Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

Use these links to rapidly review the document
TABLE OF CONTENTS

Filed pursuant to Rule 424(b)(3)
Registration No. 333-083952

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

Tables of contents

Prospectus supplement
Summary		S-1
Risk factors		S-16
Ratio of earnings to fixed charges		S-19
Use of proceeds		S-20
Capitalization		S-21
Our refinancing plan		S-22
Management's discussion and analysis of financial condition and results of operations		S-24
Description of notes		S-50
Management		S-65
United States federal income tax considerations		S-68
Underwriting		S-73
Legal		S-75
Experts		S-75
Information regarding forward-looking statements		S-75
Where you can find more information		S-77
Prospectus
About this prospectus		1
About Williams Energy Partners		1
The subsidiary guarantors		1
Risk factors		2
Where you can find more information		10
Forward-looking statements and associated risks		11
Use of proceeds		12
Ratio of earnings to fixed charges		12
Description of debt securities		13
Description of our Class B Units		23
Cash distributions		24
Material tax consequences		32
Investment in us by employee benefit plans		46
Plan of distribution		47
Legal		47
Experts		47

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of notes. The second part is the accompanying prospectus, which gives more general information about the debt securities we may offer from time to time. Generally, when we refer to the prospectus, we are referring to both parts of this document combined, some of which may not apply to the notes.

If the information about the offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.

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

S-1

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

S-2

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

S-3

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

S-4

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.

S-5

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.

S-6

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.

S-7

S-8

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.

S-9

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.

S-10

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.

S-11

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.

S-12

		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)

S-13

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.

S-14

(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.

S-15

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.

S-16

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.

S-17

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.

S-18

Ratio of earnings to fixed charges

The ratio of earnings to fixed charges for each of the periods indicated is as follows:

	Twelve months ended December 31,

	Twelve months ended December 31,							Three months ended March 31, 2004
	1999	2000	2001		2002		2003	Three months ended March 31, 2004

Ratio of earnings to fixed charges	5.3x	3.8x	7.2x	(a)	4.2x	(b)	3.2x	3.7x

(a): At the time of our initial public offering in February 2001, an affiliate note payable of approximately $59.7 million associated with our petroleum products terminals operations was contributed to us as a capital contribution by an affiliate of Williams.
(b): At the closing of our acquisition of Magellan Pipeline Company in April 2002, its affiliate note payable of approximately $106.2 million was contributed to us as a capital contribution by an affiliate of Williams.

For purposes of calculating the ratio of earnings to fixed charges:

•: "fixed charges" represent interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor; and
•: "earnings" represent the aggregate of income from continuing operations (before adjustment for minority interest, extraordinary loss and equity earnings), fixed charges and distributions from equity investment, less capitalized interest.

S-19

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.

S-20

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.

S-22

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.

S-23

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

S-26

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.

S-27

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

•: $0.6 million of reimbursable transition costs associated with the separation of our general and administrative functions from Williams, which principally included expenses during the current year related to the creation of our technology systems. These cumulative transition costs have exceeded the $5.9 million cash amount for which we are responsible. As a result, the amounts in excess of $5.9 million represent a non-cash charge to us and have been recorded as a capital contribution by our general partner;
•: $1.1 million of general and administrative costs that will be reimbursed by our general partner. Our general partner provides general and administrative services to us for an established amount, which was $10.1 million for first quarter 2004. The owner of our general partner is responsible for general and administrative expenses in excess of this cap up to a certain amount. We record total general and administrative costs, including those costs above the cap amount that are reimbursed by the owner of our general partner, as an expense, and we record this amount in excess of the cap for which we are reimbursed as a capital contribution by our general partner. When our general partner was owned by Williams, we were unable to identify specific costs required to support our operations. As a result, we recorded as expense only the general and administrative costs under the cap, which reflected our actual cash costs. As a result of the change in our organization structure following Magellan Midstream Holdings' acquisition of our general partner's membership interests from Williams in June 2003, we are now able to clearly identify all general and administrative costs required to support ourselves. The actual cash general and administrative costs we incur continue to be limited to the general and administrative cap; and
•: $0.7 million of incremental general and administrative costs associated with an annual escalation factor and costs associated with completed acquisitions. As agreed with our general partner, the amount of general and administrative costs we incur will increase on an annual basis by 7% until we are fully funding our general and administrative cost. In addition, we are responsible for incurring incremental general and administrative costs associated with completed acquisitions.

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

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

S-28

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

				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

S-29

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

•: an increase in petroleum products pipeline system revenues of $8.9 million, or 3%, primarily attributable to a higher weighted-average tariff and increased volumes during the current period. The higher transportation rates per barrel principally resulted from tariff increases during July 2002 and April 2003. Tariff adjustments generally occur during July of each year, as allowed by FERC. However, the April 2003 increase was allowed by FERC due to a change to the mid-year FERC-defined tariff calculation. The incremental volume resulted from the short-term refinery production decreases in the mid-continent region of the U.S. These production decreases resulted in substitute volumes from alternative sources moving through our pipeline system. Further, increased revenues from higher data service fees as well as greater capacity lease utilization and other ancillary revenues benefited the current year;
•: an increase in petroleum products terminals revenues of $0.8 million, or 1%, primarily due to increased throughput at our inland terminals as volumes of a former affiliate were more than replaced with higher volumes from third-party customers. Utilization at the Gulf Coast marine facilities was lower between the two periods due to the termination of a former affiliate's storage agreement at our Galena Park, Texas facility during the first quarter of 2003. Increased revenues from the $3.0 million settlement we received were more than offset by the resulting reduced storage utilization; and
•: a decrease in ammonia pipeline system revenues of $0.5 million, or 4%, primarily due to significantly reduced transportation volumes during the first quarter of 2003 resulting from extremely high prices for natural gas, the primary component in the production of ammonia. Partially offsetting this volume decline was a higher weighted-average tariff in 2003.

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

•: an increase in petroleum products pipeline system expenses of $13.8 million, or 12%, in part due to a $2.6 million affiliate paid-time off benefits accrual. Operating expenses further increased due to the retirement of assets and increased costs for tank maintenance and pipeline testing associated with the ongoing implementation of our system integrity program. Increased power costs resulting from higher transportation volumes and power rates as well as higher ad valorem taxes also resulted in greater costs during 2003;
•: a decrease in petroleum products terminals expenses of $0.8 million, or 2%, primarily due to reduced maintenance expenses resulting from efficiency projects that lowered contract labor and repair costs. Timing of tank inspection and cleaning further resulted in reduced maintenance expenses during 2003. These positive variances were partially

S-30

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

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

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

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

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

•

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

•: $3.7 million was associated with the separation of our general and administrative functions from Williams, which primarily included the creation of our information technology systems and benefits programs;
•: $2.1 million was related to recording an affiliate paid-time off benefits liability associated with general and administrative employees; and
•: $1.6 million was associated with the early vesting of units granted under our 2001 and 2002 equity-based incentive compensation plan resulting from the change in control of our general partner.

•

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

S-31

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

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

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

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

S-32

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

S-33

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.

S-34

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.

S-35

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;

S-40

•: 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,

S-41

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.

S-42

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.

S-43

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

S-44

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

S-45

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

S-46

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.

S-47

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

S-48

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.

S-49

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;

S-50

•: 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

S-51

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.

S-52

"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.

S-53

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.

S-54

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;

S-55

•: 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,

S-56

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.

S-57

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;

S-58

•: 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

S-59

•: 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

S-60

•: 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.

S-61

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.

S-62

"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;

S-63

•: 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.

S-64

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.

S-65

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

S-66

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.

S-67

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.

S-68

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.

S-69

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

S-70

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.

S-71

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.

S-72

Underwriting

J.P. Morgan Securities Inc. and Lehman Brothers Inc. are acting as joint book-running managers of the offering and as representatives of the underwriters named below.

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, each underwriter named below has agreed to purchase severally, and we have agreed to sell to that underwriter, the principal amount of notes set forth opposite the underwriter's name.

Name		Principal amount of notes


J.P. Morgan Securities Inc.		$
Lehman Brothers Inc.
Citigroup Global Markets Inc.
Scotia Capital Markets (USA) Inc.
SunTrust Capital Markets, Inc.

	Total	$	250,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the notes included in this offering are subject to the approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the notes if they purchase any of the notes.

