Edgar Filing: WILLIAMS ENERGY PARTNERS L P

FILED PURSUANT TO RULE 424(b)(2)
REGISTRATION NO. 333-83952

PROSPECTUS SUPPLEMENT

(To Prospectus dated May 16, 2002)

[WILLIAM ENERGY LOGO]

8,000,000 COMMON UNITS

REPRESENTING LIMITED PARTNER INTERESTS
--------------------------------------------------------------------------------

Williams Energy Partners is offering all of the common units in this offering.
Our common units trade on the New York Stock Exchange under the symbol "WEG."
The last reported sales price of our common units on the NYSE on May 22, 2002
was $37.15 per common unit.

INVESTING IN THE COMMON UNITS INVOLVES RISK. "RISK FACTORS" BEGIN ON PAGE S-9 OF
THIS PROSPECTUS SUPPLEMENT AND ON PAGE 2 OF THE ACCOMPANYING PROSPECTUS.

PER COMMON UNIT TOTAL
--------------- -----

Public offering price...................................... $37.150 $297,200,000
Underwriting discount...................................... $ 1.579 $ 12,632,000
Proceeds, before expenses, to Williams Energy Partners..... $35.571 $284,568,000

We have granted the underwriters a 30-day option to purchase up to 1,200,000
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 IS TRUTHFUL OR COMPLETE.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

The underwriters expect to deliver the common units on or about May 29, 2002.
--------------------------------------------------------------------------------

Joint Book-Running Managers

LEHMAN BROTHERS SALOMON SMITH BARNEY
---------------------

BANC OF AMERICA SECURITIES LLC
MERRILL LYNCH & CO.
UBS WARBURG
A.G. EDWARDS & SONS, INC.
JPMORGAN
RAYMOND JAMES
RBC CAPITAL MARKETS
WACHOVIA SECURITIES
May 23, 2002

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

You should rely 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 date on
the front of those 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.

TABLES OF CONTENTS

PROSPECTUS SUPPLEMENT

Summary..................................................... S-1
Risk Factors................................................ S-9
Use of Proceeds............................................. S-11
Price Range of Common Units and Distributions............... S-11
Capitalization.............................................. S-12
Summary Selected Historical and Pro Forma Financial and
Operating Data............................................ S-13
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-15
Business.................................................... S-38
Management.................................................. S-62
Tax Considerations.......................................... S-64
Underwriting................................................ S-65
Legal....................................................... S-68
Experts..................................................... S-68
Index to Financial Statements............................... F-1

PROSPECTUS
About this Prospectus....................................... 1
About Williams Energy Partners.............................. 1
The Subsidiary Guarantors................................... 1
Risk Factors................................................ 2
Where You Can Find More Information......................... 10
Forward-looking Statements and Associated Risks............. 11
Use of Proceeds............................................. 12
Ratio of Earnings to Fixed Charges.......................... 12
Description of Debt Securities.............................. 13
Description of Our Class B Units............................ 23
Cash Distributions.......................................... 24
Material Tax Consequences................................... 32
Investment in Us by Employee Benefit Plans.................. 46
Plan of Distribution........................................ 47
Legal....................................................... 47
Experts..................................................... 47

SUMMARY

This summary highlights information contained elsewhere in this prospectus
supplement. You should read the entire prospectus supplement, the accompanying
prospectus, the documents incorporated by reference and the other documents to
which we refer for a more complete understanding of this offering. You should
read "Risk Factors" beginning on page S-9 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. The
information presented in this prospectus supplement assumes that the
underwriters do not exercise their over-allotment option.

WILLIAMS ENERGY PARTNERS L.P.

We are a Delaware limited partnership 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. We have
little direct exposure to commodity price fluctuations because we generally do
not take title to the products we transport, store or distribute. For the year
ended December 31, 2001, on a pro forma basis, we had revenues of $402.3
million, EBITDA of $153.8 million and net income of $94.9 million. For the three
months ended March 31, 2002, on a pro forma basis, we had revenues of $92.9
million, EBITDA of $41.5 million and net income of $27.6 million.

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 completed five acquisitions and have increased our
quarterly cash distribution by an aggregate of approximately 17% from $0.525 per
unit to $0.6125 per unit, or $2.45 per unit on an annualized basis.

We intend to continue to pursue an asset acquisition strategy. Our asset
portfolio currently consists of:

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

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

- 25 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.

The Williams Pipe Line system is a common carrier pipeline that provides
transportation, storage and distribution services for refined petroleum products
and liquefied petroleum gases, or LPGs, in 11 states from Oklahoma through the
Midwest to Illinois and North Dakota. This system generates revenues principally
from FERC-regulated tariffs based on the volumes of products transported and
also from storage and other ancillary fees. Through direct refinery connections
and interconnections with other pipelines, the Williams Pipe Line system can
access approximately 45% of the refinery capacity in the United States and is
well-positioned to adapt to shifts in product supply or demand. For the year
ended December 31, 2001, on a pro forma basis, the Williams Pipe Line system
generated 78.6% of our total revenues and 73.4% of our total EBITDA.

Our marine and inland terminals store and distribute gasoline and other
petroleum products in 12 states. Our marine terminal facilities are large
storage terminals that principally serve refiners, marketers and large end-users
of petroleum products and are strategically located near major refining hubs
along the Gulf Coast and near the New York harbor. Our inland terminals are part
of a distribution network throughout the southeastern United States used by
retail suppliers, wholesalers and marketers to receive gasoline and other
refined petroleum products from large, interstate pipelines and to transfer
these products to trucks, rail cars or barges for delivery to their final
destination. For the year ended December 31, 2001, on a pro forma basis, our
marine and inland terminals generated 17.8% of our total revenues and 20.6% of
our total EBITDA.

S-1

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. For the year ended December
31, 2001, on a pro forma basis, the ammonia pipeline system generated 3.6% of
our total revenues and 6.0% of our total EBITDA.

RECENT DEVELOPMENTS

Williams Pipe Line System Acquisition. On April 11, 2002, we acquired all
of the membership interests of Williams Pipe Line Company, LLC from a wholly
owned subsidiary of The Williams Companies for approximately $1.0 billion.
Williams Pipe Line Company owns and operates the Williams Pipe Line system. The
Williams Pipe Line system further complements our "virtual supply network" that
allows us to offer our customers same-day delivery of refined petroleum products
at multiple points across our distribution network regardless of actual
transportation time. Because Williams Pipe Line Company was an affiliate of ours
at the time of the acquisition, we have restated our historical financial
statements to combine our results with those of Williams Pipe Line Company. We
financed the acquisition through a $700.0 million short-term loan and the
issuance of Class B units to The Williams Companies. The Class B units will be
treated as common units for purposes of cash distributions, but no distributions
will be made on the Class B units until we have repaid the short-term loan.

Other Acquisitions. On December 31, 2001, we acquired a natural gas
liquids pipeline in Illinois from Aux Sable Liquid Products L.P. for
approximately $8.9 million. On October 31, 2001, we acquired a marine terminal
facility in Gibson, Louisiana from Geonet Gathering, Inc. for approximately
$21.1 million. On June 30, 2001, we acquired two inland petroleum products
terminals in Little Rock, Arkansas from TransMontaigne, Inc. for approximately
$29.1 million. On April 5, 2001, we acquired a refined petroleum products
pipeline in Dallas, Texas from Equilon Pipeline Company LLC for $0.3 million.

RELATIONSHIP WITH THE WILLIAMS COMPANIES

One of our principal strengths is our relationship with The Williams
Companies. The Williams Companies is an integrated energy company with 2001
revenues in excess of $11.0 billion and is engaged in numerous aspects of the
energy industry, including exploration and production of oil and natural gas,
transportation, processing and storage of natural gas and natural gas liquids,
refining, transportation and distribution of petroleum products and energy
marketing and trading. Through our relationship with The Williams Companies, we
have access to experienced management and benefit from strong relationships
throughout the energy industry.

The Williams Companies has a long history of successfully pursuing and
consummating energy acquisitions and utilizes us as a significant growth vehicle
for its transportation, storage and distribution businesses. We will continue to
pursue strategic acquisitions from unaffiliated parties independently and
jointly with The Williams Companies, including acquisitions that we would be
unable to pursue on our own. We also expect to make additional acquisitions
directly from The Williams Companies in the future, although no such additional
acquisitions have currently been identified.

The Williams Companies has a significant interest in us. Upon completion of
this offering, The Williams Companies will own a 52.6% limited partner interest
in us and all of our 2% general partner interest. Additionally, Williams Energy
Marketing & Trading Company and Williams Refining & Marketing, L.L.C.,
subsidiaries of The Williams Companies, are significant customers of ours. For
the year ended December 31, 2001, Williams Energy Marketing & Trading, Williams
Refining & Marketing and other affiliates of The Williams Companies collectively
generated approximately 21.0% of our combined historical revenues and 13.4% of
our revenues on a pro forma basis.

S-2

BUSINESS STRATEGIES

Our primary business strategies are:

- to grow through strategic acquisitions that increase per unit cash flow;

- to maximize the benefits of our relationship with The Williams Companies;
and

- to generate stable cash flows to make quarterly cash distributions.

COMPETITIVE STRENGTHS

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

- Our acquisition strategy is enhanced by our affiliation with The Williams
Companies.

- Our officers and directors have extensive industry experience and include
some of the most senior officers of The Williams Companies.

- Our assets are strategically located in areas with high demand for our
services.

- We provide refined petroleum products distribution services through a
virtual supply network that is capable of providing same-day delivery of
refined petroleum products at multiple points across our distribution
network regardless of actual transportation time.

- We have little direct commodity price exposure because we generally do
not take title to the products we transport, store and distribute.

PARTNERSHIP STRUCTURE AND MANAGEMENT

Our operations are conducted through, and our operating assets are owned
by, our subsidiaries, including Williams Pipe Line Company. Upon consummation of
the offering of our common units:

- There will be 12,600,000 publicly held common units outstanding
representing a 45.4% limited partner interest in us;

- The Williams Companies and its affiliates, including Williams GP LLC, our
general partner, will own common units, Class B units and subordinated
units representing an aggregate 52.6% limited partner interest in us; and

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

Our general partner has sole responsibility for conducting our business and
managing our operations. Some of the senior executives who currently manage our
business also manage and operate the businesses of The Williams Companies or its
subsidiaries. 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.

Our principal executive offices are located at One Williams Center, Tulsa,
Oklahoma 74172, and our phone number is (918) 573-2000.

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 ownership interests in us and our operating
subsidiaries.

S-3

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PERCENTAGE
INTEREST
OWNERSHIP OF WILLIAMS ENERGY PARTNERS L.P. ----------

Public common units....................................... 45.4%
The Williams Companies' common units...................... 3.9%
The Williams Companies' Class B units..................... 28.2%
The Williams Companies' subordinated units................ 20.5%
The Williams Companies' general partner interest.......... 2.0%
-----
Total................................................ 100.0%
----------------------------------------------------------

[ORGANIZATIONAL CHART]

---------------

(1) Currently held by Williams GP LLC.

S-4

THE OFFERING

Common units offered.......... 8,000,000 common units; 9,200,000 common units
if the underwriters exercise their
over-allotment option in full.

Units outstanding after this
offering...................... 13,679,694 common units if the underwriters do
not exercise their over-allotment option and
14,879,694 common units if the underwriters
exercise their over-allotment option in full;

7,830,924 Class B units; and

5,679,694 subordinated units.

Use of proceeds............... We will use substantially all of the net
proceeds from this offering to partially repay
the short-term loan incurred in connection with
our acquisition of the Williams Pipe Line
system. Affiliates of some of the underwriters
for this offering are lenders to us under our
short-term loan and will be partially repaid
with the net proceeds from this offering.

Cash distributions............ Under our partnership agreement, we must
distribute all of our cash on hand at the end
of each quarter, less reserves established by
our general partner. We refer to this cash as
"available cash," and we define its meaning in
our partnership agreement.

On May 15, 2002, we paid a quarterly cash
distribution for the first quarter of 2002 of
$0.6125 per common unit, or $2.45 per common
unit on an annualized basis. When quarterly
cash distributions exceed $0.578 per unit in
any quarter, our general partner receives a
higher percentage of the cash distributed in
excess of that amount, in increasing
percentages up to 50%. For a description of our
cash distribution policy, please read "Cash
Distributions" in the accompanying prospectus.

Subordination period.......... During the subordination period, common units
are entitled to receive a minimum quarterly
distribution of $0.525 per unit, plus
arrearages from any prior quarters, before any
distributions are paid on our subordinated
units. 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....................... If we meet the financial tests in the
partnership agreement for any quarter ending on
or after December 31, 2003, 25% of the
subordinated units will convert 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 December
31, 2004, 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 to you with respect
to that period. Please read "Tax
Considerations" in this prospectus supplement
for the basis of this estimate.

New York Stock Exchange
symbol........................ WEG

S-5

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

We have derived the summary historical financial data as of December 31,
2000 and 2001 and for each of the years ended December 31, 1999, 2000 and 2001
from our audited financial statements and related notes. We have derived the
summary historical financial data as of December 31, 1999 and as of March 31,
2001 and 2002 and for the three-month periods then ended from our unaudited
financial statements, which, in the opinion of management, include all
adjustments necessary for a fair presentation of the data. We have restated our
consolidated financial statements and notes to reflect the results of
operations, financial position and cash flows of Williams Energy Partners and
Williams Pipe Line Company on a combined basis throughout the periods presented.

Our pro forma financial statements reflect adjustments to exclude income
and expenses and assets and liabilities that were conveyed to and assumed by an
affiliate of Williams Pipe Line Company prior to our acquisition of it. These
assets primarily include Williams Pipe Line Company's interest in and agreements
related to Longhorn Partners Pipeline, a discontinued refinery site at Augusta,
Kansas and the ATLAS 2000 software system. In addition, the pro forma financial
statements reflect adjustments to show that we will no longer take title to the
natural gas liquids used for blending to produce different grades of gasoline or
to the resulting gasoline but will perform these services for an affiliate of
The Williams Companies for an annual fee. Further, the general and
administrative expenses charged to us by The Williams Companies will be
initially limited to $30.0 million per year for Williams Pipe Line Company.
These pro forma financial statements also reflect the short-term loan incurred
and the Class B units issued to finance the acquisition of Williams Pipe Line
Company and the application of the proceeds from the offering of common units
made by this prospectus supplement.

We define EBITDA as income before income taxes plus interest expense (net
of interest income) and depreciation and amortization expense. EBITDA provides
additional information as to our ability to generate cash and is presented
solely as a supplemental measure. EBITDA should not be considered as an
alternative to net income, income before income taxes, cash flows from
operations or any other measure of financial performance presented in accordance
with generally accepted accounting principles. Our EBITDA may not be comparable
to EBITDA of other entities, and other entities may not calculate EBITDA in the
same manner as we do.

The following table should be read together with, and is qualified in its
entirety by reference to, the historical and pro forma financial statements and
the accompanying notes included elsewhere in this prospectus supplement and
incorporated by reference. This table should also be read together with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

S-6

HISTORICAL PRO FORMA
------------------------------------------------------------- ---------------------------
THREE MONTHS
THREE MONTHS YEAR ENDED ENDED
YEAR ENDED DECEMBER 31, ENDED MARCH 31, DECEMBER 31, MARCH 31,
----------------------------------- ----------------------- ------------ ------------
1999 2000 2001 2001 2002 2001 2002
--------- ---------- ---------- ---------- ---------- ------------ ------------
($ IN THOUSANDS)

INCOME STATEMENT DATA:
Operating revenues............... $ 375,732 $ 426,846 $ 448,599 $ 107,676 $ 102,648 $ 402,345 $ 92,907
Operating expenses............... 121,599 144,899 160,880 37,355 33,066 154,068 32,163
Product purchases................ 59,230 94,141 95,268 27,844 18,409 56,141 9,509
Affiliate construction
expenses....................... 15,464 1,025 -- -- -- -- --
Depreciation and amortization.... 25,670 31,746 35,767 9,041 8,964 33,866 8,478
General and administrative....... 47,062 51,206 47,365 10,578 13,457 38,955 10,728
--------- ---------- ---------- ---------- ---------- ---------- ----------
Total costs and expenses....... $ 269,025 $ 323,017 $ 339,280 $ 84,818 $ 73,896 $ 283,030 $ 60,878
--------- ---------- ---------- ---------- ---------- ---------- ----------
Operating profit................. $ 106,707 $ 103,829 $ 109,319 $ 22,858 $ 28,752 $ 119,315 $ 32,029
Interest expense, net............ 18,998 25,329 12,366 4,257 763 24,839 5,383
Other (income) expense, net...... (1,511) (816) (431) (211) (953) (660) (953)
--------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes....... $ 89,220 $ 79,316 $ 97,384 $ 18,812 $ 28,942 $ 95,135 $ 27,599
Income taxes (a)................. 34,121 30,414 29,512 5,759 7,816 187 --
--------- ---------- ---------- ---------- ---------- ---------- ----------
Net income....................... $ 55,099 $ 48,902 $ 67,872 $ 13,053 $ 21,126 $ 94,948 $ 27,599
========= ========== ========== ========== ========== ========== ==========
Basic net income per limited
partner unit (b)............... $ 3.38 $ 0.99
========== ==========
Diluted net income per limited
partner unit (b)............... $ 3.38 $ 0.98
========== ==========
BALANCE SHEET DATA:
Working capital (deficit)(c)..... $ (2,115) $ 17,828 $ (2,211) $ (740) $ (9,066) $ (424,398)
Total assets..................... 973,939 1,050,159 1,104,559 1,043,952 1,094,531 1,034,472
Total debt....................... -- -- 139,500 90,100 148,000 558,716
Affiliate long-term note payable
(d)............................ 406,022 432,957 138,172 170,747 108,392 --
Partners' capital................ 339,601 388,503 589,682 555,079 607,111 102,304
CASH FLOW DATA:
Net cash flow provided by (used
in):
Operating activities........... $ 84,472 $ 55,056 $ 135,333 $ 49,696 $ 37,402
Investing activities........... (277,906) (74,446) (87,502) (8,967) (16,923)
Financing activities........... 193,435 19,390 (34,004) (28,059) (26,166)
Cash distributions declared per
unit (e)....................... $ 2.02 $ 0.292 $ 0.6125
OTHER DATA:
Operating margin:
Williams Pipe Line system...... $ 153,686 $ 147,778 $ 143,711 $ 30,311 $ 35,508 $ 143,396 $ 35,570
Petroleum products terminals... 17,141 31,286 38,240 10,421 12,435 38,240 12,435
Ammonia pipeline system........ 8,612 7,717 10,500 1,745 3,230 10,500 3,230
EBITDA........................... 133,888 136,391 145,517 32,110 38,669 153,841 41,460
Maintenance capital, net of
amounts reimbursed to Williams
Energy Partners by affiliate... 29,236 25,874 20,482 4,567 7,679 20,482 7,679
OPERATING STATISTICS:
Williams Pipe Line system:
Transportation revenue per
barrel shipped (cents per
barrel)...................... 91.4 89.1 90.8 90.5 88.4 90.8 88.4
Transportation barrels shipped
(millions)................... 222.5 229.1 236.1 53.2 52.1 236.1 52.1
Barrel miles (billions)........ 67.8 68.2 70.5 15.4 14.5 70.5 14.5
Petroleum products terminals:
Marine terminal average storage
capacity utilized per month
(million barrels)(f)......... 10.1 14.7 15.7 15.2 16.0 15.7 16.0
Marine terminal throughput
(million barrels)(g)......... N/A 3.7 11.5 3.3 5.0 11.5 5.0
Inland terminal throughput
(million barrels)............ 58.1 56.1 56.7 11.7 13.9 56.7 13.9
Ammonia pipeline system:
Volume shipped (thousand
tons)........................ 795 713 763 160 257 763 257

---------------

Footnotes on following page.

S-7

(a) Prior to our acquisition of Williams Pipe Line Company on April 11, 2002,
Williams Pipe Line Company was subject to income taxes. Prior to our
initial public offering on February 9, 2001, our petroleum products
terminals and ammonia pipeline system operations were also subject to
income taxes. Following our initial public offering, the petroleum products
terminals and ammonia pipeline system were no longer subject to income
taxes because we are a partnership. Williams Pipe Line Company is no longer
subject to income taxes following its acquisition by us.

(b) Pro forma basic and diluted net income per limited partner unit includes
income attributable to Williams Pipe Line Company.

(c) Pro forma periods include the net amount of the short-term loan of $410.7
million incurred in connection with the Williams Pipe Line Company
acquisition. Working capital, excluding this short-term loan, was $(13.7)
million for the pro forma period presented.

(d) At the time of our initial public offering, the affiliate note payable
associated with the petroleum products terminals operations was contributed
to us as a capital contribution by an affiliate of The Williams Companies.
At the closing of our acquisition of Williams Pipe Line Company, its
affiliate note payable was contributed to us as a capital contribution by
an affiliate of The Williams Companies.

(e) Cash distributions declared for 2001 include a pro-rated distribution for
the first quarter, which included the period from February 10, 2001 through
March 31, 2001. The cash distribution associated with the fourth quarter of
2001 was declared on January 22, 2002 and paid on February 14, 2002.

(f) For the year ended December 31, 1999, represents the average storage
capacity utilized per month for the Gulf Coast marine terminal facilities
for the five months that we owned these assets in 1999. For the year ended
December 31, 2000, represents the average monthly storage capacity utilized
for the Gulf Coast facilities (11.8 million barrels) and the average
monthly storage capacity utilized for the four months that we owned the New
Haven, Connecticut marine terminal facility in 2000 (2.9 million barrels).
For the year ended December 31, 2001, represents the average monthly
storage capacity utilized for the Gulf Coast facilities (12.7 million
barrels) and the New Haven facility (3.0 million barrels). All of the above
amounts exclude the Gibson, Louisiana facility, which is operated as a
throughput facility.

(g) For the year ended December 31, 2000, represents four months of activity at
the New Haven, Connecticut facility, which was acquired in September 2000.
For the year ended December 31, 2001, represents a full year of activity
for the New Haven facility (9.3 million barrels) and two months of activity
at the Gibson, Louisiana facility (2.2 million barrels), which was acquired
in October 2001.

S-8

RISK FACTORS

An investment in our common units involves a high degree of risk. You
should carefully consider the following risk factors, together with all of the
other information included in, or incorporated by reference into, this
prospectus supplement, in evaluating an investment in our common units. If any
of the following risks were to occur, our business, financial condition or
results of operations could be adversely affected. In that case, the trading
price of our common units could decline and you could lose all or part of your
investment. For information concerning the other risks related to our business,
please read the risk factors included under the caption "Risk Factors" beginning
on page 2 of the accompanying prospectus.

OUR FAILURE TO MAKE PRINCIPAL OR INTEREST PAYMENTS ON OUR SHORT-TERM LOAN
INCURRED TO FINANCE THE ACQUISITION OF THE WILLIAMS PIPE LINE SYSTEM COULD HAVE
A MATERIAL ADVERSE EFFECT ON US AND THE HOLDERS OF OUR COMMON UNITS.

In April 2002, we borrowed $700.0 million from a group of financial
institutions to finance the acquisition of the Williams Pipe Line system. This
loan matures on October 8, 2002, and the interest rate increases by 1.5%
commencing on August 9, 2002. This significant amount of debt increases our
vulnerability to general adverse economic and industry conditions. We cannot
assure you that we will be able to repay this loan prior to its maturity. If we
are unable to repay or extend the loan, we will not be able to pay distributions
to our common and subordinated unitholders.

RATE REGULATION OR A SUCCESSFUL CHALLENGE TO THE RATES WE CHARGE ON THE WILLIAMS
PIPE LINE SYSTEM MAY REDUCE THE AMOUNT OF CASH WE GENERATE.

