

At any time, we may terminate all our obligations under the indenture as they relate to the notes, which we call a "legal defeasance." If we decide to make a legal defeasance, however, we may not terminate our obligations:

•: relating to the defeasance trust;
•: to register the transfer or exchange of the notes;
•: to replace mutilated, destroyed, lost or stolen notes; or
•: to maintain a registrar and paying agent in respect of the notes.

If we exercise our legal defeasance option, any subsidiary guarantee will terminate with respect to the notes.

At any time we may also effect a "covenant defeasance," which means we have elected to terminate our obligations under:

•: some of the covenants applicable to the notes, including those described above under "—Certain covenants—Limitations on liens" and "—Certain covenants—Restriction on Sale-Leasebacks;"
•: the guarantee provisions and the bankruptcy provisions with respect to a Subsidiary Guarantor described in the accompanying prospectus at pages 15 and 16 under "Events of default, remedies and notice—Events of default;" and

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•: the cross acceleration and the judgment default provisions and the provisions relating to certain amendments by our general partner described under "—Events of default—Events of default" above.

We may exercise our legal defeasance option notwithstanding our prior exercise of our covenant defeasance option. If we exercise our legal defeasance option, payment of the defeased notes may not be accelerated because of an Event of Default. If we exercise our covenant defeasance option, payment of the notes may not be accelerated because of an Event of Default specified in the fourth, fifth (with respect only to a Subsidiary Guarantor (if any)) or sixth bullet points under "—Events of default, remedies and notice—Events of default" in the accompanying prospectus or because of a default under any of the three bullet points under "—Events of default—Events of default" above.

In order to exercise either defeasance option, we must:

•: irrevocably deposit in trust with the trustee money or certain U.S. government obligations for the payment of principal, premium, if any, and interest on the notes to redemption or stated maturity, as the case may be;
•: comply with certain other conditions, including that no Default has occurred and is continuing after the deposit in trust; and
•: deliver to the trustee an opinion of counsel to the effect that holders of the notes will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such opinion of counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

Satisfaction and discharge

We may discharge all our obligations under the indenture with respect to the notes, other than our obligation to register the transfer of and exchange notes, provided that we either:

•: deliver all outstanding notes to the trustee for cancellation; or
•: all such notes not so delivered for cancellation have either become due and payable or will become due and payable at their stated maturity within one year or are to be called for redemption within one year, and in the case of this bullet point we have deposited with the trustee in trust an amount of cash or certain U.S. government obligations sufficient to pay the entire indebtedness of such notes, including interest to the stated maturity or applicable redemption date.

Amendment and waiver

We may amend the indenture or the holders of the notes may waive our compliance with certain covenants or past defaults under the indenture, as further described under the caption "Description of debt securities—Amendments and waivers" on pages 17 and 18 of the accompanying prospectus.

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Book-entry system; depository procedures

Initially, the notes will be represented by one or more notes in registered, global form without interest coupons (collectively, the "Global Note"). The Global Note will be deposited upon issuance with the trustee as custodian for DTC, and registered in the name of a nominee of DTC, as further described under the caption "Description of debt securities—Book entry, delivery and form" on pages 21 and 22 of the accompanying prospectus.

Regarding the trustee

The indenture limits the right of the trustee, if it becomes our creditor, to obtain payment of claims in certain cases, or to realize for its own account on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in certain other transactions. However, if it acquires any conflicting interest after a Default has occurred under the indenture and is continuing, it must eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign as trustee.

If an Event of Default occurs and is not cured or waived, the trustee is required to exercise such of the rights and powers vested in it by the indenture, and use the same degree of care and skill in its exercise, as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any of the holders of notes unless they have offered to the trustee reasonable security or indemnity against the costs and liabilities that it may incur.

SunTrust Bank, as the trustee under the indenture, may be a depositary for funds of, may make loans to and may perform other routine banking services for us and our affiliates in the normal course of business.

Governing law

The indenture, any Subsidiary Guarantees and the notes are governed by New York law.

Certain definitions

"Consolidated Net Tangible Assets" means, at any date of determination, the total amount of assets after deducting therefrom:

•: all current liabilities (excluding (A) any current liabilities that by their terms are extendible or renewable at the option of the obligor thereon to a time more than 12 months after the time as of which the amount thereof is being computed, and (B) current maturities of long-term debt); and
•: the amount (net of any applicable reserves) of all goodwill, trade names, trademarks, patents and other like intangible assets,

all as set forth on the consolidated balance sheet of us and our consolidated subsidiaries for our most recently completed fiscal quarter, prepared in accordance with generally accepted accounting principles in the United States, as in effect from time to time.

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"Debt" means any obligation created or assumed by any Person for the repayment of money borrowed, any purchase money obligation created or assumed by such Person and any guarantee of the foregoing.

"Default" means any event, act or condition that is, or after notice or the passage of time or both would be, an Event of Default.

"Exchange Act" means the Securities Exchange Act of 1934, as amended, and any successor statute.

"Funded Debt" means all Debt maturing one year or more from the date of the creation thereof, all Debt directly or indirectly renewable or extendible, at the option of the debtor, by its terms or by the terms of any instrument or agreement relating thereto, to a date one year or more from the date of the creation thereof, and all Debt under a revolving credit or similar agreement obligating the lender or lenders to extend credit over a period of one year or more.

"Issue Date" means the date on which notes are initially issued under the indenture.

"Lien" means, as to any Person, any mortgage, lien, pledge, security interest or other encumbrance in or on, or adverse interest or title of any vendor, lessor, lender or other secured party to or of the Person under conditional sale or other title retention agreement or capital lease with respect to, any property or asset of the Person.