The underwriters propose to offer some of the notes directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the notes to dealers at the public offering price less a concession not to exceed % of the principal amount. The underwriters may allow and dealers may reallow a concession to certain other dealers not to exceed % of the principal amount. After the initial offering of the notes to the public, the representative may change the public offering price and concessions.

In connection with the offering, the underwriters may purchase and sell notes in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves syndicate sales of notes in excess of the principal amount of notes to be purchased by the underwriters in the offering, which creates a syndicate short position. Syndicate covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover syndicate short positions. Stabilizing transactions consist of certain bids or purchases of notes made for the purpose of preventing or retarding a decline in the market price of the notes while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the syndicate member, in covering syndicate short positions or making stabilizing purchases, repurchases notes originally sold by that syndicate member.

Any of these activities may have the effect of preventing or retarding a decline in the market price of the notes. They may also cause the price of the notes to be higher than the price that otherwise would exist in the open market in the absence of these transactions. The

S-73

underwriters may conduct these transactions in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

We estimate that our total expenses for this offering will be approximately $0.6 million.

J.P. Morgan Securities Inc. and Lehman Brothers Inc. will make the notes available for distribution on the Internet through a proprietary Web site and/or a third-party system operated by Market Axess Inc., an Internet-based communications technology provider. Market Axess Inc. is providing the system as a conduit for communications between J.P. Morgan Securities Inc. and Lehman Brothers Inc. and their customers and is not a party to any transactions. Market Axess Inc., a registered broker-dealer, will receive compensation from J.P. Morgan Securities Inc. and Lehman Brothers Inc. based on transactions J.P. Morgan Securities Inc. and Lehman Brothers Inc. conduct through the system. J.P. Morgan Securities Inc. and Lehman Brothers Inc. will make notes available to their customers through the Internet distributions, whether made through a proprietary or third-party system, on the same terms as distributions made through other channels.

Certain of the underwriters and their respective affiliates have performed and may continue to perform investment banking, financial advisory, trustee and lending services for us for which they receive customary fees and compensation.

The trustee for the notes, SunTrust Bank, is an affiliate of SunTrust Capital Markets, Inc., an underwriter in this offering.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

S-74

Legal

The validity of the notes will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the notes offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas. Andrews Kurth LLP also performs legal services for us from time to time unrelated to this offering.

Experts

The consolidated balance sheets of Magellan Midstream Partners, L.P. (formerly Williams Energy Partners L.P.) as of December 31, 2003 and 2002 and the related consolidated statements of income, cash flows and partners' capital for each of the years ended December 31, 2003, 2002 and 2001 appearing in Magellan Midstream Partners, L.P.'s (formerly Williams Energy Partners L.P.) Annual Report of Form 10-K for the year ended December 31, 2003 and the consolidated balance sheets of Magellan GP, LLC (formerly WEG GP LLC) as of December 31, 2003 and 2002 appearing in Magellan Midstream Partners, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2003 have been audited by Ernst & Young LLP, independent auditors, as set forth in their reports thereon, included therein and incorporated herein by reference. Such consolidated balance sheets and financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Information regarding forward-looking statements

This prospectus supplement and the documents incorporated in this prospectus supplement by reference include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond the ability of us and our affiliates to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

•: price trends and overall demand for natural gas liquids, refined petroleum products, natural gas, oil and ammonia in the United States;
•: weather patterns materially different from historical trends;
•: development of alternative energy sources;
•: changes in demand for storage in our petroleum products terminals;
•: changes in supply patterns for our marine terminals due to geopolitical events;

S-75

•: changes in our tariff rates implemented by FERC and the United States Surface Transportation Board;
•: shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;
•: changes in throughput on petroleum products pipelines owned and operated by third-parties and connected to our petroleum products terminals or petroleum products pipeline system;
•: loss of one or more of our three customers on our ammonia pipeline system;
•: changes in the federal government's policy regarding farm subsidies, which could negatively impact the demand for ammonia and reduce the amount of ammonia transported through our ammonia pipeline system;
•: an increase in the competition our operations encounter;
•: the occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured;
•: our ability to integrate any acquired operations into our existing operations;
•: our ability to successfully identify and close strategic acquisitions and expansion projects and make cost saving changes in operations;
•: changes in general economic conditions in the United States;
•: changes in laws or regulations to which we are subject, including tax and state tax withholding issues, safety, environmental and employment laws and regulations;
•: the cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;
•: the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
•: the condition of the capital markets and equity markets in the United States;
•: the ability to raise capital in a cost-effective way;
•: the effect of changes in accounting policies;
•: the ability to manage rapid growth;
•: Williams' and Magellan Midstream Holdings' ability to perform on its environmental and rights-of-way indemnifications to us;
•: the ability of our general partner to enter into certain agreements which could negatively impact our financial position, result of operations and cash flows;
•: supply disruption; and

S-76

•: global and domestic economic repercussions from terrorist activities and the government's response thereto.

You should not put undue reliance on any forward-looking statements.

When considering forward-looking statements, please review the risk factors described under "Risk factors" in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference.

Where you can find more information

The SEC allows us to "incorporate by reference" information we file with it. This procedure means that we can disclose important information to you by referring you to documents filed with the SEC. The information we incorporate by reference is part of this prospectus and later information that we file with the SEC (excluding any information furnished pursuant to Item 9 or Item 12 on any Current Report on Form 8-K) will automatically update and supersede this information. We incorporate by reference the documents listed below:

•: Annual Report on Form 10-K for the year ended December 31, 2003;
•: Quarterly Report on Form 10-Q for the quarter ended March 31, 2004;
•: Definitive Proxy Statement on Schedule 14A filed on March 10, 2004; and
•: Current Reports on Form 8-K filed on May 5, 2004 and May 17, 2004.

You may request a copy of these filings at no cost by making written or telephone requests for copies to:

Magellan Midstream Partners, L.P.
P.O. Box 22186
Tulsa, Oklahoma 74121-2186
Attention: Investor Relations Department
Telephone: (918) 574-7000

We also make available free of charge on our internet website at http: //www.magellanlp.com our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to those reports, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this prospectus.

S-77

PROSPECTUS

$1,800,000,000

WILLIAMS ENERGY PARTNERS L.P.

Common Units
Debt Securities

Guarantees of Debt Securities of Williams Energy Partners L.P. by:

Williams GP Inc.
Williams OLP, L.P.
Williams Pipe Line Company, LLC
Williams NGL, LLC
Williams Pipelines Holdings, L.P.
Williams Terminals Holdings, L.P.
Williams Ammonia Pipeline, L.P.
Williams Fractionation Holdings, L.P.

We may from time to time offer and sell common units and debt securities that may be fully and unconditionally guaranteed by our subsidiaries, Williams GP Inc., Williams OLP, L.P., Williams Pipe Line Company, LLC, Williams NGL, LLC, Williams Pipelines Holdings, L.P., Williams Terminals Holdings, L.P., Williams Ammonia Pipeline, L.P. and Williams Fractionation Holdings, L.P. This prospectus describes the general terms of these securities and the general manner in which we will offer the securities. The specific terms of any securities we offer will be included in a supplement to this prospectus. The prospectus supplement will also describe the specific manner in which we will offer the securities.

The New York Stock Exchange has listed our common units under the symbol "WEG." Our address is One Williams Center, Tulsa, Oklahoma 74172, and our telephone number is (918) 573-2000.

Limited partnerships are inherently different from corporations. You should carefully consider the risk factors beginning on page 2 of this prospectus before you make an investment in our securities.

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

The date of this prospectus is May 16, 2002.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS
ABOUT WILLIAMS ENERGY PARTNERS
THE SUBSIDIARY GUARANTORS
RISK FACTORS
	Risks Related to our Business
	Risks Related to our Partnership Structure
	Tax Risks to Common Unitholders
WHERE YOU CAN FIND MORE INFORMATION
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
USE OF PROCEEDS
RATIO OF EARNINGS TO FIXED CHARGES
DESCRIPTION OF DEBT SECURITIES
	General
	Covenants
	Events of Default, Remedies and Notice
	Amendments and Waivers
	Defeasance
	No Personal Liability of General Partner
	Subordination
	Book Entry, Delivery and Form
	The Trustee
	Governing Law
DESCRIPTION OF OUR CLASS B UNITS
CASH DISTRIBUTIONS
	Distributions of Available Cash
	Operating Surplus, Capital Surplus and Adjusted Operating Surplus
	Subordination Period
	Distributions of Available Cash from Operating Surplus During the Subordination Period
	Distributions of Available Cash from Operating Surplus After the Subordination Period
	Incentive Distribution Rights
	Percentage Allocations of Available Cash from Operating Surplus
	Distributions from Capital Surplus
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
	Distributions of Cash Upon Liquidation
MATERIAL TAX CONSEQUENCES
	Partnership Status
	Limited Partner Status
	Tax Consequences of Unit Ownership
	Tax Treatment of Operations
	Disposition of Common Units
	Uniformity of Units
	Tax-Exempt Organizations and Other Investors
	Administrative Matters
	State, Local and Other Tax Considerations
	Tax Consequences of Ownership of Debt Securities
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS
PLAN OF DISTRIBUTION
LEGAL
EXPERTS

You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone else to give you different information. We are not offering these securities in any state where they do not permit the offer. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the SEC incorporated by reference in this prospectus.