The Federal Energy Regulatory Commission, or the FERC, regulates the tariff
rates for the Williams Pipe Line system. Shippers may protest the pipeline
system's tariffs, and the FERC may investigate the lawfulness of new or changed
tariff rates and order refunds of amounts collected under rates ultimately found
to be unlawful. The FERC may also investigate tariff rates that have become
final and effective.

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, for finished
goods minus 1%. If the PPI rises by less than 1% or falls, we are 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 pipeline.

In recent decisions involving unrelated pipeline limited partnerships, the
FERC has ruled that these partnerships may not claim an income tax allowance for
income attributable to non-corporate limited partners. A shipper could rely on
these decisions to challenge our indexed rates and claim that, because we now
own the Williams Pipe Line system, the Williams Pipe Line system's income tax
allowance should be reduced. If the FERC were to disallow all or part of our
income tax allowance, it may be more difficult to justify our rates. If a
challenge were brought and the FERC found that some of the indexed rates exceed
levels justified by the cost of service, the FERC would order a reduction in the
indexed rates and could require reparations for a period of up to two years
prior to the filing of a complaint. Any reduction in the indexed rates or
payment of reparations could have a material adverse effect on our operations
and reduce the amount of cash we generate.

MERGERS AMONG OUR CUSTOMERS AND COMPETITORS, PARTICULARLY THE PENDING MERGER
BETWEEN CONOCO, INC. AND PHILLIPS PETROLEUM COMPANY, COULD RESULT IN LOWER
VOLUMES BEING SHIPPED ON THE WILLIAMS PIPE LINE SYSTEM, THEREBY REDUCING THE
AMOUNT OF CASH WE GENERATE.

The Williams Pipe Line system and its associated terminals compete in
several markets with pipelines and terminals owned by Conoco, Inc. or by joint
ventures in which Conoco is a partner. Phillips Petroleum Company is a major
shipper on the Williams Pipe Line system. The pending merger of Phillips with
Conoco could provide strong economic incentives for Phillips to utilize the
Conoco pipeline systems instead of the Williams Pipe Line system in those
markets where the systems compete. As a result, we could lose some or all of the
volumes and associated revenues from Phillips when Phillips' current commitments
to the Williams Pipe Line system expire. We could experience difficulty in
replacing those lost volumes and revenues. Because most of our operating costs
are fixed, a reduction in volumes would result not only in a reduction of
revenues, but also a decline in net income and cash flow of a similar

S-9

magnitude, which would reduce our ability to pay cash distributions to our
unitholders. Any additional mergers among our customers and competitors could
have similar potential effects on our performance.

THE CLOSURE OF MID-CONTINENT REFINERIES THAT SUPPLY THE WILLIAMS PIPE LINE
SYSTEM COULD RESULT IN DISRUPTIONS OR REDUCTIONS IN THE VOLUMES TRANSPORTED ON
THE WILLIAMS PIPE LINE SYSTEM AND THE AMOUNT OF CASH WE GENERATE.

The U.S. Environmental Protection Agency recently adopted requirements that
require refineries to install equipment to lower the sulfur content of gasoline
and some diesel fuel they produce. The requirements relating to gasoline will
take effect and be implemented in 2004, and the requirements relating to diesel
fuel will take effect in 2006 and be implemented through 2010. If refinery
owners that use the Williams Pipe Line system determine that compliance with
these new requirements is too costly, they may close some of these refineries,
which could reduce the volumes transported on the Williams Pipe Line system and
the amount of cash we generate.

THE WILLIAMS PIPE LINE SYSTEM IS SUBJECT TO FEDERAL, STATE AND LOCAL LAWS AND
REGULATIONS THAT GOVERN THE ENVIRONMENTAL AND OPERATIONAL SAFETY ASPECTS OF ITS
OPERATIONS.

The Williams Pipe Line system is 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 its 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 our unitholders
could be adversely affected.

The terminal and pipeline facilities that comprise the Williams Pipe Line
system have been used for many years to transport, distribute or store petroleum
products. Over time, operations by us, our predecessors or third parties may
have resulted in the disposal or release of hydrocarbons or solid wastes at or
from these terminal properties and along such pipeline rights-of-way. In
addition, some of our terminals and pipelines are located on or near current or
former refining and terminal sites, and there is a risk that contamination is
present on those sites. We may be held jointly and severally liable under a
number of these environmental laws and regulations for such disposal and
releases of hydrocarbons or solid wastes or the existence of contamination, even
in circumstances where such activities or conditions were caused by third
parties not under our control or were otherwise lawful at the time that they
occurred.

COMPETITION WITH RESPECT TO THE WILLIAMS PIPE LINE SYSTEM COULD ULTIMATELY LEAD
TO LOWER LEVELS OF PROFITS AND REDUCE THE AMOUNT OF CASH WE GENERATE.

We face competition from other pipelines and terminals in the same markets
as the Williams Pipe Line system, as well as from other means of transporting,
storing and distributing petroleum products. For a description of the
competitive factors facing the Williams Pipe Line system, please read
"Business -- Williams Pipe Line System -- Competition."

ONE OF OUR AMMONIA PIPELINE SYSTEM CUSTOMERS IS EXPERIENCING LIQUIDITY
DIFFICULTIES AND MAY BE UNABLE TO PAY US.

One of the three customers that ship ammonia on our ammonia pipeline system
has disclosed that it is experiencing liquidity problems, including a potential
default under its credit agreement, and may be forced to seek protection from
its creditors if its plans to restore its liquidity are unsuccessful. If this
customer is unable to pay us or seeks protection under the federal bankruptcy
laws, it could have an adverse effect on our operations and reduce the amount of
cash we generate.

OUR RELATIONSHIP WITH THE WILLIAMS COMPANIES SUBJECTS US TO POTENTIAL RISKS THAT
ARE BEYOND OUR CONTROL.

Due to our relationship with The Williams Companies, adverse developments
or announcements concerning The Williams Companies could adversely affect our
financial condition, even if we have not suffered any similar development. For
example, a downgrade by one or more credit rating agencies of the outstanding
indebtedness of The Williams Companies could result in a similar downgrade of
our outstanding indebtedness or otherwise increase our borrowing costs or
generally impede our access to capital markets. Such a development could
adversely affect our ability to finance acquisitions and refinance existing
indebtedness and could reduce the amount of cash we distribute to you.

S-10

USE OF PROCEEDS

We will receive net proceeds of approximately $283.2 million from the sale
of the 8,000,000 common units we are offering, based on the public offering
price of $37.15 per common unit and after deducting underwriting discounts and
commissions and estimated offering expenses payable by us. If the underwriters
exercise their over-allotment option in full, we will receive net proceeds of
approximately $325.9 million. In connection with the offering, we will also
receive a capital contribution of $6.1 million from our general partner to
maintain its 2% general partner interest ($7.0 million if the underwriters
exercise the over-allotment option in full).

Assuming no exercise of the over-allotment option, we will use the net
proceeds of this offering and our general partner's capital contribution to
repay approximately $289.3 million of our $700.0 million short-term loan
incurred in connection with our acquisition of the Williams Pipe Line system.
The amount outstanding under this loan will be reduced to approximately $410.7
million following the closing of this offering. As of April 30, 2002, the
interest rate of the debt to be retired was 4.4%. Affiliates of some of the
underwriters for this offering are lenders to us under our short-term loan and
will be partially repaid with the net proceeds from this offering. Please read
"Underwriting."

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of May 7, 2002, we had 5,679,694 common units outstanding, beneficially
held by approximately 5,000 holders. The common units are traded on the NYSE
under the symbol "WEG."

The following table sets forth, for the period indicated, the high and low
closing sales price ranges for the common units, as reported on the NYSE
Composite Transaction Tape, and quarterly declared cash distributions per common
unit. The last reported sales price of our common units on the NYSE on May 22,
2002 was $37.15 per unit.

PRICE RANGES
--------------- CASH DISTRIBUTIONS
HIGH LOW PER UNIT(A)
------ ------ ------------------

2001
First Quarter..................................... $31.00 $23.00 $0.2920
Second Quarter.................................... 33.42 28.45 $0.5625
Third Quarter..................................... 40.40 29.40 $0.5775
Fourth Quarter.................................... 44.00 37.00 $0.5900
2002
First Quarter..................................... 43.30 32.85 $0.6125
Second Quarter (through May 22, 2002)............. 42.35 37.15 N/A(b)

---------------

(a) Represents cash distributions attributable to each respective quarter and
declared and paid within 45 days following the close of each quarter. The
distribution for the first quarter of 2001 was pro-rated for the period from
February 10, 2001 through March 31, 2001.

(b) We expect to declare and pay a cash distribution for the second quarter of
2002 within 45 days following the end of the quarter.

S-11

CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2002 on:

- a consolidated historical basis;

- a pro forma basis to give effect to adjustments related to the terms of
our acquisition of Williams Pipe Line Company and associated agreements,
including the short-term loan we incurred and the Class B units we
issued; and

- a pro forma as adjusted basis to give further effect to the sale of
common units offered by this prospectus supplement, to our general
partner's proportionate capital contribution and to the application of
the net proceeds therefrom to partially repay the short-term loan.

You should read our financial statements and notes that are included elsewhere
in this prospectus supplement and that are incorporated by reference for
additional information about our capital structure.

AS OF MARCH 31, 2002
--------------------------------------
CONSOLIDATED PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED
------------ --------- -----------
(UNAUDITED)
($ IN THOUSANDS)

Cash and cash equivalents.......................... $ 8,150 $ 23,146 $ 23,146
======== ========= =========
Short-term debt:
Short-term loan.................................. $ -- $ 700,000 $ 410,716
Long-term debt:
Credit facility.................................. $148,000 $ 148,000 $ 148,000
Affiliate note payable........................... 108,392 -- --
-------- --------- ---------
Total debt......................................... $256,392 $ 848,000 $ 558,716
Class B units...................................... -- 303,417 302,219
Partners' capital:
Common unitholders............................... $102,726 $ 101,008 $ 383,485
Subordinated unitholders......................... 122,511 121,798 120,929
General partner.................................. 381,874 (408,055) (402,110)
-------- --------- ---------
Total partners' capital............................ $607,111 $(185,249) $ 102,304
-------- --------- ---------
Total capitalization............................... $863,503 $ 966,168 $ 963,239
======== ========= =========

S-12

SUMMARY SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

We have derived the summary selected historical financial data as of
December 31, 2000 and 2001 and for each of the years ended December 31, 1999,
2000 and 2001 from our audited financial statements and related notes. We have
derived the summary selected historical financial data as of December 31, 1999
and as of March 31, 2001 and 2002 and for the three-month periods then ended
from our unaudited financial statements, which, in the opinion of management,
include all adjustments necessary for a fair presentation of the data. We have
restated our consolidated financial statements and notes to reflect the results
of operations, financial position and cash flows of Williams Energy Partners and
Williams Pipe Line Company on a combined basis throughout the periods presented.

S-13

INCOME STATEMENT DATA:
Operating revenues.................. $ 375,732 $ 426,846 $ 448,599 $ 107,676 $ 102,648 $ 402,345 $ 92,907
Operating expenses.................. 121,599 144,899 160,880 37,355 33,066 154,068 32,163
Product purchases................... 59,230 94,141 95,268 27,844 18,409 56,141 9,509
Affiliate construction expenses..... 15,464 1,025 -- -- -- -- --
Depreciation and amortization....... 25,670 31,746 35,767 9,041 8,964 33,866 8,478
General and administrative.......... 47,062 51,206 47,365 10,578 13,457 38,955 10,728
--------- ---------- ---------- ---------- ---------- ---------- ----------
Total costs and expenses........... $ 269,025 $ 323,017 $ 339,280 $ 84,818 $ 73,896 $ 283,030 $ 60,878
--------- ---------- ---------- ---------- ---------- ---------- ----------
Operating profit.................... $ 106,707 $ 103,829 $ 109,319 $ 22,858 $ 28,752 $ 119,315 $ 32,029
Interest expense, net............... 18,998 25,329 12,366 4,257 763 24,839 5,383
Other (income) expense, net......... (1,511) (816) (431) (211) (953) (660) (953)
--------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes.......... $ 89,220 $ 79,316 $ 97,384 $ 18,812 $ 28,942 $ 95,135 $ 27,599
Income taxes (a).................... 34,121 30,414 29,512 5,759 7,816 187 --
--------- ---------- ---------- ---------- ---------- ---------- ----------
Net income.......................... $ 55,099 $ 48,902 $ 67,872 $ 13,053 $ 21,126 $ 94,948 $ 27,599
========= ========== ========== ========== ========== ========== ==========
Basic net income per limited partner
unit (b)........................... $ 3.38 $ 0.99
========== ==========
Diluted net income per limited
partner unit (b)................... $ 3.38 $ 0.98
========== ==========
BALANCE SHEET DATA:
Working capital (deficit)(c)........ $ (2,115) $ 17,828 $ (2,211) $ (740) $ (9,066) $ (424,398)
Total assets........................ 973,939 1,050,159 1,104,559 1,043,952 1,094,531 1,034,472
Total debt.......................... -- -- 139,500 90,100 148,000 558,716
Affiliate long-term note payable
(d)................................ 406,022 432,957 138,172 170,747 108,392 --
Partners' capital................... 339,601 388,503 589,682 555,079 607,111 102,304
CASH FLOW DATA:
Net cash flow provided by (used in):
Operating activities............... $ 84,472 $ 55,056 $ 135,333 $ 49,696 $ 37,402
Investing activities............... (277,906) (74,446) (87,502) (8,967) (16,923)
Financing activities............... 193,435 19,390 (34,004) (28,059) (26,166)
Cash distributions declared per unit
(e)................................ $ 2.02 $ 0.292 $ 0.6125
OTHER DATA:
Operating margin:
Williams Pipe Line system.......... $ 153,686 $ 147,778 $ 143,711 $ 30,311 $ 35,508 $ 143,396 $ 35,570
Petroleum products terminals....... 17,141 31,286 38,240 10,421 12,435 38,240 12,435
Ammonia pipeline system............ 8,612 7,717 10,500 1,745 3,230 10,500 3,230
EBITDA.............................. 133,888 136,391 145,517 32,110 38,669 153,841 41,460
Maintenance capital, net of amounts
reimbursed to Williams Energy
Partners by affiliate.............. 29,236 25,874 20,482 4,567 7,679 20,482 7,679
OPERATING STATISTICS:
Williams Pipe Line system:
Transportation revenue per barrel
shipped (cents per barrel)....... 91.4 89.1 90.8 90.5 88.4 90.8 88.4
Transportation barrels shipped
(millions)....................... 222.5 229.1 236.1 53.2 52.1 236.1 52.1
Barrel miles (billions)............ 67.8 68.2 70.5 15.4 14.5 70.5 14.5
Petroleum products terminals:
Marine terminal average storage
capacity utilized per month
(million barrels)(f)............. 10.1 14.7 15.7 15.2 16.0 15.7 16.0
Marine terminal throughput (million
barrels)(g)...................... N/A 3.7 11.5 3.3 5.0 11.5 5.0
Inland terminal throughput (million
barrels)......................... 58.1 56.1 56.7 11.7 13.9 56.7 13.9
Ammonia pipeline system:
Volume shipped (thousand tons)..... 795 713 763 160 257 763 257

---------------
(a) Prior to our acquisition of Williams Pipe Line Company on April 11, 2002,
Williams Pipe Line Company was subject to income taxes. Prior to our
initial public offering on February 9, 2001, our petroleum products
terminals and ammonia pipeline system operations were also subject to
income taxes. Following our initial public offering, the petroleum products
terminals and ammonia pipeline system were no longer subject to income
taxes because we are a partnership. Williams Pipe Line Company is no longer
subject to income taxes following its acquisition by us.
(b) Pro forma basic and diluted net income per limited partner unit includes
income attributable to Williams Pipe Line Company.
(c) Pro forma periods include the net amount of the short-term loan of $410.7
million incurred in connection with the Williams Pipe Line Company
acquisition. Working capital, excluding this short-term loan, was $(13.7)
million for the pro forma period presented.
(d) At the time of our initial public offering, the affiliate note payable
associated with the petroleum products terminals operations was contributed
to us as a capital contribution by an affiliate of The Williams Companies.
At the closing of our acquisition of Williams Pipe Line Company, its
affiliate note payable was contributed to us as a capital contribution by
an affiliate of The Williams Companies.
(e) Cash distributions declared for 2001 include a pro-rated distribution for
the first quarter, which included the period from February 10, 2001 through
March 31, 2001. The cash distribution associated with the fourth quarter of
2001 was declared on January 22, 2002 and paid on February 14, 2002.
(f) For the year ended December 31, 1999, represents the average storage
capacity utilized per month for the Gulf Coast marine terminal facilities
for the five months that we owned these assets in 1999. For the year ended
December 31, 2000, represents the average monthly storage capacity utilized
for the Gulf Coast facilities (11.8 million barrels) and the average
monthly storage capacity utilized for the four months that we owned the New
Haven, Connecticut marine terminal facility in 2000 (2.9 million barrels).
For the year ended December 31, 2001, represents the average monthly
storage capacity utilized for the Gulf Coast facilities (12.7 million
barrels) and the New Haven facility (3.0 million barrels). All of the above
amounts exclude the Gibson, Louisiana facility, which is operated as a
throughput facility.
(g) For the year ended December 31, 2000, represents four months of activity at
the New Haven, Connecticut facility, which was acquired in September 2000.
For the year ended December 31, 2001, represents a full year of activity
for the New Haven facility (9.3 million barrels) and two months of activity
at the Gibson, Louisiana facility (2.2 million barrels), which was acquired
in October 2001.

S-14

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

We are a publicly traded limited partnership formed by The Williams
Companies 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. We intend to
pursue an asset acquisition strategy, and our asset portfolio currently consists
of:

- the Williams Pipe Line system;

- five marine terminal facilities;

- 25 inland terminals; and

- an ammonia pipeline system.

On April 11, 2002, we acquired for approximately $1.0 billion all of the
membership interests of Williams Pipe Line Company, which owns and operates the
Williams Pipe Line system. Because Williams Pipe Line Company was an affiliate
of ours at the time of the acquisition, the transaction was between entities
under common control and, as such, was accounted for similarly to a pooling of
interest. Accordingly, our consolidated financial statements and notes have been
restated to reflect the historical results of operations, financial position and
cash flows of Williams Energy Partners and Williams Pipe Line Company on a
combined basis throughout the periods presented. We will report the Williams
Pipe Line system's operations as a separate operating segment.

OVERVIEW

The Williams Pipe Line System. The Williams Pipe Line system is a common
carrier transportation pipeline and terminals network. The system generates
approximately 80% of its revenues, excluding the sale of petroleum products,
through transportation tariffs for volumes of petroleum products it ships. These
tariffs vary depending upon where the product originates, where ultimate
delivery occurs and any applicable discounts. All transportation rates and
discounts are in published tariffs filed with the FERC. The Williams Pipe Line
system also earns revenues from non-tariff based activities, including leasing
pipeline and storage tank capacity to shippers on a long-term basis, providing
data services and providing product services such as ethanol unloading and
loading, additive injection, custom blending and laboratory testing.

The Williams Pipe Line system generally does not produce or trade refined
petroleum products or LPGs or take title to the products it transports. The
system generates small volumes of product by blending natural gas liquids with
gasoline and by fractionating transmix, which is a mixture of products resulting
from the intermingling of different product grades during normal operation of
the pipeline. The Williams Pipe Line system has historically purchased and taken
title to the inventories associated with blending and fractionation until the
processed product has been sold. In connection with the acquisition of Williams
Pipe Line Company, we and Williams Energy Services, an affiliate of The Williams
Companies, agreed that the Williams Pipe Line system will no longer take title
to the natural gas liquids it blends with gasoline or the resulting product.
Consequently, both product sales and product purchases are expected to decline
by approximately 40-45% in future periods. We will continue to perform these
blending services for Williams Energy Services under a ten-year agreement for an
annual fee of approximately $3.0 million. Through the Williams Pipe Line system,
we will continue to purchase and fractionate transmix and to sell the resulting
separated products.

The historical results for Williams Pipe Line Company include income and
expenses and assets and liabilities that were conveyed to and assumed by an
affiliate of Williams Pipe Line Company prior to our acquisition of it. These
assets primarily include Williams Pipe Line Company's interest in and agreements
related to Longhorn Partners Pipeline, a discontinued refinery site at Augusta,
Kansas and the

S-15

ATLAS 2000 software system. Longhorn Partners Pipeline is a 700-mile pipeline
developed to transport refined petroleum products from Gulf Coast refineries
west to Odessa and El Paso, Texas. Williams Pipe Line Company formerly owned a
0.3% partnership interest in Longhorn Partners Pipeline and managed the
project's construction and operations in exchange for a management fee.

Operating costs and expenses incurred by the Williams Pipe Line system are
principally fixed costs related to routine maintenance and system integrity as
well as field and support personnel. Other costs, including fuel and power,
fluctuate with volumes transported and stored on the system. Expenses resulting
from environmental remediation projects are also included in operating expenses
and have historically included costs from projects relating both to current and
past events. In connection with our acquisition of Williams Pipe Line Company,
Williams Energy Services generally agreed to indemnify us for costs and expenses
relating to environmental remediation for events that occurred before April 11,
2002 and are discovered within six years from that date. Please read
"Business -- Environmental."

Petroleum Products Terminals. Within our terminals network, we operate two
types of terminals: marine terminal facilities and inland terminals. The marine
terminal facilities are large product storage facilities that generate revenues
primarily from fees that we charge customers for storage and throughput
services. The inland terminals earn revenues primarily from fees that we charge
based on the volumes of refined petroleum products distributed from these
terminals. The inland terminals also earn ancillary revenues from injecting
additives into gasoline and jet fuel, from filtering jet fuel and from rental
income. Also included in ancillary revenues is the gain or loss resulting from
differences in metered-versus-physical volumes of refined petroleum products
received at our terminals.

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

Ammonia Pipeline System. The ammonia pipeline system earns the majority of
its revenue from transportation tariffs that we charge for transporting ammonia
through the ammonia pipeline. Generally, most of the operating costs for the
ammonia pipeline system fluctuate with the volume of ammonia transported.

General and Administrative Expenses. The Williams Companies allocates both
direct and indirect general and administrative expenses to its subsidiaries.
Direct expenses allocated by The Williams Companies are primarily salaries and
benefits of employees and officers associated with the business activities of
the subsidiary. Indirect expenses include legal, accounting, treasury,
engineering, information technology and other corporate services. The Williams
Companies allocates indirect expenses to its subsidiaries, including to our
general partner, based on a three-factor formula that considers operating
margins, payroll costs and property, plant and equipment. Under our partnership
agreement, we are generally required to reimburse our general partner and its
affiliates for direct and indirect expenses incurred by or allocated to them on
our behalf.

In connection with our initial public offering, and with respect solely to
the petroleum products terminal and ammonia pipeline assets we owned at the time
of that offering, we and our general partner agreed with The Williams Companies
that the general and administrative expenses to be reimbursed to our general
partner by us would not exceed $6.0 million for 2001, excluding expenses
associated with our long-term incentive plans, regardless of the amount of the
direct and indirect general and administrative expenses actually incurred by or
allocated to our general partner. The reimbursement limitation will remain in
place through 2011 and may increase by no more than the greater of 7.0% per year
or the percentage increase in the consumer price index for that year. If we make
an acquisition, general and administrative expenses may also increase by the
amount of these expenses included in the valuation of the business acquired. As
a result of the acquisitions made during 2001, the annual amount of the general
and administrative expense reimbursement limitation increased to $6.3 million,
excluding expenses associated with our long-term incentive plans. Based on the
7.0% escalation, our maximum reimbursement obligation for general and
administrative expenses in 2002 is $6.7 million before long-term incentive plans
and adjustments for acquisitions.