"Permitted Liens" means:

•: Liens upon rights-of-way for pipeline purposes;
•: any statutory or governmental Lien, mechanics', materialmen's, carriers' or similar Lien incurred in the ordinary course of business which is not yet due or which is being contested in good faith by appropriate proceedings and any undetermined Lien which is incidental to construction;
•: the right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise, grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of, any property or assets;
•: Liens for taxes and assessments which are (A) for the then current year, (B) not at the time delinquent, or (C) delinquent but the validity of which is being contested at the time by us or any Restricted Subsidiary in good faith;
•: Liens arising under, or to secure performance of, leases, other than capital leases;
•: any Lien upon, or deposits of, any assets in favor of any surety company or clerk of court for the purpose of obtaining indemnity or stay of judicial proceedings;
•: any Lien upon property or assets acquired or sold by us or any Restricted Subsidiary resulting from the exercise of any rights arising out of defaults on receivables;
•: any Lien incurred in the ordinary course of business in connection with workmen's compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations;

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•: any Lien in favor of the United States of America or any state thereof, or any other country, or any political subdivision of any of the foregoing, to secure partial, progress, advance or other payments pursuant to any contract or statute, or any Lien securing industrial development, pollution control or similar revenue bonds; or
•: any easements, exceptions or reservations in any property or assets of us or any Restricted Subsidiary granted or reserved for the purpose of pipelines, roads, the removal of oil, gas, coal or other minerals, and other like purposes, or for the joint or common use of real property, facilities and equipment, which are incidental to, and do not materially interfere with, the ordinary conduct of our or its business or the business of ourself and our Subsidiaries, taken as a whole.

"Person" means any individual, corporation, partnership, joint venture, limited liability company, association, joint-stock company, trust, other entity, unincorporated organization or government, or any agency or political subdivision thereof.

"Principal Property" means any pipeline, terminal or terminal facility property or asset owned or leased by us or any Subsidiary, including any related property or asset employed in the transportation (including vehicles that generate transportation revenues), distribution, terminalling, gathering, treating, processing, marketing or storage of crude oil or refined petroleum products, natural gas, natural gas liquids, fuel additives, petrochemicals or ammonia, except, in the case of:

•: any property or asset consisting of inventories, furniture, office fixtures and equipment (including data processing equipment), vehicles and equipment used on, or useful with, vehicles (but excluding vehicles that generate transportation revenues as provided above), and
•: any such property or asset, plant or terminal which, in the opinion of the board of directors of our general partner, is not material in relation to the activities of us and our Subsidiaries, taken as a whole.

"Restricted Subsidiary" means any of our Subsidiaries that owns or leases, directly or indirectly through the ownership of or an ownership interest in another Subsidiary, any Principal Property.

"Sale-Leaseback Transaction" means the sale or transfer by us or any Restricted Subsidiary of any Principal Property to a Person (other than us or a Restricted Subsidiary) and the taking back by us or any Restricted Subsidiary, as the case may be, of a lease of such Principal Property.

"Securities Act" means the Securities Act of 1933, as amended, and any successor statute.

"Subsidiary" means, with respect to any Person,

•: any other Person of which more than 50% of the total voting power of capital interests (without regard to any contingency to vote in the election of directors, managers, trustees, or equivalent persons), at the time of such determination, is owned or controlled, directly or indirectly, by such Person or one or more of the Subsidiaries of such Person;
•: in the case of a partnership, any Person of which more than 50% of the partners' capital interests (considering all partners' capital interests as a single class), at the time of such determination, is owned or controlled, directly or indirectly, by such Person or one or more of the Subsidiaries of such Person; or
•: any other Person in which such Person or one or more of the Subsidiaries of such Person have the power to control, by contract or otherwise, the board of directors, managers, trustees or equivalent governing body of, or otherwise control, such other Person.

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Management

The following table sets forth information with respect to the executive officers and members of the board of directors of our general partner. Executive officers are elected by the board of directors of our general partner and serve until the earlier of their resignation or removal. The board of directors of our general partner has seven directors divided into three classes serving staggered three-year terms.

Name	Age	Position with general partner


Don R. Wellendorf	51	Chairman of the Board, President and Chief Executive Officer
John D. Chandler	34	Chief Financial Officer and Treasurer
Michael N. Mears	41	Vice President, Transportation
Richard A. Olson	46	Vice President, Pipeline Operations
Brett C. Riley	34	Vice President, Business Development
Lonny E. Townsend	47	General Counsel
Jay A. Wiese	48	Vice President, Terminal Services and Development
Patrick C. Eilers	37	Director
Justin S. Huscher	50	Director
Pierre F. Lapeyre, Jr.	41	Director
James R. Montague	56	Director
George A. O'Brien, Jr.	55	Director
Mark G. Papa	57	Director

Don R. Wellendorf has served as Chairman of the Board since June 17, 2003, and as a director and the President and Chief Executive Officer of our general partner since November 15, 2002. Mr. Wellendorf also served as President and Chief Executive Officer of our former general partner from May 13, 2002 until November 15, 2002 and served as a director of our former general partner from February 9, 2001 until November 15, 2002. He served as Treasurer and Chief Financial Officer of our former general partner from January 7, 2001 to July 24, 2002 and as Senior Vice President of our former general partner from January 7, 2001 until May 13, 2002. From 1998 to March 2003, he served as Vice President of Strategic Development and Planning for Williams Energy Services, LLC. Prior to Williams' merger with MAPCO Inc. in 1998, he was Vice President and Treasurer for MAPCO from 1995 to 1998. From 1994 to 1995, he served in various management positions including Vice President, Treasurer and Corporate Controller for MAPCO.