(i)

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission using a "shelf" registration process. Under this shelf registration process, we may sell up to $1.8 billion in aggregate offering price of the common units or debt securities described in this prospectus in one or more offerings. This prospectus generally describes us and the common units, debt securities and the guarantees of the debt securities. Each time we sell common units or debt securities with this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add to, update or change information in this prospectus. The information in this prospectus is accurate as of May 15, 2002. You should carefully read both this prospectus and any prospectus supplement and the additional information described under the heading "Where You Can Find More Information."

ABOUT WILLIAMS ENERGY PARTNERS

We were formed by The Williams Companies, Inc. in August 2000 to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products and ammonia. Williams GP LLC serves as our general partner and is an indirect wholly owned subsidiary of The Williams Companies, Inc.

As used in this prospectus, "we," "us," "our" and "Williams Energy Partners" mean Williams Energy Partners L.P. and, where the context requires, include our operating subsidiaries.

THE SUBSIDIARY GUARANTORS

Williams GP Inc., Williams OLP, L.P., Williams Pipe Line Company, LLC, Williams NGL, LLC, Williams Pipelines Holdings, L.P., Williams Terminals Holdings, L.P., Williams Ammonia Pipeline, L.P. and Williams Fractionation Holdings, L.P. are our only subsidiaries as of the date of this prospectus. Williams GP Inc. and Williams Pipe Line Company, LLC are wholly owned subsidiaries of Williams Energy Partners L.P. Williams GP Inc. owns a 0.001% general partner interest and Williams Energy Partners, L.P. owns a 99.999% limited partner interest in Williams OLP, L.P. Williams OLP, L.P. owns all of the membership interests in Williams NGL LLC and a 99.999% limited partner interest in each of Williams Pipelines Holdings, L.P., Williams Terminals Holdings, L.P., Williams Ammonia Pipeline, L.P. and Williams Fractionation Holdings, L.P. Williams NGL, LLC owns a 0.001% general partner interest in each of these four partnerships. We sometimes refer to Williams GP Inc., Williams OLP, L.P., Williams NGL, LLC, Williams Pipelines Holdings, L.P., Williams Terminals Holdings, L.P., Williams Ammonia Pipeline, L.P. and Williams Fractionation Holdings, L.P. in this prospectus as the "Subsidiary Guarantors." The Subsidiary Guarantors may jointly and severally and unconditionally guarantee our payment obligations under any series of debt securities offered by this prospectus, as set forth in a related prospectus supplement.

RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus, any prospectus supplement and the documents we have incorporated by reference into this document in evaluating an investment in the common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not be able to generate sufficient cash from operations to allow us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

The amount of cash we can distribute on our common units principally depends upon the cash we generate from our operations. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to pay the minimum quarterly distribution for each quarter. Our ability to pay the minimum quarterly distribution each quarter depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.

Our financial results depend on the demand for the refined petroleum products that we store and distribute.

Any sustained decrease in demand for refined petroleum products in the markets served by our terminals could result in a significant reduction in the volume of products that we store at our marine terminal facilities and in the throughput in our inland terminals, and therefore reduce our cash flow and our ability to pay cash distributions to you. Factors that could lead to a decrease in market demand include:

•: an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for gasoline and other petroleum products. Market prices for refined

petroleum products are subject to wide fluctuation in response to changes in global and regional supply over which we have no control;

•: a recession or other adverse economic condition that results in lower spending by consumers and businesses on transportation fuels such as gasoline, jet fuel and diesel;
•: higher fuel taxes or other governmental or regulatory actions that increase the cost of gasoline;
•: an increase in fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; and
•: the increased use of alternative fuel sources, such as fuel cells and solar, electric and battery-powered engines. Several state and federal initiatives mandate this increased use.

When prices for the future delivery of petroleum products that we store in our marine terminals fall below current prices, customers are less likely to store these products, thereby reducing our storage revenues.

This market condition is commonly referred to as "backwardation." When the petroleum product market is in backwardation, the demand for storage capacity at our marine terminal facilities may decrease. The forward pricing market for petroleum products moved to backwardation in the second quarter of 1999 and continued for a majority of 2000. This market condition contributed to reduced storage revenues in 1999 and 2000. In 2001, the forward pricing market remained backwardated during the first half of the year, reversing during the latter half of 2001. If this market becomes strongly backwardated for an extended period of time, it may affect our ability to pay cash distributions to you.

We depend on petroleum product pipelines owned and operated by others to supply our terminals.

Most of our inland and marine terminal facilities depend on connections with petroleum product pipelines owned and operated by third parties. Reduced throughput on these pipelines because of testing, line repair, damage to pipelines, reduced operating pressures or other causes could result in our being unable to deliver products to our customers from our terminals or receive products for storage and could adversely affect our ability to pay cash distributions to you.

Collectively, our affiliates williams energy marketing & trading company and williams refining & marketing, l.l.c. are our largest customer, and any reduction in their use of our terminal facilities could reduce our ability to pay cash distributions to you.

For the year ended December 31, 2001, our affiliates Williams Energy Marketing & Trading and Williams Refining & Marketing collectively accounted for approximately 21.0 percent of our combined historical revenues. If Williams Energy Marketing & Trading and Williams Refining & Marketing were to decrease the throughput volume they allocate to our terminals for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in throughput would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to pay cash distributions to you. Either Williams Energy Marketing & Trading or Williams Refining & Marketing could reduce the volume of throughput it allocates to us because of market conditions or because of factors that specifically affect Williams Energy Marketing & Trading or Williams Refining & Marketing, including a decrease in demand for products in the markets served by our terminals or a loss of customers in those markets.

Our ammonia pipeline and terminals system is dependent on three customers.

Three customers ship all of the ammonia on our pipeline and utilize the six terminals that we own and operate on the pipeline. We have contracts with Farmland Industries, Inc., Agrium U.S. Inc. and Terra Nitrogen, L.P. through June 2005 that obligate them to ship-or-pay for specified minimum quantities of ammonia. Two of these customers have credit ratings below investment grade. The loss of any one of these three customers or their failure or inability to pay us would adversely affect our ability to pay cash distributions to you.

High natural gas prices can increase ammonia production costs and reduce the amount of ammonia transported through our ammonia pipeline and terminals system.

The profitability of our customers that produce ammonia partially depends on the price of natural gas, which is the principal raw material used in the production of ammonia. From 1999 through the first half of 2001, natural gas prices were substantially higher than historical averages. As a result, our customers substantially curtailed their production of ammonia and shipped lower volumes of ammonia on our pipeline. Because of this, our ammonia business realized reduced revenues and cash flows in 1999, 2000 and the first six months of 2001. Our ammonia pipeline and terminals system revenues increased during the second half of 2001, when high natural gas prices returned to lower historical levels. An extended period of high natural gas prices may cause our customers to produce and ship lower volumes of ammonia, which could adversely affect our ability to pay cash distributions to you.

Changes in or challenges to the federal government's policy regarding farm subsidies could negatively impact the demand for ammonia and result in decreased shipments through our ammonia pipeline and terminals system.

Our customers who ship ammonia through our pipeline primarily sell the ammonia to corn farmers in the Midwest. The recently enacted 2002 Farm Bill continues the Freedom to Farm Program that provides incentives to farmers to grow corn that has resulted in large corn crops over the last few years. In addition, the bill provides for a target-price program and loan-price supports for corn farmers. This legislation extends to September 2007. If this legislation is revised, terminated or successfully attacked by foreign governments that allege it violates the General Agreement on Tariffs and Trade, it could reduce farmers' incentive to grow corn and reduce the demand for the ammonia used to fertilize corn crops. In addition, the federal government and state governments have been providing tax credits related to the production of ethanol, for which corn is the essential element. If these tax incentives are reduced or repealed, the demand for ammonia would be reduced and our customers might reduce the volumes transported through our pipeline.