S-16

As a result of our acquisition of the Williams Pipe Line system, general
and administrative expenses that had previously been incurred by or allocated to
Williams Pipe Line Company will be charged to our general partner. In connection
with the acquisition, we and our general partner agreed with The Williams
Companies that the general and administrative expenses to be reimbursed to our
general partner by us for charges related to the Williams Pipe Line system would
be $30.0 million for 2002, pro rated for the actual period that we own the
Williams Pipe Line system. In each year after 2002, these expenses may increase
by the lesser of 2.5% per year or the percentage increase in the consumer price
index for that year.

ACQUISITION HISTORY

We have materially increased our operations through a series of
transactions since our initial public offering in February 2001 including:

- in April 2002, the acquisition of the Williams Pipe Line system from an
affiliate of The Williams Companies;

- in December 2001, the acquisition of a natural gas liquids pipeline in
Illinois from Aux Sable Liquid Products L.P.;

- in October 2001, the acquisition of a marine crude oil terminal facility
in Gibson, Louisiana from Geonet Gathering, Inc.;

- in June 2001, the acquisition of two inland refined petroleum products
terminals in Little Rock, Arkansas from TransMontaigne, Inc.; and

- in April 2001, the acquisition of a refined petroleum products pipeline
in Dallas, Texas from Equilon Pipeline Company LLC.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2002 COMPARED TO THREE MONTHS ENDED MARCH 31,
2001

THREE MONTHS ENDED
MARCH 31,
------------------
2001 2002
------- -------
($ IN MILLIONS)

FINANCIAL HIGHLIGHTS
Revenues:
Williams Pipe Line system transportation and related
activities............................................. $ 57.5 $ 56.6
Petroleum products terminals.............................. 17.6 19.8
Ammonia pipeline system................................... 2.7 4.4
------ ------
Revenues excluding product sales and construction
revenues.............................................. $ 77.8 $ 80.8
Williams Pipe Line system product sales and construction
revenues............................................... 29.9 21.8
------ ------
Total revenues......................................... $107.7 $102.6
Operating expenses:
Williams Pipe Line system transportation and related
activities............................................. $ 29.3 $ 24.5
Petroleum products terminals.............................. 7.2 7.5
Ammonia pipeline system................................... 0.9 1.1
------ ------
Operating expenses excluding product purchases and
construction expenses................................. $ 37.4 $ 33.1
Williams Pipe Line system product purchases and
construction expenses.................................. 27.8 18.4
------ ------
Total operating expenses............................... $ 65.2 $ 51.5
------ ------
Total operating margin................................. $ 42.5 $ 51.1
====== ======

S-17

THREE MONTHS ENDED
MARCH 31,
------------------
2001 2002
------- -------
($ IN MILLIONS)

OPERATING STATISTICS
Williams Pipe Line system:
Transportation revenue per barrel shipped (cents per
barrel)................................................ 90.5 88.4
Transportation barrels shipped (million barrels).......... 53.2 52.1
Barrel miles (billions)................................... 15.4 14.5
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions)............................................. 15.2 16.0
Throughput (barrels in millions) (a)................... 3.3 5.0
Inland terminals:
Throughput (barrels in millions)....................... 11.7 13.9
Ammonia pipeline system:
Volume shipped (tons in thousands)........................ 160 257

---------------

(a) For the three months ended March 31, 2002, represents throughput at the
Gibson and New Haven marine facilities. As the Gibson facility was acquired
in October 2001, the three months ended March 31, 2001 represents
throughput at the New Haven facility only.

Our revenues excluding product sales and construction revenues for the
three months ended March 31, 2002 were $80.8 million compared to $77.8 million
for the three months ended March 31, 2001, an increase of $3.0 million, or 4%.
This increase was a result of:

- a decrease in Williams Pipe Line system's transportation and related
activities revenues of $0.9 million, or 2%. This decrease was primarily
attributable to reduced transportation volumes and lower weighted-average
tariffs. Demand for distillates, utilized in the farming industry as a
fuel oil, was lower as farmers took advantage of the warm weather during
late 2001 to begin working their fields versus waiting until the first
quarter of 2002. In addition, gasoline volumes were slightly lower due to
competitive market conditions. The transportation revenue per barrel
shipped declined due to our customers transporting products a shorter
distance which results in a lower tariff;

- an increase in petroleum products terminals revenues of $2.2 million, or
13%, primarily due to the acquisitions of the Gibson marine terminal
facility in October 2001 and two Little Rock inland terminals in June
2001. Further, revenues increased due to the initiation of jet fuel
service to Dallas Love Field, partially offset by lower throughput
volumes at several of our inland terminals due to unfavorable market
conditions;

- an increase in ammonia pipeline system revenues of $1.7 million, or 63%,
primarily due to a 97,000 ton, or 61%, increase in ammonia shipped
through our pipeline. Natural gas is the primary component for the
production of ammonia. As the price of natural gas has declined to more
historical levels, our customers have elected to produce and ship more
ammonia through our pipeline.

Operating expenses excluding product purchases for the three months ended
March 31, 2002 were $33.1 million compared to $37.4 million for the three months
ended March 31, 2001, a decrease of $4.3 million, or 12%. This decrease was a
result of:

- a decrease in Williams Pipe Line system expenses of $4.7 million, or 16%,
primarily due to reduced power costs associated with less volume
transported, lower property taxes and reduced environmental expenses;

S-18

- an increase in petroleum products terminals expenses of $0.2 million, or
3%, primarily due to the addition of the Gibson marine facility and the
Little Rock inland terminals;

- an increase in ammonia pipeline system expenses of $0.2 million primarily
due to higher property taxes and increased costs associated with greater
volume shipments.

Revenues from product sales were $21.6 million for the three months ended
March 31, 2002, while product purchases were $18.4 million, resulting in a net
margin of $3.2 million in 2002. The 2002 net margin represents an increase of
$1.5 million compared to a net margin in 2001 of $1.6 million resulting from
product sales for the three months ended March 31, 2001 of $29.5 million and
product purchases of $27.8 million. This increase was due to lower average
product costs in the current quarter.

Affiliate construction and management fee revenues for the three months
ended March 31, 2002 were $0.2 million compared to $0.4 million for the three
months ended March 31, 2001. Williams Pipe Line Company received a fee to manage
Longhorn Partners Pipeline and to provide consulting services associated with
the pipeline's construction and start-up, as needed. During 2002, no consulting
services were rendered.

Depreciation and amortization expense for the three months ended March 31,
2002 was unchanged from 2001 at $9.0 million. Additional depreciation associated
with acquisitions and capital improvements was offset by lower depreciation on
existing assets.

General and administrative expenses for the three months ended March 31,
2002 were $13.5 million compared to $10.6 million for the three months ended
March 31, 2001, an increase of $2.9 million, or 27%. For our petroleum products
terminals and ammonia pipeline system, general and administrative expenses are
allocated from The Williams Companies as defined by the omnibus agreement. For
2002, these expense allocations were limited to $1.7 million per quarter plus
actual incentive compensation expenses related to Williams Energy Partners'
performance. The amount of general and administrative expenses incurred by our
general partner but not allocated to us was $2.8 million for the three months
ended March 31, 2002. Incentive compensation costs associated with our long-term
incentive plan are specifically excluded from the expense limitation and were
$1.5 million during the three months ended March 31, 2002. The current quarter
incentive compensation costs included a $1.0 million charge associated with the
early vesting of a portion of the restricted units, or phantom units, issued to
key employees at the time of our initial public offering. The early vesting was
triggered as a result of our growth in cash distributions paid to unitholders.
Williams Pipe Line Company was allocated general and administrative costs from
The Williams Companies during these periods based on a three-factor formula that
considers operating margin, payroll costs and property, plant and equipment. The
amounts allocated to Williams Pipe Line Company were $10.2 million during the
three months ended March 31, 2002 compared to $8.3 million for 2001. The limit
on general and administrative expenses that can be charged by our general
partner to us will continue to be adjusted in the future to reflect additional
general and administrative expenses associated with completed acquisitions.
Following the acquisition of Williams Pipe Line Company, we expect the aggregate
limit to be $9.2 million per quarter plus long-term incentive compensation
expenses.

Net interest expense for the three months ended March 31, 2002 was $0.8
million compared to $4.3 million for the three months ended March 31, 2001. The
decline in interest expense was primarily related to significantly lower
interest rates and the partial payment and cancellation of an affiliate note in
connection with the closing of our initial public offering on February 9, 2001.

We do not pay income taxes because we are a partnership. However, Williams
Pipe Line Company was subject to income taxes prior to our acquisition of it in
April 2002, and our pre-IPO earnings in 2001 were also taxable. We primarily
based our income tax rate of 38.2% and 37.9% for the three months ended March
31, 2002 and 2001, respectively, upon the effective income tax rate for The
Williams Companies. The effective income tax rate exceeds the U.S. federal
statutory income tax rate primarily due to state income taxes.

S-19

Net income for the three months ended March 31, 2002 was $21.1 million
compared to $13.1 million for the three months ended March 31, 2001, an increase
of $8.0 million, or 61%. The operating margin increased by $8.7 million during
the period, largely as a result of reduced operating expenses for the Williams
Pipe Line system and enhanced earnings from the acquisitions of the Little Rock
and Gibson terminal facilities and increased volumes on the ammonia pipeline
system. General and administrative and depreciation expenses increased by $2.8
million while net interest expense decreased by $3.5 million. Other income
increased $0.7 million primarily due to a gain on the sale of land, and income
taxes increased $2.1 million.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

YEAR ENDED
DECEMBER 31,
---------------
2000 2001
------ ------
($ IN MILLIONS)

FINANCIAL HIGHLIGHTS
Revenues:
Williams Pipe Line system transportation and related
activities............................................. $245.6 $254.9
Petroleum products terminals.............................. 60.8 71.5
Ammonia pipeline system................................... 11.7 14.5
------ ------
Revenues excluding product sales and construction
revenues........................................ $318.1 $340.9
Williams Pipe Line system product sales and construction
revenues............................................... 108.7 107.7
------ ------
Total revenues......................................... $426.8 $448.6
Operating expenses:
Williams Pipe Line system transportation and related
activities............................................. $111.4 $123.6
Petroleum products terminals.............................. 29.5 33.3
Ammonia pipeline system................................... 4.0 4.0
------ ------
Operating expenses excluding product purchases and
construction expenses........................... $144.9 $160.9
Williams Pipe Line system product purchases and
construction expenses.................................. 95.2 95.3
------ ------
Total operating expenses............................... $240.1 $256.2
------ ------
Total operating margin................................. $186.7 $192.4
====== ======
OPERATING STATISTICS
Williams Pipe Line system:
Transportation revenue per barrel shipped (cents per
barrel)................................................ 89.1 90.8
Transportation barrels shipped (million barrels).......... 229.1 236.1
Barrel miles (billion miles).............................. 68.2 70.5
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions)(a).......................................... 14.7 15.7
Throughput (barrels in millions)(b).................... 3.7 11.5
Inland terminals:
Throughput (barrels in millions)....................... 56.1 56.7
Ammonia pipeline system:
Volume shipped (tons in thousands)........................ 713 763

---------------

(a) For the year ended December 31, 2001, represents the average monthly
storage capacity utilized for the Gulf Coast marine terminal facilities
(12.7 million barrels) and the New Haven, Connecticut marine terminal
facility (3.0 million barrels). For the

S-20

year ended December 31, 2000, represents the average monthly storage
capacity utilized for the Gulf Coast marine terminals facilities (11.8
million barrels) and the average monthly storage capacity utilized for the
four months that we owned the New Haven, Connecticut marine terminal
facility (2.9 million barrels), which we acquired in September 2000. All of
the above amounts exclude the Gibson, Louisiana facility.

(b) For the year ended December 31, 2001, represents a full year of activity at
the New Haven, Connecticut marine terminal facility (9.3 million barrels)
and two months of activity at the Gibson, Louisiana marine terminal
facility (2.2 million barrels), which we acquired on October 31, 2001. For
the year ended December 31, 2000, represents four months of activity at the
New Haven marine terminal facility, which we acquired in September 2000.

Our revenues excluding product sales and construction revenues for the year
ended December 31, 2001 were $340.9 million compared to $318.1 million for the
year ended December 31, 2000, an increase of $22.8 million, or 7%. This increase
was primarily a result of:

- Williams Pipe Line system's transportation and other related revenues
increasing by $9.2 million, or 4%, from $245.6 million for the year ended
December 31, 2000 to $254.8 million for the year ended December 31, 2001.
The increase was due primarily to higher transportation revenues, offset
by a decrease in revenues from product services. The increase in
transportation revenues resulted from a 3% increase in volumes shipped
and an approximate 3% increase in tariff rates in July 2001.
Transportation volumes increased in part due to system expansions made to
secure new volumes from customers. Volumes also increased as a result of
additional volume incentive agreements and general demand increases for
gasoline and distillates, slightly offset by a decrease in demand for
aviation fuel resulting from the recession and consumer reaction to the
terrorist attacks of September 11, 2001. Product services decreased
primarily due to a reduction in revenues from additive injection, due to
lower prices for those services under new agreements;

- an increase in the petroleum products terminal revenues of $10.7 million,
or 18%, from $60.8 million for the year ended December 31, 2000 to $71.5
million for the year ended December 31, 2001. The increase was primarily
a result of the acquisitions of the New Haven, Connecticut marine
terminal facility in September 2000, the Little Rock, Arkansas inland
terminals in June 2001 and the Gibson, Louisiana marine terminal facility
in October 2001, as well as an improved Gulf Coast marketing environment
which resulted in a 0.9 million barrel per month higher utilization at
the Gulf Coast marine terminal facilities. These increases were slightly
offset by a decrease in inland terminals revenues, primarily due to the
December 2000 expiration of a customer's contractual commitment to
utilize a specified amount of throughput capacity; and

- an increase in ammonia pipeline system revenues of $2.8 million, or 24%,
from $11.7 million for the year ended December 31, 2000 to $14.5 million
for the year ended December 31, 2001, partly due to a $1.3 million
throughput deficiency billing resulting from a shipper not meeting its
minimum annual throughput commitment for the contract year ended June
2001. In addition, warm fall weather and a return to historically average
prices for natural gas, which is the primary component for the production
of ammonia, combined to create favorable conditions for the application
of ammonia during the fourth quarter of 2001, resulting in a 50,000 ton,
or 7%, increase in volume shipped on the pipeline compared to 2000.

Operating expenses excluding product purchases and construction expenses
for the year ended December 31, 2001 were $160.9 million compared to $144.9
million for the year ended December 31, 2000, an increase of $16.0 million, or
11%. This increase was a result of:

- an increase in Williams Pipe Line system's operating expenses of $12.2
million, or 11%, from $111.4 million for the year ended December 31, 2000
to $123.6 million for the year ended December 31, 2001. The increase was
primarily caused by a $14.4 million increase in Williams Pipe Line
system's field operating expenses and $3.0 million higher power and
utilities expenses, partially offset by $2.5 million lower environmental
remediation expenses and $3.3 million lower casualty losses. Field
operating costs increased as a result of higher pipeline integrity costs
due to new regulations, increased tank maintenance and coating costs
related to our system integrity program, the Department of
Transportation's adoption of the API 653 tank inspection requirements and
mainline pump overhauls and repairs. Power and utilities expenses
increased $3.0 million, with

S-21

30% of the increase related to increased shipments and 70% related to the
rising cost of power for the pumps and terminals along the system.
Remediation expenses declined after increased costs were recognized in
2000 related to a discontinued refining site, which was not included in
the assets and liabilities transferred to us in connection with the
acquisition of Williams Pipe Line Company. Casualty losses decreased
compared to higher losses incurred in 2000 as a result of a $2.4 million
expense accrual associated with a groundwater contamination lawsuit that
was settled in 2001; and

- an increase in petroleum products terminals expenses of $3.8 million, or
13%, from $29.5 million for the year ended December 31, 2000 to $33.3
million for the year ended December 31, 2001, due primarily to the
acquisitions of the New Haven, Connecticut marine terminal facility in
September 2000, the Little Rock, Arkansas inland terminals in June 2001
and the Gibson, Louisiana marine terminal facility in October 2001.
Expenses at the other Gulf Coast marine terminal facilities increased
slightly due to higher utility costs, partially offset by lower
environmental and maintenance expenses, while property taxes at some
inland terminals increased.

Revenues from product sales were $106.7 million for the year ended December
31, 2001, while product purchases were $95.3 million, resulting in a net margin
of $11.4 million in 2001. The 2001 net margin represents a decrease of $1.4
million compared to a net margin in 2000 of $12.7 million resulting from product
sales in 2000 of $106.9 million and product purchases of $94.1 million. This
decrease was due primarily to lower blending and fractionation margins as a
result of lower price volatility during 2001, partially offset by an increase in
over and short margins, which result from management of the system's physical
inventory balances through the purchasing of physical shortages and selling of
physical overages.

Affiliate construction and management fee revenues were $1.0 million for
the year ended December 31, 2001, while there were no affiliate construction
expenses, resulting in a net margin of $1.0 million. The 2001 net margin
represents an increase of $0.2 million compared to a net margin in 2000 of $0.8
million resulting from affiliate construction and management fee revenues in
2000 of $1.9 million and affiliate construction expenses of $1.0 million.

Depreciation and amortization expense for the year ended December 31, 2001
was $35.8 million compared to $31.7 million for the year ended December 31,
2000, an increase of $4.0 million, or 13%. The increase was due primarily to the
acquisitions of the New Haven, Connecticut marine terminal facility in September
2000, the Little Rock, Arkansas inland terminals in June 2001, and the Gibson,
Louisiana marine terminal facility in October 2001, as well as maintenance
capital expenditures.

General and administrative expenses for the year ended December 31, 2001
were $47.4 million compared to $51.2 million for the year ended December 31,
2000, a decrease of $3.8 million, or 7%. This decrease is primarily the result
of the general and administrative expense limit agreed to at the time of our
initial public offering. For 2001, general and administrative expenses related
to the petroleum products terminals and ammonia pipeline system include the
established limit of $6.0 million per year plus additional general and
administrative costs associated with businesses acquired during 2001 and $2.0
million of expenses associated with our long-term incentive compensation plan.
For 2000, general and administrative costs related to the petroleum products
terminals and ammonia pipeline system were $12.0 million. The general and
administrative expenses incurred by or allocated to Williams Pipe Line Company
in 2001 were $38.4 million compared to $39.2 million in 2000.

Interest expense for the year ended December 31, 2001 was $14.9 million
compared to $27.0 million for the year ended December 31, 2000, a decrease of
$12.1 million or 45%. This decrease is primarily the result of a decline in
affiliate notes payable to The Williams Companies and lower interest rates. The
affiliate note payable associated with the Williams Pipe Line system declined by
$68.6 million as a result of a partial repayment using cash generated from
operations in excess of capital expenditures. At the end of 2001, the affiliate
note payable associated with the Williams Pipe Line system had a balance of
$138.2 million. The affiliate note payable associated with the petroleum
products terminals and ammonia pipeline system was partially repaid and the
balance was canceled and contributed to us as capital in connection with our
initial public offering in February 2001. Concurrent with the closing of our
initial public offering, we borrowed $90.0 million under our term loan facility
and $0.1 under our revolving credit
S-22

facility. At the end of 2001, $90.0 million was outstanding under the term loan
facility and $49.5 million was outstanding under the revolving credit facility
due to the acquisition of the Little Rock, Arkansas inland terminals and the
Gibson, Louisiana marine terminal facility.

Interest income for the year ended December 31, 2001 was $2.5 million
compared to $1.7 million for the year ended December 31, 2000, an increase of
$0.8 million due primarily to a larger average balance of an affiliate
receivable due from Longhorn Partners Pipeline.

We do not pay income taxes because we are a partnership. We primarily based
our income tax rate of 38.0% for our pre-initial public offering earnings from
our petroleum products terminals and ammonia pipeline businesses upon the
effective income tax rate for The Williams Companies. In addition, the Williams
Pipe Line Company was taxed as a corporation prior to its acquisition by us on
April 11, 2002. Williams Pipe Line Company's effective tax rates for the years
ended December 31, 2001 and 2000 were 38.9% and 38.4%, respectively, also based
primarily on the effective income tax rates for The Williams Companies for those
periods. The effective income tax rates exceeded the U.S. federal statutory
income tax rate for corporations primarily due to state income taxes.

Net income for the year ended December 31, 2001 was $67.9 million compared
to $48.9 million for the year ended December 31, 2000, an increase of $19.0
million, or 39%. The operating margin increased by $5.7 million during the
period, primarily as a result of increased transportation revenues on the
Williams Pipe Line system and the New Haven, Little Rock and Gibson petroleum
products terminals acquisitions, offset by higher operating costs associated
with those acquisitions and higher system integrity costs on the Williams Pipe
Line system. While depreciation and amortization increased by $4.0 million and
other income fell by $0.4 million, general and administrative expenses and
interest expense declined by $16.0 million in the aggregate, interest income
increased by $0.8 million, and income taxes declined by $0.9 million.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

YEAR ENDED
DECEMBER 31,
---------------
1999 2000
------ ------
($ IN MILLIONS)

FINANCIAL HIGHLIGHTS
Revenues:
Williams Pipe Line system transportation and related
activities............................................. $242.7 $245.6
Petroleum products terminals.............................. 32.3 60.8
Ammonia pipeline system................................... 12.1 11.7
------ ------
Revenues excluding product sales and construction
revenues........................................ $287.1 $318.1
Williams Pipe Line system product sales and construction
revenues............................................... 88.6 108.7
------ ------
Total revenues......................................... $375.7 $426.8
Operating expenses:
Williams Pipe Line system transportation and related
activities............................................. $103.0 $111.4
Petroleum products terminals.............................. 15.1 29.5
Ammonia pipeline system................................... 3.5 4.0
------ ------
Operating expenses excluding product purchases and
construction expenses........................... $121.6 $144.9
Williams Pipe Line system product purchases and
construction expenses.................................. 74.7 95.2
------ ------
Total operating expenses............................... $196.3 $240.1
------ ------
Total operating margin................................. $179.4 $186.7
====== ======

S-23

YEAR ENDED
DECEMBER 31,
---------------
1999 2000
------ ------
($ IN MILLIONS)

OPERATING STATISTICS
Williams Pipe Line system:
Transportation revenue per barrel shipped (cents per
barrel)................................................ 91.4 89.1
Transportation barrels shipped (million barrels).......... 222.5 229.1
Barrel miles (billion miles).............................. 67.8 68.2
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in
millions)(a).......................................... 10.1 14.7
Throughput (barrels in millions)(b).................... N/A 3.7
Inland terminals:
Throughput (barrels in millions)....................... 58.1 56.1
Ammonia pipeline system:
Volume shipped (tons in thousands)........................ 795 713

---------------

(a) For the year ended December 31, 2000, represents the average monthly
storage capacity utilized for the Gulf Coast marine terminal facilities
(11.8 million barrels) and the average monthly storage capacity for the
four months that we owned the New Haven, Connecticut marine terminal
facility in 2000 (2.9 million barrels). For the year ended December 31,
1999, represents the average monthly storage capacity utilized for the Gulf
Coast marine terminal facilities for the five months that we owned these
assets in 1999. All of the above amounts exclude the Gibson, Louisiana
facility.

(b) For the year ended December 31, 2000, represents four months of activity at
the New Haven, Connecticut marine terminal facility, which we acquired in
September 2000.

Our revenues excluding product sales and construction revenues for the year
ended December 31, 2000 were $318.1 million compared to $287.1 million for the
year ended December 31, 1999, an increase of $31.0 million, or 11%. This
increase was primarily a result of:

- an increase in petroleum products terminals revenues of $28.5 million, or
89%, due primarily to the acquisitions of three Gulf Coast marine
terminal facilities in August 1999 and the New Haven marine terminal
facility in September 2000, as well as a 1.7 million barrel per month
increase in utilization of the Gulf Coast marine terminal facilities,
slightly offset by a storage rate decline because of the expiration in
July 2000 of a revenue deficiency billing associated with the purchase of
the Gulf Coast marine terminal facilities;

- a $1.9 million increase in Williams Pipe Line system's non-tariff based
revenues, consisting primarily of $0.7 million from new capacity lease
agreements, $0.6 million in increased laboratory testing fees from the
addition of a new laboratory in mid-1999, $0.5 million in increased data
service revenues largely due to an over-billing which was reversed in
2001, and $0.5 million from a new reclamation facility added to the
system in 1999; and

- an increase of $0.7 million, or 0.3%, in transportation revenues on the
Williams Pipe Line system, due to higher shipments of diesel and aviation
fuel as a result of capital expenditures that were made to secure new
volumes from several significant customers, partially offset by an
approximate 3% decrease in the rate per barrel shipped due to reduced
average haul miles.