John D. Chandler has served as the Chief Financial Officer and Treasurer of our general partner since November 15, 2002 and served in that capacity for our former general partner from July 24, 2002 until November 15, 2002. He was Director of Financial Planning and Analysis for Williams Energy Services from September 2000 to July 2002. He also served as Director of Strategic Development for Williams Energy Services from 1999 to 2000 and served as Manager of Strategic Analysis from 1998 to 1999. Prior to Williams' merger with MAPCO Inc. in 1998, he was a Manager of Business Development for MAPCO. He began his career in 1992 as an accountant with MAPCO in a professional development rotational program and held various accounting and finance positions with MAPCO from 1992 to 1998.

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Michael N. Mears has served as the Vice President, Transportation of our general partner since November 15, 2002 and served in that capacity for our former general partner from April 22, 2002 until November 15, 2002. He served as Vice President of Williams Petroleum Services, LLC from March 2002 until June 17, 2003. Mr. Mears served as Vice President of Transportation and Terminals for Williams Pipe Line Company from 1998 to 2002. He also served as Vice President, Petroleum Development for Williams Energy Services from 1996 to 1998. Prior to 1996, Mr. Mears served as Director of Operations Control and Business Development for Williams Pipe Line Company from 1993 to 1996. From 1985 to 1993, he worked in various engineering, project analysis and operations control positions for Williams Pipe Line Company.

Richard A. Olson has served as the Vice President, Pipeline Operations of our general partner since November 15, 2002 and served in that capacity for our former general partner from April 22, 2002 until November 15, 2002. He served as Vice President of Mid Continent Operations for Williams Energy Services from 1996 to 2002. Mr. Olson was Vice President of Operations and Terminal Marketing for Williams Pipe Line Company from 1996 to 1998, Director of Southern Operations from 1992 to 1996, Director of Product Movements from 1991 to 1992 and Central Division Manager from 1990 to 1991. From 1981 to 1990, Mr. Olson held various positions with Williams Pipe Line Company.

Brett C. Riley has served as the Vice President, Business Development of our general partner since June 17, 2003. Mr. Riley served as Director of Mergers & Acquisitions for Williams Energy Marketing & Trading Company from September 2000 until June 2003. He also served as Director of Financial Planning and Analysis for Williams Energy Services from 1998 to 2000. Prior to Williams' merger with MAPCO Inc. in 1998, he was a Business Development Analyst with MAPCO's Natural Gas Liquids division beginning in 1996. He began his career in 1992 as a Planning Analyst with Williams Pipe Line Company and held various finance and business development positions with Williams from 1992 to 1996.

Lonny E. Townsend has served as the General Counsel of our general partner since June 17, 2003. He was Assistant General Counsel for Williams from February 2001 to June 17, 2003. He also served as Senior Counsel for Williams from September 1995 to February 2001. From 1991 to 1995, he worked in various positions as an attorney for Williams. Prior to joining Williams, Mr. Townsend was an associate in the law firm of Davis Wright Tremaine LLP in Seattle, Washington, from 1986 to 1991.

Jay A. Wiese has served as the Vice President, Terminal Services and Development of our general partner since November 15, 2002 and served in that capacity for our former general partner from January 7, 2001 until November 15, 2002. He was Managing Director, Terminal Services and Commercial Development for Williams Energy Services from 2000 to January 2001. From 1995 to 2000, he served as Director, Terminal Services and Commercial Development of Williams Energy Services' terminal distribution business. Prior to 1995, Mr. Wiese held various operations, marketing and business development positions with Williams Pipe Line Company, Williams Energy Ventures, Inc. and Williams Energy Services. He joined Williams Pipe Line Company in 1982.

Patrick C. Eilers has served as a director of our general partner since June 17, 2003. He has been employed by Madison Dearborn Partners, Inc. since 1999 where he serves as a Director. Prior to joining Madison Dearborn Partners, he served as a Director with Jordan Industries, Inc. from 1995 to 1997 and as an Associate with IAI Venture Capital, Inc. from 1990 to 1994 while

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playing professional football with the Chicago Bears, the Washington Redskins and the Minnesota Vikings from 1990 to 1995. Mr. Eilers received a Masters in Business Administration from the Northwestern J.L. Kellogg Graduate School of Management in 1999.

Justin S. Huscher has served as a director of our general partner since June 17, 2003. He is a founder of Madison Dearborn Partners, Inc. where he has served as a Managing Director since 1993. He currently serves as a member of the board of directors of Bay State Paper Company, Jefferson Smurfit Group plc and Packaging Corporation of America. Previously, he served as a director of Buckeye Technologies, Inc. and HomeSide, Inc. Prior to joining Madison Dearborn Partners, he was with First Chicago Venture Capital for seven years.

Pierre F. Lapeyre, Jr. has served as a director of our general partner since June 17, 2003. He is a founder of Riverstone Holdings, LLC where he has served as a Managing Director since May 2000. He serves as a member of the board of directors of Legend Natural Gas, L.P., InTank, Inc. and CDM Resource Management, Ltd. He is also a member of the board of directors of Seabulk International Inc., where he serves on the compensation committee. Prior to joining Riverstone Holdings, Mr. Lapeyre spent 14 years with Goldman, Sachs & Co. where he served as a Managing Director of the Global Energy and Power Group. During his investment banking career at Goldman, Sachs & Co., he focused on energy and power, particularly the midstream/infrastructure, oil service and technology sectors.

James R. Montague has served as a director of our general partner since November 21, 2003. He is also a director of the general partner of Penn Virginia Resource Partners. From December 2001 to October 2002, Mr. Montague served as President of AEC Gulf of Mexico, Inc., a subsidiary of Alberta Energy Company, Ltd., which is involved in oil and gas exploration and production. From 1996 to June 2001, he served as President of two subsidiaries of International Paper Company, IP Petroleum Company, an oil and gas exploration and production company, and GCO Minerals Company, a company that manages International Paper Company's mineral holdings.