Our marine and inland terminals encounter competition from other terminal companies and our ammonia pipeline and terminals system encounters competition from rail carriers and another ammonia pipeline.

Our marine and inland terminals face competition from large, generally well-financed companies that own many terminals, as well as from small companies. Our marine and inland terminals also encounter competition from integrated refining and marketing companies that own their own terminal facilities. Our customers demand delivery of products on tight time schedules and in a number of geographic markets. If our quality of service declines or we cannot meet the demands of our customers, they may use our competitors.

We compete primarily with rail carriers for the transportation of ammonia. If our customers elect to transport ammonia by rail rather than pipeline, we may realize lower revenues and cash flows and our ability to pay cash distributions may be adversely affected. Our ammonia pipeline also competes with the Koch Pipeline Company LP ammonia pipeline in Iowa and Nebraska.

Our business is subject to federal, state and local laws and regulations that govern the environmental and operational safety aspects of our operations.

Our marine and inland terminal facilities and ammonia pipeline and terminals system are subject to the risk of incurring substantial costs and liabilities under environmental and safety laws. These costs and liabilities arise under increasingly strict environmental and safety laws, including regulations and governmental enforcement policies, and as a result of claims for damages to property or persons arising from our operations. Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. If we were unable to recover these costs through increased revenues, our ability to pay cash distributions to you could be adversely affected.

We own a number of properties that have been used for many years to distribute or store petroleum products by third parties not under our control. In some cases, owners, tenants or users of these properties have disposed of or released hydrocarbons or solid wastes on or under these properties. In addition, some of our terminals are located on or near current or former refining and terminal operations, and there is a risk that contamination is present on these sites. The transportation of ammonia by our pipeline is hazardous and may result in environmental damage, including accidental releases that may cause death or injuries to humans and farm animals and damage to crops.

Terrorist attacks aimed at our facilities could adversely affect our business.

On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the U.S. government has issued warnings that energy assets, specifically our nation's pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

Our business involves many hazards and operational risks, some of which may not be covered by insurance.

Our operations are subject to the many hazards inherent in the transportation of refined petroleum products and ammonia, including ruptures, leaks and fires. These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. In addition, as a result of market conditions, premiums and deductibles for some of our insurance policies have increased substantially and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist and sabotage acts. If a significant accident or event occurs that is not fully insured, it could adversely affect our financial position or results of operations.

Risks Related to Our Partnership Structure

We are a holding company and depend entirely on our operating subsidiaries' distributions to service our debt obligations.

We are a holding company with no material operations. If we cannot receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations. Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions which could further limit each operating subsidiary's ability to make distributions to us.

The debt securities we issue and any guarantees issued by the subsidiary guarantors will be structurally subordinated to the claims of the creditors of any of our operating subsidiaries who are not guarantors of the debt securities. Holders of the debt securities will not be creditors of our operating subsidiaries who have not guaranteed the debt securities. The claims to the assets of these non-guarantor operating subsidiaries derive from our own ownership interests in those operating subsidiaries. Claims of our non-guarantor operating subsidiaries' creditors will generally have priority as to the assets of such operating subsidiaries over our own ownership interest claims and will therefore have priority over the holders of our debt, including the debt securities. Our non-guarantor operating subsidiaries' creditors may include:

•: general creditors;
•: trade creditors;
•: secured creditors;

•: taxing authorities; and
•: creditors holding guarantees.

Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to you.

Prior to making any distribution on the common units, we will reimburse the general partner and its affiliates, including officers and directors of our general partner, for expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to pay cash distributions to you. Our general partner has sole discretion to determine the amount of these expenses, subject to an annual limit. In addition, our general partner and its affiliates may provide us other services for which we will be charged fees as determined by our general partner.

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 compensation 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.

Unitholders have limited voting rights and control of management.

Our general partner manages and controls our activities and the activities of our operating partnerships. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or other ongoing basis. However, if the general partner resigns or is removed, its successor may be elected by holders of a majority of the limited partnership units. Unitholders may remove the general partner only by a vote of the holders of at least 66 2/3% of the common units. As a result, unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to gain control of us or influence our actions.

Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

We may issue additional common units without your approval, which would dilute your existing ownership interests.

During the subordination period, our general partner may cause us to issue up to 2,839,847 additional common units without your approval. Our general partner may also cause us to issue an unlimited number of additional common units, without your approval, in a number of circumstances, such as:

•: the issuance of common units in connection with acquisitions that increase cash flow from operations per unit on a pro forma basis;
•: the conversion of subordinated units into common units;
•: the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;
•: issuances of common units under our long-term incentive plan; or
•: issuances of common units to repay up to $40.0 million in indebtedness.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

•: your proportionate ownership interest in Williams Energy Partners will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: since a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by the common unitholders will increase;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the common units may decline.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Our partnership agreement does not give the unitholders the right to approve our issuance of equity securities ranking junior to the common units.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own 80% or more of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

You may not have limited liability if a court finds that unitholder actions constitute control of our business.

Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under the partnership agreement constituted participation in the "control" of our business.

The general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Tax Risks to Common Unitholders

You should read "Material Tax Consequences" for a more complete discussion of the expected federal income tax consequences related to owning and disposing of common units.

The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you.

The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again to you as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, the cash available for distribution to you would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the after-tax return to you, likely causing a substantial reduction in the value of the common units.

Current law may change so as to cause us to be taxed as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be decreased to reflect that impact on us.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for common units, and the costs of any contests will be borne by our unitholders and our general partner.

We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain our counsel's conclusions or the positions we take. A court may not concur with our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.

You may be required to pay taxes even if you do not receive any cash distributions.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

Tax gain or loss on disposition of common units could be different than expected.

If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common

unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities, regulated investment companies, and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company or mutual fund. Distributions to foreign persons will be reduced by withholding taxes at the highest effective U.S. federal income tax rate for individuals, and foreign persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

We are registered as a tax shelter. this may increase the risk of an IRS audit of us or a unitholder.

We are registered with the IRS as a "tax shelter." Our tax shelter registration number is 01036000014. The IRS requires that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that do not conform with all aspects of final Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to your tax returns. Please read "Material Tax Consequences—Uniformity of Units" for a further discussion of the effect of the depreciation and amortization positions we adopt.

You will likely be subject to state and local taxes in states where you do not live as a result of an investment in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property and in which you do not reside. You may be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we do business or own property. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

WHERE YOU CAN FIND MORE INFORMATION

Williams Energy Partners files annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC's web site at http://www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

The SEC allows Williams Energy Partners to "incorporate by reference" the information it has filed with the SEC. This means that Williams Energy Partners can disclose important information to you without actually including the specific information in this prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus. Information that Williams Energy Partners files later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. The documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 are incorporated by reference in this prospectus until the termination of each offering under this prospectus.

•: Annual Report on Form 10-K for the fiscal year ended December 31, 2001.
•: Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2001.
•: Current Report on Form 8-K filed January 3, 2002.
•: Amended Current Report on Form 8-K/A filed January 14, 2002.
•: Current Report on Form 8-K filed January 30, 2002.
•: Current Report on Form 8-K filed March 8, 2002.
•: Current Report on Form 8-K filed April 11, 2002.
•: Current Report on Form 8-K filed April 19, 2002.
•: Current Report on Form 8-K filed April 29, 2002.
•: Current Report on Form 8-K filed May 3, 2002.
•: Amended Current Report on Form 8-K/A filed May 9, 2002.
•: Quarterly Report on Form 10-Q filed May 10, 2002.
•: Current Report on Form 8-K filed May 15, 2002.
•: The description of the limited partnership units contained in the Registration Statement on Form 8-A, initially filed February 2, 2001, and any subsequent amendment thereto filed for the purpose of updating such description.