Operating expenses excluding product purchases and construction expenses
for the year ended December 31, 2000 were $144.9 million compared to $121.6
million for the year ended December 31, 1999, an increase of $23.3 million, or
19%. This increase was a result of:

- an increase in petroleum products terminals expenses of $14.4 million, or
95%, due to a $15.2 million increase in marine terminal facilities
expense as a result of the acquisition of three Gulf Coast marine
terminal facilities in August 1999 and of the New Haven marine terminal
facility in September 2000, offset by a decrease of $0.8 million in
inland terminal expenses resulting

S-24

from higher environmental expenses in 1999 associated with a system-wide
environmental evaluation, higher employee relocation expenses in 1999
related to the acquisition of 12 terminals and lower utility expenses due
to lower throughput volumes;

- an increase in Williams Pipe Line system expenses of $8.4 million, or 8%,
consisting primarily of a $2.8 million increase in casualty losses, $2.3
million higher environmental remediation expenses, $2.0 million of higher
power and utilities expenses and $1.9 million higher field operating
expenses, offset by $0.5 lower product loss expenses. The casualty loss
increase was largely due to a $2.4 million expense accrual associated
with a groundwater contamination lawsuit in 2000. Environmental
remediation expenses increased primarily from accruals related to a
discontinued refining site, which was not included in the assets and
liabilities transferred to us in connection with the acquisition of the
Williams Pipe Line Company. Power and utilities expenses increased
primarily because of higher prices for electricity and natural gas. Field
operating expenses increased from higher expenses related to a new
laboratory and inflation; and

- an increase of ammonia pipeline system expenses of $0.5 million, or 13%,
primarily due to a one-time adjustment for lease expense and increased
utility expenses as a result of higher natural gas prices.

Revenues from product sales were $106.9 million for the year ended December
31, 2000, while product purchases were $94.1 million, resulting in a net margin
of $12.9 million in 2000. The 2000 net margin represents an increase of $1.2
million compared to a net margin in 1999 of $11.5 million resulting from product
sales in 1999 of $70.8 million and product purchases of $59.2 million. This
increase was due primarily to higher blending revenues due to greater volatility
in the blending and fractionation markets, offset by reduced over and short
margins.

Affiliate construction and management fee revenues were $1.9 million for
the year ended December 31, 2000, while affiliate construction expenses were
$1.0 million, resulting in a net margin of $0.8 million. The 2000 net margin
represents a decrease of $1.6 million compared to a net margin in 1999 of $2.4
million resulting from affiliate construction and management fee revenues in
1999 of $17.9 million and affiliate construction expenses of $15.5 million. This
decrease was due primarily to a significant reduction during 2000 in
construction activity on the Longhorn Partners Pipeline, which was managed by
Williams Pipe Line Company during those periods.

Depreciation and amortization expense for the year ended December 31, 2000
was $31.7 million compared to $25.7 million for the year ended December 31,
1999, an increase of $6.1 million, or 24%. The increase was due primarily to the
acquisition of the New Haven, Connecticut marine terminal facility in September
2000 and a full year of depreciation related to the Gulf Coast marine terminal
facilities acquired in August 1999, as well as maintenance capital expenditures,
largely on the Williams Pipe Line system.

General and administrative expenses for the year ended December 31, 2000
were $51.2 million compared to $47.1 million for the year ended December 31,
1999, an increase of $4.1 million, or 9%. This increase is primarily the result
of the acquisitions of three Gulf Coast marine terminal facilities in August
1999 and of the New Haven, Connecticut marine terminal facility in September
2000. These acquisitions increased our size relative to other subsidiaries of
The Williams Companies, and as a result increased the percentage of general and
administrative expenses allocated by The Williams Companies to us. This increase
was partially offset by a decrease in the general and administrative expense
allocated by The Williams Companies to Williams Pipe Line Company, due largely
to a significant acquisition made by The Williams Companies which reduced
Williams Pipe Line Company's size relative to other subsidiaries of The Williams
Companies.

Interest expense for the year ended December 31, 2000 was $27.0 million
compared to $19.2 million for the year ended December 31, 1999, an increase of
$7.8 million or 41%. This increase is primarily the result of a full year of
interest on debt incurred in the acquisition of three Gulf Coast marine terminal

S-25

facilities in August 1999 and four months of interest on debt incurred in the
acquisition of the New Haven marine terminal facility in September 2000.

Interest income for the year ended December 31, 2000 was $1.7 million
compared to $0.2 million for the year ended December 31, 1999, an increase of
$1.5 million due primarily to an increase in the balance of a receivable due
from Longhorn Partners Pipeline.

We do not pay income taxes because we are a partnership. We primarily based
our income tax rate of 38.0% for the pre-initial public offering earnings from
our petroleum products terminals and ammonia pipeline businesses upon the
effective income tax rate for The Williams Companies. In addition, the Williams
Pipe Line Company was taxed as a corporation prior to its acquisition by us on
April 11, 2002. Williams Pipe Line Company's effective tax rates for the years
ended December 31, 2000 and 1999 were 38.4% and 38.3%, respectively, also based
primarily on the effective income tax rates for The Williams Companies for those
periods. The effective income tax rates exceeded the U.S. federal statutory
income tax rate for corporations primarily due to state income taxes.

Net income for the year ended December 31, 2000 was $48.9 million compared
to $55.1 million for the year ended December 31, 1999, a decrease of $6.2
million, or 11%. The operating margin increased by $7.3 million during the
period, primarily as a result of the acquisition of three Gulf Coast marine
terminal facilities in August 1999 and the New Haven marine terminal facility in
September 2000, partially offset by higher expenses related to those
acquisitions as well as higher casualty loss, environmental remediation, power
and other field operating expenses on the Williams Pipe Line system.
Depreciation and amortization expense increased by $6.1 million and general and
administrative and interest expense increased by $12.0 million in the aggregate.
Interest income rose $1.5 million, and other income fell $0.7 million. In
addition, income taxes declined by $3.7 million.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS AND CAPITAL EXPENDITURES

Net cash provided by operating activities for the three months ended March
31, 2002 was $37.4 million compared to $49.7 million for the three months ended
March 31, 2001. The $12.3 million decrease in cash flows from operating
activities from 2001 to 2002 was primarily a result of changes in our affiliate
and accounts receivable balances. Prior to 2001, some of Williams Pipe Line
Company's affiliates did not remit payment each month associated with
intercompany receivables, allowing the balances to build. Beginning in 2001,
these affiliate accounts receivable balances were paid each month, resulting in
a large cash inflow during the first quarter of 2001 to eliminate the
accumulated balances. In addition, in 2001 we collected a significant accounts
receivable balance associated with a one-time service provided to a third party.
These working capital changes were partially offset by increased net income
before depreciation and deferred compensation costs due to enhanced results from
our existing assets and acquisitions.

Net cash used by investing activities for the three months ended March 31,
2002 and 2001 was $16.9 million and $9.0 million, respectively. Investing
activities in 2002 included $8.9 million for the purchase of the natural gas
liquids pipeline from Aux Sable in December 2001. Maintenance capital
expenditures for the period ended March 31, 2002 were $7.7 million, compared
with $4.6 million during 2001. Please see "Capital Requirements" below for more
discussion of capital expenditures.

Net cash used by financing activities for the three months ended March 31,
2002 and 2001 was $26.2 million and $28.1 million, respectively. The cash used
for the first three months of 2002 principally involved the partial repayment of
an affiliate note by Williams Pipe Line Company. The cash used for the first
three months of 2001 principally involved the repayment of a portion of two
affiliate notes, partially offset by the net equity proceeds from our initial
public offering and the net proceeds from borrowings under our operating
partnership's credit facility at the time of our initial public offering.

Net cash provided by operating activities for the year ended December 31,
2001 was $135.3 million compared to $55.1 million for the year ended December
31, 2000 and $84.5 million for the year ended
S-26

December 31, 1999. The increase from 2000 to 2001 was primarily attributable to
increased net income before non-cash items such as depreciation, deferred
compensation expense and deferred income taxes for the year ended December 31,
2001, and to changes in components of operating assets and liabilities between
2000 and 2001. Net income was increased primarily by the New Haven, Little Rock
and Gibson petroleum products terminals acquisitions, as well as by lower
general and administrative and interest expenses. Significant changes in
components of operating assets and liabilities during 2001 included:

- a decrease of $10.4 million in accounts receivable versus a $9.7 million
increase in 2000, due primarily to the collection during 2001 of
receivables related to reimbursable construction projects;

- a decrease of $15.8 million in affiliate accounts receivable versus a
$1.9 million increase in 2000, due to the collection in 2001 of a large
outstanding short-term affiliate receivable due from a subsidiary of The
Williams Companies; and

- an increase of $12.9 million in inventories associated with blending,
fractionation and over and short activities, versus a $2.5 million
decrease in 2000, due primarily to higher commodity prices during 2001.

The decrease in net cash from operating activities from 1999 to 2000 was
partially attributable to lower deferred income taxes in 2000 compared to 1999
and to changes in components of assets and liabilities between 1999 and 2000.
Deferred taxes were $2.2 million for the year ended December 31, 2000 compared
to $22.4 million for the year ended December 31, 1999, largely due to one-time
adjustments in 1999 to accruals for rate refunds and payroll liabilities that
required adjustments to the related deferred income taxes. Significant changes
in components of operating assets and liabilities during 2000 included:

- an increase of $9.7 million in accounts receivable, versus a $5.7 million
increase in 1999, due primarily to an increase during 2000 in receivables
related to reimbursable construction projects;

- a decrease of $6.6 million in accounts payable, versus a $5.3 million
increase in 1999, due primarily to the conversion during 2000 of Williams
Pipe Line Company's accounts payable accounting system, which resulted in
lower total accounts payable outstanding;

- an increase of $4.5 million in current and noncurrent environmental
liabilities, due primarily to acrruals for environmental remediation
expenses related to a discontinued refinery site, which was not included
in the assets and liabilities transferred to us in connection with the
acquisition of Williams Pipe Line Company; and

- a negative change of $16.5 million in other current and noncurrent assets
and liabilities, versus a $21.8 million negative change in 1999, due
primarily to an increase in unbilled reimbursable construction projects
classified as other current assets and to an increase in long-term
affiliate receivables related to reimbursable Longhorn Partners Pipeline
construction costs. The large negative change in 1999 was due primarily
to reductions during the year of rate refund and pension liabilities.

Net cash used by investing activities for the years ended December 31,
2001, 2000 and 1999 was $87.5 million, $74.4 million and $277.9 million,
respectively. We increased capital expenditures during these years primarily to
make acquisitions of petroleum products terminals, as well as to maintain and
expand the Williams Pipe Line system. In 2001, we acquired two inland terminals
in Little Rock, Arkansas and a marine terminal facility in Gibson, Louisiana. In
2000, we acquired an inland terminal and the New Haven, Connecticut marine
terminal facility. In 1999, we acquired 12 inland terminals, the Gulf Coast
marine terminal facilities and an additional ownership interest in eight
existing inland terminals. Capital expenditures related to the Williams Pipe
Line system were higher in 2000 and 1999 as a result of construction costs for
truck racks and costs related to the development of the ATLAS 2000 software
system. These costs totaled $9.1 million in 2000 and $16.8 million in 1999.

Net cash provided (used) by financing activities for the years ended
December 31, 2001, 2000 and 1999 was $(34.0) million, $19.4 million and $193.4
million, respectively. The cash flow for 2001 is primarily comprised of $77.3
million of net equity proceeds from our initial public offering, $89.2 million
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of net proceeds from borrowings under our operating partnership's credit
facility at the time of our initial public offering and $49.5 million of
additional proceeds from borrowings under that facility for the acquisitions of
the Little Rock, Arkansas inland terminals and Gibson, Louisiana marine terminal
facility. These proceeds were offset by a $166.5 million repayment of the
affiliate note payable associated with petroleum products terminal acquisitions
using funds from the equity and debt proceeds and a $68.6 million repayment of
the affiliate note payable associated with the Williams Pipe Line system using
free cash flow generated by the system. The 2000 and 1999 amounts primarily
represent loans we received from The Williams Companies to fund our terminal
acquisitions, offset by repayments of $6.7 million in 2000 and $38.6 million in
1999 of the affiliate note payable associated with the Williams Pipe Line system
using free cash flow generated by the system.

CAPITAL REQUIREMENTS

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

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

- expansion capital expenditures to acquire additional complementary assets
to grow our business and to expand or upgrade our existing facilities,
such as projects that increase storage or throughput volumes or develop
pipeline connections to new supply sources.

The Williams Companies has agreed to reimburse us for maintenance capital
expenditures incurred in 2001 and 2002 in excess of $4.9 million per year
related to the assets contributed to us at the time of our initial public
offering. This reimbursement obligation is subject to a maximum combined
reimbursement for 2001 and 2002 of $15.0 million. Of the $9.2 million in
maintenance capital expenditures in 2001 related to these assets, we incurred
$8.8 million after our initial public offering. Consequently, we recorded a
reimbursement from The Williams Companies of $3.9 million in 2001. As a result
of these reimbursements, the maximum reimbursement obligation of The Williams
Companies with respect to these assets has been reduced to $11.1 million for
2002. For 2002 we expect to incur maintenance capital expenditures for these
assets of approximately $16.0 million, of which $11.1 million will be reimbursed
by The Williams Companies.

In connection with the acquisition of Williams Pipe Line Company, The
Williams Companies has agreed to reimburse us for maintenance capital
expenditures incurred in 2002, 2003 and 2004 in excess of $19.0 million per year
related to the Williams Pipe Line system, subject to a maximum combined
reimbursement for 2002, 2003 and 2004 of $15.0 million. In 2002, we expect to
incur maintenance capital expenditures related to the Williams Pipe Line system
of approximately $16.8 million and, therefore, do not anticipate that we will be
reimbursed for such expenditures.

We expect to incur aggregate maintenance capital expenditures for 2002 for
all of our businesses, in excess of reimbursements from The Williams Companies,
of $21.7 million.

In addition to maintenance capital expenditures, we are also planning to
incur expansion and upgrade capital expenditures at our existing facilities,
including pipeline connections. The total we plan to spend for expansion is
approximately $7.0 million in 2002, not including capital needs associated with
additional acquisitions, if any. We expect to fund our expansion capital
expenditures, including any acquisitions, from:

- cash provided by operations;

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

- the issuance of additional common units.

If capital markets tighten and we are unable to fund these expenditures,
our business may be adversely affected and we may not be able to acquire
additional assets and businesses.

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LIQUIDITY

Williams Pipe Line Short-term Loan. In connection with the acquisition of
the Williams Pipe Line system, we and our subsidiary, Williams Pipe Line
Company, entered into a 180-day $700.0 million credit agreement. Substantially
all of the proceeds were used to finance this acquisition.

Our obligations under this short-term loan are unsecured. This indebtedness
ranks equally with all of our outstanding unsecured and unsubordinated debt. Our
operating partnership is not a borrower under this credit agreement. We may
prepay this short-term loan at any time, in whole or in part, without penalty.

This indebtedness bears interest, at our election, at the Eurodollar rate
plus 2.5%, or the prime rate plus 1.5%, for the first 120 days of the short-term
loan and, thereafter, at the Eurodollar rate plus 4.0%, or the prime rate plus
3.0%.

In addition, the credit agreement contains various covenants limiting our
and Williams Pipe Line Company's ability to:

- incur additional unsecured indebtedness other than under our operating
partnership's credit facility described below;

- grant liens other than tax liens, mechanic's and materialman's liens and
other liens and encumbrances incurred in the ordinary course of business;

- make investments, other than investments in the Williams Pipe Line
system, cash and short-term securities and acquisitions;

- merge or consolidate unless Williams Energy Partners is the survivor;

- dispose of assets;

- make distributions other than from available cash or, in the case of
Williams Pipe Line Company, in excess of $7.5 million in each quarter;

- engage in any business other than the transportation, storage and
distribution of hydrocarbons and ammonia;

- create obligations for some lease payments; or

- engage in transactions with affiliates other than arm's-length
transactions.

The credit agreement also contains a covenant requiring Williams Pipe Line
Company to maintain EBITDA (as defined in the credit agreement) of at least
$20.0 million for each fiscal quarter.

Operating Partnership Credit Facility. Subsequent to the closing of our
initial public offering on February 9, 2001, we have relied on cash generated
from internal operations as our primary source of funding. Additional funding
requirements are met by a $175.0 million credit facility of our operating
partnership that expires on February 5, 2004. This credit facility is comprised
of a $90.0 million term loan and an $85.0 million revolving credit facility. The
revolving credit facility is comprised of a $73.0 million acquisition
subfacility and a $12.0 million working capital subfacility.

Immediately after the closing of our initial public offering, we borrowed
the entire $90.0 million term loan and $0.1 million under the revolving credit
facility. As of December 31, 2001, $23.5 million was available under the
acquisition subfacility after borrowing $49.5 million to fund the Little Rock,
Arkansas and Gibson, Louisiana acquisitions. In January 2002, we borrowed $8.9
million to pay for the Aux Sable transaction. In addition, $12.0 million was
available under the working capital subfacility at December 31, 2001.

Obligations under the credit facility are unsecured but are guaranteed by
all of the subsidiaries of our operating partnership. Indebtedness under the
credit facility ranks equally with all the outstanding unsecured and
unsubordinated debt of our operating partnership. Williams Pipe Line Company is
a separate operating subsidiary of ours and is not a borrower or guarantor under
this credit facility.

S-29

We may prepay all loans at any time without penalty. We must reduce all
borrowings under the working capital subfacility to zero for a period of at
least 15 consecutive days once during each year, beginning on the effective date
of the credit facility.

Indebtedness under the credit facility bears interest at the Eurodollar
rate plus an applicable margin that ranges from 1.00% to 1.45%. We incur a
commitment fee on the unused portions of the revolving credit facility and the
term loan.

In addition, the credit facility contains various covenants limiting our
operating partnership's ability to:

- incur additional unsecured indebtedness of more than $75.0 million,
subordinated debt owed to affiliates of more than $50.0 million and
secured purchase money debt of more than $5.0 million, including
maintaining the ratios described below;

- grant liens other than tax liens, mechanic's and materialman's liens and
other liens and encumbrances incurred in the ordinary course of the
operating partnership's business;

- make investments, other than investments in the operating partnership's
subsidiaries, cash and short term securities and acquisitions;

- merge or consolidate;

- sell all of the operating partnership's assets;

- make distributions other than from available cash;

- engage in any business other than the transportation, storage and
distribution of hydrocarbons and ammonia;

- create obligations for some lease payments; or

- engage in transactions with affiliates other than arm's-length
transactions.

The credit facility also contains covenants requiring the operating
partnership to maintain specified ratios of:

- EBITDA (as defined in the credit facility), pro forma for any asset
acquisitions, to interest expense of not less than 3.0 to 1.0; and

- total debt to EBITDA, pro forma for any asset acquisitions, of not more
than 4.0 to 1.0.

Our management believes that our operating partnership is in compliance with all
of these covenants.

ENVIRONMENTAL

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

In conjunction with our initial public offering, and with respect solely to
the petroleum products terminals and ammonia pipeline assets owned at the time
of that offering, Williams Energy Services, an affiliate of ours and a
subsidiary of The Williams Companies, agreed to indemnify us against
environmental liabilities, up to $15.0 million, that arose prior to February 9,
2001, that become known within three years after February 9, 2001 and that
exceed all amounts recovered or recoverable by us under contractual indemnities
from third parties or under any applicable insurance policies.

As of December 31, 2001, we had accrued environmental remediation
liabilities associated with our petroleum products terminals and ammonia
pipeline system of $5.4 million. This amount includes a

S-30

$2.6 million liability recorded in 2001 associated with our New Haven,
Connecticut marine terminal facility, based on third-party estimates developed
as part of a Phase II environmental assessment required by the State of
Connecticut. Management estimates that these expenditures for environmental
remediation liabilities will be paid over the next two to five years.
Receivables of $5.1 million associated with these environmental liabilities have
been recognized as recoverable from affiliates and third parties.

In connection with our acquisition of Williams Pipe Line Company on April
11, 2002, Williams Energy Services agreed to indemnify us for losses and damages
related to breach of environmental representations and warranties and the
failure to comply with environmental laws prior to closing in excess of $2.0
million up to a maximum of $125.0 million. This $125.0 million will also be
subject to indemnification claims made by us for breaches of other
representations and warranties. The environmental indemnification obligation
applies to liabilities that result from conduct prior to the closing of our
acquisition of Williams Pipe Line Company and that are discovered within six
years of closing. In addition, certain of Williams Pipe Line Company's assets
and liabilities, including environmental remediation liabilities, were
transferred to an affiliate of The Williams Companies prior to our acquisition
of Williams Pipe Line Company.

During 2001, we recorded $7.5 million of environmental remediation expenses
associated with the Williams Pipe Line system. These expenses were primarily the
result of cleanup at several terminals located on the system and at a
discontinued refining site, which was not included in the assets and liabilities
transferred to us in connection with the acquisition of the Williams Pipe Line
system. In addition, we incurred costs related to the assessment and monitoring
of soil, groundwater and surface water conditions at various locations on the
system where operations may have resulted in releases of hydrocarbons and other
wastes.

As of December 31, 2001, we had accrued environmental remediation
liabilities associated with the Williams Pipe Line system of $11.5 million. Of
these liabilities, $2.0 million were transferred to an affiliate of The Williams
Companies prior to our acquisition of Williams Pipe Line Company on April 11,
2002, and a receivable was recognized at the time of the closing of the
acquisition for $7.5 million that is recoverable under the indemnification from
Williams Energy Services. We expect to pay the remaining $2.0 million of the
$11.5 million of accrued environmental remediation liabilities as the deductible
required under that indemnification. Management estimates that these remaining
expenditures for environmental remediation liabilities will be paid over the
next two to five years.

IMPACT OF INFLATION

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

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates. We deem the following accounting policies to be critical:

- Transportation revenues are recognized when products are delivered to
customers. Injection service fees associated with customary proprietary
additives are recognized upon injection to the customer's product, which
occurs at the time the product is delivered. Leased storage, terminalling
and other related revenues are recognized upon provision of contract
services. Other revenue, principally blending and fractionation revenue,
is recognized upon sale of the product.

S-31

- Depreciation expense is calculated based on our estimate of the remaining
useful lives of our assets. Because of the expected long useful lives of
our assets, we depreciate terminals and pipelines over a 6-year to
67-year period for financial statement purposes. Changes in the estimated
lives of our assets could have a material effect on results of
operations.

- Incentive compensation expense is recorded for the restricted unit
compensation program for The Williams Companies employees assigned to our
businesses. The expense associated with the one-time IPO award is based
on the price of the units on the date of grant. The expense associated
with the annual incentive compensation plan is computed based on the
estimated number of units that will ultimately vest adjusted by the
current market value of the units at each period end. We are accruing
costs for these units assuming the maximum number of units that can vest.
Any changes in those assumptions would result in lower compensation
expense to the us.

- Environmental liabilities are recorded when site restoration,
environmental remediation and cleanup obligations are either known or
considered probable and can be reasonably estimated. Environmental
liabilities are recorded independently of any potential claim for
recovery. Receivables are recognized in cases where reimbursements for
remediation costs are considered probable.

