Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

Definitive Prospectus Supplement

Filed Pursuant to Rule No.: 424(b)(5)

Registration No.: 333-83952

PROSPECTUS SUPPLEMENT

(To Prospectus dated May 16, 2002)

LOGO

2,600,000 Common Units

Representing Limited Partner Interests

We are selling 2,600,000 common units representing limited partner interests in Magellan Midstream Partners, L.P. Our common units trade on the New York Stock Exchange under the symbol “MMP.” The last reported sales price of our common units on the New York Stock Exchange on October 4, 2004 was $54.50 per common unit.

Investing in our common units involves risk. Please read “ Risk Factors” beginning on page S-11 of this prospectus supplement and on page 2 of the accompanying prospectus.


	Per Common Unit		Total

Public offering price	$	54.500	$	141,700,000
Underwriting discount	$	2.316	$	6,021,600
Proceeds to us (before expenses)	$	52.184	$	135,678,400

We have granted the underwriters a 30-day option to purchase up to 390,000 common units on the same terms and conditions as set forth above to cover over-allotments of common units, if any.

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

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about October 8, 2004.

Joint Book-Running Managers


LEHMAN BROTHERS		CITIGROUP

GOLDMAN, SACHS & CO.

UBS INVESTMENT BANK

WACHOVIA SECURITIES

October 4, 2004

LOGO

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this common unit offering. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this common unit offering.

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.

TABLES OF CONTENTS

Prospectus Supplement


Summary		S-1
Risk Factors		S-11
Use of Proceeds		S-13
Capitalization		S-14
Price Range of Common Units and Distributions		S-15
Overview of the Shell Acquisition		S-16
Management		S-20
Tax Considerations		S-23
Underwriting		S-24
Legal		S-27
Experts		S-27
Information Regarding Forward-Looking Statements		S-28
Where You Can Find More Information		S-29

Prospectus dated May 16, 2002


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		31
Investment in Us by Employee Benefit Plans		44
Plan of Distribution		45
Legal		45
Experts		45

SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. It does not contain all of the information you should consider before making an investment decision. 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. Please read “Risk Factors” beginning on page S-11 of this prospectus supplement and page 2 of the accompanying prospectus for more information about important factors that you should consider before buying common units in this offering. Unless we indicate otherwise, the information we present in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option. 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. 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 six months ended June 30, 2004, we had revenues of $275.4 million, EBITDA of $85.7 million and net income of $44.3 million. For a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please read “—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 13 consecutive quarters, resulting in an aggregate increase of approximately 65.7% from $0.525 per unit, or $2.10 per unit on an annualized basis, to $0.87 per unit, or $3.48 per unit on an annualized basis. Since February 2001, we have completed nine acquisitions, including the Shell acquisition described below, for an aggregate purchase price of approximately $1.7 billion, and we intend to continue pursuing an asset acquisition strategy.

On October 1, 2004, we acquired more than 2,000 miles of refined petroleum products pipeline system assets from Shell Pipeline Company LP and Equilon Enterprises LLC, which had operated these assets under the name Shell Oil Products US, or Shell, for approximately $489.7 million. For more information about this acquisition, please read “—Recent Developments—Acquisition of Shell Refined Petroleum Products Pipeline Systems.”

In addition to the assets that we recently acquired from Shell, our other assets consist of:

•

a 6,700-mile petroleum products pipeline system, including 39 petroleum products terminals, serving the mid-continent region of the United States, referred to as our “6,700-mile petroleum products pipeline system”;

•

five petroleum products terminal facilities located along the U.S. Gulf Coast and near the New York harbor, referred to as “marine terminal facilities”;

•

29 petroleum products terminals 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.

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Our 6,700-mile petroleum products pipeline system is a common carrier pipeline that provides transportation, storage and distribution services for petroleum products and liquefied petroleum gases, or LPGs, in 11 states from Oklahoma through the Midwest to North Dakota, Minnesota, Wisconsin and Illinois. This system generates revenues principally from tariffs regulated by the Federal Energy Regulatory Commission, or the FERC, based on the volumes transported and also from storage and other ancillary fees. Through direct refinery connections and interconnections with other pipelines, this system can access approximately 41% of the refinery capacity in the United States and is well-positioned to adapt to shifts in product supply or demand. For each of the year ended December 31, 2003 and the six months ended June 30, 2004, our 6,700-mile petroleum products pipeline system generated approximately 80% of our total revenues.

Our inland terminals and marine terminal facilities, which we refer to collectively as our petroleum products terminals, store and distribute gasoline and other petroleum products throughout 11 states. Our inland terminals are part of a distribution network located primarily throughout the southeastern United States and used by retail suppliers, wholesalers and marketers to receive gasoline and other petroleum products from large, interstate pipelines and to transfer these products to trucks, railcars or barges for delivery to their final destination. Our marine terminal facilities are large storage terminals that principally serve refiners, marketers and large end-users of petroleum products and are strategically located near major refining hubs along the U.S. Gulf Coast and near the New York harbor. Our petroleum products terminals generate revenues principally from volume-based fees charged for the storage and delivery of gasoline and other petroleum products handled by these terminals. For each of the year ended December 31, 2003 and the six months ended June 30, 2004, our petroleum products terminals generated approximately 17% and 18%, respectively, of our total revenues.

Our ammonia pipeline system transports and distributes ammonia from production facilities in Texas and Oklahoma to various distribution points in the Midwest for use as an agricultural fertilizer. Our ammonia pipeline system generates revenues principally from volume-based fees charged for the transportation of ammonia on the pipeline system. For each of the year ended December 31, 2003 and the six months ended June 30, 2004, our ammonia pipeline system generated approximately 3% and 2%, respectively, of our total revenues.

Business Strategies

Our primary business strategies are to:

•

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

•

generate stable cash flows to make quarterly cash distributions; and

•

conduct safe and efficient operations.

Competitive Strengths

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

•

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

•

we have little direct commodity price exposure;

•

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

•

we have a strong financial position that allows us to make acquisitions and complete expansion projects; and

•

our senior management has extensive industry experience.

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Recent Developments

Distribution Increase. On July 22, 2004, the board of directors of our general partner declared a quarterly cash distribution of $0.87 per common and subordinated unit for the period of April 1 through June 30, 2004. This distribution represents an 11.5% increase over the distribution for the second quarter of 2003 of $0.78 per unit and an approximate 65.7% increase in our distribution since our initial public offering in February 2001. The distribution was paid on August 13, 2004 to unitholders of record at the close of business on August 3, 2004.

Acquisition of Shell Refined Petroleum Products Pipeline Systems. On October 1, 2004, we acquired more than 2,000 miles of refined petroleum products pipeline system assets from Shell for approximately $489.7 million. In addition to the purchase price, we paid approximately $30.0 million for inventory related to a third-party supply agreement under which we received a security interest in a related $14.0 million cash collateral account, assumed approximately $25.7 million of existing liabilities and expect to incur approximately $9.6 million for transaction costs. These assets are located in Colorado, Kansas, Oklahoma and Texas and primarily comprise the following four refined petroleum products pipeline systems, which include six active terminals and six system storage facilities that have a combined storage capacity of approximately 6.4 million barrels:

•

Orion refined products system: an approximate 1,000-mile pipeline originating at the East Houston terminal in Houston, Texas that we acquired as part of this acquisition that delivers refined products to (i) a terminal in Odessa, Texas that we acquired as part of this acquisition, (ii) a third-party terminal in El Paso, Texas, (iii) third-party facilities in central Texas and (iv) the mid-continent region of the United States through an interconnection with our 6,700-mile petroleum products pipeline system at Duncan, Oklahoma;

•

Hearne refined products system: an approximate 145-mile pipeline originating in Hearne, Texas that delivers refined products to third-party terminals in Waco and Dallas, Texas and to our existing terminal in Dallas;

•

Chase refined products system: an approximate 700-mile pipeline originating in El Dorado, Kansas that delivers refined products to (i) two terminals that we acquired as part of this acquisition and one third-party terminal in Kansas, (ii) a terminal near Denver, Colorado that we acquired as part of this acquisition and (iii) the Denver International Airport; and

•

Cimarron refined products system: an approximate 175-mile pipeline with origin points in Glenpool and Cushing, Oklahoma that delivers refined products to the Chase pipeline connection at El Dorado, Kansas. Our 6,700-mile petroleum products pipeline system serves as an interconnect between the Orion pipeline at Duncan, Oklahoma and the Cimarron pipeline at Cushing, Oklahoma.