You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:

Investor Relations Department
Williams Energy Partners L.P.
One Williams Center
Tulsa, Oklahoma 74172
(918) 573-2000

FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS

Some of the information included in this prospectus, the accompanying prospectus supplement and the documents we incorporate by reference contain forward-looking statements. These statements use forward-looking words such as "may," "will," "anticipate," "believe," "expect," "project" or other similar words. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other "forward-looking" information. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference. These statements reflect Williams Energy Partners' current views with respect to future events and are subject to various risks, uncertainties and assumptions including, but not limited, to the following:

•: Price trends and overall demand for natural gas liquids, refined petroleum products, natural gas, oil and ammonia in the United States; economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demand;
•: Changes in demand for refined petroleum products that we store and distribute;
•: Changes in demand for storage in our petroleum product terminals;
•: Changes in our tariff rates implemented by the Federal Energy Regulatory Commission and the United States Surface Transportation Board;
•: Shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;
•: Changes in the throughput on petroleum product pipelines owned and operated by third parties and connected to our petroleum product terminals;
•: Loss of Williams Energy Marketing & Trading Company and/or Williams Refining & Marketing, L.L.C. as customers;
•: Loss of one or all of our three customers on our ammonia pipeline and terminals system;
•: An increase in the price of natural gas, which increases ammonia production costs and reduces the amount of ammonia transported through our ammonia pipeline and terminals system;
•: Changes in the federal government's policy regarding farm subsidies, which negatively impact the demand for ammonia and reduce the amount of ammonia transported through our ammonia pipeline and terminals system;
•: An increase in the competition our petroleum products terminals and ammonia pipeline and terminals system encounter;
•: The occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured;
•: Our ability to integrate any acquired operations into our existing operations;
•: Our ability to successfully identify and close strategic acquisitions and make cost saving changes in operations;
•: Changes in general economic conditions in the United States;
•: Changes in laws and regulations to which we are subject, including tax, environmental and employment laws and regulations;
•: The amount of our respective indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
•: The condition of the capital markets and equity markets in the United States;
•: The ability to raise capital in a cost-effective way;
•: The cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;
•: The effect of changes in accounting policies;
•: The ability to control costs; and
•: The political and economic stability of the oil producing nations of the world.

USE OF PROCEEDS

Except as otherwise provided in the applicable prospectus supplement, we will use the net proceeds we receive from the sale of the securities to pay all or a portion of indebtedness outstanding at the time and to acquire assets as suitable opportunities arise.

RATIO OF EARNINGS TO FIXED CHARGES

The ratio of earnings to fixed charges for each of the periods indicated is as follows:

			Twelve Months Ended December 31,
			1997		1998		1999		2000		2001
	Ratio of Earnings to Fixed Charges		6.77x		6.69x		5.32x		3.75x		7.20x

For purposes of calculating the ratio of earnings to fixed charges:

•: "fixed charges" represent interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor; and
•: "earnings" represent the aggregate of income from continuing operations (before adjustment for minority interest, extraordinary loss and equity earnings), fixed charges and distributions from equity investment, less capitalized interest.

DESCRIPTION OF DEBT SECURITIES

We will issue our debt securities under an indenture, among us, as issuer, the Trustee, and the subsidiary guarantors. The debt securities will be governed by the provisions of the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939. We, the Trustee and the Subsidiary Guarantors may enter into supplements to the Indenture from time to time. If we decide to issue subordinated debt securities, we will issue them under a separate Indenture containing subordination provisions.

This description is a summary of the material provisions of the debt securities and the Indentures. We urge you to read the forms of senior indenture and subordinated indenture filed as exhibits to the registration statement of which this prospectus is a part because those Indentures, and not this description, govern your rights as a holder of debt securities. References in this prospectus to an "Indenture" refer to the particular Indenture under which we issue a series of debt securities.

General

The Debt Securities

Any series of debt securities that we issue:

•: will be our general obligations;
•: will be general obligations of the Subsidiary Guarantors if they are guaranteed by the Subsidiary Guarantors; and
•: may be subordinated to our Senior Indebtedness and that of the Subsidiary Guarantors.

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

We will prepare a prospectus supplement and either an indenture supplement or a resolution of the board of directors of our general partner and accompanying officers' certificate relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:

•: the form and title of the debt securities;
•: the total principal amount of the debt securities;
•: the date or dates on which the debt securities may be issued;
•: the portion of the principal amount which will be payable if the maturity of the debt securities is accelerated;
•: any right we may have to defer payments of interest by extending the dates payments are due and whether interest on those deferred amounts will be payable;
•: the dates on which the principal and premium, if any, of the debt securities will be payable;
•: the interest rate which the debt securities will bear and the interest payment dates for the debt securities;
•: any optional redemption provisions;
•: any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;
•: whether the debt securities are entitled to the benefits of any guarantees by the Subsidiary Guarantors;
•: whether the debt securities may be issued in amounts other than $1,000 each or multiples thereof;

•: any changes to or additional Events of Default or covenants;
•: the subordination, if any, of the debt securities and any changes to the subordination provisions of the Indenture; and
•: any other terms of the debt securities.

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

The prospectus supplement will also describe any material United States federal income tax consequences or other special considerations regarding the applicable series of debt securities, including those relating to:

•: debt securities with respect to which payments of principal, premium or interest are determined with reference to an index or formula, including changes in prices of particular securities, currencies or commodities;
•: debt securities with respect to which principal, premium or interest is payable in a foreign or composite currency;
•: debt securities that are issued at a discount below their stated principal amount, bearing no interest or interest at a rate that at the time of issuance is below market rates; and
•: variable rate debt securities that are exchangeable for fixed rate debt securities.

At our option, we may make interest payments by check mailed to the registered holders of debt securities or, if so stated in the applicable prospectus supplement, at the option of a holder by wire transfer to an account designated by the holder.

Unless otherwise provided in the applicable prospectus supplement, fully registered securities may be transferred or exchanged at the office of the Trustee at which its corporate trust business is principally administered in the United States, subject to the limitations provided in the Indenture, without the payment of any service charge, other than any applicable tax or governmental charge.

Any funds we pay to a paying agent for the payment of amounts due on any debt securities that remain unclaimed for two years will be returned to us, and the holders of the debt securities must look only to us for payment after that time.

The Subsidiary Guarantees

Our payment obligations under any series of debt securities may be jointly and severally, fully and unconditionally guaranteed by the Subsidiary Guarantors. If a series of debt securities are so guaranteed, the Subsidiary Guarantors will execute a notation of guarantee as further evidence of their guarantee. The applicable prospectus supplement will describe the terms of any guarantee by the Subsidiary Guarantors.

The obligations of each Subsidiary Guarantor under its guarantee of the debt securities 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 Guarantors in respect of the obligations of the Subsidiary Guarantor under its guarantee.

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If no default has occurred and is continuing under the Indenture, and to the extent not otherwise prohibited by the Indenture, a Subsidiary Guarantor will be unconditionally released and discharged from the guarantee:

•: automatically upon any sale, exchange or transfer, to any person that is not our affiliate, of all of our direct or indirect limited partnership 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 and 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 debt of ours for borrowed money (or a guarantee of such debt), except for any series of debt securities.

If a series of debt securities is guaranteed by the Subsidiary Guarantors and is designated as subordinate to our Senior Indebtedness, then the guarantees by the Subsidiary Guarantors will be subordinated to the Senior Indebtedness of the Subsidiary Guarantors to substantially the same extent as the series is subordinated to our Senior Indebtedness. See "—Subordination."

Covenants

Reports

The Indenture contains the following covenant for the benefit of the holders of all series of debt securities:

So long as any debt securities are outstanding, we will:

•: for as long as we are required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after we are required to file with the SEC, copies of the annual report and of the information, documents and other reports which we are required to file with the SEC pursuant to the Exchange Act;
•: if we are not required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after we would have been required to file with the SEC, financial statements and a Management's Discussion and Analysis of Financial Condition and Results of Operations, both comparable to what we would have been required to file with the SEC had we been subject to the reporting requirements of the Exchange Act; and
•: if we are required to furnish annual or quarterly reports to our unitholders pursuant to the Exchange Act, we will file with the Trustee any annual report or other reports sent to our unitholders generally.

A series of debt securities may contain additional financial and other covenants applicable to us and our subsidiaries. The applicable prospectus supplement will contain a description of any such covenants that are added to the Indenture specifically for the benefit of holders of a particular series.