- With the adoption of Statement of Financial Accounting Standards No. 142,
goodwill will no longer be amortized beginning January 1, 2002 but will
be tested periodically for impairment. Management's judgments and
assumptions relative to estimating the future cash flows of our various
assets will be critical in determining whether an impairment exists and,
if so, the financial impact of such impairment. Changes in market
conditions, customers and/or industry financial conditions, technology
and other factors could materially impact the future assessment of
goodwill values, which could have a material impact on our results of
operations, financial condition and cash flows.

NEW ACCOUNTING PRONOUNCEMENTS

In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." The Statement retains the basic framework of SFAS No.
121, resolves certain implementation issues of SFAS No. 121, extends
applicability to discontinued operations and broadens the presentation of
discontinued operations to include a component of an entity. The Statement is to
be applied prospectively and is effective for financial statements issued for
fiscal years beginning after December 15, 2001. The Statement is not expected to
have any initial impact on our results of operations, financial position or cash
flows.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This Statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The
Statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002. We plan to adopt this standard in January 2003,
and we are evaluating its effect on our results of operations, financial
position or cash flows.

S-32

Under this Statement, goodwill and intangible assets with indefinite useful
lives will no longer be amortized but will be tested annually for impairment.
The Statement becomes effective for all fiscal years beginning after December
15, 2001. We will apply the new rules on accounting for goodwill and other
intangible assets beginning January 1, 2002. Based on the amount of goodwill
recorded as of December 31, 2001, application of the non-amortization provision
of the Statement will result in a decrease to amortization expense in future
years of approximately $1.1 million.

In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities." The
Statement provides guidance for determining whether a transfer of financial
assets should be accounted for as a sale or a secured borrowing and whether a
liability has been extinguished. The Statement is effective for recognition and
reclassification of collateral and for disclosures ending after December 15,
2000. The Statement became effective for transfers and servicing of financial
assets and extinguishments of liabilities occurring after March 31, 2001. The
initial application of SFAS No. 140 had no impact on our results of operations,
financial position or cash flows.

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This was followed in June 2000 by the
issuance of SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities," which amends SFAS No. 133. SFAS No. 133 and No. 138
establish accounting and reporting standards for derivative financial
instruments. The standards require that all derivative financial instruments be
recorded on the balance sheet at their fair value. Changes in fair value of
derivatives will be recorded each period in earnings if the derivative is not a
hedge. If a derivative qualifies for special hedge accounting, changes in the
fair value of the derivative will either be recognized in earnings as an offset
against the change in fair value of the hedged assets, liabilities or firm
commitments also recognized in earnings, or the changes in fair value will be
deferred on the balance sheet until the hedged item is recognized in earnings.
The ineffective portion of a derivative's change in fair value will be
recognized immediately in earnings. These standards were adopted on January 1,
2001. There was no impact on our results of operations, financial position or
cash flows from adopting these standards.

RELATED PARTY TRANSACTIONS

We have entered into a number of commercial agreements with affiliates,
including Williams Energy Marketing & Trading, Williams Refining & Marketing,
Williams Ethanol Services, Inc. and Mid-America Pipeline Company. Each of these
entities is a subsidiary of The Williams Companies and an affiliate of ours and
of our general partner. The principal business of Williams Energy Marketing &
Trading is the marketing and trading of energy commodities including natural
gas, natural gas liquids, power, crude oil and refined petroleum products.
Williams Refining & Marketing primarily owns and operates a refinery in Memphis,
Tennessee and also engages in the purchase and sale of crude and refined
petroleum products. Williams Ethanol Services operates two ethanol plants and an
ethanol distribution system and also engages in the purchase and sale of
ethanol. Mid-America Pipeline is an interstate common carrier pipeline company
engaged in the transportation and distribution of natural gas liquids.

The agreements with our affiliates vary depending upon location and the
types of services provided. Approximately $15.9 million of our revenues in 2001
were generated from agreements with affiliates at our petroleum products
terminals while approximately $78.4 million of revenue in 2001 was generated
from agreements with affiliates on The Williams Pipe Line system. In addition,
approximately $81.0 million of expenses were incurred from product purchases
with our affiliates on the Williams Pipe Line system. A summary of the
significant agreements follows:

THE WILLIAMS PIPE LINE SYSTEM

Tariff-Based Shipments. Williams Energy Marketing & Trading and Williams
Refining & Marketing ship refined petroleum products on our pipeline system. We
charge rates for the shipments based upon tariffs filed with the FERC or the
applicable state agency that are the same rates we charge to non-affiliated
entities. These tariffs serve as individual contractual agreements that commit
our affiliate to pay

S-33

for volume transported on our system as long as we abide by the terms of the
tariff. As a result, contracts do not exist that obligate our affiliates to ship
volume or make payments to us in the future. These tariff-based shipments
generated approximately $5.0 million of revenue in 2001.

System Lease Storage Agreements. We have entered into several agreements
with Williams Energy Marketing & Trading and Williams Refining & Marketing for
the access and utilization of storage along the Williams Pipe Line system. These
agreements provide for a fixed monthly storage capacity on the pipeline system
at a fixed rate. The rates charged to our affiliates are consistent with those
charged to non-affiliated entities. Services provided under these agreements
include the receipt of refined petroleum products into our system at any origin
point on our system. Our affiliates remain responsible for tariff charges
related to the actual shipment of product and delivery through our terminals. A
majority of these contracts have a term of one to two years. Historically, at
the end of the contract term, we have extended the agreements for one to two
additional years. These agreements generated approximately $2.2 million in
revenues in 2001.

Ethanol Storage and Throughput Agreements. We have entered into several
agreements with Williams Ethanol Services for the access and utilization of
storage along the Williams Pipe Line system. These agreements provide for a
fixed monthly ethanol storage capacity at our terminals at a fixed storage rate.
The rates charged to our affiliates are consistent with those charged to
non-affiliated entities. In addition, we charge additional fees ranging from
$0.80 per barrel to over $1.25 per barrel for blending services and handling
fees at certain terminals. A majority of these contracts have a term ranging
from less than one year and up to two years. These agreements generated
approximately $3.2 million in revenues in 2001.

Facility Rental Agreement. We have entered into an agreement to lease to
Mid-America Pipeline approximately 292 miles of pipeline, three active pump
stations and a propane storage and loading facility in Canton, South Dakota.
Mid-America Pipeline is responsible for utilities and other operating costs. The
agreement was entered into in 1998 and has been renewed yearly since that time.
The rate charged for this lease has not changed from year to year. This
agreement generated approximately $0.3 million in revenues in 2001.

System Services Agreements. We have entered into agreements with Williams
Energy Marketing & Trading, Williams Refining & Marketing and Williams Ethanol
Services providing them with a non-exclusive and non-transferable sublicense to
use the ATLAS 2000 software system. The system can be utilized to access data
for monitoring shipment and inventory status and performing other functions
related to shipment activities. The agreements establish fixed rates at which we
provide certain services. These agreements generated approximately $0.3 million
in revenues in 2001.

Over and Short Settlement and Product Purchases and Sales Agreements. We
have entered into agreements with Williams Energy Marketing & Trading to buy
natural gas liquids blendstocks and sell the refined petroleum products related
to our blending program and to purchase from or sell to us refined petroleum
products needed to maintain inventory balances on our pipeline system (which we
refer to as over and short settlements). These transactions are subject to
master purchase and sale agreements for refined petroleum products or a master
purchase agreement for natural gas liquids. Each transaction with our affiliate
is recorded on a confirmation statement, which is subject to the general terms
outlined in the master agreements. These confirmation statements determine the
volume, price and timing associated with the product purchases and sales.
Because the confirmation statements are generally associated with discrete
transactions over short time frames, contracts do not exist that obligate our
affiliate to buy or sell refined petroleum products or natural gas liquids to us
in the future. The revenues associated with these agreements were approximately
$66.4 million in 2001, while the expenses incurred to purchase products from our
affiliates were approximately $76.8 million in 2001. Additional details related
to the activities that produce the purchase and sale opportunities are as
follows:

- Blending. Historically, Williams Pipe Line Company purchased natural gas
liquids from Williams Energy Marketing & Trading at cost plus a fixed fee
of $0.105 per barrel. Williams Energy Marketing & Trading purchased at
prevailing market prices a majority of the finished gasoline that
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was produced from blending. In connection with the acquisition of the
Williams Pipe Line system, we and Williams Energy Services agreed that
the Williams Pipe Line system will no longer take title to the natural
gas liquids it blends or the resulting product. We will continue to
perform these blending services for Williams Energy Services under a
ten-year agreement for an annual fee of approximately $3.0 million. This
agreement provides for a total annual amount of $3.5 million, of which
$0.5 million is attributable to blending services provided at one of our
inland petroleum products terminals not connected to the Williams Pipe
Line system.

- Over and Short Settlement. Generally, the physical volumes on our system
will not match the balances recorded by our customers. These differences
are either product quality differences or absolute volume differences.
Quality differences usually result from the commingling of product on the
pipeline during times when we change the product being shipped on our
pipeline. When these differences occur, we purchase and sell product at
prevailing market prices from our affiliate to manage the imbalances.

Longhorn Partners Pipeline Construction Revenue Agreement. Williams Pipe
Line Company entered into agreements with Longhorn Partners Pipeline to provide
engineering, design, construction, start-up and pipeline operating services.
Under these agreements, Williams Pipe Line Company was reimbursed for costs
incurred and received contractor and operating fees. The revenues associated
with these agreements were approximately $1.0 million in 2001. In connection
with our acquisition of Williams Pipe Line Company, these agreements were
transferred to another affiliate of The Williams Companies and consequently we
will no longer provide these services and receive these fees.

Mid-America Pipeline Agreements. We have entered into agreements to lease
from Mid-America Pipeline underground natural gas liquids storage in Kansas, to
ship natural gas liquids on Mid-America Pipeline at published tariffs and to
lease from Mid-America Pipeline approximately 15 miles of pipeline in Illinois.
The natural gas liquids storage leases are typically renewed yearly, and the
pipeline lease has a term of ten years. Any tariff-based shipments are subject
to the prevailing tariff and are not subject to any other contract. Together,
these agreements generated operating expenses of $0.8 million in 2001.

Natural Gas and Fuel Oil Supply Agreements. We have entered into
agreements with Williams Energy Marketing & Trading and Williams Refining &
Marketing for the supply of natural gas and fuel oil used at pump stations
throughout the Williams Pipe Line system. We purchase fuel oil from Williams
Refining & Marketing at the prevailing market price. These purchases are
identified on confirmation statements that are subject to the master refined
products purchase and sale agreements used in the blending and over and short
program. We purchase natural gas from Williams Energy Marketing & Trading either
based on indexed prices or at fixed prices. In 2001, we elected to purchase a
majority of our natural gas at fixed prices, which required that we commit to a
definite volume of natural gas purchases. Long-term volume commitments are not
required for index-based pricing. The natural gas purchase agreement for fixed
price natural gas expires in August 2002. At that time, we expect to enter into
a new agreement with Williams Energy Marketing & Trading on terms similar to
those in the existing contract. These agreements generated operating expenses of
$4.2 million in 2001.

PETROLEUM PRODUCTS TERMINALS

Inland Terminal Use and Access Agreements. We have entered into several
agreements with Williams Energy Marketing & Trading and William Refining &
Marketing for the access and utilization of our inland terminals. The services
provided under these agreements include the receipt and delivery of refined
petroleum products via connecting pipelines, tank trucks or transport terminals.
Additional services include product handling, storage and additive injection.
These agreements establish a fixed fee at which these services are provided at
rates consistent with those charged to non-affiliated entities. A majority of
these contracts have a term of one year and are renewed on an annual basis. The
revenue associated with these agreements in 2001 was approximately $6.5 million.

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Products Terminalling Agreement for the Galena Park, Texas Marine Terminal
Facility. We entered into an agreement with Williams Energy Marketing & Trading
to provide approximately 2.5 million barrels of storage capacity and to provide
other ancillary services at our Galena Park, Texas marine terminal facility.
Because the storage fees are fixed and the storage capacity is already
committed, revenues only fluctuate to the extent other ancillary services are
utilized. The primary services provided include receipt and delivery of refined
petroleum products and blendstocks via marine vessel, pipeline, tank truck or
other transfers from customers within the terminal facility. Upon the request of
Williams Energy Marketing & Trading, we provide gasoline blending services to
their product at an additional cost. The prices charged under this agreement are
consistent with those charged to non-affiliated entities. The agreement
generated approximately $7.4 million of revenue during 2001 and extends until
September 30, 2004, at which time it may be renewed monthly.

Products Terminalling Agreement for Marrero, Louisiana and Galena Park,
Texas Marine Terminal Facilities. We entered into an agreement with Williams
Energy Marketing & Trading to provide up to 0.4 million barrels of storage
capacity at Marrero and 0.1 million barrels of storage capacity at Galena Park.
We also agreed to provide other ancillary services including blending and tank
heating services. The primary services provided include receipt and delivery of
refined petroleum products and blendstocks at Galena Park and heavy oils and
feedstocks at Marrero. The prices charged under this agreement are consistent
with those charged to non-affiliated entities. The agreement generated
approximately $1.4 million of revenue during 2001. This contract has been
canceled and replaced with the contract described immediately above.

Products Terminalling Agreement for the Gibson, Louisiana Marine Terminal
Facility. We entered into an agreement to provide Williams Energy Marketing &
Trading capacity utilization rights to substantially all of the capacity of the
Gibson, Louisiana facility for nine years starting November 1, 2001. This
agreement allows for the delivery of crude oil and condensate to our facility by
barge, truck and pipeline where we then provide storage, blending and throughput
services. Williams Energy Marketing & Trading has committed to utilize
substantially all of the capacity at our facility at a fixed rate which is
consistent with rates charged by other service providers for similar services at
other locations. As a result, the revenues we receive should not significantly
vary as long as the services we provide do not fall below certain performance
standards. This contract expires after nine years and we expect it to generate
approximately $4.0 million in revenue in 2002. This contract generated
approximately $0.6 million in revenue for the two months we owned the facility
in 2001.

OTHER AFFILIATE AGREEMENTS

In addition to the expenses incurred under the commercial agreements with
our affiliates discussed above, we also incur affiliate expenses for general and
administrative, operating and maintenance services under the terms of our
partnership agreement and our omnibus agreement, which governs the relationship
between us, our general partner and The Williams Companies.

ENRON EXPOSURE

We have a crude oil storage contract with an affiliate of Enron. Following
Enron's voluntary bankruptcy petition, the Enron affiliate failed to pay
approximately $0.2 million of the amount due to us under this contract. Under
the terms of our agreement, we seized assets from the Enron affiliate in an
amount sufficient to settle the obligation. As a result, we did not incur any
loss exposure associated with Enron or its affiliates at December 31, 2001. We
have continued our business dealings with Enron's affiliate but the terms have
been changed such that the crude storage services are on a prepaid basis.

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Through a variety of energy commodity and derivative contracts, Williams
Energy Marketing & Trading, a subsidiary of The Williams Companies, has credit
exposure to various Enron entities. During the fourth-quarter 2001, Williams
Energy Marketing & Trading recorded a reduction in trading revenues of
approximately $130.0 million as a part of its valuation of energy commodity and
derivative tracking contracts with Enron entities. Approximately $91.0 million
of this reduction in revenues was recorded pursuant to events immediately
preceding and following Enron's announced bankruptcy. At December 31, 2001, The
Williams Companies had reduced its exposure to accounts receivable from Enron,
net of margin deposits, to expected recoverable amounts.

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BUSINESS

INTRODUCTION

We were formed by The Williams Companies 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. Our asset portfolio currently consists of:

- the Williams Pipe Line system;

- five marine terminal facilities;

- 25 inland terminals; and

- an 1,100-mile ammonia pipeline system.

The Williams Pipe Line system is a 6,700-mile common carrier pipeline that
provides refined petroleum products transportation and terminalling services in
11 states from Oklahoma through the Midwest to Illinois and North Dakota. Our
marine and inland terminals store and distribute refined petroleum products in
12 states. 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.

RELATIONSHIP WITH THE WILLIAMS COMPANIES

One of our principal attributes is our relationship with The Williams
Companies. Through this relationship, we have access to experienced management
and strong relationships throughout the energy industry. The Williams Companies
has a long history of successfully pursuing and consummating energy acquisitions
and utilizes us as a significant growth vehicle for its transportation, storage
and distribution businesses. We will continue to pursue strategic acquisitions
from unaffiliated parties independently and jointly with The Williams Companies,
including acquisitions that we would be unable to pursue on our own. We also
expect to make additional acquisitions directly from The Williams Companies in
the future, although no such additional acquisitions have currently been
identified.

The Williams Companies has a significant interest in us. Upon completion of
this offering, The Williams Companies will own a 52.6% limited partner interest
in us and all of our 2% general partner interest. Additionally, Williams Energy
Marketing & Trading and Williams Refining & Marketing subsidiaries of The
Williams Companies, are significant customers of ours. For the year ended
December 31, 2001, Williams Energy Marketing & Trading, Williams Refining &
Marketing and other affiliates of The Williams Companies collectively
represented approximately 21.0% of our combined historical revenues.

RECENT DEVELOPMENTS

Williams Pipe Line System Acquisition. On April 11, 2002, we acquired all
of the membership interests of Williams Pipe Line Company from a wholly owned
subsidiary of The Williams Companies for approximately $1.0 billion. Williams
Pipe Line Company owns and operates the Williams Pipe Line system. The Williams
Pipe Line system further complements our virtual supply network that allows us
to offer our customers same-day delivery of refined petroleum products at
multiple points across our distribution network regardless of actual
transportation time.

We financed the acquisition through a $700.0 million short-term loan and
the issuance of Class B units to The Williams Companies. The Class B units will
be treated as common units for purposes of cash distributions, but no
distributions will be made on the Class B units until we have repaid the
short-term loan. The terms of the short-term loan are described under the
caption "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Liquidity and Capital Resources" in this

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prospectus supplement and the Class B Units are described under the caption
"Description of Our Class B Units" in the accompanying prospectus.

In connection with the acquisition of Williams Pipe Line Company, Williams
Energy Services agreed to indemnify us for any breach of a representation or
warranty that results in losses and damages of up to $110.0 million after the
payment of a $6.0 million deductible. With respect to any amount exceeding
$110.0 million, Williams Energy Services will be responsible for one-half of
that amount up to $140.0 million. In no event will Williams Energy Services'
liability exceed $125.0 million. These indemnification obligations will survive
for one year, except that those relating to employees and employee benefits will
survive for the applicable statute of limitations and those relating to real
property, including title to Williams Energy Services' assets, will survive for
ten years. This indemnity also provides that we will be indemnified for an
unlimited amount of losses and damages related to tax liabilities. In addition,
any losses and damages related to environmental liabilities that arose prior to
the acquisition will be subject only to a $2.0 million deductible.

In connection with the acquisition of the Williams Pipe Line system, we and
The Williams Companies also amended the omnibus agreement among ourselves and
the other affiliated entities named therein. The amended omnibus agreement
includes provisions governing:

- potential competition between us and The Williams Companies with respect
to the acquisition or construction of additional transportation assets;

- the maximum reimbursement amount to be paid by us to The Williams
Companies for general and administrative expenses related to the
operation of the Williams Pipe Line system through 2017; and

- the amount of reimbursement to be paid by The Williams Companies to us if
the maintenance capital expenditures related to the Williams Pipe Line
system exceed certain levels through 2004.

Other Acquisitions. On December 31, 2001, we acquired a natural gas
liquids pipeline in Illinois from Aux Sable Liquid Products L.P. for
approximately $8.9 million. On October 31, 2001, we acquired a marine terminal
facility in Gibson, Louisiana from Geonet Gathering, Inc. for approximately
$21.1 million. On June 30, 2001, we acquired two inland petroleum products
terminals in Little Rock, Arkansas, from TransMontaigne, Inc. for approximately
$29.1 million. On April 5, 2001, we acquired a refined petroleum products
pipeline in Dallas, Texas from Equilon Pipeline Company LLC for $0.3 million.

BUSINESS STRATEGIES

Our primary business strategies are to:

Grow through strategic acquisitions that increase per unit cash
flow. Since our initial public offering in February 2001, we have successfully
completed five acquisitions and have increased our quarterly cash distribution
by approximately 17% from $0.525 per common unit to $0.6125 per common unit for
the first quarter of 2002. We will continue to pursue acquisitions
independently, as well as jointly with The Williams Companies. Future
acquisition targets may include assets to be directly integrated into our
current operations, such as additional pipelines or terminals that will expand
and complement our existing refined petroleum products distribution network, or
acquisitions of other businesses in which we are not currently active. The
acquisition of the Williams Pipe Line system was a significant transaction for
us and our first acquisition directly from The Williams Companies. We will
continue to capitalize on the opportunity to make acquisitions directly from The
Williams Companies in the future, although no such additional acquisitions have
currently been identified.

Maximize the benefits of our relationship with The Williams Companies. The
Williams Companies is engaged in numerous aspects of the energy industry and has
a long history of aggressively pursuing and consummating energy acquisitions.
Through our relationship with The Williams Companies, we have access to a
significant pool of management talent and strong relationships throughout the
energy industry that we utilize to execute our strategies. The Williams
Companies formed us as a primary growth vehicle

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for its transportation, storage and distribution businesses. For this reason, we
have the opportunity to participate with The Williams Companies in considering
transactions that we would not be able to pursue on our own. We also benefit
from an increased likelihood that potential sellers will contact, and solicit
bids from, us as a result of our affiliation with The Williams Companies. In
addition, Williams Energy Marketing & Trading and Williams Refining & Marketing
are two of our largest customers.

Generate stable cash flows to make quarterly cash distributions. In
conducting our existing operations and pursuing future opportunities, we focus
on businesses and assets that generate stable cash flows with limited exposure
to commodity price fluctuations. In each of our business lines, our customers
pay fees based on the amount of product they transport, store and distribute. We
have little direct exposure to commodity price fluctuations because we take
title to less than 2% of the products we transport, store and distribute. We
will continue to focus on businesses that generate stable cash flows with
limited exposure to commodity price fluctuations as we consider future
acquisition opportunities.

COMPETITIVE STRENGTHS

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

Our acquisition strategy is enhanced by our affiliation with The Williams
Companies. We believe that our affiliation with The Williams Companies will
provide us with a competitive advantage when we jointly pursue acquisition
opportunities. As is frequently the case in the petroleum industry, potential
acquisition opportunities may have an element of commodity price risk inherent
in its operations. We expect to be able to pursue such acquisitions jointly with
The Williams Companies in a manner that minimizes or eliminates commodity price
exposure to us. In these circumstances, Williams Energy Marketing & Trading and
Williams Refining & Marketing may assume most or all of the commodity price
exposure inherent in the acquired business and incorporate these risks into
their overall commodity trading operations. As a result of this affiliation, we
expect to be able to pursue acquisition targets that would otherwise not be
attractive acquisition candidates for us or other competing potential acquirers
because of the commodity price risk inherent in the target operations.
Additionally, we will continue to explore acquisition opportunities, like the
Williams Pipe Line system, directly from The Williams Companies in the future.

Our officers and directors have extensive industry experience and include
some of the most senior officers of The Williams Companies. Steve Malcolm,
Chief Executive Officer and President of The Williams Companies, serves as a
director of our general partner, and Phil Wright, the Chief Executive Officer
and President of Williams Energy Services, serves as the Chairman of the Board
of our general partner. We believe that we benefit from the experience and
long-standing industry relationships of our senior management team.
Additionally, our senior management team enhances our ability to benefit from
our relationship with The Williams Companies.