The Orion, Chase and Cimarron refined products systems already have connections to our 6,700-mile petroleum products pipeline system. Given the strategic importance of these assets to us and their connections to our existing assets, we believe that opportunities exist for several expansion projects to improve the utilization of, and integrate the acquired assets into, our existing operations.

Giving effect to the anticipated expansion projects and our marketing of these assets to third parties, including Shell, we expect annual operating profit from the acquired assets to be between $40.0 and $45.0 million by 2007 and to average approximately $37.0 million for the period 2005 to 2007. We expect the related book depreciation to average approximately $18.0 million per year for the period 2005 to 2007, and the maintenance capital for the acquired assets to be approximately $2.0 million annually. For information about

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certain factors that could cause the actual operating results attributable to the acquired assets to materially differ from that which we expect, please read “Information Regarding Forward-Looking Statements” in this prospectus supplement and “Risk Factors” included in and incorporated by reference into this prospectus supplement and the accompanying prospectus.

In connection with this acquisition, we amended our partnership agreement to reduce the incentive cash distributions to be paid to our general partner by $5.0 million and $3.0 million for 2005 and 2006, respectively. In addition, the amended partnership agreement reduces the incentive cash distributions to be paid to our general partner for the fourth quarter of 2004 by $1.25 million. These reductions will accelerate the accretion attributable to the acquisition and increase the cash available for distribution to our limited partners.

At the time this acquisition closed on October 1, 2004, we financed the acquisition with cash on hand of approximately $179.3 million, including net proceeds of approximately $87.3 million from our August 2004 equity offering and net of an escrow payment of approximately $24.6 million to Shell in June 2004, $300.0 million of borrowings under our short-term acquisition facility and $50.0 million of borrowings under our revolving credit facility. Affiliates of each of the underwriters participating in this offering are lenders under our $300.0 million short-term acquisition facility. We intend to use the net proceeds from this offering to repay a portion of the borrowings under our short-term acquisition facility. We expect to repay the remaining borrowings under our short-term acquisition facility with net proceeds from a future issuance of long-term debt.

For more information about the acquisition and our related financing plan, please read “Overview of the Shell Acquisition,” “Use of Proceeds” and “Underwriting.”

Partnership Structure and Management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. After giving effect to this offering of our common units:

•

There will be 25,795,000 publicly held common units outstanding, representing a 77.1% limited partner interest in us;

•

Magellan Midstream Holdings, L.P. will own 2,735,541 common units and 4,259,771 subordinated units, representing an aggregate 20.9% 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.

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 this offering. The percentages reflected in the organizational chart represent the approximate ownership interests in us and our operating subsidiaries.

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Ownership of Magellan Midstream Partners, L.P.		Percentage Interest
Public common units		77.1%
Magellan Midstream Holdings, L.P. common units		8.2%
Magellan Midstream Holdings, L.P. subordinated units		12.7%
Magellan GP, LLC general partner interest		2.0%

Total		100.0%

LOGO

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The Offering

Common units offered

2,600,000 common units; 2,990,000 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering

28,530,541 common units if the underwriters do not exercise their over-allotment option and 28,920,541 common units if the underwriters exercise their over-allotment option in full; and 4,259,771 subordinated units.

Use of proceeds

Cash distributions

Under our partnership agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define it in our partnership agreement.

We declared a quarterly cash distribution for the second quarter of 2004 of $0.87 per common and subordinated unit, or $3.48 per unit on an annualized basis. We paid this cash distribution on August 13, 2004 to unitholders of record at the close of business on August 3, 2004.

When our quarterly cash distributions exceed $0.578 per unit in any given quarter, our general partner receives a higher percentage of the cash distributed in excess of that amount, in increasing percentages up to 50% if the quarterly cash distributions exceed $0.788 per unit. For a description of our cash distribution policy, please read “Cash Distributions” in the accompanying prospectus. In connection with the Shell acquisition, we have amended our partnership agreement to reduce the incentive cash distributions to our general partner as described in “Overview of the Shell Acquisition—Overview.”

Subordination period

The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before December 31, 2005.

When the subordination period ends, all remaining subordinated units will convert into common units, and the common units will no longer be entitled to arrearages.

Early conversion of subordinated units

We met the financial tests in our partnership agreement for the quarter ended December 31, 2003 for the early conversion of a portion of our subordinated units. As a result, in February 2004, 25%, or 1,419,923,

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of our subordinated units converted into common units. If we meet these tests for any quarter ending on or after December 31, 2004, an additional 25% of the subordinated units will convert into common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for the distribution for the fourth calendar quarter of 2006, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed with respect to that period. Please read “Tax Considerations” in this prospectus supplement for the basis of this estimate.

New York Stock Exchange symbol

MMP

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Summary Selected Financial and Operating Data

We have derived the summary selected historical financial data as of and for the years ended December 31, 2001, 2002 and 2003 from our audited consolidated financial statements and related notes. We have derived the summary selected historical financial data as of and for the six months ended June 30, 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. All other amounts have been prepared from our financial records. Information concerning significant trends in our financial condition and results of operations is contained in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which has been filed with the SEC and is incorporated by reference.

The 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 fee amortization, write-off of unamortized debt placement fees, 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 the following page.

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, such as depreciation and amortization and general and administrative expenses, that management does not consider when evaluating the core profitability of an operation. Our management uses operating margin in deciding how to allocate capital resources between our business segments. We believe that operating margin is an important measure for investors of the economic performance of our core operations.

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	Year Ended December 31,									Six Months Ended June 30,
	2001			2002			2003			2003		2004
	($ in thousands, except per unit amounts)
Income Statement Data:
Transportation and terminals revenues	$	339,412		$	363,740		$	372,848		$	183,430	$	192,629
Product sales revenues		108,169			70,527			112,312			44,210		82,735
Affiliate construction and management fee revenues		1,018			210			—			—		—

Total revenues		448,599			434,477			485,160			227,640		275,364

Operating expenses including environmental expenses net of indemnifications		160,880			155,146			166,883			76,402		80,915
Product purchases		95,268			63,982			99,907			39,851		70,881
Equity earnings(a)		—			—			—			—		(268	)

Operating margin		192,451			215,349			218,370			111,387		123,836
Depreciation and amortization		35,767			35,096			36,081			18,262		19,344
General and administrative		47,365			43,182			56,846			26,923		26,394

Operating profit		109,319			137,071			125,443			66,202		78,098
Interest expense, net		12,113			21,758			34,536			16,976		15,773
Debt placement fee amortization		253			9,950			2,830			1,309		1,338
Debt prepayment premium		—			—			—			—		12,666
Write-off of unamortized debt placement fees		—			—			—			—		5,002
Gain on derivative		—			—			—			—		(953	)
Other income, net		(431	)		(2,112	)		(92	)		—		—

Income before income taxes		97,384			107,475			88,169			47,917		44,272
Provision for income taxes(b)		29,512			8,322			—			—		—

Net income	$	67,872		$	99,153		$	88,169		$	47,917	$	44,272

Basic net income per limited partner unit	$	1.87		$	3.68		$	3.32		$	1.75	$	1.50

Diluted net income per limited partner unit	$	1.87		$	3.67		$	3.31		$	1.74	$	1.50