George A. O'Brien, Jr. has served as a director of our general partner since December 12, 2003. He is Senior Vice President of Forest Products for International Paper Company and is responsible for its forestry and wood products businesses. His responsibilities during his 16-year tenure at International Paper have included corporate development, chief financial officer of its New Zealand subsidiary and operations management. Prior to joining International Paper in 1988, he was an investment banker in the energy divisions of Smith Barney and E.F. Hutton. Mr. O'Brien has also served in senior-level financial management positions, including vice president and treasurer of Transco Energy Company.

Mark G. Papa has served as a director of our general partner since July 21, 2003. He has served as Chairman of EOG Resources Inc., an independent exploration and production company, since August 1999, where he also has served as Chief Executive Officer, a director since September 1998 and as President since December 1996. He serves as a member of the board of directors of Oil States International, Inc. and Chairman of the U.S. Oil and Gas Association. In 1981, Mr. Papa joined Belco Petroleum Corporation, predecessor company to EOG Resources.

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United States federal income tax considerations

The following discussion summarizes the material U.S. federal income tax considerations that may be relevant to the acquisition, ownership and disposition of the notes. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the "Code"), applicable Treasury Regulations promulgated thereunder, judicial authority and administrative interpretations, as of the date of this document, all of which are subject to change, possibly with retroactive effect, or are subject to different interpretations. We cannot assure you that the Internal Revenue Service, or IRS, will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal tax consequences of acquiring, holding or disposing of the notes.

In this discussion, we do not purport to address all tax considerations that may be important to a particular holder in light of the holder's circumstances, or to certain categories of investors that may be subject to special rules, such as financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, U.S holders whose functional currency is not the U.S. dollar, U.S. expatriates, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction. This discussion is limited to holders who purchase the notes in this offering and who hold the notes as capital assets (within the meaning of section 1221 of the Code). This discussion also does not address the tax considerations arising under the laws of any foreign, state, local, or other jurisdiction. We intend to treat the notes as indebtedness for federal income tax purposes, and the U.S. federal income tax considerations described below are based on that characterization.

Investors considering the purchase of notes are urged to consult their own tax advisors regarding the application of the U.S. federal income tax laws to their particular situations and the applicability and effect of state, local or foreign tax laws and tax treaties.

Tax consequences to U.S. holders

You are a "U.S. holder" for purposes of this discussion if you are a beneficial owner of a note and you are for U.S. federal income tax purposes:

•: an individual who is a U.S. citizen or U.S. resident alien;
•: a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
•: an estate whose income is subject to U.S. federal income taxation regardless of its source; or
•: a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

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If a partnership holds notes, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership acquiring the notes, you are urged to consult your own tax advisor about the U.S. federal income tax consequences of acquiring, holding and disposing of the notes.

Interest on the notes

The notes are not expected to be issued with "original issue discount" for U.S. federal income tax purposes. Accordingly, if you are a U.S. holder, you will generally be required to recognize as ordinary income any interest paid or accrued on the notes, in accordance with your regular method of accounting for federal income tax purposes.

Disposition of the notes

You will generally recognize capital gain or loss on the sale, redemption, exchange, retirement or other taxable disposition of a note. This gain or loss will equal the difference between your adjusted tax basis in the note and the proceeds you receive, excluding any proceeds attributable to accrued interest which will be recognized as ordinary interest income to the extent you have not previously included the accrued interest in income. The proceeds you receive will include the amount of any cash and the fair market value of any other property received for the note. Your adjusted tax basis in the note will generally equal the amount you paid for the note less any principal payments received. The gain or loss will be long-term capital gain or loss if you held the note for more than one year. Long-term capital gains of individuals, estates and trusts currently are taxed at a maximum rate of 15%. The deductibility of capital losses may be subject to limitation.

Information reporting and backup withholding

Information reporting will apply to payments of interest and principal on, or the proceeds of the sale or other disposition of, notes held by you, and backup withholding (currently at a rate of 28%) may apply to payments of interest unless you provide the appropriate intermediary with a taxpayer identification number, certified under penalties of perjury, as well as certain other information or otherwise establish an exemption from backup withholding. Any amount withheld under the backup withholding rules is allowable as a credit against your U.S. federal income tax liability, if any, and a refund may be obtained if the amounts withheld exceed your actual U.S. federal income tax liability and you provide the required information or appropriate claim form to the IRS.

Tax consequences to non-U.S. holders

You are a "non-U.S. holder" for purposes of this discussion if you are a beneficial owner of notes and you are not a U.S. holder.

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Interest on the notes

If you are a non-U.S. holder, payments of interest on the notes generally will be exempt from withholding of U.S. federal income tax under the "portfolio interest" exemption if you properly certify as to your foreign status as described below, and:

•: you do not own, actually or constructively, 10% or more of our capital or profits interests; and
•: you are not a "controlled foreign corporation" that is related to us.

The portfolio interest exemption and several of the special rules for non-U.S. holders described below generally apply only if you appropriately certify as to your foreign status. You can generally meet this certification requirement by providing a properly executed IRS Form W-8BEN or appropriate substitute form to us, or our paying agent. If you hold the notes through a financial institution or other agent acting on your behalf, you may be required to provide appropriate certifications to the agent. Your agent will then generally be required to provide appropriate certifications to us or our paying agent, either directly or through other intermediaries. Special rules apply to foreign partnerships, estates and trusts, and in certain circumstances certifications as to foreign status of partners, trust owners or beneficiaries may have to be provided to us or our paying agent. In addition, special rules apply to qualified intermediaries that enter into withholding agreements with the IRS.

If you cannot satisfy the requirements described above, payments of interest made to you will be subject to the 30% U.S. federal withholding tax, unless you provide us with a properly executed IRS Form W-8BEN (or successor form) claiming an exemption from (or a reduction of) withholding under the benefit of a tax treaty, or the payments of interest are effectively connected with your conduct of a trade or business in the United States and you meet the certification requirements described below. Please read "Income or Gain Effectively Connected With a U.S. Trade or Business."