Our assets are strategically located in areas with high demand for our
services. The Williams Pipe Line system includes more than 6,700 miles of
pipeline and 39 terminals that play a critical role in the transportation and
distribution of refined petroleum products across 11 states in the mid-continent
region of the United States. This region has historically had high demand for
refined petroleum products, and this demand is expected to grow at an average
rate of 1.7% per year over the next 10 years. Additionally, four of our marine
terminal facilities are located along the Gulf Coast, which has the largest
concentration of petroleum refineries and petrochemical plants in the United
States and is connected to most major distribution systems. Our fifth marine
terminal facility is located in close proximity to the New York harbor, a key
trading hub for refined petroleum products. Most of our inland terminals are
connected to the Colonial or Plantation pipelines, which are the principal
common carrier refined products pipelines serving the southeastern United
States. Additionally, our ammonia pipeline system connects ammonia production
facilities located in Texas and Oklahoma with ammonia consumption areas
throughout the agricultural regions of the Midwest.

S-40

We provide refined petroleum products distribution services through a
virtual supply network that is capable of providing same-day delivery of refined
petroleum products at multiple points across our distribution network regardless
of actual transportation time. We benefit from owning and operating
geographically diverse refined petroleum products distribution facilities that
are interconnected by the Williams Pipe Line system as well as pipelines owned
by third parties. This permits us to offer our customers same-day delivery of
refined petroleum products at multiple points across our distribution network,
regardless of actual transportation time. For example, a customer may deliver
gasoline to our Tulsa terminal and be able to withdraw gasoline on the same day
from any one of our terminals on the Williams Pipe Line system.

We have little direct commodity price exposure because we generally do not
take title to the products we transport, store and distribute. Substantially
all of our operations are conducted under storage contracts or involve
transportation and distribution services in which we generally do not take title
to the customers' products. As a result, our business depends primarily upon the
volumes of products that we transport, store and distribute, and we have little
direct exposure to commodity prices. However, commodity prices may affect demand
for our services. We intend to continue to minimize our direct exposure to
commodity prices in the future.

REFINED PETROLEUM PRODUCTS TRANSPORTATION AND DISTRIBUTION

The United States refined petroleum products transportation and
distribution system links oil and gas refineries to end-users of gasoline and
other refined petroleum products and is comprised of a network of pipelines,
terminals, storage facilities, tankers, barges, rail cars and trucks. For
transportation of refined petroleum products, pipelines are generally the
lowest-cost alternative for intermediate and long-haul movements between
different markets. Throughout the distribution system, terminals play a key role
in moving products to the end-user market by providing storage, distribution,
blending and other ancillary services. Products transported, stored and
distributed through the Williams Pipe Line system and marine and inland
terminals include:

- Refined Petroleum Products, which are the output from refineries and are
often used as fuels by consumers. Refined petroleum products include
gasoline, diesel, jet fuel, kerosene and heating oil.

- Liquefied Petroleum Gases, or LPGs, which are produced as by-products of
the crude oil refining process and in connection with natural gas
production. LPGs include butane and propane.

- Blendstocks, which are blended with petroleum products to change or
enhance their characteristics such as increasing a gasoline's octane or
oxygen content. Blendstocks include alkylates and oxygenates.

- Heavy Oils and Feedstocks, which are often used as burner fuels or
feedstocks for further processing by refineries and petrochemical
facilities. Heavy oils and feedstocks include #6 fuel oil and vacuum gas
oil.

The Energy Information Administration forecasts that total petroleum demand
throughout the United States will grow at an average rate of 1.9% per year over
the next 10 years. More than 70% of the growth in petroleum demand is predicted
to come from increased demand for transportation fuels, which is projected to
grow 2.2% annually over the same period. Meanwhile, U.S. petroleum supply is
expected to continue shifting as the petroleum industry furthers the process of
consolidation that began in the 1990s, when refiners and marketers began to
pursue development of large-scale, cost-efficient operations. This process has
led to many refinery acquisitions, mergers, alliances and joint ventures. Major
integrated oil companies have re-deployed resources to core competencies of
exploration and production, refining and retail marketing and have sought to
lower their distribution costs. The pace of consolidation has accelerated as
increasingly strict environmental regulations and fuel standards are forcing
many refineries to make significant capital investments or cease operations.
This regulatory pressure has further increased the importance of large-scale
refining operations such as those found along the U.S. Gulf Coast, often at the
expense of refineries in other regions.

S-41

One effect of the increasing U.S. demand for refined petroleum products and
the concurrent shifts in U.S. refined petroleum products supply is an increasing
emphasis on the role of the transportation and distribution system. Pipelines
and terminals, especially those with connections to the U.S. Gulf Coast, are
well-positioned to capitalize on the need to satisfy growing demand while
adapting to shifting supply. Our ability to adapt to these market shifts is
enhanced by the broad geographic coverage of our distribution network and our
ability to utilize a virtual supply network to provide our customers with
same-day delivery of refined petroleum products regardless of actual
transportation time.

WILLIAMS PIPE LINE SYSTEM

The Williams Pipe Line system covers an 11-state area extending from
Oklahoma through the Midwest to North Dakota, Minnesota and Illinois. The system
transports refined petroleum products and LPGs and includes a common carrier
pipeline and 39 terminals that provide transportation and terminalling services.
The products transported on the Williams Pipe Line system are largely
transportation fuels, comprised of 58% gasolines, 32% diesel fuels and 10% LPGs
and aviation fuels in 2001. Product originates on the system from direct
connections to refineries and interconnections with other interstate pipelines
for transportation and ultimate distribution to retail gasoline stations, truck
stops, railroads, airlines and other end-users.

The Williams Pipe Line system largely depends on the demand for refined
petroleum products and LPGs in the markets it serves and the ability of refiners
and marketers to meet those needs through the pipeline system. According to
statistics provided by the Energy Information Administration, the demand for
refined petroleum products in the market area served by Williams Pipe Line
system, known as Petroleum Administration for Defense District II, or PADD II,
is expected to grow at an average rate of 1.7% per year over the next 10 years.
The total production of refined petroleum products from refineries located in
PADD II is currently insufficient to meet the demand for refined petroleum
products in PADD II. The excess PADD II demand has been and is expected to be
met largely by imports of refined petroleum products via pipelines from Gulf
Coast refineries that are located in PADD III.

U.S. refineries, including the refineries located in PADD II, are required
to comply with increasingly strict clean fuels regulations mandated by the
Environmental Protection Agency. Many refineries will be forced to make
significant capital investments in order to meet these higher regulatory
standards. Some refineries located in PADD II, including some refineries
directly connected to the Williams Pipe Line system, may be unable or unwilling
to make such additional investments and may find it more economically attractive
to cease operations. The possibility of such refinery closings in PADD II,
coupled with continued increases in PADD II demand growth, will likely result in
shifts in the supply of refined petroleum products in PADD II, potentially
resulting in increasing imports to PADD II from the Gulf Coast refineries via
pipeline.

The Williams Pipe Line system is well-connected to the Gulf Coast
refineries through interconnections with the Explorer, Equilon, Phillips and
CITGO pipelines. These connections to Gulf Coast refineries, together with the
Williams Pipe Line system's extensive network throughout PADD II and connections
to PADD II refineries, should allow it to accommodate not only demand growth,
but also any major supply shifts that may occur.

The Williams Pipe Line system has experienced steadily increased shipments
over the last three years, with total shipments increasing by 3.3% from 1999 to
2000 and by 2.3% from 2000 to 2001. The volume increases have come as a result
of development projects on the system and from incentive agreements with
shippers utilizing the system. In addition, the volume increase is partially a
result of refined petroleum

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products demand growth in the markets served by the system. The operating
statistics below reflect the Williams Pipe Line system's operations for the
periods indicated:

1999 2000 2001
------- ------- -------

Shipments (thousands of barrels):
Refined Products
Gasolines.......................................... 132,444 130,580 137,552
Distillates........................................ 70,466 74,299 75,887
Aviation fuels..................................... 12,060 16,488 14,752
LPGs.................................................. 7,521 7,781 7,901
Capacity Lease........................................ 23,215 24,780 23,671
------- ------- -------
Total Shipments............................... 245,706 253,928 259,763
======= ======= =======
Daily average (thousands of barrels).................... 673 694 712
Barrel miles (billions)................................. 67.8 68.2 70.5

The maximum number of barrels that the system can transport per day depends
upon the operating balance achieved at a given time between various segments on
the system. This balance is dependent upon the mix of petroleum products to be
shipped and the demand levels at the various delivery points. We believe that we
will be able to accommodate anticipated demand increases in the markets we serve
through expansions or modifications of the Williams Pipe Line system, if
necessary.

OPERATIONS

The Williams Pipe Line system is the fifth largest common carrier pipeline
of refined petroleum products and LPGs in the United States based on barrel
miles shipped. Through direct refinery connections, and interconnections with
other interstate pipelines, the system can access approximately 45% of the
refinery capacity in the United States. In general, the system does not produce
or trade refined petroleum products or LPGs and does not take title to the
petroleum products it transports.

The Williams Pipe Line system generates approximately 80% of its revenue,
excluding product sales revenue, through transportation tariffs for volumes it
ships. These tariffs vary depending upon where the product originates, where
ultimate delivery occurs and any applicable discounts. All interstate
transportation rates and discounts are in published tariffs filed with the FERC.
Such tariffs also include charges for terminalling and storage of products at
the Williams Pipe Line system's 39 terminals. Currently, the tariffs we charge
to shippers for transportation of products generally do not vary according to
the type of products transported. Published tariffs serve as contracts and
shippers nominate the volume to be shipped on a monthly basis. In addition, we
enter into supplemental agreements with shippers that commonly result in volume
commitments by shippers in exchange for capital expansion commitments. These
agreements have terms ranging from one to ten years. Nearly 60% of the shipments
in 2001 were subject to these supplemental agreements. While many of these
agreements do not represent guaranteed volumes, they do reflect a significant
level of shipper commitment to the Williams Pipe Line system.

The system also earns revenue from leasing pipeline and storage tank
capacity to shippers on a long-term basis and from providing product and other
services such as ethanol unloading and loading, additive injection, custom
blending, laboratory testing data services to shippers and from blending and
fractionation activities. Product services such as ethanol unloading and
loading, additive injection, custom blending and laboratory testing are
performed under a mix of "as needed," monthly and long-term agreements. Data
services provided to shippers are covered by a standard agreement and are
generally performed on an as needed basis.

Blending activities involve the generation of small volumes of gasoline by
blending natural gas liquids with gasoline already in the Williams Pipe Line
system to produce grades of gasoline that satisfy quality and regulatory
requirements for specific markets. We and Williams Energy Services agreed that
we will

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perform these blending activities for ten years at an annual fee of
approximately $3.0 million. Please read "Management Discussion and Analysis of
Financial Condition and Results of Operations."

Fractionation activities involve processing transmix, a mixture of products
resulting from the intermingling of different product grades during normal
operation of a pipeline. Some of the transmix processed comes from the Williams
Pipe Line system and some is purchased from other parties that do not have their
own fractionation capacity. The transmix is fractionated at a unit in Des
Moines, Iowa, and the recovered gasoline and fuel oil is sold to third parties.

FACILITIES

The Williams Pipe Line system consists of a 6,700-mile pipeline. The
pipeline system includes 25.8 million barrels of aggregate storage capacity at
39 terminals and at various pump stations. The terminals deliver refined
petroleum products primarily into tank trucks, although two terminals can load
into tank rail cars.

Pipe Line Map

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The following table contains information regarding the Williams Pipe Line
system's terminal facilities:

TOTAL SHELL NUMBER OF NUMBER OF
DELIVERY POINTS STORAGE CAPACITY TANKS LOADING RACKS
--------------- --------------------- --------- -------------
(IN THOUSAND BARRELS)

Arkansas
Ft. Smith........................................ 205 8 6
Illinois
Amboy............................................ 199 10 2
Chicago.......................................... 657 15 3
Heyworth......................................... 433 10 2
Menard County.................................... 236 6 2
Iowa
Des Moines....................................... 2,153 50 6
Dubuque.......................................... 101 6 2
Ft. Dodge........................................ 138 7 2
Iowa City........................................ 722 27 4
Mason City....................................... 655 18 3
Milford.......................................... 188 9 2
Sioux City....................................... 590 28 5
Waterloo......................................... 372 8 4
Kansas
Kansas City...................................... 1,783 34 8
Olathe........................................... 223 5 2
St. Joseph....................................... 58 2 2
Topeka........................................... 157 7 2
Wichita.......................................... 177 5 2
Minnesota
Alexandria....................................... 646 28 3
Mankato.......................................... 440 17 3
Marshall......................................... 208 10 2
Minneapolis...................................... 1,971 34 8
Rochester........................................ 146 8 2
Missouri
Carthage......................................... 132 8 2
Columbia......................................... 297 9 3
Palmyra.......................................... 185 7 2
Springfield...................................... 312 10 4
Nebraska
Capehart......................................... 112 3 2
Doniphan......................................... 533 15 3
Lincoln.......................................... 152 8 2
Omaha............................................ 1,034 27 4
North Dakota
Fargo............................................ 639 27 3
Grand Forks...................................... 358 21 3
Oklahoma
Enid............................................. 322 6 2
Oklahoma City.................................... 324 8 4
Tulsa............................................ 2,058 29 4
South Dakota
Sioux Falls...................................... 665 29 3
Watertown........................................ 223 12 2
Wisconsin
Wausau........................................... 166 7 2
Pump Stations...................................... 5,792 83 --
------ --- ---
Total.............................................. 25,762 661 122
====== === ===

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REFINED PETROLEUM PRODUCTS SUPPLY

Refined petroleum products originate from both refining and pipeline
interconnection points along the Williams Pipe Line system. In 2001, 57% of the
refined petroleum products transported on the Williams Pipe Line system
originated from direct refinery connections and 43% originated from
interconnections with other pipelines. As set forth in the table below, the
system is directly connected to, and receives product from, ten operating
refineries. The largest supply of originated product comes from a Pine Bend,
Minnesota refinery owned by Flint Hills Resources, a division of Koch
Industries, Inc.

MAJOR ORIGINS -- REFINERIES (LISTED ALPHABETICALLY)

COMPANY REFINERY LOCATION
------- -----------------

Conoco, Inc................................................. Ponca City, OK
Farmland Industries, Inc.................................... Coffeyville, KS
Flint Hills Resources (Koch)................................ Pine Bend, MN
Frontier Oil Corporation.................................... El Dorado, KS
Gary Williams Energy Corp................................... Wynnewood, OK
Marathon Ashland Petroleum Company.......................... St. Paul, MN
Murphy Oil USA, Inc......................................... Superior, WI
Sinclair Oil Corp........................................... Tulsa, OK
Sunoco, Inc................................................. Tulsa, OK
Valero Energy Corp.......................................... Ardmore, OK

The Williams Pipe Line system receives product from 13 other pipeline
systems. The most significant of these pipeline connections is to Explorer
Pipeline in Glenpool, Oklahoma, which transports product from the large refining
complexes located on the Texas and Louisiana Gulf Coast. Product from Explorer
can be transferred into the Williams Pipe Line system for delivery into the
mid-continent and northern-tier states. Another significant connection is to the
Phillips Pipeline at Kansas City, Kansas, which transports product from the
Phillips refinery in Borger, Texas and the U.S. Gulf Coast via the Seaway
Products Pipeline. The Williams Pipe Line system is also connected to all
Chicago area refineries through the West Shore Pipe Line.

MAJOR ORIGINS -- PIPELINE CONNECTIONS (LISTED ALPHABETICALLY)

PIPELINE CONNECTION LOCATION SOURCE OF PRODUCT
-------- ------------------- -----------------

BP............................... Manhattan, IL Whiting, IN refinery
Buckeye.......................... Mazon, IL East Chicago, IL storage
Cenex............................ Fargo, ND Laurel, MT refinery
CITGO Pipeline................... Drumright, OK Various Gulf Coast refineries
Explorer Pipeline................ Glenpool, OK; Mt. Vernon, MO Various Gulf Coast refineries
Kaneb Pipeline................... El Dorado, KS Various OK & KS refineries
Kinder Morgan.................... Plattsburg, MO; Des Moines, IA; Bushton, KS storage and Chicago
Wayne, IL area refineries
Mid-America Pipeline El Dorado, KS Conway, KS storage
(Williams).....................
Orion Pipeline (Equilon)......... Duncan, OK Various Gulf Coast refineries
Phillips Pipeline................ Kansas City, KS Various Gulf Coast refineries (via
Seaway/Standish Pipeline); Borger,
TX refinery
Tesoro........................... Minneapolis, MN Mandan, ND refinery
Total (Valero)................... Wynnewood, OK Ardmore, OK refinery
West Shore Pipe Line............. East Chicago, IL Various Chicago, IL area refineries

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CUSTOMERS AND CONTRACTS

We ship refined petroleum products for several different types of
customers, including independent and integrated oil companies, wholesalers,
retailers, railroads, airlines and regional farm cooperatives. End markets for
these deliveries are primarily retail gasoline stations, truck stops, farm
cooperatives, railroad fueling depots and military and commercial jet fuel
users. Propane shippers include wholesalers and retailers who, in turn, sell to
commercial, industrial, agricultural and residential heating customers, as well
as utilities who use propane as a fuel source.

For the year ended December 31, 2001, the pipeline system had approximately
50 customers. The principal shippers include six independent refining companies,
three integrated oil companies and one large farm cooperative. Transportation
revenues attributable to these top 10 shippers were $170.0 million, or 47% of
the Williams Pipe Line system's total revenues (54% on a pro forma basis), for
the year ended December 31, 2001.

In 2001, Williams Energy Marketing & Trading accounted for $69.6 million or
approximately 19% of the Williams Pipe Line system's total revenues. Of these
revenues approximately 92% were generated from products sales related to
blending, fractionation and over and short settlement activities. As described
above under "-- Operations," we will perform blending services for an annual fee
of approximately $3.0 million in the future, and as a result, we will not
purchase and sell products related to blending activities.

COMPETITION

Pipelines are generally the lowest-cost alternative for refined product
movements between different markets. As a result, the Williams Pipe Line
system's most significant competitors are other pipelines that serve the same
markets. We believe that the pipeline system is competitive with other pipelines
as evidenced by the growth in shipments over the last three years. Three key
pipeline competitors include the Kaneb pipeline systems in the western markets,
the BP pipeline system in the northern markets and the Conoco pipeline system in
the southern markets.

Kaneb's East Pipeline, which runs from southern Kansas to North Dakota,
operates approximately 100 miles west of and parallel to the Williams Pipe Line
system. Kaneb's East Pipeline receives product from both Gulf Coast and
mid-continent refiners through connections to pipelines such as the Conoco
pipeline and through direct refinery connections including a direct connection
to the Frontier refinery in El Dorado, Kansas, to which the Williams Pipe Line
system is also connected.

The portion of the BP pipeline system with which the Williams Pipe Line
system competes is a non-common carrier pipeline system that is supplied by BP's
refinery in Whiting, Indiana. This system extends south to Kansas City, Missouri
and west through Iowa and Minnesota. If BP were to convert its pipeline system
to a common carrier system, it could result in additional competition. The
Conoco pipeline system and its joint venture, Heartland Pipeline Company, are
common carrier systems that run through Oklahoma, north into Iowa and east
through Missouri to Wood River, Illinois. Conoco's pipeline receives its product
supply from mid-continent and Gulf Coast refiners, some of which also supply the
Williams Pipe Line system.

Competition with each of these pipeline systems is based primarily on
transportation charges, quality of customer service, proximity to end-users and
longstanding customer relationships. However, given the different supply sources
on each pipeline, pricing at either the origin or terminal point on a pipeline
may outweigh transportation costs.

Shippers on the Williams Pipe Line system can reduce their transportation
costs by entering into exchange agreements with other shippers. Under these
arrangements, a shipper will agree to supply a market near its refinery in
exchange for receiving supply from another refinery in a more distant market.
These agreements allow the two parties to reduce the average transportation rate
paid to us. We have been able to compete with these alternatives through price
incentives and through long-term commercial arrangements with potential exchange
partners. Nevertheless, a significant amount of exchange activity has occurred
historically and is likely to continue.

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TARIFF REGULATION

Interstate Regulation. The Williams Pipe Line system's interstate common
carrier pipeline operations are subject to rate regulation by the Federal Energy
Regulatory Commission, or FERC, under the Interstate Commerce Act, the Energy
Policy Act of 1992 and rules and orders promulgated pursuant thereto. FERC
regulation requires that interstate oil pipeline rates be posted publicly and
that these rates be "just and reasonable" and nondiscriminatory. Rates of
interstate oil pipeline companies, like those charged by the Williams Pipe Line
system, are currently regulated by FERC primarily through an index methodology,
whereby a pipeline is allowed to change its rates based on the annual change in
the producer price index, or PPI, for finished goods less 1%. Under the indexing
regulations, a pipeline can request a rate increase that exceeds index levels
for indexed rates using a cost-of-service approach, but only after the pipeline
establishes that a substantial divergence exists between the actual costs
experienced by the pipeline and the rate resulting from application of the PPI.
Approximately one-third of the Williams Pipe Line system is subject to this
indexing methodology. In addition to rate indexing and cost-of-service filings,
interstate oil pipeline companies may elect to support rate filings by obtaining
authority to charge market based rates or through an agreement between a shipper
and the oil pipeline company that a rate is acceptable. Two-thirds of the
Williams Pipe Line system's markets are deemed competitive by the FERC, and we
are allowed to charge market-based rates in these markets.

In a June 1996 decision, the FERC disallowed the inclusion of a full income
tax allowance in the cost-of-service tariff filing of Lakehead Pipe Line
Company, L.P., an unrelated oil pipeline limited partnership. The FERC held that
Lakehead was entitled to include an income tax allowance in its cost-of-service
for income attributable to corporate partners but not on income attributable to
individual partners. In 1997, Lakehead reached an agreement with its shippers on
all contested rates, so there was no judicial review of the FERC's decision. In
January 1999, in a FERC proceeding involving SFPP, L.P., another unrelated oil
pipeline limited partnership, the FERC followed its decision in Lakehead and
held that SFPP may not claim an income tax allowance with respect to income
attributable to non-corporate limited partners. Several parties sought rehearing
of the FERC's decision in SFPP and of several FERC orders issued on rehearing in
the SFPP case. Several parties have also filed appeals of the FERC's orders,
which are currently being held in abeyance by the court of appeals pending
resolution by the FERC of the remaining requests for rehearing. The FERC's
decision in the Lakehead and SFPP proceedings should have no effect on the
market-based rates Williams Pipe Line charges in its competitive markets.
However, the Lakehead and SFPP decisions might become relevant to the pipeline
system should it (1) elect in the future to raise its indexed rates using the
cost-of-service methodology, (2) be required to use a cost-of-service
methodology to defend its indexed rates against a shipper protest alleging that
an indexed rate increase substantially exceeds actual cost increases, or (3) be
required to defend its indexed rates against a shipper complaint alleging that
the pipeline's rates are not just and reasonable. In such case, a complainant or
protestant could assert that, in light of the decisions regarding Lakehead and
SFPP and our ownership of the Williams Pipe Line system, we should be allowed to
collect an income tax allowance only with respect to the portion of our
partnership units held by corporations. We believe that most if not all of the
indexed rates can be supported on a cost-of-service basis, even assuming a
reduction in the income tax allowance. Nevertheless, if the indexed rates were
challenged, we cannot assure you that some or all of the indexed rates may not
be reduced. If indexed rates were reduced, the amount of available cash could be
materially reduced.

Intrastate Regulation. Some shipments the Williams Pipe Line system makes
move within a single state and thus are considered to be in intrastate commerce.
The Williams Pipe Line system is subject to certain regulation with respect to
such intrastate transportation by state regulatory authorities in the states of
Illinois, Kansas and Oklahoma. However, in most instances, the state commissions
have not initiated investigations of the rates or practices of refined products
pipelines.