Balance Sheet Data:
Working capital (deficit)	$	(2,211	)	$	47,328		$	77,438		$	64,523	$	70,261
Total assets		1,104,559			1,120,359			1,194,930			1,147,999		1,248,680
Total debt		139,500			570,000			570,000			570,000		551,690
Affiliate long-term note payable(c)		138,172			—			—			—		—
Partners’ capital		589,682			451,757			498,149			484,742		547,242
Cash Flow Data:
Cash distributions declared per unit(d)	$	2.02		$	2.71		$	3.17		$	1.53	$	1.72
Other Data:
Operating margin:
Petroleum products pipeline system	$	143,711		$	163,233		$	162,494		$	81,583	$	89,711
Petroleum products terminals		38,240			43,844			46,909			26,890		28,517
Ammonia pipeline system		10,500			8,272			8,094			2,914		4,160
Allocated partnership depreciation costs		—			—			873			—		1,448

Operating margin	$	192,451		$	215,349		$	218,370		$	111,387	$	123,836

EBITDA:
Net income	$	67,872		$	99,153		$	88,169		$	47,917	$	44,272
Income taxes(b)		29,512			8,322			—			—		—
Debt placement fee amortization		253			9,950			2,830			1,309		1,338
Write-off of unamortized debt placement fees		—			—			—			—		5,002
Interest expense, net		12,113			21,758			34,536			16,976		15,773
Depreciation and amortization		35,767			35,096			36,081			18,262		19,344

EBITDA(e)	$	145,517		$	174,279		$	161,616		$	84,464	$	85,729

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	Year Ended December 31,			Six Months Ended June 30,
	2001	2002	2003	2003	2004
Operating Statistics:
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per barrel)	90.8	94.9	96.4	98.9	99.1
Transportation barrels shipped (millions)	236.1	234.6	237.6	111.7	115.4
Barrel miles (billions)	70.5	71.0	70.5	33.3	32.1
Petroleum products terminals:
Marine terminal average storage capacity utilized per month (million barrels)	15.7	16.2	15.2	15.7	15.6
Marine terminal throughput (million barrels)(f)	11.5	20.5	22.2	10.4	11.2
Inland terminal throughput (million barrels)	56.7	57.3	61.2	28.3	46.6
Ammonia pipeline system:
Volume shipped (thousand tons)	763	712	614	236	381

(a)	Represents equity earnings related to our 50% ownership interest in Osage Pipe Line Company, LLC.

(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 6,700-mile 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 closing of our acquisition of Magellan Pipeline Company, its affiliate note payable was contributed to us as a capital contribution by an affiliate of The Williams Companies, Inc., or Williams.

(d)

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

(e)	Includes $5.9 million and $3.6 million of reimbursable general and administrative expenses and $10.8 million and $0.8 million of transition costs for the year ended December 31, 2003 and the six months ended June 30, 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 for the Gibson facility (2.2 million barrels), which was acquired in October 2001.

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RISK FACTORS

An investment in our common units involves risk. You should carefully read the risk factors set forth below, the risk factors included under the caption “Risk Factors” beginning on page 2 of 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 into this prospectus supplement and the accompanying prospectus.

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

Since December 2003, Magellan Midstream Holdings, L.P. has sold common units that represented an approximate 28% interest in our capital and profits for tax purposes. We will be considered to have been terminated for federal income tax purposes if the common units sold by Magellan Midstream Holdings, L.P., together with all common units sold within a 12-month period, represent a sale or exchange of 50% or more of our capital and profits interests. Our termination for tax purposes would, among other things, result in a significant deferral of the depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. For a discussion of the consequences of our termination for federal income tax purposes, please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” in the accompanying prospectus.

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 our general partner in a manner that is beneficial to Magellan Midstream Holdings, L.P., its sole member. At the same time, our general partner has duties to manage us in a manner that is beneficial to us. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Magellan Midstream Holdings, L.P.

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 our 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. Specifically, our general partner is owned by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P. which also owns, through affiliates, an interest in the general partner of Buckeye Partners, L.P. Although we do not have extensive operations in the geographic areas primarily served by Buckeye Partners, we will compete directly with Buckeye Partners and perhaps other entities in which the Carlyle/Riverstone Fund has an interest for acquisition opportunities throughout the United States and potentially will compete with Buckeye Partners and these other entities for new business or extensions of the existing services provided by our operating partnerships, creating actual and potential conflicts of interest between us and affiliates of our general partner.

The assets acquired from Shell are subject to ongoing remediation obligations, and we may incur substantial environmental costs and liabilities that are not covered by Shell’s indemnification of us.

Some of the assets acquired from Shell have been used for many years to distribute, store or transport petroleum products, and releases may have occurred from terminals or along pipeline rights-of-way that require remediation. In addition, past releases may have occurred but have not yet been discovered, which could require costly future remediation. As part of the acquisition, Shell agreed to retain liabilities and expenses related to active environmental remediation projects, other than those relating to the consent decree discussed in the paragraph below. In addition, Shell agreed to indemnify us for certain environmental liabilities arising from pre-closing conditions so long as we provide notice of those conditions no later than October 1, 2006. Shell’s indemnification obligation is subject to a $250,000 per-claim deductible and a $30.0 million aggregate cap.

In 2003, Shell entered into a consent decree with the United States Environmental Protection Agency arising out of a June 1999 incident unrelated to the assets we acquired from Shell. In order to resolve Shell’s civil

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liability for the incident, Shell agreed to pay civil penalties of $10.0 million and to comply with certain terms set out in the consent decree. These terms include requirements for testing and maintenance of a number of Shell’s pipelines, including the Chase and Orion pipelines, the creation of a damage prevention program, submission to independent monitoring and various reporting requirements. The consent decree imposes penalties for non-compliance for a period of at least five years from the date of the consent decree. Under our purchase agreement with Shell, we agreed, at our own expense, to complete any remaining remediation work required under the consent decree with respect to the Chase and Orion pipelines and have assumed a liability of approximately $8.1 million for this remediation work. Shell has agreed to retain responsibility under the consent decree for the ongoing independent monitoring obligations related to the Chase pipeline.

If a significant accident or event occurred in the past for which indemnification is not available or if the costs of performing any remediation significantly exceed our expectations, it could adversely affect our financial position, results of operations and our ability to make distributions to our unitholders.

Rate regulation or a successful challenge to the rates we charge on our petroleum products pipelines may reduce the amount of cash we generate.

The FERC regulates the tariff rates for interstate movements on our petroleum products pipelines. Shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates and order refunds of amounts collected under rates that were in excess of a just and reasonable level. In addition, shippers may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint.

The FERC’s ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. The FERC’s primary ratemaking methodology is price indexing. We use this methodology to establish our rates in approximately one-third of our interstate markets. The indexing method allows a pipeline to increase its rates by a percentage equal to the change in the producer price index, or PPI. If the PPI falls, we could be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the PPI might not be large enough to fully reflect actual increases in the costs associated with the pipelines subject to indexing.

The potential for a challenge to our indexed rates creates the risk that the FERC might find some of our indexed rates to be in excess of a just and reasonable level—that is, a level justified by our cost of service. In such an event, the FERC would order us to reduce any such rates and, could require the payment of reparations to complaining shippers for up to two years prior to the complaint.

On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which vacated the FERC’s application of its Lakehead policy. Under that policy, the FERC allowed a regulated entity organized as a master limited partnership to include in its cost of service an income tax allowance to the extent that its unitholders, or limited partners, were corporations subject to income tax. Because the court’s ruling on the FERC’s Lakehead policy in BP West Coast appears to focus on the facts and record presented to it in that case, it is not clear what impact, if any, the opinion will have on our indexed rates. Moreover, it is not clear what action the FERC will take in response to BP West Coast, to what extent such action will be challenged and, if so, whether it will withstand further FERC or judicial review. Nevertheless, a shipper might rely on this decision to challenge our indexed rates and claim that our income tax allowance should be eliminated. If the FERC were to disallow our income tax allowance, it may be somewhat more difficult to justify our indexed rates on a cost of service basis. However, because of the relatively small percentage of our unitholders that are corporations, which results in our including only a small income tax allowance in our cost of service, we do not believe that a challenge to our indexed rates based solely on an elimination of our income tax allowance would be likely to succeed.