Disposition of notes

You generally will not be subject to U.S. federal income tax on any gain realized on the sale, redemption, exchange, retirement or other taxable disposition of a note unless:

•: the gain is effectively connected with the conduct by you of a U.S. trade or business (or in the case of an applicable tax treaty, attributable to your permanent establishment in the United States);
•: you are an individual who has been present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met; or
•: you were a citizen or resident of the United States and are subject to special rules that apply to certain expatriates.

Income or gain effectively connected with a U.S. trade or business

The preceding discussion of the tax consequences of the purchase, ownership and disposition of notes by you generally assumes that you are not engaged in a U.S. trade or business. If any interest on the notes or gain from the sale, exchange or other taxable disposition of the notes

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is effectively connected with a U.S. trade or business conducted by you, (or in the case of an applicable treaty, attributable to your permanent establishment in the United States) then the income or gain will be subject to U.S. federal income tax at regular graduated income tax rates, but will not be subject to withholding tax if certain certification requirements are satisfied. You can generally meet the certification requirements by providing a properly executed IRS Form W-8ECI or appropriate substitute form to us, or our paying agent. If you are a corporation, that portion of your earnings and profits that is effectively connected with your U.S. trade or business (or in the case of an applicable tax treaty, attributable to your permanent establishment in the United States) also may be subject to a "branch profits tax" at a 30% rate, although an applicable tax treaty may provide for a lower rate.

U.S. federal estate tax

If you are an individual and qualify for the portfolio interest exemption under the rules described above, the notes will not be included in your estate for U.S. federal estate tax purposes unless the income on the notes is, at the time of your death, effectively connected with your conduct of a trade or business in the United States.

Information reporting and backup withholding

Payments to non-U.S. holders of interest on a note, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to you.

United States backup withholding tax generally will not apply to payments of interest and principal on a note to a non-U.S. holder if the statement described in "Tax consequences to non-U.S. holders—Interest on the notes" is duly provided by the holder or the holder otherwise establishes an exemption, provided that we do not have actual knowledge or reason to know that the holder is a United States person.

Payment of the proceeds of a sale of a note effected by the U.S. office of a U.S. or foreign broker will be subject to information reporting requirements and backup withholding unless you properly certify under penalties of perjury as to your foreign status and certain other conditions are met or you otherwise establish an exemption. Information reporting requirements and backup withholding generally will not apply to any payment of the proceeds of the sale of a note effected outside the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that you are a non-U.S. holder and certain other conditions are met, or you otherwise establish an exemption, information reporting will apply to a payment of the proceeds of the sale of a note effected outside the United States by such a broker if it:

•: is a United States person;
•: derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States;
•: is a controlled foreign corporation for U.S. federal income tax purposes; or
•: is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business.

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Any amount withheld under the backup withholding rules may be credited against your U.S. federal income tax liability and any excess may be refundable if the proper information is provided to the IRS.

The preceding discussion of material U.S. federal income tax considerations is for general information only and is not tax advice. We urge each prospective investor to consult its own tax advisor regarding the particular federal, state, local and foreign tax consequences of purchasing, holding, and disposing of our notes, including the consequences of any proposed change in applicable laws.

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Subject to Completion, dated May 17, 2004

We will amend and complete the information in this prospectus supplement. This preliminary prospectus supplement and the prospectuses are part of effective registration statements filed with the Securities and Exchange Commission. This preliminary prospectus supplement and the prospectuses are not offers to sell nor solicitations of offers to buy these securities in any jurisdiction where such offer or sale is not permitted.

PROSPECTUS SUPPLEMENT
(To Prospectuses dated May 16, 2002 and November 3, 2003)

3,000,000 Common Units

Representing Limited Partner Interests

We are selling 1,000,000 common units and Magellan Midstream Holdings, L.P., the selling unitholder, is selling 2,000,000 common units with this prospectus supplement and the accompanying prospectuses dated May 16, 2002 and November 3, 2003. Our common units trade on the New York Stock Exchange under the symbol "MMP." The last reported sales price of our common units on the New York Stock Exchange on May 14, 2004 was $50.03 per common unit.

Investing in the common units involves risk. See "Risk Factors" beginning on page S-11 of this prospectus supplement and on page 2 of each of the accompanying prospectuses.

	Per Common Unit	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling unitholder (before expenses)	$	$

The selling unitholder has granted the underwriters a 30-day option to purchase up to 450,000 common units on the same terms and conditions as set forth above to cover over-allotments of common units.

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 prospectuses are truthful or complete. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about May , 2004.

Joint Book-Running Managers

LEHMAN BROTHERS GOLDMAN, SACHS & CO.

CITIGROUP

MORGAN STANLEY

UBS INVESTMENT BANK

WACHOVIA SECURITIES

May , 2004

SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectuses. You should read the entire prospectus supplement, the accompanying prospectuses, 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-11 of this prospectus supplement and page 2 of each of the accompanying prospectuses for more information about important factors that you should consider before buying common units in this offering. Unless we indicate otherwise, the information we present in this prospectus supplement assumes that we will consummate the senior notes offering described below in "—Overview of Our Refinancing Plan" and that the underwriters do not exercise their over-allotment option. As used in this prospectus supplement and the accompanying prospectuses, 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.

Our asset portfolio currently consists of:

•: a 6,700-mile petroleum products pipeline system, including 39 petroleum products terminals, serving the mid-continent region of the United States;
•: five petroleum products terminal facilities located along the Gulf Coast and near the New York harbor, referred to as "marine terminal facilities";
•: 29 petroleum products terminals (three of which we partially own) located principally in the southeastern United States, referred to as "inland terminals"; and
•: an 1,100-mile ammonia pipeline system, including six ammonia terminals, serving the mid-continent region of the United States.