Events of Default, Remedies and Notice

Events of Default

Each of the following events will be an "Event of Default" under the Indenture with respect to a series of debt securities:

•: default in any payment of interest on any debt securities of that series when due that continues for 30 days;
•: default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;
•: default in the payment of any sinking fund payment on any debt securities of that series when due;
•: failure by us or, if the series of debt securities is guaranteed by the Subsidiary Guarantors, by a Subsidiary Guarantor, to comply for 60 days after notice with the other agreements contained in the Indenture, any supplement to the Indenture or any board resolution authorizing the issuance of that series;

•

certain events of bankruptcy, insolvency or reorganization of us or, if the series of debt securities is guaranteed by the Subsidiary Guarantors, of the Subsidiary Guarantors; or

•

if the series of debt securities is guaranteed by the Subsidiary Guarantors:

•: any of the guarantees by the Subsidiary Guarantors ceases to be in full force and effect, except as otherwise provided in the Indenture;
•: any of the guarantees by the Subsidiary Guarantors is declared null and void in a judicial proceeding; or
•: any Subsidiary Guarantor denies or disaffirms its obligations under the Indenture or its guarantee.

Exercise of Remedies

If an Event of Default, other than an Event of Default described in the fifth bullet point above, occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the outstanding debt securities of that series may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the debt securities of that series to be due and payable immediately.

A default under the fourth bullet point above will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding debt securities of that series notify us and, if the series of debt securities is guaranteed by the Subsidiary Guarantors, the Subsidiary Guarantors, of the default and such default is not cured within 60 days after receipt of notice.

If an Event of Default described in the fifth bullet point above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all outstanding debt securities of all series 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 debt securities of a series may:

•: waive all past defaults, except with respect to nonpayment of principal, premium or interest; and
•: rescind any declaration of acceleration by the Trustee or the holders with respect to the debt securities of that series,

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 have been cured or waived, other than the nonpayment of principal, premium or interest on the debt securities of that series that have become due solely by the declaration of acceleration.

If an Event of Default occurs and is continuing, the Trustee will be under no obligation, 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 unless such holders have offered to the Trustee reasonable indemnity or security against any costs, liability or expense. No holder may pursue any remedy with respect to the Indenture or the debt securities of any series, except to enforce the right to receive payment of principal, premium or interest when due, unless:

•: such holder has previously given the Trustee notice that an Event of Default with respect to that series is continuing;
•: holders of at least 25% in principal amount of the outstanding debt securities of that series have requested that the Trustee pursue the remedy;
•: such holders have offered the Trustee reasonable indemnity or security against any cost, liability or expense;

•: 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
•: the holders of a majority in principal amount of the outstanding debt securities of that series have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

The holders of a majority in principal amount of the outstanding debt securities of a series 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 that series of debt securities. 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 other holder;
•: would involve the Trustee in personal liability.

Notice of Event of Default

Within 30 days after the occurrence of an Event of Default, we are required to give written notice to the Trustee and indicate the status of the default and what action we are taking or propose to take to cure the default. In addition, we are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a compliance certificate indicating that we have complied with all covenants contained in the Indenture or whether any default or Event of Default has occurred during the previous year.

If an Event of Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder a notice of the Event of Default by the later of 90 days after the Event of Default occurs or 30 days after the Trustee knows of the Event of Default. Except in the case of a default in the payment of principal, premium or interest with respect to any debt securities, the Trustee may withhold such notice, but only if and so long as the board of directors, the executive committee or a committee of directors or responsible officers of the Trustee in good faith determines that withholding such notice is in the interests of the holders.

Amendments and Waivers

We may amend the Indenture without the consent of any holder of debt securities to:

•: cure any ambiguity, omission, defect or inconsistency;
•: convey, transfer, assign, mortgage or pledge any property to or with the Trustee;
•: provide for the assumption by a successor of our obligations under the Indenture;
•: add Subsidiary Guarantors with respect to the debt securities;
•: change or eliminate any restriction on the payment of principal of, or premium, if any, on, any debt securities;
•: secure the debt securities;
•: add covenants for the benefit of the holders or surrender any right or power conferred upon us or any Subsidiary Guarantor;
•: make any change that does not adversely affect the rights of any holder;
•: add or appoint a successor or separate Trustee; or

•: comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act.

In addition, we may amend the Indenture if the holders of a majority in principal amount of all debt securities of each series that would be affected then outstanding under the Indenture consent to it. We may not, however, without the consent of each holder of outstanding debt securities of each series that would be affected, amend the Indenture to:

•: reduce the percentage in principal amount of debt securities of any series whose holders must consent to an amendment;
•: reduce the rate of or extend the time for payment of interest on any debt securities;
•: reduce the principal of or extend the stated maturity of any debt securities;
•: reduce the premium payable upon the redemption of any debt securities or change the time at which any debt securities may or shall be redeemed;
•: make any debt securities payable in other than U.S. dollars;
•: impair the right of any holder to receive payment of premium, principal or interest with respect to such holder's debt securities on or after the applicable due date;
•: impair the right of any holder to institute suit for the enforcement of any payment with respect to such holder's debt securities;
•: release any security that has been granted in respect of the debt securities;
•: make any change in the amendment provisions which require each holder's consent;
•: make any change in the waiver provisions; or
•: release a Subsidiary Guarantor or modify such Subsidiary Guarantor's guarantee in any manner adverse to the holders.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture becomes effective, we are required to mail to all holders a notice briefly describing the amendment. The failure to give, or any defect in, such notice, however, will not impair or affect the validity of the amendment.

The holders of a majority in aggregate principal amount of the outstanding debt securities of each affected series, on behalf of all such holders, and subject to certain rights of the Trustee, may waive:

•: compliance by us or a Subsidiary Guarantor with certain restrictive provisions of the Indenture; and
•: any past default under the Indenture, subject to certain rights of the Trustee under the Indenture;

except that such majority of holders may not waive a default:

•: in the payment of principal, premium or interest; or
•: in respect of a provision that under the Indenture cannot be amended without the consent of all holders of the series of debt securities that is affected.

Defeasance

At any time, we may terminate, with respect to debt securities of a particular series, all our obligations under such series of debt securities and the Indenture, 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 debt securities;
•: to replace mutilated, destroyed, lost or stolen debt securities; or
•: to maintain a registrar and paying agent in respect of the debt securities.

If we exercise our legal defeasance option, any subsidiary guarantee will terminate with respect to that series of debt securities.

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

•: covenants applicable to a series of debt securities and described in the prospectus supplement applicable to such series, other than as described in such prospectus supplement;
•: the bankruptcy provisions with respect to the Subsidiary Guarantors, if any; and
•: the guarantee provision described under "Events of Default" above with respect to a series of debt securities.

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 affected series of debt securities may not be accelerated because of an Event of Default with respect to that series. If we exercise our covenant defeasance option, payment of the affected series of debt securities 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" above or an Event of Default that is added specifically for such series and described in a prospectus supplement.

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 series of debt securities to redemption or 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 of an opinion of counsel to the effect that holders of the series of debt securities 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 amount 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.

No Personal Liability of General Partner

Williams GP LLC, our general partner, and its directors, officers, employees, incorporators and stockholders, as such, will not be liable for:

•: any of our obligations or the obligations of the Subsidiary Guarantors under the debt securities, the Indentures or the guarantees; or
•: any claim based on, in respect of, or by reason of, such obligations or their creation.

By accepting a debt security, each holder will be deemed to have waived and released all such liability. This waiver and release are part of the consideration for our issuance of the debt securities. This waiver may not be effective, however, to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Subordination

Debt securities of a series may be subordinated to our "Senior Indebtedness," which we define generally to include any obligation created or assumed by us (or, if the series is guaranteed, the Subsidiary Guarantors) for the repayment of borrowed money and any guarantee therefor, whether outstanding or hereafter issued, unless, by the terms of the instrument creating or evidencing such obligation, it is provided that such obligation is subordinate or not superior in right of payment to the debt securities (or, if the series is guaranteed, the guarantee of the Subsidiary Guarantors), or to other obligations which are pari passu with or subordinated to the debt securities (or, if the series is guaranteed, the guarantee of the Subsidiary Guarantors). Subordinated debt securities will be subordinate in right of payment, to the extent and in the manner set forth in the Indenture and the prospectus supplement relating to such series, to the prior payment of all of our indebtedness and that of any Subsidiary Guarantor that is designated as "Senior Indebtedness" with respect to the series.

The holders of Senior Indebtedness of ours or, if applicable, a Subsidiary Guarantor, will receive payment in full of the Senior Indebtedness before holders of subordinated debt securities will receive any payment of principal, premium or interest with respect to the subordinated debt securities:

•: upon any payment or distribution of our assets or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors' assets, to creditors;
•: upon a liquidation or dissolution of us or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors; or
•: in a bankruptcy, receivership or similar proceeding relating to us or, if applicable to any series of outstanding debt securities, to the Subsidiary Guarantors.