TITLE TO PROPERTIES

Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of the property, and in some instances, these
rights-of-way are revocable at the election of the
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grantor. Several rights-of-way for our pipelines and other real property assets
are shared with other pipelines and other assets owned by affiliates of The
Williams Companies and by third parties. In many instances, lands over which
rights-of-way have been obtained are subject to prior liens which have not been
subordinated to the right-of-way grants. We have obtained permits from public
authorities to cross over or under, or to lay facilities in or along, water
courses, county roads, municipal streets and state highways, and in some
instances, these permits are revocable at the election of the grantor. We have
also obtained permits from railroad companies to cross over or under lands or
rights-of-way, many of which are also revocable at the grantor's election. In
some cases, property for pipeline purposes was purchased in fee. In some states
and under some circumstances, we have the right of eminent domain to acquire
rights-of-way and lands necessary for our pipelines. The previous owners of the
applicable pipelines may not have commenced or concluded eminent domain
proceedings for some rights-of-way.

Some of the leases, easements, rights-of-way, permits and licenses that
have been transferred to us will require the consent of the grantor to transfer
these rights, which in some instances is a governmental entity. Our general
partner believes that it has obtained or will obtain sufficient third-party
consents, permits and authorizations for the transfer of the assets necessary
for us to operate our business in all material respects as described in this
prospectus supplement. With respect to any consents, permits or authorizations
that have not been obtained, our general partner believes that these consents,
permits, or authorizations will be obtained after the closing of this offering,
or that the failure to obtain these consents, permits, or authorizations will
have no material adverse effect on the operation of our business.

Our general partner believes that we have satisfactory title to all of our
assets or are entitled to indemnification from affiliates of The Williams
Companies (1) for title defects to the ammonia pipeline that arise within 15
years after the closing of our initial public offering and (2) for title defects
related to the Williams Pipe Line system that arise within ten years from its
acquisition. Record title to some of our assets may continue to be held by
affiliates of The Williams Companies until we have made the appropriate filings
in the jurisdictions in which such assets are located and obtained consents and
approvals that have not been obtained prior to transfer. We intend to make these
filings and obtain these consents. Although title to these properties is subject
to encumbrances in some cases, such as customary interests generally retained in
connection with acquisition of real property, liens that can be imposed in some
jurisdictions for government-initiated action to clean up environmental
contamination, liens for current taxes and other burdens, and easements,
restrictions and other encumbrances to which the underlying properties were
subject at the time of acquisition by us or our predecessor, our general partner
believes that none of these burdens should materially detract from the value of
our properties or from our interest in them or should materially interfere with
their use in the operation of our business.

EMPLOYEES

To carry out our operations, our general partner or its affiliates employ
approximately 800 employees, of which 600 conduct the operations of the Williams
Pipe Line system. Of these 600 employees, approximately 230 are represented by
the Paper, Allied-Industrial, Chemical and Energy Workers International Union,
or PACE. The employees represented by PACE are subject to a contract that
extends to January 2006. We consider our employee relations to be good.

PETROLEUM PRODUCTS TERMINALS

MARINE TERMINAL FACILITIES

The Gulf Coast region is a major hub for petroleum refining, representing
approximately 42% of total U.S. daily refining capacity in 2000 and 67% of U.S.
refining capacity expansion from 1990 to 2000. The growth in Gulf Coast refining
capacity has resulted in part from consolidation in the petroleum industry to
take advantage of economies of scale from operating larger, concentrated
refineries. We expect this trend to continue in order to meet growing domestic
and international demand. From 1990 to 2000, the amount of petroleum products
exported from the Gulf Coast region increased by approximately 18%, or 195
million barrels. The growth in refining capacity and increased product flow
attributable to the Gulf

S-49

Coast region has created a need for additional transportation, storage and
distribution facilities. In the future, the larger competitors resulting from
the consolidation trend, combined with continued environmental pressures,
governmental regulations and market conditions, could result in the closing of
smaller, less economical inland refiners, creating even greater demand for
petroleum products refined in the Gulf Coast region.

We own and operate five marine terminal facilities, including four marine
terminal facilities located along the Gulf Coast and one terminal facility
located in Connecticut near the New York harbor. Our marine terminals are large
storage and distribution facilities that provide inventory management, storage
and distribution services for refiners and other large end-users of petroleum
products. Our marine terminal facilities have an aggregate storage capacity of
approximately 17.6 million barrels.

Our marine terminal facilities receive petroleum products by ship and
barge, short-haul pipeline connections to neighboring refineries and common
carrier pipelines. We distribute petroleum products from our marine terminals by
all of those means as well as by truck and rail. Once the product has reached
its terminal facilities, we store the product for a period of time ranging from
a few days to several months. Products that we store in our marine terminal
facilities include refined petroleum products, blendstocks and heavy oils and
feedstocks.

In addition to providing storage and distribution services, our marine
terminal facilities provide ancillary services including heating, blending and
mixing of stored products and injection services. Many heavy oils require
heating to keep them in a liquid state. In addition, in order to meet government
specifications, products often must be combined with other products through the
blending and mixing process. Blending is the combination of products from
different storage tanks. Once the products are blended together, the mixing
process circulates the blended product through mixing lines and nozzles to
further combine the products. Finally, injection is the process of injecting
refined petroleum products with additives and dyes to comply with governmental
regulations.

Our marine terminal facilities generate fees primarily through providing
long-term or spot "on demand" storage services and inventory management for a
variety of customers. Refiners and chemical companies will typically use our
facilities because their own facilities are inadequate, either because of size
constraints or the specialized handling requirements of the stored products. We
also provide storage services and inventory management to various industrial
end-users, marketers and traders that require access to large storage capacity.

The following table outlines our marine terminal facility locations,
capacities, primary products handled and the connections to and from these
terminal facilities:

RATED STORAGE PRIMARY PRODUCTS
FACILITY CAPACITY HANDLED CONNECTIONS
-------- ------------- ---------------- -----------
(IN THOUSAND
BARRELS)

Galena Park, Texas..... 8,884 Refined petroleum products, Pipeline, barge, ship,
blendstocks, heavy oils and rail and truck
feedstocks
Corpus Christi, Blendstocks, heavy oils and Pipeline, barge, ship
Texas................ 2,711 feedstocks and truck
Marrero, Louisiana..... 2,006 Heavy oils and feedstocks Barge, ship, rail and
truck
New Haven, Refined petroleum products, Pipeline, barge, ship
Connecticut.......... 3,986 heavy oils and feedstocks and truck
Gibson, Louisiana...... 56 Crude oil and condensate Pipeline, barge and
truck
------
Total storage
capacity........ 17,643
======

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Customers and Contracts. We have long-standing relationships with oil
refiners, suppliers and traders at our facilities, and most of our customers
have consistently renewed their short-term contracts. During 2001, approximately
89% of our marine terminal working storage capacity was under contract. As of
December 31, 2001, approximately 44% of the revenues that we generated were from
contracts with remaining terms in excess of one year or that renew on an annual
basis. Williams Energy Marketing & Trading Company represented approximately 17%
of revenues at our marine terminal facilities for the year ended December 31,
2001.

Markets and Competition. We believe that the strong demand for our marine
terminal facilities from our refining and chemical customers results from our
cost-effective distribution services and key transportation links such as
deep-water ports. We experience the greatest demand at our marine terminal
facilities in a contango market, when customers tend to store more product to
take advantage of favorable pricing expected in the future. When the opposite
market condition, known as backwardation, exists, some companies choose not to
store product. The additional heating and blending services that we provide at
our marine terminal facilities, however, attract additional demand for our
storage services and result in increased revenue opportunities.

Several major and integrated oil companies have their own proprietary
storage terminals along the Gulf Coast that are currently being used in their
refining operations. If these companies choose to shut down their refining
operations and elect to store and distribute refined petroleum products through
their proprietary terminals, we would experience increased competition for the
services that we provide. In addition, several companies have facilities in the
Gulf Coast region and offer competing storage and distribution services.

INLAND TERMINALS

We own and operate a network of 25 refined petroleum products terminals
located primarily in the southeastern United States with an aggregate storage
capacity of 5.0 million barrels. Our customers utilize these facilities to take
delivery of refined petroleum products transported on major common-carrier
interstate pipelines. The majority of our inland terminals connect to the
Colonial, Plantation, TEPPCO or Explorer pipelines, and some facilities have
multiple pipeline connections. In addition, the Dallas terminal connects to
Dallas Love Field airport via a 6-inch pipeline purchased in April 2001. During
2001, gasoline represented approximately 53% of the volume of product
distributed through our inland terminals, with the remaining 47% consisting of
distillates such as low sulfur diesel and jet fuel.

Our inland terminals typically consist of multiple storage tanks that are
connected by a third-party intra-facility pipeline system. We load and unload
products through an automated system that allows products to move directly from
the common carrier pipeline to our storage tanks and directly from our storage
tanks to a truck or rail car loading rack.

We are an independent provider of storage and distribution services.
Because we do not own the products moving through our terminals, we are not
exposed to the risks of product ownership. We operate our inland terminals as
distribution terminals, and we primarily serve the retail, industrial and
commercial sales markets. We provide the following services at our inland
terminals:

- inventory and supply management through our virtual supply network and
the ATLAS 2000 software system;

- distribution; and

- other services such as injection of gasoline additives.

We generate revenues by charging our customers a fee based on the amount of
product that we deliver through our terminals. We charge these fees when we
deliver the product to our customers and load it into a truck or rail car. In
addition to throughput fees, we generate revenues by charging our customers a
fee for injecting additives into gasoline, diesel and jet fuel, and for
filtering jet fuel.

S-51

We wholly own 14 of these inland terminals and our percentage ownership of
the remaining 11 inland terminals ranges between 50% and 79%. The following
table sets forth our inland terminal locations, percentage ownership, capacities
and methods of supply:

PERCENTAGE TOTAL STORAGE
FACILITY OWNERSHIP CAPACITY CONNECTIONS
-------- ---------- ------------- -----------
(IN THOUSAND
BARRELS)

Alabama
Mobile................... 100% 135 Barge
Montgomery............... 100 104 Plantation Pipeline
Arkansas
North Little Rock........ 100 273 TEPPCO Pipeline
South Little Rock........ 100 179 TEPPCO Pipeline
Florida
Jacksonville............. 100 252 Barge and ship
Georgia
Doraville................ 100 295 Colonial and Plantation Pipelines
South Albany............. 79 124 Colonial Pipeline
Missouri
St. Charles.............. 100 118 Explorer Pipeline
North Carolina
Charlotte................ 100 334 Colonial Pipeline
Charlotte................ 79 158 Colonial Pipeline
Greensboro............... 60 248 Colonial Pipeline
Greensboro............... 79 239 Colonial and Plantation Pipelines
Selma.................... 79 305 Colonial Pipeline
South Carolina
North Augusta............ 79 156 Colonial Pipeline
North Augusta............ 100 123 Colonial Pipeline
Spartanburg.............. 100 116 Colonial Pipeline
Tennessee
Chattanooga.............. 100 105 Colonial Pipeline
Knoxville................ 100 115 Colonial and Plantation Pipelines
Nashville................ 50 252 Colonial Pipeline and barge
Nashville................ 100 164 Colonial Pipeline
Nashville................ 79 148 Colonial Pipeline
Texas
Dallas................... 100 400 Explorer and Magtex Pipelines; pipeline
to Dallas Love Field
Southlake................ 50 277 Explorer, Koch and Valero Pipelines
Virginia
Montvale................. 79 171 Colonial Pipeline
Richmond................. 79 169 Colonial Pipeline
-----
Total............ 4,960
=====

Customers and Contracts. All but four of our inland terminals were
acquired by The Williams Companies over a period of five years, beginning with
the acquisition of interests in eight terminals in

S-52

1996. When The Williams Companies acquired the new terminals, it generally
entered into long-term throughput contracts with the sellers under which they
agreed to continue to use the facilities. These agreements typically last for
two to ten years from the beginning of the agreement and must be renegotiated at
the end of the term. In addition to these agreements, we entered into separate
contracts with new customers that typically last for one year with a continuing
one year renewal provision. Most of these contracts contain a minimum throughput
provision that obligates the customer to move a minimum amount of product
through our terminals or pay for terminal capacity reserved but not used. Our
customers include:

- retailers that sell gasoline and other petroleum products through
proprietary retail networks;

- wholesalers that sell petroleum products to retailers as well as to large
commercial and industrial end-users;

- exchange transaction customers, where we act as an intermediary so that
the parties to the transaction are able to exchange petroleum products;
and

- traders that arbitrage, trade and market products stored in our
terminals.

For the year ended December 31, 2001, Williams Refining & Marketing
accounted for approximately 38% of our inland terminal revenues.

Markets and Competition. We compete with other independent terminal
operators, as well as integrated oil companies, on the basis of terminal
location and versatility, services provided and price. Our competition from
independent operators primarily comes from distribution companies with marketing
and trading arms, independent terminal operators and refining and marketing
companies.

AMMONIA PIPELINE SYSTEM

INDUSTRY OVERVIEW

We own and operate an 1,100-mile pipeline system that transports ammonia
from production facilities in Texas and Oklahoma to terminals throughout the
Midwest for ultimate distribution to end-users in Iowa, Kansas, Minnesota,
Missouri, Nebraska, Oklahoma and South Dakota. Ammonia is produced by reacting
natural gas with air at high temperatures and pressures in the presence of
catalysts. Because natural gas is the primary feedstock for the production of
ammonia, ammonia is typically produced near abundant sources of natural gas.
Ammonia is primarily used as a nitrogen fertilizer. Nitrogen is an essential
nutrient for plant growth and is the single most important element for
maintenance of high crop yields for all grains. Unlike other primary nutrients,
however, nitrogen must be applied each year because virtually all of its
nutritional value is consumed during the growing season. Ammonia is the most
cost-effective source of nitrogen and the simplest nitrogen fertilizer. It is
also the primary feedstock for the production of upgraded nitrogen fertilizers
and chemicals.

Although ammonia consumption peaks in the fall and early spring, ammonia
production is reasonably consistent throughout the year. Generally, storage
facilities reach their peak storage capacities during early spring, prior to
agricultural application. As a result, we experience only limited seasonal
fluctuations for transportation services on the ammonia pipeline system. Our
customers inject the ammonia they produce into the ammonia pipeline system, and
we transport it as a liquid to terminal facilities and storage and upgrade
facilities located in the Midwest.

OPERATIONS

The ammonia pipeline system is a common carrier ammonia transportation
pipeline. We do not produce or trade ammonia, and we do not take title to the
ammonia it transports. Rather, we earn revenue from the following sources:

- transportation tariffs for the use of our pipeline capacity; and

- throughput fees at our six company-owned terminals.
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We generate approximately 94% of our ammonia pipeline system revenue
through transportation tariffs. These tariffs are "postage stamp" tariffs, which
means that each shipper pays a defined rate per ton of ammonia shipped
regardless of the distance that ton of ammonia travels on the ammonia pipeline
system. In addition to transportation tariffs, we also earn revenue by charging
our customers for services at the six terminals we own along the ammonia
pipeline system, including unloading ammonia from our customers' trucks to
inject the ammonia into the pipeline for shipment and removing ammonia from our
pipeline to load the ammonia into our customers' trucks.

FACILITIES

The ammonia pipeline system was the world's first common carrier pipeline
for ammonia. The main trunk line was completed in 1968. Today, it represents one
of two ammonia pipelines operating in the United States and has a maximum annual
delivery capacity of approximately 900,000 tons. Our ammonia pipeline system
originates at production facilities in Borger, Texas, Verdigris, Oklahoma and
Enid, Oklahoma and terminates in Mankato, Minnesota.

[MAP]

S-54

We transport ammonia to 13 delivery points along our pipeline system. The
facilities at these points provide our customers with the ability to deliver
ammonia to distributors who sell the ammonia to farmers and to store ammonia for
future use. These facilities also provide our customers with the ability to
remove ammonia from our pipeline for distribution to upgrade facilities that
produce nitrogen compounds such as urea, ammonium nitrate, ammonium phosphate
and ammonium sulfate.

The following table contains information regarding the delivery facilities
on our ammonia pipeline system:

DELIVERY POINTS FACILITY OPERATIONS OWNER
--------------- ------------------- -----

Iowa
Early.............. Terminal and storage Agrium
Garner............. Terminal and storage Agrium
Terminal and storage Farmland
Terminal and storage Terra(a)
Port Neal.......... Terminal, storage, upgrade and production Terra
Sgt. Bluff......... Terminal and storage Farmland
Whiting............ Terminal and storage Williams Energy Partners

Kansas
Clay Center........ Terminal and storage Williams Energy Partners
Conway............. Terminal and storage Farmland
Terminal and storage Williams Energy Partners
Minnesota
Mankato............ Storage Farmland
Terminal and storage Williams Energy Partners
Nebraska
Beatrice........... Terminal, storage and upgrade Agrium
Terminal, storage and upgrade Farmland
Blair.............. Terminal and storage Terra
Greenwood.......... Storage Farmland
Terminal and storage Williams Energy Partners
Oklahoma
Mocane............. Terminal and storage Williams Energy Partners

Texas
Farnsworth......... Terminal and storage Farmland

---------------

(a) Facility owned by CF Industries, Inc. but utilized by Terra.

Customers and Contracts. We ship ammonia for three customers:

- Farmland Industries, Inc., one of the largest farmer-owned cooperatives
in the United States;

- Agrium U.S. Inc., a subsidiary of Agrium Inc., the largest producer of
nitrogen fertilizers in North America; and

- Terra Nitrogen, L.P., a wholesaler of nitrogen fertilizer products.

Each of these companies has an ammonia production facility connected to our
pipeline as well as related storage and distribution facilities along the
pipeline. The transportation contracts with our customers extend through June
2005. Our customers are obligated to ship an aggregate minimum of

S-55

700,000 tons per year and have historically shipped an amount in excess of the
required minimum. Our customers have been shipping ammonia through our pipeline
for an average of more than 20 years.

Each transportation contract contains a ship-or-pay mechanism, whereby each
customer must ship a specific minimum tonnage per year and an aggregate minimum
tonnage amount over the life of the contract. On July 1 of each contract year,
each of our customers nominates a tonnage that it expects to ship during the
upcoming year. This annual commitment may be equal to or greater than the
contractual minimum tonnage.

Currently the annual commitments of our customers represent 78% of our
pipeline's 900,000 ton per year capacity. If a customer fails to ship its annual
commitment, that customer must pay for the pipeline capacity it did not use.

In general, our customers have historically shipped ammonia in excess of
their annual commitments. We allow our customers to bank any ammonia shipped in
excess of their annual commitments. If a customer has previously shipped an
amount in excess of its annual commitment, the shipper may offset subsequent
annual shipment shortfalls against the excess tonnage in its bank. There are
approximately 115,000 tons in this combined bank that may be used to offset
future ship or pay obligations.

The transportation contracts establish a fixed tariff schedule per ton of
ammonia shipped for each customer for the first five years of the contract
period. Because of the long-term nature of these contracts, the shippers receive
a volume incentive tariff per ton that decreases with increased commitments.
Since July 1, 2000, we have had the right to adjust our tariff schedule on an
annual basis pursuant to a formula contained in the contracts. The adjustment
formula takes into consideration the cost of labor, power, property taxes and
changes in the producer price index. We use the combined increase or decrease in
these factors to calculate any increases or decreases in tariffs. Any annual
adjustment is limited to a maximum increase or decrease of five percent measured
against the rate previously in effect. These tariff adjustments cannot decrease
the tariffs to rates less than those charged in 1997. Two of our three customers
have credit ratings below investment grade.

Markets and Competition. Demand for nitrogen fertilizer has typically
followed a combination of weather patterns and growth in population, acres
planted and fertilizer application rates. Because natural gas is the primary
feedstock for the production of ammonia, the profitability of our customers is
impacted by high natural gas prices. To the extent our customers are unable to
pass on higher costs to their customers, they may reduce shipments through our
ammonia pipeline.

We compete primarily with ammonia shipped by rail carriers, but believe we
have a distinct advantage over rail carriers because ammonia is a gas under
normal atmospheric conditions and must be either placed under pressure or cooled
to negative 33 degrees Celsius to be shipped or stored. Because the
transportation and storage of ammonia requires specialized handling, we believe
that pipeline transportation is the safest and most cost-effective method for
transporting bulk quantities of ammonia.

We also compete to a limited extent in the areas served by the far northern
segment of our ammonia pipeline system with the other United States ammonia
pipeline, which originates on the Gulf Coast and transports domestically
produced and imported ammonia.

TARIFF REGULATION

Interstate Regulation. The Surface Transportation Board, or Board, a part
of the United States Department of Transportation, has jurisdiction over
interstate pipeline transportation of ammonia, including the rates charged for
such transportation. These transportation rates must be reasonable, and a
pipeline carrier may not unreasonably discriminate among its shippers. The Board
will evaluate a pipeline's rates only if it determines that the pipeline's
shippers lack effective competitive alternatives. In determining whether rates
are reasonable, the Board considers, among other factors, the effect of the
rates on the volumes transported by that carrier and the carrier's revenue
needs. If the Board finds that a carrier's rates are unreasonable, it will
prescribe reasonable rates. With regard to discrimination, the Board has held
that unreasonable discrimination occurs when (1) there is a disparity in rates,
(2) the complaining party is
S-56

competitively injured, (3) the carrier is the common source of both the
allegedly prejudicial and preferential treatment and (4) the disparity in rates
is not justified by transportation conditions.

Intrastate Regulation. Because in some instances our ammonia pipeline
transports ammonia between two terminals in the same state, the pipeline's
operations are subject to regulation by the state regulatory authorities in
Iowa, Nebraska, Oklahoma and Texas. Although the Oklahoma Corporation Commission
and the Texas Railroad Commission have the authority to regulate our rates, the
state commissions have generally not investigated the rates or practices of
ammonia pipelines in the absence of shipper complaints.

PIPELINE MAINTENANCE AND SAFETY REGULATION

The Williams Pipe Line system and the ammonia pipeline system have been
constructed, operated, maintained, repaired, tested and used in general
compliance with applicable federal, state and local laws and regulations,
American Petroleum Institute standards and other generally accepted industry
standards and practices. The Williams Companies has performed regular
maintenance on all the facilities of both pipeline systems and has an ongoing
process of inspecting segments of the pipeline systems and making repairs and
replacements when necessary or appropriate. In addition, The Williams Companies
has conducted periodic air patrols of the pipeline systems to monitor pipeline
integrity and third-party right of way encroachments. The Williams Companies
will continue these inspection and maintenance and repair activities on our
behalf.

The Williams Pipe Line system and the ammonia pipeline system are subject
to regulation by the United States Department of Transportation under the
Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, and comparable state
statutes relating to the design, installation, testing, construction, operation,
replacement and management of its pipeline facilities. HLPSA covers petroleum
and petroleum products and requires any entity that owns or operates pipeline
facilities to comply with such regulations, to permit access to and copying of
records and to make certain reports and provide information as required by the
Secretary of Transportation.

In December 2000, the Department of Transportation adopted new regulations
requiring operators of interstate pipelines to develop and follow an integrity
management program that provides for continual assessment of the integrity of
all pipeline segments that could affect designated "high consequence areas,"
including high population areas, drinking water and ecological resource areas
that are unusually sensitive to environmental damage from a pipeline release,
and commercially navigable waterways. Segments of our pipeline systems are
located in high consequence areas. In response to this new rule, we utilize a
management system known as the "System Integrity Plan," which is designed to
control environmental, health, safety and property risk within its pipelines.
Under this new rule, we are required to evaluate pipeline conditions by means of
periodic internal inspection, pressure testing or other equally effective
assessment means and to correct identified anomalies. If, as a result of our
evaluation process, we determine that there is a need to provide further
protection to high consequence areas, then we will be required to implement
additional prevention and mitigation risk control measures for our pipelines,
including enhanced damage prevention programs, corrosion control program
improvements, leak detection system enhancements, installation of Emergency Flow
Restricting Devices and emergency preparedness improvements. Under this new
rule, we will also be required to evaluate and, as necessary, improve our
management and analysis processes for integrating available integrity-related
data relating to our pipeline segments and to remediate potential problems found
as a result of the required assessment and evaluation process. Based on
currently available information, the costs to implement this program are
estimated to be approximately $34.5 million between the years of 2002 and 2006.