Our petroleum products pipeline system is a common carrier pipeline that provides transportation, storage and distribution services for petroleum products and liquefied petroleum gases, or LPGs, in 11 states from Oklahoma through the Midwest to North Dakota, Minnesota and Illinois. This system generates revenues principally from tariffs regulated by the Federal Energy Regulatory Commission, or FERC, based on the volumes transported and also from storage and other ancillary fees. 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. 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.

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Our marine terminal facilities and inland terminals store and distribute gasoline and other petroleum products throughout 11 states. Our inland terminals are part of a distribution network 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 marine terminal facilities are large storage terminals that principally serve refiners, marketers and large end-users of petroleum products and are strategically located near major refining hubs along the Gulf Coast and near the New York harbor. Our marine terminal facilities and inland terminals generate revenues principally from volume-based fees charged for storage and delivery of the gasoline and other petroleum products handled by these facilities. 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.

Our ammonia pipeline system transports and distributes ammonia from production facilities in Texas and Oklahoma to various distribution points in the Midwest for use as an agricultural fertilizer. Our ammonia pipeline system generates revenues principally from volume-based fees charged for transportation of ammonia on the pipeline system. 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.

Business Strategies

Our primary business strategies are to:

•: grow through strategic acquisitions and expansion projects that increase per unit cash flow;
•: generate stable cash flows to make quarterly cash distributions; and
•: 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:

•: our assets are strategically located in areas with high demand for our services;
•: we have little direct commodity price exposure;
•: we have long-term relationships with many of our customers that utilize our pipeline and terminal assets;
•: we have a strong financial position with additional borrowing capacity and cash reserves available for making acquisitions and completing expansion projects; and
•: our senior management has extensive industry experience.

Overview of Our Refinancing Plan

•: the issuance of 1.0 million common units by us in this offering 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 units), including our general partner's related capital contribution; and

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•: our proposed $250.0 million senior notes offering.

The combined net proceeds to us from our common unit and proposed senior notes 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, LLC 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 common unit offering is not conditioned upon the consummation of our proposed senior notes offering. If we do not consummate our proposed senior notes offering, we will use the net proceeds from our common unit offering to replenish cash used to fund recent acquisitions or repay a portion of the amount outstanding under our term loan. For more information about our refinancing plan, please read "Use of Proceeds," "Capitalization" and "Our Refinancing Plan" on page S-12, S-13 and S-15, respectively.

Although not part of our refinancing plan, the selling unitholder is selling 2.0 million common units together with our offering of 1.0 million common units. We will not receive any proceeds from the selling unitholder's 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. The distribution was paid 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 the selling unitholder 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

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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.

Partnership Structure and Management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. Upon consummation of this offering of our common units:

•: There will be 20,775,000 publicly held common units outstanding, representing a 71.7% limited partner interest in us;
•: 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
•: 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, The Williams Companies, Inc., or 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.

The chart on the following page depicts our organizational and ownership structure after giving effect to this offering. The percentages reflected in the organizational chart represent the approximate ownership interests in us and our operating subsidiaries.

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The Offering

Common units offered by us	1,000,000 common units.
Common units offered by the selling unitholder	2,000,000 common units; 2,450,000 common units if the underwriters exercise their over-allotment option in full.
Units outstanding after this offering	24,130,541 common units and 4,259,771 subordinated units.
Use of proceeds	We will use the net proceeds from the common units we are offering and our general partner's related capital contribution, together with the net proceeds from our proposed senior notes offering, to:
	•	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;
	•	repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility;
	•	pay $1.9 million to Magellan Pipeline Company's Series B noteholders to release the collateral held by them;
	•	replenish cash used to fund our recent acquisitions; and
	•	pay various fees and expenses in connection with our refinancing plan.
	We will not receive any proceeds from the common units sold by the selling unitholder or any exercise of the underwriters' over-allotment option.
Cash distributions	Under our partnership agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our general partner. We refer to this cash as "available cash," and we define it in our partnership agreement.
	We declared a quarterly cash distribution for the first quarter of 2004 of $0.85 per common and subordinated unit, or $3.40 on an annualized basis. We paid this cash distribution on May 14, 2004 to unitholders of record at the close of business on May 3, 2004.
	When our quarterly cash distributions exceed $0.578 per unit in any given quarter, our general partner receives a higher percentage of the cash distributed in excess of that amount, in increasing percentages up to 50% if the quarterly cash distributions exceed $0.788 per unit. For a description of our cash distribution policy, please read "Cash Distributions" in each of the accompanying prospectuses.
Subordination period	The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before December 31, 2005.

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		When the subordination period ends, all remaining subordinated units will convert into common units, and the common units will no longer be entitled to arrearages.
Early conversion of subordinated units		We met the financial tests in our partnership agreement for the quarter ending on December 31, 2003 for the early conversion of a portion of our subordinated units. As a result, on February 7, 2004, 25%, or 1,419,923, of our subordinated units converted into common units. If we meet these tests for any quarter ending on or after December 31, 2004, an additional 25% of the subordinated units will convert into common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.
Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for the distribution for the fourth calendar quarter of 2006, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed with respect to that period. Please read "Tax Considerations" in this prospectus supplement for the basis of this estimate.
New York Stock Exchange symbol		MMP

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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 our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations," which has been filed with the SEC and is incorporated by reference.