We establish rates in approximately two-thirds of our markets using the FERC’s market-based ratemaking regulations. These regulations allow us to establish rates based on conditions in individual markets without regard to the index or our cost of service. If successfully challenged, the FERC could take away our ability to establish market-based rates. We would then have to establish rates that would be justified on some other basis such as our cost of service.

Any reduction in the indexed rates, removal of our ability to establish market-based rates, or payment of reparations could have a material adverse effect on our operations and reduce the amount of cash we generate.

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USE OF PROCEEDS

We will receive net proceeds of approximately $138.3 million from the sale of the 2,600,000 common units we are offering and our general partner’s related capital contribution, after deducting the underwriting discounts and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering, including the net proceeds from the exercise of the underwriters’ over-allotment option, if any, and our general partner’s related capital contribution to repay a portion of the indebtedness and accrued interest outstanding under our $300.0 million short-term acquisition facility that we used to finance the acquisition from Shell. Affiliates of each of the underwriters participating in this offering are lenders under our short-term acquisition facility. Please read “Overview of the Shell Acquisition” for more information regarding this acquisition. As of October 1, 2004, this short-term acquisition facility had a weighted average interest rate of 2.8% per year and matures in September 2005.

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CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2004:

•

on a historical basis;

•

as adjusted to give effect to the sale of 1,800,000 common units sold by us in August 2004, our general partner’s related capital contribution and the application of the net proceeds from both;

•

as adjusted to give effect to the consummation of the Shell acquisition and the financing of a portion of the purchase price with borrowings under our short-term acquisition facility and our revolving credit facility; and

•

as adjusted to give effect to the sale of 2,600,000 common units offered by us pursuant to this prospectus supplement, our general partner’s related capital contribution and the application of the net proceeds therefrom in the manner described under “Use of Proceeds.”

The net proceeds from the common units offered by us and our general partner’s related capital contribution are approximately $138.3 million, after deducting the underwriting discounts and estimated offering expenses payable by us.

This table should be read together with our historical financial statements and the accompanying notes incorporated by reference into this prospectus supplement and the accompanying prospectus. This table does not reflect the issuance of up to 390,000 common units that we may sell to the underwriters upon exercise of their over-allotment option, the proceeds of which, together with our general partner’s related capital contribution, will be used to repay a portion of the indebtedness and accrued interest outstanding under our short-term acquisition facility that we used to finance the acquisition from Shell. Please read “Use of Proceeds.”


	As of June 30, 2004
	Historical			As Adjusted for August 2004 Offering			As Adjusted for Shell Acquisition Financing		As Adjusted for this Offering
	(unaudited)
	($ in thousands)
Cash and cash equivalents	$	51,951	(a)	$	174,258	(b)	$	19,640	$	19,910

Debt:
Short-term acquisition facility		—			—		$	300,000	$	162,000
Revolving credit facility		—			—			50,000		50,000
Magellan Pipeline Company Series B senior notes due 2007(c)	$	302,202		$	302,202			302,202		302,202
Magellan Midstream Partners 6.45% senior notes due 2014(d)		249,488			249,488			249,488		249,488

Total debt	$	551,690		$	551,690		$	901,690	$	763,690
Total partners’ capital		547,242			634,549			634,549		772,819

Total capitalization	$	1,098,932		$	1,186,239		$	1,536,239	$	1,536,509

(a)	Net of a $24.6 million escrow payment made to Shell in June 2004 in connection with the acquisition.

(b)	Reflects a $35.0 million cash receipt on July 1, 2004 in connection with our indemnification settlement with Williams.

(c)	Reflects a $0.2 million change in the fair value of these notes between May 25, 2004 and June 30, 2004 in connection with the fair value hedges associated with these notes.

(d)	Reflects $0.5 million of original issue discount.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of September 30, 2004, there were 25,930,541 common units outstanding, held by approximately 29,000 holders, including common units held in street name and units held by Magellan Midstream Holdings, L.P. Our common units are traded on the New York Stock Exchange under the symbol “MMP.”

As of September 30, 2004, 4,259,771 subordinated units were outstanding. These subordinated units are held by Magellan Midstream Holdings, L.P. and are not publicly traded.

The following table sets forth, for the periods indicated, the high and low closing sales prices for our common units, as reported on the New York Stock Exchange Composite Transaction Tape, and quarterly declared cash distributions per common unit. The closing sales price of our common units on the New York Stock Exchange on October 4, 2004 was $54.50 per common unit.


	Price Ranges				Cash Distributions Per Unit(a)
	High		Low		Cash Distributions Per Unit(a)
2004
Fourth Quarter (through October 4, 2004)	$	55.84	$	54.50		N/A	(b)
Third Quarter		55.00		49.77		N/A	(b)
Second Quarter		55.50		46.89	$	0.8700
First Quarter		55.35		50.05		0.8500
2003
Fourth Quarter	$	55.03	$	45.80	$	0.8300
Third Quarter		48.55		42.40		0.8100
Second Quarter		48.20		37.54		0.7800
First Quarter		37.19		33.30		0.7500
2002
Fourth Quarter	$	34.70	$	29.50	$	0.7250
Third Quarter		36.40		25.20		0.7000
Second Quarter		42.35		30.75		0.6750
First Quarter		43.30		32.85		0.6125
2001
Fourth Quarter	$	44.00	$	37.00	$	0.5900
Third Quarter		40.40		29.40		0.5775
Second Quarter		33.42		28.45		0.5625
First Quarter		31.00		24.00		0.2920

(a)	Cash distributions declared for each respective quarter. Cash distributions were declared and paid within 45 days following the close of each quarter. The cash distribution for the first quarter of 2001 was prorated for the period from February 10, 2001 through March 31, 2001.

(b)	We expect to declare and pay a cash distribution within 45 days following the end of the quarter.

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OVERVIEW OF THE SHELL ACQUISITION

Substantially all of the information presented below related to the Shell assets is based on information provided to us by Shell in connection with our acquisition of Shell’s refined petroleum products pipeline system assets.

Overview

On October 1, 2004, we acquired more than 2,000 miles of refined petroleum products pipeline system assets from Shell for approximately $489.7 million. In addition to the purchase price, we paid approximately $30.0 million for inventory related to a third-party supply agreement under which we received a security interest in a related $14.0 million cash collateral account, assumed approximately $25.7 million of existing liabilities and expect to incur approximately $9.6 million for transaction costs. These assets are located in Colorado, Kansas, Oklahoma and Texas and primarily comprise the following four refined products pipeline systems, which include six active terminals and six system storage facilities that have a combined storage capacity of approximately 6.4 million barrels:

•

Giving effect to anticipated expansion projects discussed below under “—Strategic Rationale” and our marketing of these assets to third parties, including Shell, we expect annual operating profit from the acquired assets to be between $40.0 and $45.0 million by 2007 and to average approximately $37.0 million for the period 2005 to 2007. We expect the related book depreciation to average approximately $18.0 million per year for the period 2005 to 2007, and the maintenance capital for the acquired assets to be approximately $2.0 million annually. For information about certain factors that could cause the actual operating results attributable to the acquired assets to materially differ from that which we expect, please read “Information Regarding Forward-Looking Statements” in this prospectus supplement and “Risk Factors” included in and incorporated by reference into this prospectus supplement and the accompanying prospectus.

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million of borrowings under our short-term acquisition facility and $50.0 million of borrowings under our revolving credit facility. Affiliates of each of the underwriters participating in this offering are lenders under our short-term acquisition facility. We intend to use the net proceeds from this offering to repay a portion of the borrowings under our short-term acquisition facility. We expect to repay the remaining borrowings under our short-term acquisition facility with net proceeds from a future issuance of long-term debt.