Until the Senior Indebtedness is paid in full, any distribution to which holders of subordinated debt securities would otherwise be entitled will be made to the holders of Senior Indebtedness, except that the holders of subordinated debt securities may receive units representing limited partner interests and any debt securities that are subordinated to Senior Indebtedness to at least the same extent as the subordinated debt securities.

If we do not pay any principal, premium or interest with respect to Senior Indebtedness within any applicable grace period (including at maturity), or any other default on Senior Indebtedness occurs and the maturity of the Senior Indebtedness is accelerated in accordance with its terms, we may not:

•: make any payments of principal, premium, if any, or interest with respect to subordinated debt securities;
•: make any deposit for the purpose of defeasance of the subordinated debt securities; or
•: repurchase, redeem or otherwise retire any subordinated debt securities, except that in the case of subordinated debt securities that provide for a mandatory sinking fund, we may deliver subordinated debt securities to the Trustee in satisfaction of our sinking fund obligation,

unless, in either case,

•: the default has been cured or waived and any declaration of acceleration has been rescinded;
•: the Senior Indebtedness has been paid in full in cash; or
•: we and the Trustee receive written notice approving the payment from the representatives of each issue of "Designated Senior Indebtedness."

Generally, "Designated Senior Indebtedness" will include:

•: any specified issue of Senior Indebtedness of at least $100 million; and

•: any other Senior Indebtedness that we may designate in respect of any series of subordinated debt securities.

During the continuance of any default, other than a default described in the immediately preceding paragraph, that may cause the maturity of any Designated Senior Indebtedness to be accelerated immediately without further notice, other than any notice required to effect such acceleration, or the expiration of any applicable grace periods, we may not pay the subordinated debt securities for a period called the "Payment Blockage Period." A Payment Blockage Period will commence on the receipt by us and the Trustee of written notice of the default, called a "Blockage Notice," from the representative of any Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period and will end 179 days thereafter.

The Payment Blockage Period may be terminated before its expiration:

•: by written notice from the person or persons who gave the Blockage Notice;
•: by repayment in full in cash of the Designated Senior Indebtedness with respect to which the Blockage Notice was given; or
•: if the default giving rise to the Payment Blockage Period is no longer continuing.

Unless the holders of the Designated Senior Indebtedness have accelerated the maturity of the Designated Senior Indebtedness, we may resume payments on the subordinated debt securities after the expiration of the Payment Blockage Period.

Generally, not more than one Blockage Notice may be given in any period of 360 consecutive days. The total number of days during which any one or more Payment Blockage Periods are in effect, however, may not exceed an aggregate of 179 days during any period of 360 consecutive days.

After all Senior Indebtedness is paid in full and until the subordinated debt securities are paid in full, holders of the subordinated debt securities shall be subrogated to the rights of holders of Senior Indebtedness to receive distributions applicable to Senior Indebtedness.

As a result of the subordination provisions described above, in the event of insolvency, the holders of Senior Indebtedness, as well as certain of our general creditors, may recover more, ratably, than the holders of the subordinated debt securities.

Book Entry, Delivery and Form

We may issue debt securities of a series in the form of one or more global certificates deposited with a depositary. We expect that The Depository Trust Company, New York, New York, or "DTC," will act as depositary. If we issue debt securities of a series in book-entry form, we will issue one or more global certificates that will be deposited with or on behalf of DTC and will not issue physical certificates to each holder. A global security may not be transferred unless it is exchanged in whole or in part for a certificated security, except that DTC, its nominees and their successors may transfer a global security as a whole to one another.

DTC will keep a computerized record of its participants, such as a broker, whose clients have purchased the debt securities. The participants will then keep records of their clients who purchased the debt securities. Beneficial interests in global securities will be shown on, and transfers of beneficial interests in global securities will be made only through, records maintained by DTC and its participants.

DTC advises us that it is:

•: a limited-purpose trust company organized under the New York Banking Law;
•: a "banking organization" within the meaning of the New York Banking Law;

•: a member of the United States Federal Reserve System;
•: a "clearing corporation" within the meaning of the New York Uniform Commercial Code; and
•: a "clearing agency" registered under the provisions of Section 17A of the Securities Exchange Act of 1934.

DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. The rules that apply to DTC and its participants are on file with the Securities and Exchange Commission.

DTC holds securities that its participants deposit with DTC. DTC also records the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for participants' accounts. This eliminates the need to exchange certificates. Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

We will wire principal, premium, if any, and interest payments due on the global securities to DTC's nominee. We, the Trustee and any paying agent will treat DTC's nominee as the owner of the global securities for all purposes. Accordingly, we, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global securities to owners of beneficial interests in the global securities.

It is DTC's current practice, upon receipt of any payment of principal, premium, if any, or interest, to credit participants' accounts on the payment date according to their respective holdings of beneficial interests in the global securities as shown on DTC's records. In addition, it is DTC's current practice to assign any consenting or voting rights to participants, whose accounts are credited with debt securities on a record date, by using an omnibus proxy.

Payments by participants to owners of beneficial interests in the global securities, as well as voting by participants, will be governed by the customary practices between the participants and the owners of beneficial interests, as is the case with debt securities held for the account of customers registered in "street name." Payments to holders of beneficial interests are the responsibility of the participants and not of DTC, the Trustee or us.

Beneficial interests in global securities will be exchangeable for certificated securities with the same terms in authorized denominations only if:

•: DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and a successor depositary is not appointed by us within 90 days; or
•: we determine not to require all of the debt securities of a series to be represented by a global security and notify the Trustee of our decision.

The Trustee

We may appoint a separate trustee for any series of debt securities. We use the term "Trustee" to refer to the trustee appointed with respect to any such series of debt securities. We may maintain banking and other commercial relationships with the Trustee and its affiliates in the ordinary course of business, and the Trustee may own debt securities.

Governing Law

The Indenture and the debt securities will be governed by, and construed in accordance with, the laws of the State of New York.

DESCRIPTION OF OUR CLASS B UNITS

We issued Class B units to our general partner, in connection with the acquisition of Williams Pipe Line Company. Our general partner, as the holder of the Class B units, has the same rights as the holders of our common units with respect to distributions, voting and allocations of income, gain, loss and deductions. However, during the period in which any portion of the short-term loan we used to finance the acquisition of Williams Pipe Line Company is outstanding, our general partner will not receive distributions, of any kind with respect to the Class B units. Upon our repayment in full of the short-term loan:

•: Our general partner will be entitled to receive a distribution of available cash with respect to its Class B units equal to the distributions of available cash that were paid or declared payable to the common units during the term of the short-term loan; and
•: We, at our option, may redeem the Class B units for cash based on the 15-day average closing price of the common units prior to the redemption date.

In addition, after one year from the date of issuance of the Class B units, upon the request of our general partner and the approval of the holders of a majority of the common units voting at a meeting of unitholders, the Class B units will convert into common units. If the approval of the conversion by the common unitholders is not obtained within 120 days of our general partner's request, our general partner will be entitled to receive distributions with respect to its Class B units, on a per unit basis, equal to 115% of the amount of distributions paid on a common unit. You should read our historical financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations incorporated by reference in this prospectus for additional information regarding the terms of our short-term loan.

CASH DISTRIBUTIONS

Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, we will distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

•

less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:

•: provide for the proper conduct of our business;
•: comply with applicable law, any of our debt instruments, or other agreements; or
•: provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.525 per quarter or $2.10 per year to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit facility.

Operating Surplus, Capital Surplus and Adjusted Operating Surplus

General. All cash distributed to unitholders will be characterized either as operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus. For any period, operating surplus generally means:

•: our cash balance on the closing date of our initial public offering; plus
•: $15.0 million; plus
•: all of our cash receipts since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
•: working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
•: all of our operating expenditures since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
•: the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus. Capital surplus will generally be generated only by:

•: borrowings other than working capital borrowings;
•: sales of debt and equity securities; and
•: sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Adjusted operating surplus for any period generally means:

•: operating surplus generated with respect to that period; less
•: any net increase in working capital borrowings with respect to that period; less
•: any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
•: any net decrease in working capital borrowings with respect to that period; plus
•: any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Subordination Period

General. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.525 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Definition of Subordination Period. The subordination period will extend until the first day of any quarter beginning after December 31, 2005 that each of the following tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the adjusted operating surplus generated during each of the three immediately preceding non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Conversion of Subordinated Units. Before the end of the subordination period, 50% of the subordinated units, or up to 2,839,847 subordinated units, may convert into common units on a one-for-one basis on the first day after the record date established for the distribution for any quarter ending on or after:

•: December 31, 2003 with respect to 25% of the subordinated units; and
•: December 31, 2004 with respect to 25% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following three tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.

Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of this removal:

•: the subordination period will end and each subordinated unit will immediately convert into one common unit;
•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•: First, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•: Second, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
•: Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
•: Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
•: Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

If for any quarter:

•: we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
•: we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.578 per unit for that quarter (the "first target distribution");
•: Second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.656 per unit for that quarter (the "second target distribution");
•: Third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.788 per unit for that quarter (the "third target distribution"); and
•: Thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for

the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders	General Partner
Minimum Quarterly Distribution	$0.525	98%	2%
First Target Distribution	up to $0.578	98%	2%
Second Target Distribution	above $0.578 up to $0.656	85%	15%
Third Target Distribution	above $0.656 up to $0.788	75%	25%
Thereafter	above $0.788	50%	50%

Distributions From Capital Surplus

How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to the initial public offering price;
•: Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in the offering, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
•: Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the unit price from our initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the unrecovered initial unit price. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero and we will make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to the general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•: the minimum quarterly distribution;
•: target distribution levels;
•: unrecovered initial unit price;

•: the number of common units issuable during the subordination period without a unitholder vote; and
•: the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon the liquidation of Williams Energy Partners, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon liquidation of Williams Energy Partners to enable the holder of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•: First, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
•: Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of:

(1) the unrecovered initial unit price for that common unit; plus

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus

(3) any unpaid arrearages in payment of the minimum quarterly distribution on that common unit;

•: Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until the capital account for each subordinated unit is equal to the sum of:

(1) the unrecovered initial unit price on that subordinated unit; and

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•: Fourth, 98% to all unitholders, pro rata, and 2% to the general partner, pro rata, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the units, pro rata, and 2% to the general partner, pro rata, for each quarter of our existence;

•: Fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

•: Sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence;

•: Thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third above bullet point will no longer be applicable.

Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner:

•: First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the holders of the subordinated units have been reduced to zero;
•: Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the common unitholders have been reduced to zero; and
•: Thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

MATERIAL TAX CONSEQUENCES

This section is a summary of all the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., special counsel to the general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Williams Energy Partners and the operating partnership.

No attempt has been made in this section to comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and some are based on the accuracy of the representations we make.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. An opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:

(1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales");

(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and

(3) whether our method for depreciating Section 743 adjustments is sustainable (please read "—Tax Consequences of Unit Ownership—Section 754 Election").

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnership as partnerships for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, Williams Energy Partners and the operating partnership are and will be classified as partnerships for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied are:

(a) Neither we nor the operating partnership has elected or will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income has been and will be income that our counsel has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof and fertilizer. Other types of qualifying income include interest other than from a financial business, dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 7% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our separate tax returns rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of Williams Energy Partners' current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Vinson & Elkins L.L.P.'s opinion that we and the operating partnership will be classified as partnerships for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Williams Energy Partners will be treated as partners of Williams Energy Partners for federal income tax purposes. Also:

(a) assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Williams Energy Partners for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, counsel's opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders should consult their own tax advisors with respect to their status as partners in Williams Energy Partners for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, and/or substantially appreciated "inventory items," both as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been

distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A limited partner will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." The IRS has indicated that net passive income from a publicly-traded partnership constitutes investment income for purposes of the limitations on the deductibility of investment interest. In addition, the unitholder's share of our portfolio income will be treated as investment income. Investment interest expense includes:

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributed to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as "Contributed Property." The effect of these allocations to a unitholder purchasing common units in our offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity", will

generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including his relative contributions to us, the interests of all the partners in profits and losses, the interest of all the partners in cash flow and other nonliquidating distributions and rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•: any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
•: any cash distributions received by the unitholder as to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders should consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals for 2002 is 38.6% and the maximum United States federal income tax rate for net capital gains of an individual for 2002 is 20% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a

Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read "—Tax Treatment of Operations—Uniformity of Units."

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Tax Treatment of Operations—Uniformity of Units."

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read "—Allocation of Income, Gain, Loss and Deduction."

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 20%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized

receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury regulations allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions should consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A purchaser of units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder which is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company or "mutual fund" is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. And, under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective rate applicable to individuals, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an

audit of his own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement names Williams GP LLC as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is

(1) a person that is not a United States person,

(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3) a tax-exempt entity;

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Registration as a Tax Shelter. The Internal Revenue Code requires that "tax shelters" be registered with the Secretary of the Treasury. The temporary Treasury regulations interpreting the tax shelter registration provisions of the Internal Revenue Code are extremely broad. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken. Our tax shelter registration number is 01036000014.

Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, "substantial authority," or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply to "tax shelters," a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in 18 states, most of which impose income taxes. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder

who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, each prospective unitholder should consult, and must depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth on the prospectus supplement relating to the offering of debt securities.

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to certain additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and restrictions imposed by Section 4975 of the Internal Revenue Code. As used herein, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to (a) whether such investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making such investment, such plan will satisfy the diversification requirement of Section 404(a)(1)(C) of ERISA; and (c) whether such investment will result in recognition of unrelated business taxable income by such plan and, if so, the potential after-tax investment return. Please read "Tax Considerations—Tax-Exempt Organizations and Other Investors." The person with investment discretion with respect to the assets of an employee benefit plan (a "fiduciary") should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for such plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which also applies to IRAs that are not considered part of an employee benefit plan) prohibit an employee benefit plan from engaging in certain transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of limited partnership units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether such plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under certain circumstances. Pursuant to these regulations, an entity's assets would not be considered to be "plan assets" if, among other things, (a) the equity interest acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered pursuant to certain provisions of the federal securities laws, (b) the entity is an "Operating Partnership"—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons) is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA (such as governmental plans). Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c).

Plan fiduciaries contemplating a purchase of limited partnership units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

PLAN OF DISTRIBUTION

We may sell the securities being offered hereby:

•: directly to purchasers;
•: through agents;
•: through underwriters; and
•: through dealers.

We, or agents designated by us, may directly solicit, from time to time, offers to purchase the securities. Any such agent may be deemed to be an underwriter as that term is defined in the Securities Act of 1933. We will name the agents involved in the offer or sale of the securities and describe any commissions payable by us to these agents in the prospectus supplement. Unless otherwise indicated in the prospectus supplement, these agents will be acting on a best efforts basis for the period of their appointment. The agents may be entitled under agreements which may be entered into with us to indemnification by us against specific civil liabilities, including liabilities under the Securities Act of 1933. The agents may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize any underwriters in the sale of the securities in respect of which this prospectus is delivered, we will enter into an underwriting agreement with those underwriters at the time of sale to them. We will set forth the names of these underwriters and the terms of the transaction in the prospectus supplement, which will be used by the underwriters to make resales of the securities in respect of which this prospectus is delivered to the public. We may indemnify the underwriters under the relevant underwriting agreement to indemnification by us against specific liabilities, including liabilities under the Securities Act. The underwriters may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize a dealer in the sale of the securities in respect of which this prospectus is delivered, we will sell those securities to the dealer, as principal. The dealer may then resell those securities to the public at varying prices to be determined by the dealer at the time of resale. We may indemnify the dealers against specific liabilities, including liabilities under the Securities Act. The dealers may also be our customers or may engage in transactions with, or perform services for us in the ordinary course of business.

The place and time of delivery for the securities in respect of which this prospectus is delivered are set forth in the accompanying prospectus supplement.

LEGAL

Certain legal matters in connection with the securities will be passed upon by Vinson & Elkins L.L.P., Houston, Texas, as our counsel. Any underwriter will be advised about other issues relating to any offering by its own legal counsel.

EXPERTS

The consolidated financial statements of Williams Energy Partners L.P. for the year ended December 31, 2001 appearing in Williams Energy Partners L.P.'s Current Report on Form 8-K/A filed May 9, 2002 have been audited by Ernst & Young LLP, independent auditors, as set forth in their reports thereon included therein and incorporated herein by reference. These consolidated financial statements and consolidated balance sheet are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.