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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			Year Ended December 31,									Three Months Ended March 31,
			2001			2002			2003			2003			2004
			($ in thousands, except per unit amounts)
Income Statement Data:
Transportation and terminals revenues			$	339,412		$	363,740		$	372,848		$	87,714		$	88,930
Product sales revenues				108,169			70,527			112,312			32,001			44,214
Affiliate construction and management fee revenues				1,018			210			—			—			—

	Total revenues			448,599			434,477			485,160			119,715			133,144

Operating expenses including environmental expenses net of indemnifications				160,880			155,146			166,883			33,970			37,790
Product purchases				95,268			63,982			99,907			27,818			38,499
Equity earnings(a)				—			—			—			—			(120	)

	Operating margin			192,451			215,349			218,370			57,927			56,975
Depreciation and amortization				35,767			35,096			36,081			9,379			9,522
General and administrative				47,365			43,182			56,846			10,438			12,887

	Operating profit			109,319			137,071			125,443			38,110			34,566
Interest expense, net				12,113			21,758			34,536			8,505			8,069
Debt placement fees amortization				253			9,950			2,830			547			682
Other income, net				(431	)		(2,112	)		(92	)		—			—

	Income before income taxes			97,384			107,475			88,169			29,058			25,815
Provision for income taxes(b)				29,512			8,322			—			—			—

	Net income		$	67,872		$	99,153		$	88,169		$	29,058		$	25,815

	Basic net income per limited partner unit		$	1.87		$	3.68		$	3.32		$	0.99		$	0.87

	Diluted net income per limited partner unit		$	1.87		$	3.67		$	3.31		$	0.99		$	0.87

Balance Sheet Data:
Working capital (deficit)			$	(2,211	)	$	47,328		$	77,438		$	(30,479	)	$	32,160
Total assets				1,104,559			1,120,359			1,194,930			1,132,549			1,209,433
Total debt				139,500			570,000			570,000			570,000			570,000
Affiliate long-term note payable(c)				138,172			—			—			—			—
Partners' capital				589,682			451,757			498,149			464,040			497,778
Cash Flow Data:
Cash distributions declared per unit(d)			$	2.02		$	2.71		$	3.17		$	0.75		$	0.85
Other Data:
Operating margin:
	Petroleum products pipeline system		$	143,711		$	163,233		$	162,494		$	41,202		$	40,326
	Petroleum products terminals			38,240			43,844			46,909			16,167			13,381
	Ammonia pipeline system			10,500			8,272			8,094			558			2,613
	Allocated partnership depreciation costs			—			—			873			—			655

		Operating margin	$	192,451		$	215,349		$	218,370		$	57,927		$	56,975

EBITDA:
	Net income		$	67,872		$	99,153		$	88,169		$	29,058		$	25,815
	Income taxes(b)			29,512			8,322			—			—			—
	Debt placement fee amortization			253			9,950			2,830			547			682
	Interest expense, net			12,113			21,758			34,536			8,505			8,069
	Depreciation and amortization			35,767			35,096			36,081			9,379			9,522

		EBITDA(e)	$	145,517		$	174,279		$	161,616		$	47,489		$	44,088

Operating Statistics:
Petroleum products pipeline system:
	Transportation revenues per barrel shipped (cents per barrel)			90.8			94.9			96.4			98.0			97.2
	Transportation barrels shipped (millions)			236.1			234.6			237.6			52.7			52.8
	Barrel miles (billions)			70.5			71.0			70.5			15.8			14.9
Petroleum products terminals:
	Marine terminal average storage capacity utilized per month (million barrels)			15.7			16.2			15.2			15.8			15.5
	Marine terminal throughput (million barrels)(f)			11.5			20.5			22.2			5.3			5.5
	Inland terminal throughput (million barrels)			56.7			57.3			61.2			12.6			20.5
Ammonia pipeline system:
	Volume shipped (thousand tons)			763			712			614			47			219

Footnotes on following page.

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(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.
(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 common units involves a high degree of risk. You should carefully read the risk factors set forth below, the risk factors included under the caption "Risk Factors" beginning on page 2 of each of the accompanying prospectuses, and those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, which is incorporated by reference.

The sale or exchange of 50% or more of our capital and profit interests will result in the termination of our partnership for federal income tax purposes.

The common units offered by the selling unitholder in this offering, excluding any common units sold upon exercise of the underwriters' over-allotment option, represent an approximate 7% interest in our capital and profits for tax purposes. In late December 2003 and early January 2004, the selling unitholder also sold 4,975,000 common units, which represented an approximate 18% interest in our capital and profits for tax purposes. We will be considered to have been terminated for federal income tax purposes if the common units sold by the selling unitholder, together with all common units sold within a 12-month period, which includes this offering, represent a sale or exchange of 50% or more of our capital and profits interests. Our termination for tax purposes would, among other things, result in a significant deferral of the depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. For a discussion of the consequences of our termination for federal income tax purposes, please read "Material Tax Consequences—Dispositions of Common Units—Constructive Termination" in the accompanying prospectuses.

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

Such conflicts may include, among others, the following:

•: 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;
•: 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 to receive net proceeds of approximately $48.7 million from the sale of the 1,000,000 common units we are 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 expect the net proceeds of our proposed senior notes offering to be approximately $247.5 million, after deducting underwriting discounts and the estimated offering expenses. We will not receive any proceeds from the sale of common units by the selling unitholder or any exercise of the underwriters' over-allotment option.

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

•: 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;
•: repay the $90.0 million outstanding principal balance of the term loan under our existing credit facility;
•: pay $1.9 million to Magellan Pipeline Company's Series B noteholders to release the collateral held by them;
•: replenish cash used to fund our recent acquisitions; and
•: pay various fees and expenses in connection with our refinancing plan.

Our common unit offering is not conditioned upon the consummation of our proposed senior notes offering. If we do not consummate our proposed senior notes offering, we will use the net proceeds from our common unit offering of approximately $48.7 million, including our general partner's related capital contribution, to replenish cash used to fund recent acquisitions or to repay a portion of the amount outstanding under our term loan. As a result, we would not be able to complete all of the transactions related to our refinancing plan concurrently with the closing of our common unit offering.