Strategic Rationale

The acquisition of the Shell refined petroleum products pipeline system assets provides us with a direct connection to the U.S. Gulf Coast, which is the primary refining region of the United States and a major point of entry for foreign imports of refined petroleum products. The acquisition also extends the reach of our 6,700-mile petroleum products pipeline system into key markets in Colorado and western and northern Texas, including the growing metropolitan centers of Denver, Colorado, Dallas/Fort Worth, Texas and El Paso, Texas. According to the U.S. Census Bureau, the annual population growth in these areas has exceeded the national average over the past ten years. The compound annual growth in population for the Dallas/Fort Worth, Denver and El Paso markets was approximately 2.6%, 2.6% and 1.4%, respectively, from 1990 to 2000 compared to the compound annual growth of approximately 1.2% for the nation on average. Based on this historical trend, we believe that demand for refined products in these markets will also increase more than the national average. Further, statistics from the Energy Information Administration indicate the demand for refined petroleum products in the market areas served by our 6,700-mile petroleum products pipeline system is also expected to grow at an average compound annual rate of approximately 1.7% per year over the next ten years. We believe that a substantial part of this growth in demand will be satisfied by shipments of refined products from the U.S. Gulf Coast region. The integration of the acquired assets into our 6,700-mile petroleum products pipeline system will provide us with the ability to efficiently connect these growing markets with the U.S. Gulf Coast as a source of supply.

The Orion, Chase and Cimarron refined products systems already have connections to our 6,700-mile petroleum products pipeline system. For example, the Orion refined products system currently serves markets in the mid-continent region through a connection with our 6,700-mile petroleum products pipeline system, and the Chase refined products system can be supplied with refined products from the U.S. Gulf Coast region through our 6,700-mile petroleum products pipeline system. In addition, prior to the acquisition, we leased and operated a portion of the Cimarron pipeline. Given the strategic importance of these assets to us, we believe that opportunities exist for several projects to expand our 6,700-mile petroleum products pipeline system, our existing terminal network and the Orion refined products system’s point of origin at the East Houston terminal, thereby enhancing our connectivity to U.S. Gulf Coast refineries.

Description of the Assets

Orion Refined Products System

The Orion refined products system, or Orion, comprises three main segments which total approximately 1,000 miles:

•

the South segment, which extends from its East Houston terminal located near Houston, Texas to its Frost storage facility located approximately 50 miles south of Dallas, Texas, both of which we acquired as part of this acquisition;

•

the North segment, which extends from the Frost storage facility to Duncan, Oklahoma, where it interconnects with our 6,700-mile petroleum products pipeline system; and

•

the West segment, which extends from the Frost storage facility to El Paso, Texas.

Orion’s three segments are linked at the Frost storage facility and form a system capable of transporting approximately 100,000 barrels per day, or bpd. Orion also includes one active terminal located in Odessa, Texas, which has an aggregate storage capacity of approximately 709,000 barrels, and one idle terminal located in El Paso. The East Houston terminal includes a number of crude oil storage tanks that we are leasing to Shell under a long-term lease agreement.

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Orion receives all of the refined products it transports from the East Houston terminal, which receives the majority of its supply from Shell’s Deer Park, Texas refinery. The remainder of the refined products received by the East Houston terminal originate from Kinder Morgan Energy Partners L.P.’s terminals located in Galena Park and Pasadena, Texas.

Orion is a common-carrier pipeline, and its tariffs are regulated by the FERC and the Texas Railroad Commission.

Hearne Refined Products System

The Hearne refined products system, or Hearne, consists of an approximate 145-mile pipeline that originates at the Hearne, Texas storage facility located approximately 120 miles northwest of Houston, Texas and delivers refined products to third-party terminals in Waco and Dallas, Texas and to our existing terminal in Dallas. Additionally, refined products from Hearne can be delivered to the Hearne/Bryan/College Station area through a third-party truck loading rack at the Hearne storage facility and from facilities in Reagan, Texas to a railroad fueling facility in Temple, Texas through an interconnection with a pipeline owned by Koch Pipeline Company L.P. Hearne has a current throughput capacity of approximately 70,000 bpd and also includes an approximate 25-mile pipeline from Dallas to Fort Worth, Texas that has been idle since 2001.

Hearne receives a majority of its volumes through the Magtex pipeline from two major Gulf Coast refineries owned by ExxonMobil and Motiva. Hearne also has a newly constructed interconnection with Orion at Bee Creek, Texas.

Hearne is a common-carrier pipeline, and its tariffs are regulated by the Texas Railroad Commission.

Chase Refined Products System

The Chase refined products system, or Chase, consists of an approximate 700-mile pipeline that originates at its El Dorado, Kansas storage facility and has two segments, the Chase Mainline and the Chase Loop. The Chase Mainline currently has capacity to transport approximately 60,000 bpd of refined products from El Dorado, Kansas to its Aurora terminal near Denver, Colorado. The Chase Mainline also includes a pipeline that extends from its Aurora terminal to Denver International Airport and is the only pipeline serving that airport. The Chase Loop has a current capacity of approximately 21,000 bpd that delivers refined products to two terminals located in Great Bend and Scott City, Kansas, which have storage capacities of approximately 96,000 and 156,000 barrels, respectively. In addition, the Chase Loop delivers refined products to a third-party terminal located in Valley Center, Kansas, a northern suburb of Wichita.

Chase receives refined products from its El Dorado storage facility, which receives refined products primarily from Frontier Oil Corporation’s approximate 110,000 bpd refinery located in El Dorado. The El Dorado storage facility also receives products from U.S. Gulf Coast refineries through an interconnection with our 6,700-mile petroleum products pipeline system through the Cimarron pipeline described below.

The Chase Mainline is a common-carrier pipeline, and its tariffs are regulated by the FERC, except for the segment serving the Denver International Airport, the tariffs for which are regulated by the Colorado Public Utility Commission. The Chase Loop is a common-carrier pipeline, and its tariffs are regulated by the Kansas Corporation Commission.

Cimarron Refined Products System

The Cimarron refined products system, or Cimarron, consists of an approximate 175-mile pipeline that originates at its Glenpool storage facility near Glenpool, Oklahoma and extends approximately 40 miles west to Cushing, Oklahoma. At Cushing, the pipeline extends north approximately 130 miles to the El Dorado storage facility, where it interconnects with Chase. Cimarron has current capacity to transport approximately 25,000 bpd

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of refined products. The approximate 620,000-barrel Glenpool storage facility is connected to an approximate 3.8 million-barrel storage facility on the Explorer pipeline, and is also connected to the storage facility that we lease in Glenpool. Cimarron also includes the approximate 292,000-barrel Boyer storage facility which provides additional tankage for Cimarron and allows Cimarron to access the El Dorado storage facility more efficiently.

The section of Cimarron extending from Glenpool to Cushing is leased to a third party through January 31, 2005 and currently transports crude oil.

Other Assets

In addition to the four refined products pipeline systems described above, we also acquired:

•

a five-mile pipeline that extends from an interconnection with the Magtex pipeline to Bush Intercontinental Airport in Houston, Texas, including four storage tanks connected to the pipeline with an aggregate capacity of approximately 226,000 barrels; and

•

a terminal in Oklahoma City, Oklahoma, with a storage capacity of approximately 152,000 barrels, located on our 6,700-mile petroleum products pipeline system.

Because we already own a terminal in Oklahoma City, the Federal Trade Commission is requiring us to sell the newly acquired terminal in Oklahoma City. We believe the Oklahoma City terminal is not material to the operation of the Shell assets.

No Historical Financial Information

The Shell assets we acquired have not been operated historically as a separate division or subsidiary. Shell operated these assets as part of its more extensive transportation and terminalling and crude oil and refined products operations. As a result, Shell did not maintain complete and separate financial statements for these assets as an independent business unit.