S-12

CAPITALIZATION

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

•: on a historical basis;
•: as adjusted to give effect to the sale of common units offered by us, our general partner's related capital contribution 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 senior notes offering and the application of the net proceeds therefrom.

We expect the net proceeds from the common units offered by us and our general partner's related capital contribution to be approximately $48.7 million (based on 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 the underwriting discount and estimated offering expenses payable by us. We expect the proceeds from our proposed senior notes offering to be approximately $247.5 million, after deducting the underwriting discount and estimated offering expenses payable by us. Please read "Use of Proceeds."

		As of March 31, 2004
		Historical		As Adjusted for this Offering(a)		As Further Adjusted for Our Proposed Senior Notes Offering(b)
		(unaudited) ($ in thousands)
Cash and cash equivalents		$	43,891	$	43,891	$	56,768

Debt:
	Credit facility	$	90,000	$	41,315	$	—
	Magellan Pipeline Company Series A senior notes		178,000		178,000		—
	Magellan Pipeline Company Series B senior notes		302,000		302,000		302,000
	% Senior Notes due 2014		—		—		250,000

Total debt		$	570,000	$	521,315	$	552,000
Total partners' capital			497,778		546,463		528,764

Total capitalization		$	1,067,778	$	1,067,778	$	1,080,764

(a): This table assumes that we will use the net proceeds from our common unit offering and our general partner's related capital contribution to repay approximately $48.7 million of the $90.0 million outstanding principal balance under our existing term loan. We will repay the remaining outstanding indebtedness under our existing term loan using the proceeds from our proposed senior notes offering. If we do not consummate our proposed senior notes offering, we will use net proceeds from our common unit offering to replenish cash used to fund recent acquisitions or repay a portion of the amount outstanding under our term loan.
(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.

S-13

OUR REFINANCING PLAN

•: the issuance of 1.0 million common units by us in this offering with expected net proceeds of approximately $48.7 million, including our general partner's related capital contribution; and
•: our proposed $250.0 million senior notes offering.

The combined net proceeds from our common unit and senior notes 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 Magellan Pipeline Company, 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 common unit offering is not conditioned upon the consummation of our proposed senior notes offering. If we do not consummate our proposed senior notes offering, we will use the net proceeds from our common unit offering of approximately $48.7 million and our general partner's related capital contribution to replenish cash used to fund recent acquisitions or to repay a portion of the amount outstanding under our term loan. As a result, we would not be able to complete all of the transactions related to our refinancing plan concurrently with the closing of this offering.

Our Senior Notes Offering

In connection with the repayment of our existing credit facility and the repayment of the Magellan Pipeline Company senior notes, we are offering in a separate registered public offering up to $250.0 million in aggregate principal amount of senior notes due 2014.

The notes will be our senior unsecured obligations and will rank equally with all our other existing and future senior indebtedness, including indebtedness under our revolving credit facility.

We will cause any of our existing and future subsidiaries that guarantees or becomes a co-obligor in respect of any of our funded debt to equally and ratably guarantee the notes.

We will issue the notes under an indenture with SunTrust Bank, as trustee. The indenture does not limit the amount of unsecured debt we may incur. The indenture will contain limitations on, among other things, our ability to:

•: incur indebtedness secured by certain liens;
•: engage in certain sale-leaseback transactions; and

S-14

•: consolidate, merge or transfer all or substantially all of our assets.

The indenture will provide for certain events of default, including default on certain other indebtedness.

We may redeem some or all of the notes at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest, if any, to the redemption date.

For a description of the use of proceeds from both our proposed senior notes offering and this offering, please read "Use of Proceeds" on page S-12 of this prospectus supplement.

Our New 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.

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 and 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

S-15

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 senior notes 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.

S-16

TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units, please read "Material Tax Consequences" in the accompanying prospectuses. You are urged to consult with your own tax advisor about the federal, state and local tax consequences peculiar to your circumstances.

We estimate that if you purchase common units in this offering and own them through the record date for the distribution for the fourth quarter of 2006, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed with respect to that period. These estimates are based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of our common units in an amount of at least the current quarterly distribution of $0.85 per unit and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and certain tax reporting positions that we have adopted with which the Internal Revenue Service could disagree. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. See "Material Tax Consequences" in the accompanying prospectuses.

Ownership of common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. Please read "Material Tax Consequences—Tax-Exempt Organizations and Other Investors" in the accompanying prospectuses.

Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction." You may be required to file this form with the Internal Revenue Service if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As described in the accompanying prospectuses, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and furnish this information to the Internal Revenue Service upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment, and you should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

The top marginal income tax rate for individuals is currently 35%. In general, net capital gains of an individual are subject to a maximum 15% tax rate if the asset disposed of was held for more than 12 months at the time of disposition.

In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the implementation of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, our cash available for distribution would be reduced.

S-18

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		MAGELLAN MIDSTREAM PARTNERS, L.P.
		By:	Magellan GP, LLC, as general partner
		By:	/s/ SUZANNE H. COSTIN Suzanne H. Costin Corporate Secretary

Date: May 17, 2004

QuickLinks

EXPLANATORY NOTE
Summary
Magellan Midstream Partners, L.P.
The offering
Summary selected financial and operating data
Risk factors
Use of proceeds
Capitalization
Our refinancing plan
Management's discussion and analysis of financial condition and results of operations
Description of notes
Management
United States federal income tax considerations
SUMMARY
Magellan Midstream Partners, L.P.
The Offering
Summary Selected Financial and Operating Data
RISK FACTORS
USE OF PROCEEDS
CAPITALIZATION
OUR REFINANCING PLAN
TAX CONSIDERATIONS
SIGNATURES