We plan to integrate the assets into the operations of our 6,700-mile petroleum products pipeline system utilizing our existing accounting, financial reporting and measurement and control systems. In order to facilitate this integration, we entered into a transition services agreement with Shell. Under the transition services agreement, Shell agreed to provide certain pipeline control services in connection with the operation of the assets for up to one year following the closing of the acquisition. We employ field operations personnel to operate the assets, including some former Shell employees, and utilize our existing marketing and managerial employees as well as additional personnel to perform these functions. We also entered into transportation, terminalling and supply agreements with third parties, including Shell, for the refined petroleum products pipeline system assets, terminals and system storage facilities that we acquired. We charge applicable tariffs and fees for transportation and terminalling services with respect to these assets in order to generate revenues and cash for distribution to our unitholders.

Terminalling and Transportation Agreements with Shell

In connection with our acquisition of these refined petroleum products pipeline system assets, we entered into three-year terminalling and transportation agreements and a five-year storage lease agreement with Shell for a combined minimum revenue commitment averaging approximately $28.1 million per year through September 30, 2007 and approximately $750,000 per year thereafter through September 30, 2009.

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MANAGEMENT

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


Name	Age	Position with General Partner
Don R. Wellendorf	52	Chairman of the Board, President and Chief Executive Officer
John D. Chandler	34	Vice President, Chief Financial Officer and Treasurer
Michael N. Mears	41	Vice President, Transportation
Richard A. Olson	47	Vice President, Pipeline Operations
Brett C. Riley	34	Vice President, Business Development
Lonny E. Townsend	47	Vice President and General Counsel
Jay A. Wiese	48	Vice President, Terminal Services and Development
Patrick C. Eilers	38	Director
Justin S. Huscher	50	Director
N. John Lancaster, Jr.	36	Director
Pierre F. Lapeyre, Jr.	42	Director
James R. Montague	57	Director
George A. O’Brien, Jr.	55	Director
Mark G. Papa	58	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. He has served as the President and Chief Executive Officer of Magellan Midstream Management, LLC, the general partner of Magellan Midstream Holdings, L.P., since June 17, 2003. 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 a Vice President of a subsidiary of Williams. Prior to Williams’ merger with MAPCO Inc., he served in various management positions since joining MAPCO in 1979.

John D. Chandler has served as a Vice President since June 17, 2003 and 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 has served as Vice President, Chief Financial Officer and Treasurer of Magellan Midstream Management, LLC since June 17, 2003. He was Director of Financial Planning and Analysis for a subsidiary of Williams from September 2000 to July 2002. He also served as Director of Strategic Development for a subsidiary of Williams from 1999 to 2000 and served as Manager of Strategic Analysis from 1998 to 1999. Prior to Williams’ merger with MAPCO Inc., he held various accounting and finance positions with MAPCO from 1992 to 1998.

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 has served as a Vice President of Magellan Midstream Management, LLC since June 17, 2003. He served as a Vice President of subsidiaries of Williams from 1996 to June 17, 2003. Mr. Mears also worked in various management positions with Magellan Pipeline Company, L.P. since joining Williams in 1985.

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 a Vice President of subsidiaries of Williams from 1996 to 2002. Mr. Olson also worked in various management positions with Magellan Pipeline Company, L.P. since joining Williams in 1981.

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Brett C. Riley has served as the Vice President, Business Development of our general partner since June 17, 2003. He has served as a Vice President of Magellan Midstream Management, LLC since June 17, 2003. Mr. Riley served as Director of Mergers & Acquisitions for a subsidiary of Williams from September 2000 until June 2003. He also served as Director of Financial Planning and Analysis for a subsidiary of Williams from 1998 to 2000. Mr. Riley also worked in various financial positions with MAPCO and Williams since 1992.

Lonny E. Townsend has served as Vice President and General Counsel of our general partner since June 17, 2003. He has served as Vice President, General Counsel and Assistant Secretary of Magellan Midstream Management, LLC 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.

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 has served as a Vice President of Magellan Midstream Management, LLC since June 17, 2003. He was Managing Director, Terminal Services and Commercial Development for a subsidiary of Williams from 2000 to January 2001. From 1995 to 2000, he served as Director, Terminal Services and Commercial Development for a subsidiary of Williams and held various operations, marketing and business development positions for Williams from 1982 to 1995.

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. He has served as a Vice President of Magellan Midstream Management, LLC since April 17, 2003. 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 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 has served as a Vice President of Magellan Midstream Management, LLC since April 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.

N. John Lancaster, Jr. has served as a director of our general partner since May 20, 2004. He has served as a Vice President of Magellan Midstream Management, LLC since May 4, 2004. He is a Managing Director of Riverstone Holdings, LLC where his primary focus includes sourcing and executing investments in the energy industry. Prior to joining Riverstone in April 2000, he was a director with The Beacon Group, LLC, a strategic advisory and private equity investment firm. He attended Harvard Business School from January 1998 through May 1999. He also served previously in the energy investment banking groups of both Credit Suisse First Boston and Bankers Trust.

Pierre F. Lapeyre, Jr. has served as a director of our general partner since June 17, 2003. He has served as a Vice President of Magellan Midstream Management, LLC since April 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.

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James R. Montague has served as a director of our general partner since November 21, 2003. 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. He is also a director of the general partner of Penn Virginia Resource Partners.

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 Resources for International Paper Company and is responsible for its forestry and wood products businesses. Since joining International Paper in 1988, his responsibilities have included corporate development, chief financial officer of its New Zealand subsidiary and operations management.

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.

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TAX CONSIDERATIONS

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

We estimate that if you purchase common units in this offering and own them through the record date for the distribution for the fourth quarter of 2006, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed with respect to that period. These estimates are based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of our common units in an amount of at least the current quarterly distribution of $0.87 per unit and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and certain tax reporting positions that we have adopted with which the Internal Revenue Service could disagree. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. Please read “Material Tax Consequences” in the accompanying prospectus.

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

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

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

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

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UNDERWRITING

Under the underwriting agreement, which we will file as an exhibit to our current report on Form 8-K relating to this common unit offering, each of the underwriters named below have severally agreed to purchase common units from us. Each underwriter is obligated to purchase the respective number of common units indicated in the following table:


Underwriters		Number of Common Units
Lehman Brothers Inc.		650,000
Citigroup Global Markets Inc.		650,000
Goldman, Sachs & Co.		433,334
UBS Securities LLC		433,333
Wachovia Capital Markets, LLC		433,333

Total		2,600,000

The underwriting agreement provides that the underwriters are obligated to purchase, subject to certain conditions, all of the common units from us in the offering if any are purchased, other than those covered by the over-allotment option described below. The conditions contained in the underwriting agreement include requirements that:

•

the representations and warranties made by us to the underwriters are true;

•

there has been no material adverse change in our condition or in the financial markets; and

•

we deliver the customary closing documents to the underwriters.

Over-Allotment Option

We have granted the underwriters a 30-day option to purchase, in whole or part, up to an aggregate of 390,000 additional common units at the public offering price less the underwriting discount and commissions. This option may be exercised to cover over-allotments, if any, made in connection with the common unit offering. To the extent that the option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase a number of additional common units proportionate to the underwriter’s percentage underwriting commitment in the offering as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters.

Commission and Expenses

We have been advised by the underwriters that the underwriters propose to offer the common units directly to the public at the price to the public set forth on the cover page of this prospectus supplement and to selected dealers, who may include the underwriters, at the offering price less a selling concession not in excess of $1.396 per unit. The underwriters may allow, and the selected dealers may reallow, a discount from the concession not in excess of $0.10 per unit to other dealers. After the common unit offering, the underwriters may change the offering price and other selling terms.

The following table shows the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option to purchase 390,000 additional common units from us. The underwriting fee is the difference between the public offering price and the amount the underwriters pay us for the common units.


	No Exercise		Full Exercise
Per unit	$	2.316	$	2.316
Total	$	6,021,600	$	6,924,840

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We estimate that the total expenses for this common unit offering, excluding underwriting discounts and commissions, will be approximately $0.3 million.

Lock-up Agreements

We, our affiliates that own common units and the directors and the executive officers of our general partner have agreed that we and they will not, subject to limited exceptions, directly or indirectly, sell, offer for sale, pledge or otherwise dispose of any common units or any securities convertible into or exchangeable or exercisable for common units or enter into any derivative transaction with similar effect as a sale of common units for a period of 90 days after the date of this prospectus supplement without the prior written consent of Lehman Brothers Inc. and Citigroup Global Markets Inc. The restrictions described in this paragraph do not apply to (i) the sale of common units by us to the underwriters, (ii) issuances of common units pursuant to any existing employee benefit plans or (iii) sales of our registered common units to one or more investors in a transaction other than an underwritten public offering, provided that such investors agree in writing to be subject to the same restrictions set forth above for the period between the date of any such issuance and the date 90 days after the date of this prospectus.

Lehman Brothers Inc. and Citigroup Global Markets Inc., in their discretion, may release the common units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release common units from lock-up agreements, Lehman Brothers Inc. and Citigroup Global Markets Inc. will consider, among other factors, our or the unitholders’ reasons for requesting the release, the number of common units for which the release is being requested, and market conditions at the time.

Indemnification

We, our general partner and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities relating to the offering, including liabilities under the Securities Act of 1933, as amended, and liabilities arising from breaches of the representations and warranties contained in the underwriting agreement or to contribute to payments that may be required to be made in respect of these liabilities.

Stabilization, Short Positions and Penalty Bids

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units in accordance with Regulation M under the Securities Exchange Act of 1934, as amended.

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common units over-allotted by the underwriters is not greater than the number of common units they may purchase in the over-allotment option. In a naked short position, the number of common units involved is greater than the number of common units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing the common units in the open market.

•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common

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units than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover a syndicate short position.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time. Prior to purchasing the common units being offered pursuant to this prospectus supplement, one of the underwriters purchased on behalf of the syndicate 20,000 common units at an average price of $54.67 per unit, in stabilizing transactions.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Affiliations

Some of the underwriters and their affiliates have performed investment banking, financial advisory and other commercial services for us and our affiliates in the ordinary course of business from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time in the future, engage in transactions with and perform such services for us and our affiliates in the ordinary course of their business.

Affiliates of each of the underwriters participating in this offering are lenders under the short-term acquisition facility that we used to finance the acquisition from Shell. Each of these lenders will receive a partial repayment of amounts outstanding under this facility from the net proceeds of this offering. Because we intend to use more than 10% of the net proceeds from the sale of the common units to repay indebtedness owed by us to such affiliates under our short-term acquisition facility, this offering is being made in compliance with the requirements of Rule 2710(h) of the Conduct Rules of the National Association of Securities Dealers, Inc. Pursuant to that rule, the appointment of a qualified independent underwriter is not necessary in connection with this offering as a bona fide independent market (as defined in the NASD Conduct Rules) exists in our common units.

Affiliates of each of the underwriters participating in this offering are also lenders under our revolving credit facility.

The decision of the underwriters to participate in this offering was made independently of any of their respective affiliates that are lenders under our revolving credit facility and our short-term acquisition facility.

Electronic Distribution

A prospectus supplement and the accompanying prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this common unit offering, or by their affiliates. In those cases, prospective

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investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus supplement and the accompanying prospectus in electronic format, the information on any underwriter’s or selling group member’s website and any information contained in any other website maintained by any underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus supplement forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as an underwriter or selling group member and should not be relied upon by investors.

Listing

Our common units are traded on the New York Stock Exchange under the symbol “MMP.”

National Association of Securities Dealers Conduct Rules

Because the NASD views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD Conduct Rules.

LEGAL

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units 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, 2002 and 2003 and the related consolidated statements of income, cash flows and partners’ capital for each of the years ended December 31, 2001, 2002 and 2003 appearing in Magellan Midstream Partners, L.P.’s (formerly Williams Energy Partners L.P.) Annual Report on 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, 2002 and 2003 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 registered public accounting firm, 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.

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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 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, cash flow or cash to be distributed to unitholders 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. In addition to the risk factors included under “Risk Factors” in this prospectus supplement and the accompanying prospectus, other 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;

•

changes in our tariff rates implemented by the FERC, the United States Surface Transportation Board and/or state regulators;

•

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 federal, state and local tax, 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 could have other adverse consequences;

•

the condition of the capital markets and equity markets in the United States;

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•

our ability to raise capital in a cost-effective manner;

•

the effect of changes in accounting policies;

•

our ability to manage rapid growth;

•

Magellan Midstream Holdings, L.P.’s ability to perform on its environmental and right-of-way indemnifications to us;

•

Williams’ ability to pay the amounts owed to us under the indemnification settlement;

•

the ability of our general partner to enter into certain agreements which could negatively impact our financial position, results of operations and cash flows;

•

supply disruption; and

•

global and domestic economic repercussions from terrorist activities and international hostilities 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 we filed with the SEC. The information we incorporate by reference is part of this prospectus supplement and later information that we file with the SEC (excluding any information furnished pursuant to Item 2.02 or Item 7.01 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 Reports on Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004;

•

Definitive Proxy Statement on Schedule 14A filed on March 10, 2004;

•

Current Reports on Form 8-K filed on May 5, 2004, May 18, 2004, May 21, 2004, May 25, 2004, May 27, 2004, June 24, 2004, August 13, 2004, September 16, 2004 and October 1, 2004; and

•

the description of our common units contained in our 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 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 supplement or the accompanying prospectus.

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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		1
ABOUT WILLIAMS ENERGY PARTNERS		1
THE SUBSIDIARY GUARANTORS		1
RISK FACTORS		2
Risks Related to our Business		2
Risks Related to our Partnership Structure		5
Tax Risks to Common Unitholders		7
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
General		13
Covenants		15
Events of Default, Remedies and Notice		15
Amendments and Waivers		17
Defeasance		18
No Personal Liability of General Partner		19
Subordination		20
Book Entry, Delivery and Form		21
The Trustee		22
Governing Law		22
DESCRIPTION OF OUR CLASS B UNITS		23
CASH DISTRIBUTIONS		24
Distributions of Available Cash		24
Operating Surplus, Capital Surplus and Adjusted Operating Surplus		24
Subordination Period		25


Distributions of Available Cash from Operating Surplus During the Subordination Period		26
Distributions of Available Cash from Operating Surplus After the Subordination Period		26
Incentive Distribution Rights		27
Percentage Allocations of Available Cash from Operating Surplus		27
Distributions from Capital Surplus		27
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		28
Distributions of Cash Upon Liquidation		28
MATERIAL TAX CONSEQUENCES		31
Partnership Status		31
Limited Partner Status		32
Tax Consequences of Unit Ownership		33
Tax Treatment of Operations		37
Disposition of Common Units		38
Uniformity of Units		40
Tax-Exempt Organizations and Other Investors		40
Administrative Matters		41
State, Local and Other Tax Considerations		43
Tax Consequences of Ownership of Debt Securities		43
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS		44
PLAN OF DISTRIBUTION		45
LEGAL		45
EXPERTS		45

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:

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general creditors;

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trade creditors;

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secured creditors;

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taxing authorities; and

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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.

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

Such conflicts may include, among others, the following:

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

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

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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 66²/3% 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:

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the issuance of common units in connection with acquisitions that increase cash flow from operations per unit on a pro forma basis;

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the conversion of subordinated units into common units;

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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;

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issuances of common units under our long-term incentive plan; or

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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:

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your proportionate ownership interest in Williams Energy Partners will decrease;

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the amount of cash available for distribution on each unit may decrease;

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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;

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the relative voting strength of each previously outstanding unit may be diminished; and

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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.

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Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

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Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2001.

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Current Report on Form 8-K filed January 3, 2002.

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Amended Current Report on Form 8-K/A filed January 14, 2002.

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Current Report on Form 8-K filed January 30, 2002.

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Current Report on Form 8-K filed March 8, 2002.

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Current Report on Form 8-K filed April 11, 2002.

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Current Report on Form 8-K filed April 19, 2002.

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Current Report on Form 8-K filed April 29, 2002.

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Current Report on Form 8-K filed May 3, 2002.

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Amended Current Report on Form 8-K/A filed May 9, 2002.

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Quarterly Report on Form 10-Q filed May 10, 2002.

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Current Report on Form 8-K filed May 15, 2002.

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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:

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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;

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Changes in demand for refined petroleum products that we store and distribute;

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Changes in demand for storage in our petroleum product terminals;

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Changes in our tariff rates implemented by the Federal Energy Regulatory Commission and the United States Surface Transportation Board;

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Shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;

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Changes in the throughput on petroleum product pipelines owned and operated by third parties and connected to our petroleum product terminals;

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Loss of Williams Energy Marketing & Trading Company and/or Williams Refining & Marketing, L.L.C. as customers;

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Loss of one or all of our three customers on our ammonia pipeline and terminals system;

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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;

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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;

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An increase in the competition our petroleum products terminals and ammonia pipeline and terminals system encounter;

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The occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured;

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Our ability to integrate any acquired operations into our existing operations;

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Our ability to successfully identify and close strategic acquisitions and make cost saving changes in operations;

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Changes in general economic conditions in the United States;

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Changes in laws and regulations to which we are subject, including tax, environmental and employment laws and regulations;

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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;

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The condition of the capital markets and equity markets in the United States;

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The ability to raise capital in a cost-effective way;

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The cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;

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The effect of changes in accounting policies;

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The ability to control costs; and

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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:

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“fixed charges” represent interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor; and

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“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:

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will be our general obligations;

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will be general obligations of the Subsidiary Guarantors if they are guaranteed by the Subsidiary Guarantors; and

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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:

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the form and title of the debt securities;

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the total principal amount of the debt securities;

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the date or dates on which the debt securities may be issued;

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the portion of the principal amount which will be payable if the maturity of the debt securities is accelerated;

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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;

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the dates on which the principal and premium, if any, of the debt securities will be payable;

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the interest rate which the debt securities will bear and the interest payment dates for the debt securities;

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any optional redemption provisions;

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any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

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whether the debt securities are entitled to the benefits of any guarantees by the Subsidiary Guarantors;

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whether the debt securities may be issued in amounts other than $1,000 each or multiples thereof;

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any changes to or additional Events of Default or covenants;

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the subordination, if any, of the debt securities and any changes to the subordination provisions of the Indenture; and

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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:

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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;

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debt securities with respect to which principal, premium or interest is payable in a foreign or composite currency;

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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

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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:

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all other contingent and fixed liabilities of the Subsidiary Guarantor; and

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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:

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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;

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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

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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:

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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;

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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

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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:

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default in any payment of interest on any debt securities of that series when due that continues for 30 days;

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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;

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default in the payment of any sinking fund payment on any debt securities of that series when due;

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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;

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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

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

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any of the guarantees by the Subsidiary Guarantors ceases to be in full force and effect, except as otherwise provided in the Indenture;

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any of the guarantees by the Subsidiary Guarantors is declared null and void in a judicial proceeding; or

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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:

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waive all past defaults, except with respect to nonpayment of principal, premium or interest; and

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rescind any declaration of acceleration by the Trustee or the holders with respect to the debt securities of that series,

but only if:

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rescinding the declaration of acceleration would not conflict with any judgment or decree of a court of competent jurisdiction; and

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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:

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such holder has previously given the Trustee notice that an Event of Default with respect to that series is continuing;

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holders of at least 25% in principal amount of the outstanding debt securities of that series have requested that the Trustee pursue the remedy;

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such holders have offered the Trustee reasonable indemnity or security against any cost, liability or expense;

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the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of indemnity or security; and

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the holders of a majority in principal amount of the outstanding 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:

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conflicts with law;

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is inconsistent with any provision of the Indenture;

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the Trustee determines is unduly prejudicial to the rights of any other holder;

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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:

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cure any ambiguity, omission, defect or inconsistency;

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convey, transfer, assign, mortgage or pledge any property to or with the Trustee;

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provide for the assumption by a successor of our obligations under the Indenture;

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add Subsidiary Guarantors with respect to the debt securities;

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change or eliminate any restriction on the payment of principal of, or premium, if any, on, any debt securities;

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secure the debt securities;

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add covenants for the benefit of the holders or surrender any right or power conferred upon us or any Subsidiary Guarantor;

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make any change that does not adversely affect the rights of any holder;

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add or appoint a successor or separate Trustee; or

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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:

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reduce the percentage in principal amount of debt securities of any series whose holders must consent to an amendment;

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reduce the rate of or extend the time for payment of interest on any debt securities;

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reduce the principal of or extend the stated maturity of any debt securities;

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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;

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make any debt securities payable in other than U.S. dollars;

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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;

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impair the right of any holder to institute suit for the enforcement of any payment with respect to such holder’s debt securities;

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release any security that has been granted in respect of the debt securities;

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make any change in the amendment provisions which require each holder’s consent;

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make any change in the waiver provisions; or

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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:

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compliance by us or a Subsidiary Guarantor with certain restrictive provisions of the Indenture; and

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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:

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in the payment of principal, premium or interest; or

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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:

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relating to the defeasance trust;

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to register the transfer or exchange of the debt securities;

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to replace mutilated, destroyed, lost or stolen debt securities; or

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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:

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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;

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the bankruptcy provisions with respect to the Subsidiary Guarantors, if any; and

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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:

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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;

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comply with certain other conditions, including that no default has occurred and is continuing after the deposit in trust; and

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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:

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any of our obligations or the obligations of the Subsidiary Guarantors under the debt securities, the Indentures or the guarantees; or

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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:

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upon any payment or distribution of our assets or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors’ assets, to creditors;

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upon a liquidation or dissolution of us or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors; or

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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:

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make any payments of principal, premium, if any, or interest with respect to subordinated debt securities;

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make any deposit for the purpose of defeasance of the subordinated debt securities; or

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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,

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the default has been cured or waived and any declaration of acceleration has been rescinded;

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the Senior Indebtedness has been paid in full in cash; or

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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:

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

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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:

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by written notice from the person or persons who gave the Blockage Notice;

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by repayment in full in cash of the Designated Senior Indebtedness with respect to which the Blockage Notice was given; or

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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:

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a limited-purpose trust company organized under the New York Banking Law;

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a “banking organization” within the meaning of the New York Banking Law;

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a member of the United States Federal Reserve System;

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a “clearing corporation” within the meaning of the New York Uniform Commercial Code; and

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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:

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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

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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:

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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

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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:

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

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provide for the proper conduct of our business;

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comply with applicable law, any of our debt instruments, or other agreements; or

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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

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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:

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our cash balance on the closing date of our initial public offering; plus

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$15.0 million; plus

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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

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working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

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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

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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:

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borrowings other than working capital borrowings;

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sales of debt and equity securities; and

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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:

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operating surplus generated with respect to that period; less

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any net increase in working capital borrowings with respect to that period; less

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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

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any net decrease in working capital borrowings with respect to that period; plus

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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:

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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;

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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

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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:

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December 31, 2003 with respect to 25% of the subordinated units; and

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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:

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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

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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:

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the subordination period will end and each subordinated unit will immediately convert into one common unit;

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any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

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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:

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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;

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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;

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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

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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:

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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

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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:

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we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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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.


	Total Quarterly Distribution Target Amount	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.

MATERIA L 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:

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a short sale;

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an offsetting notional principal contract; or

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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:

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directly to purchasers;

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through agents;

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through underwriters; and

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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.

LOGO

2,600,000 Common Units

Representing Limited Partner Interests

PROSPECTUS SUPPLEMENT

October 4, 2004

Joint Book-Running Managers

LEHMAN BROTHERS

CITIGROUP

GOLDMAN, SACHS & CO.

UBS INVESTMENT BANK

WACHOVIA SECURITIES