We believe we are in material compliance with HLPSA requirements.
Nevertheless, legislation that would increase the stringency of federal pipeline
safety requirements is currently pending before the U.S. Congress. Significant
expenses could be incurred in the future if additional safety measures are
required or if existing safety standards are raised and exceed the current
pipeline capabilities.

The Williams Pipe Line system and the ammonia pipeline system are also
subject to the requirements of the federal Occupational Safety and Health Act,
or OSHA, and comparable state statutes. We believe
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we are in material compliance with OSHA and state requirements, including
general industry standards, record-keeping requirements and monitoring of
occupational exposures. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes require us to
organize and disclose information about the hazardous materials used in our
operations. Certain parts of this information must be reported to employees,
state and local governmental authorities and local citizens upon request. In
general, we expect to increase our expenditures during the next decade to comply
with higher industry and regulatory safety standards such as those described
above. We are subject to OSHA Process Safety Management, or PSM, regulations
that are designed to prevent or minimize the consequences of catastrophic
releases of toxic, reactive, flammable or explosive chemicals. These regulations
apply to any process that involves a chemical at or above the specified
thresholds or any process that involves a flammable liquid or gas, as defined in
the regulations, stored on site in one location in a quantity of 10,000 pounds
or more. We utilize certain covered processes and maintain storage of LPGs in
pressurized tanks, caverns and wells in excess of 10,000 pounds at various
locations. Flammable liquids stored in atmospheric tanks below their normal
boiling point without benefit of chilling or refrigeration are exempt. We
believe we are in material compliance with the PSM regulations.

ENVIRONMENTAL

GENERAL

Our operation of our pipeline systems, terminals and associated facilities
in connection with the transportation, storage and distribution of refined
petroleum products, crude oil and other liquid hydrocarbons are subject to
stringent and complex laws and regulations governing the discharge of materials
into the environment or otherwise related to environmental protection. As an
owner or lessee and operator of these facilities, we must comply with these laws
and regulations at the federal, state and local levels. Compliance with existing
and anticipated laws and regulations increases the cost of planning,
constructing and operating pipelines, terminals and other facilities. Included
in our construction and operation costs are capital cost items necessary to
maintain or upgrade our equipment and facilities. Failure to comply with these
laws and regulations may result in the assessment of administrative, civil and
criminal penalties, imposition of remedial actions and the issuance of
injunctions or construction bans or delays on ongoing operations. We believe
that our operations are in material compliance with applicable environmental
laws and regulations. However, these laws and regulations are subject to
frequent change, and we cannot assure you that the cost to comply with these
laws and regulations in the future will not have a material adverse effect on
our financial position or results of operations.

INDEMNIFICATION

As described below, we will be indemnified for environmental liabilities by
Williams Energy Services, Williams Natural Gas Liquids and by the entities from
which The Williams Companies originally acquired some of the assets owned by us.
Williams Energy Services and Williams Natural Gas Liquids are major operating
subsidiaries of The Williams Companies with combined 2001 revenues in excess of
$4.0 billion. We will also be a beneficiary of environmental insurance relating
to our marine terminal facilities. The terms and limitations of these
indemnification agreements and insurance policies are summarized below.

For assets transferred to us from The Williams Companies at the time of our
initial public offering, Williams Energy Services agreed to indemnify us for up
to $15.0 million for environmental liabilities that exceed the amounts covered
by the seller indemnities and insurance coverage described below. The indemnity
applies to environmental liabilities arising from conduct prior to the closing
of the initial public offering and discovered within three years of closing the
initial public offering. Liabilities resulting from a change in law after the
closing of our initial public offering are excluded from this indemnity.

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In accordance with our acquisition agreement with Amerada Hess, Amerada
Hess will indemnify us for environmental and other liabilities related to the
three Gulf Coast marine terminal facilities acquired in August 1999, including:

- Indemnification for special cleanup actions of pre-acquisition releases
of hazardous substances. This indemnity is capped at a maximum of $15.0
million. Amerada Hess, however, has no liability until the aggregate
amount of initial losses is in excess of a $2.5 million deductible, and
then Amerada Hess is liable only for the succeeding $12.5 million in
losses. This indemnity will remain in effect until July 30, 2004.

- Indemnification for already known and required cleanup actions at the
Corpus Christi, Texas and Galena Park, Texas terminal facilities. This
indemnity has no limit and will remain in effect until July 30, 2014.

- Indemnification for a variety of pre-acquisition fines and claims that
may be imposed or asserted under the Superfund Law and RCRA or analogous
state laws. This indemnity is not subject to any limit or deductible
amount.

In addition to these indemnities, Amerada Hess retained liability for the
performance of corrective actions associated with hydrocarbon recovery from
ground water and a cooling tower at the Corpus Christi, Texas terminal and
process safety management compliance matter at the Galena Park, Texas terminal
facility.

We have insurance against the first $2.5 million of environmental
liabilities related to the Amerada Hess terminal facilities that arose prior to
closing of the acquisition from Amerada Hess, with a deductible of $0.3 million,
and any environmental liabilities in excess of $15.0 million up to an aggregate
of $50.0 million.

In connection with the acquisition of the New Haven, Connecticut marine
terminal facility acquired from Wyatt Energy and the acquisition of our inland
terminals, the sellers of those terminals agreed to indemnify us against
specified environmental liabilities. We also have insurance for up to $25.0
million of environmental liabilities for the New Haven marine terminal facility,
with a deductible of $0.3 million.

For a description of indemnification with respect to the Williams Pipe Line
system, please read "Environmental Liability Associated with the Williams Pipe
Line System" below.

RECENT DEMAND MADE BY EL PASO CORPORATION

On March 11, 2002, El Paso Corporation served on The Williams Companies a
demand letter alleging that it had incurred approximately $5.3 million in costs
responding to hydrocarbon and benzene releases at our Corpus Christi, Texas
marine terminal and asserting its belief that The Williams Companies is
responsible for at least a portion of the releases and threatened releases.
Specifically, the letter states that contamination on the affected property
originated from the former Amerada Hess terminal, which The Williams Companies
acquired in 1999 and transferred to us in connection with our initial public
offering. Subsequently, on or about March 29, 2002, El Paso Corporation filed in
the U.S. District Court for the Southern District of Texas a motion for leave to
file third-party original complaint and an original third-party complaint in the
matter styled Elementis Chromium, L.P., and Elementis Chromium, Inc. v. Coastal
States Petroleum Company et al., in which it sought to join Amerada Hess
Corporation, The Williams Companies, Williams Terminals Holdings, L.L.C.,
Williams Energy Marketing & Trading Company f/k/a Williams Energy Services
Company, Williams NGL, L.L.C., CITGO Petroleum Corporation, CITGO Refining and
Chemicals Company, Inc., Koch Industries, Inc., and Koch Petroleum Group, L.P.
f/k/a Koch Refining Company, L.P. The Williams Companies was served with a
subsequent original third-party complaint on April 8, 2002.

We and The Williams Companies have only begun to investigate the merits of
this demand. We believe that this matter is subject to an indemnification
obligation of Amerada Hess, for which there is a $2.5 million aggregate claims
deductible, as discussed above. In addition, our Corpus Christi terminal is

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subject to a pollution legal liability insurance policy. For these reasons, we
cannot assure you at this time that this matter will not have a material adverse
impact on us.

ENVIRONMENTAL LIABILITY ASSOCIATED WITH THE WILLIAMS PIPE LINE SYSTEM

Contamination resulting from spills of refined products is not unusual
within the petroleum pipeline industry. Historic spills of refined products
along the pipelines and terminals of the Williams Pipe Line system as a result
of past operations have resulted in contamination of the environment, including
soils and groundwater. Site conditions, including soils and groundwater, are
being evaluated at a number of properties associated with the Williams Pipe Line
system where operations may have resulted in releases of hydrocarbons and other
wastes.

Potentially significant assessment, monitoring and remediation programs are
being performed at 17 sites in Illinois, Iowa, Kansas, Minnesota, Nebraska,
South Dakota and Wisconsin. These 17 sites include 13 terminals owned or
operated by us and four right-of-way locations that were impacted by pipeline
releases of petroleum products. We estimate that the total cost of performing
the currently anticipated assessment, monitoring and remediation at these 17
sites over the next several years to be $8.3 million. The most significant
remedial costs at these 17 sites are costs attributed to cleanup at six
terminals in Des Moines, Iowa City and Sioux City, all in Iowa, Kansas City,
Kansas and Sioux Falls and Watertown, South Dakota, where we estimate that $5.4
million of the $8.3 million in costs of assessment, monitoring and remediation
will be incurred. This estimate assumes that we will be able to use common
remedial and monitoring methods or associated engineering or institutional
controls to demonstrate compliance with applicable regulatory requirements. This
estimate covers the cost of performing assessment, remediation and/or monitoring
of impacted soils, groundwater and surface water conditions, but does not
include any costs for potential claims by others with respect to these sites.
While we do not expect any such potential claims by others to be materially
adverse to our operations, financial position, or cash flows, we cannot assure
you that the actual remediation costs or associated remediation liabilities will
not exceed this $8.3 million amount. In addition, we recently discovered a
release from one of the refined product pipelines on the Williams Pipe Line
system near Cottonwood, Minnesota. We have notified federal and state agencies
of this release and are currently investigating the extent of the release. While
the ultimate cost associated with cleanup of this incident cannot be determined
at this time, we have preliminarily estimated a cleanup cost of between $0.5
million and $1.0 million.

In addition, there are several sites where capital expenditures such as the
installation of new loading racks, new tank seals and/or secondary containment
equipment will be required in order to comply with or otherwise satisfy
applicable environmental requirements. In particular, we expect to incur $7.7
million to $8.5 million in capital expenditures, including: an estimated $1.4
million to $1.7 million to complete a new loading rack at Waterloo, Iowa; an
estimated $2.5 million to $3.0 million to install a new loading rack at Palmyra,
Missouri; an estimated $1.6 million to install secondary containment for an
existing rail rack at Des Moines, Iowa; an estimated $1.6 million to install
dike linings at Alexandria, Minnesota; and an estimated $0.6 million to install
breakout tank linings at Sioux Falls, South Dakota. In addition, we are
considering several measures to address emissions concerns at an existing
loading rack at Enid, Oklahoma.

In connection with historical operations at the terminal in Waterloo, Iowa,
the Iowa Department of Natural Resources has alleged that this terminal
incorrectly reported its air emissions from 1993 through 1999 by using an
incorrect emission factor for the loading rack. This matter was referred to the
Iowa Attorney General's office in July 2001, and we currently estimate that a
penalty of up to $150,000 may be assessed for this matter. Also, in connection
with historical operations at five former Williams Pipe Line system facilities
in Roseville, Mankato, Apple Valley, Albert Lee, and Marshall, all in Minnesota,
the Minnesota Pollution Control Agency issued three notices of violation between
March 28, 2001 and August 17, 2001, alleging violations of wastewater discharge
and aboveground storage tank permits and water quality and hazardous waste
rules. This matter is being negotiated with the Minnesota Pollution Control
Agency, and we currently estimate that a penalty of up to $150,000 may be
assessed for this matter. In addition, in connection with a liquid petroleum
release discovered in Menard County, Illinois, in July 1994, the state of
Illinois filed a suit against Williams Pipe Line Company in July 1996 with
respect
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to remediation of impacts arising from the release. Two landowners adjacent to
the release area subsequently intervened in the suit. Currently, a consent order
resolving this matter is being negotiated with the Illinois Attorney General's
office. The proposed consent order includes a civil penalty of $30,000 and a
supplemental environmental project estimated to cost $72,000. The total cost of
the settlement, including the costs of smart pigging, has been estimated by
Williams Energy Services to be about $1.0 million.

Williams Energy Services has agreed to indemnify us for losses and damages
related to breach of environmental representations and warranties and the
failure to comply with environmental laws prior to the acquisition of Williams
Pipe Line Company in excess of $2.0 million up to a maximum of $125.0 million.
Consequently, the remedial programs, assessed penalties and capital expenditures
discussed above arising in connection with a failure to comply with
environmental laws prior to the acquisition are subject to claims of
indemnification by us of Williams Energy Services, in accordance with the stated
deductible amounts, capped amounts and term limits. Moreover, as discussed
above, this $125.0 million amount will also be subject to indemnification claims
made by us for breaches of other than environmental representations and
warranties. This environmental indemnity obligation will survive for six years.

We may experience future releases of refined petroleum products into the
environment from the Williams Pipe Line system and our other pipelines and
terminals or discover historical releases that were previously unidentified or
not assessed. While we maintain an extensive inspection and audit program
designed, as applicable, to prevent, detect and address these releases promptly,
damages and liabilities incurred due to any future environmental releases from
its assets nevertheless have the potential to substantially affect our business.

On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from The Williams
Companies and its affiliates' pipelines, pipeline systems and pipeline
facilities used in the movement of oil or petroleum products during the period
from July 1, 1998 through July 2, 2001. In November 2001, The Williams Companies
furnished its response, which related primarily to the Williams Pipe Line
system.

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MANAGEMENT

The following table sets forth certain information with respect to the
executive officers and members of the board of directors of our general partner.
Executive officers and directors are elected for one-year terms.

NAME AGE POSITION WITH GENERAL PARTNER
---- --- -----------------------------

Phillip D. Wright............... 46 Chairman of the Board
Don R. Wellendorf............... 49 President, Chief Executive Officer, Chief
Financial Officer and Treasurer, Director
Jay A. Wiese.................... 46 Vice President, Terminals
Michael N. Mears................ 39 Vice President, Transportation
Richard A. Olson................ 43 Vice President, Pipeline Operations
Craig R. Rich................... 51 General Counsel
Keith E. Bailey................. 60 Director
William A. Bruckmann, III....... 50 Director
Don J. Gunther.................. 63 Director
William W. Hanna................ 66 Director
Steven J. Malcolm............... 53 Director

Phillip D. Wright was elected Chairman of the Board of Directors of our
general partner on May 13, 2002. He served as President and Chief Operating
Officer of our general partner from January 7, 2001 to May 12, 2002, and was
elected as a director on February 9, 2001. He is currently President and Chief
Executive Officer for Williams Energy Services and has served in that capacity
since September 2001. From 1996 to September 2001, he served as Senior Vice
President of Enterprise Development and Planning for Williams Energy Services.
From 1989 to 1996 he held various senior management positions with The Williams
Companies' primary refined product pipeline, Williams Pipe Line Company,
Williams Energy Ventures, Inc. and Williams Energy Services. Prior to 1989, he
spent 13 years working for Conoco, Inc.

Don R. Wellendorf serves as President, Chief Executive Officer, Chief
Financial Officer, Treasurer and director of our general partner. He was elected
President and Chief Executive Officer on May 13, 2002, Chief Financial Officer
and Treasurer on January 7, 2001, and as a director on February 9, 2001. He
served as Senior Vice President and Chief Financial Officer of our general
partner from January 7, 2001 to May 12, 2002. Since 1998, he has served as Vice
President of Strategic Development and Planning for Williams Energy Services.
Prior to The Williams Companies' merger with MAPCO Inc. in 1998, he was Vice
President and Treasurer for MAPCO from 1995 to 1998. From 1994 to 1995, he
served as Vice President and Corporate Controller for MAPCO. He began his career
in 1979 as an accountant with MAPCO and held various accounting positions with
MAPCO from 1979 to 1994.

Jay A. Wiese serves as Vice President, Terminals of our general partner and
was elected on January 7, 2001. He is currently Managing Director, Terminal
Services and Commercial Development for Williams Energy Services and has served
in that capacity since 2000. From 1995 to 2000, he served as Director, Terminal
Services and Commercial Development of The Williams Companies' terminal
distribution business. Prior to 1995, Mr. Wiese held various operations,
marketing and business development positions with Williams Pipe Line Company,
Williams Energy Ventures and Williams Energy Services. He joined Williams Pipe
Line Company in 1982.

Michael N. Mears was elected Vice President, Transportation of our general
partner on April 22, 2002. He was elected Vice President of Williams Petroleum
Services, LLC in March 2002 and currently serves in that position. Mr. Mears
served as Vice President of Transportation and Terminals for Williams Pipe Line
Company from 1998 to 2002. He also served as Vice President, Petroleum
Development for Williams Energy Services from 1996 to 1998. Prior to 1996, Mr.
Mears served as Director of Operations Control and Business Development for
Williams Pipe Line Company from 1993 to 1996. From 1985 to

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1993 he worked in various engineering, project analysis, and operations control
positions for Williams Pipe Line Company.

Richard A. Olson was elected Vice President, Pipeline Operations of our
general partner on April 22, 2002. He is currently Vice President of Mid
Continent Operations for Williams Energy Services and has served in that
capacity since 1996. Mr. Olson was Vice President of Operations and Terminal
Marketing for Williams Pipe Line Company from 1996 to 1998, Director of Southern
Operations from 1992 to 1997, Director of Product Movements from 1991 to 1992,
and Central Division Manager from 1990 to 1991. From 1981 to 1990, Mr. Olson
held various positions with Williams Pipe Line Company.

Craig R. Rich serves as General Counsel of our general partner and was
elected on January 7, 2001. He is currently Associate General Counsel of
Williams Energy Services and has served in that capacity since 1996. From 1993
to 1996, he served as General Counsel of The Williams Companies' midstream gas
and liquids division. Prior to that time, Mr. Rich was a Senior Attorney
representing Williams Gas Pipeline-West. He joined Williams in 1985.

Keith E. Bailey serves as a Director of the general partner and was elected
on February 9, 2001. He is currently Chairman of the Board of The Williams
Companies and has served in that capacity since 1994. He served as President of
The Williams Companies from 1992 to 1994 and served as its Chief Executive
Officer from 1994 to January 2002. He served as Executive Vice President of The
Williams Companies from 1986 to 1992.

William A. Bruckmann, III serves as a director of our general partner and
was elected on May 9, 2001. He is a former managing director at Chase
Securities, Inc. He has more than 25 years of banking experience, starting with
Manufacturers Hanover Trust Company, where he became a senior officer in 1985.
Mr. Bruckmann later served as managing director, sector head of the
Manufacturers Hanover's gas pipeline and midstream practices through the
acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of
Chemical Bank by Chase Bank.

Don J. Gunther serves as a director of our general partner and was elected
May 9, 2001. He is a retired vice chairman of Bechtel Group Inc. He began his
career with Bechtel in 1961 and was promoted to a variety of positions,
including Bechtel's executive committee in 1989; president of Bechtel Petroleum
in 1984; president of Europe, Africa, Middle East and southwest Asia operations
in 1992; and president of Bechtel Americas in 1995. He was named vice chairman
in July 1997, retiring from the position in 1998.

William W. Hanna serves as a director of our general partner and was
elected on January 18, 2002. He is a retired vice chairman of Koch Industries
where he held management and leadership positions since he commenced employment
in 1968. In his first year, he established a gas and gas liquids group. In 1981,
he became executive vice president of energy products for Koch. In 1984, he was
elected to the board of directors, and in 1987, was named president and chief
operating officer. In 1999, he was named vice chairman.

Steven J. Malcolm serves as a director of our general partner. He served as
Chief Executive Officer of our general partner from January 7, 2001 to May 12,
2002, and was elected as a director on February 9, 2001. He is currently
President and Chief Executive Officer of The Williams Companies and has served
in the capacity as President since September 2001, and as Chief Executive
Officer since January 2002. From 1998 to September 2001, he served as President
and Chief Executive Officer of Williams Energy Services. From 1994 to 1998, he
served as Senior Vice President for The Williams Companies' midstream gas and
liquids division, and from 1993 to 1994, worked as Senior Vice President of the
mid-continent region for Williams Field Services. From 1984 to 1993, he held
various positions with Williams Natural Gas Company, including director of
business development, director of gas management and vice president of gas
management and supply.

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TAX CONSIDERATIONS

The tax consequences to you of an investment in 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 ownership and
disposition of common units, please read "Material Tax Consequences" in the
accompanying prospectus. You are urged to consult your own tax advisor about the
federal, state and local tax consequences peculiar to your circumstances.

We estimate that if you purchase common units in this offering and own them
through the record date for the distribution for the fourth quarter of 2004,
then you will be allocated, on a cumulative basis, an amount of federal taxable
income for such period that will be less than 20% of the cash distributed with
respect to the years 2002, 2003 and 2004. If you own common units purchased in
this offering for a shorter period, the percentage of federal taxable income
allocated to you may be higher. 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 the common units in an amount equal to the
current quarterly distribution of $0.6125 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 IRS 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.

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UNDERWRITING

Subject to the terms and conditions set forth in the underwriting agreement
dated May 22, 2002, each of the managing underwriters named below for whom
Lehman Brothers Inc. and Salomon Smith Barney Inc. are acting as joint
book-running managers, have severally agreed to purchase from us the respective
number of common units opposite their names below:

NUMBER OF
UNDERWRITERS COMMON UNITS
------------ ------------

Lehman Brothers Inc. ....................................... 1,600,000
Salomon Smith Barney Inc. .................................. 1,600,000
Banc of America Securities LLC.............................. 800,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated.......... 800,000
UBS Warburg LLC............................................. 800,000
A.G. Edwards & Sons, Inc. .................................. 480,000
J.P. Morgan Securities Inc. ................................ 480,000
Raymond James & Associates, Inc. ........................... 480,000
RBC Dain Rauscher Inc. ..................................... 480,000
First Union Securities, Inc. ............................... 480,000
----------
Total..................................................... 8,000,000
==========

The underwriting agreement provides that the underwriters are obligated to
purchase, subject to certain conditions, all of the common units 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
the requirements that:

- all 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 to the underwriters customary closing documents.

We have granted to the underwriters an option to purchase up to an
aggregate of 1,200,000 additional common units at the price to the public less
the underwriting discount set forth on the cover page of this prospectus
supplement exercisable to cover over-allotments, if any. Such option may be
exercised at any time until 30 days after the date of this prospectus
supplement. If this option is exercised, each underwriter will be committed,
subject to satisfaction of the conditions specified in the underwriting
agreement, to purchase a number of additional common units proportionate to the
underwriters' initial commitment as indicated in the preceding table, and we
will be obligated, pursuant to the option, to sell these common units to the
underwriters.

The following table shows the underwriting fees to be paid to the
underwriters by us in connection with this offering. These amounts are shown
assuming both no exercise and full exercise of the underwriters' option to
purchase additional common units. The underwriting fee is the difference between
the public offering price and the amount the underwriters pay to us to purchase
the common units from us.

NO EXERCISE FULL EXERCISE
----------- -------------

Per unit................................................... $ 1.579 $ 1.579
Total................................................. $12,632,000 $14,526,800

We estimate that the total expenses of the offering, excluding underwriting
discounts and commissions, will be approximately $1.4 million.

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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 dealers (who may
include the underwriters) at this price to the public less a concession not in
excess of $0.947 per unit. The underwriters may allow, and the dealers may
reallow, a concession not in excess of $0.100 per unit to certain brokers and
dealers. After the offering, the underwriters may change the offering price and
other selling terms.

We, our general partner and all of our subsidiaries have agreed to
indemnify the underwriters against certain liabilities, including liabilities
under the Securities Act of 1933 and liabilities arising from breaches of
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.

We, our affiliates that own common units and the directors and executive
officers of our general partner have agreed that they will not, directly or
indirectly, sell, offer or otherwise dispose of any 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 Salomon Smith Barney. The
restrictions described in this paragraph do not apply to the sale of common
units to the underwriters.

Lehman Brothers Inc. and Salomon Smith Barney, 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 Salomon Smith
Barney will consider, among other factors, 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.

In connection with this offering, the underwriter may engage in stabilizing
transactions, over-allotment transactions, syndicate covering transactions and
penalty bids in accordance with Regulation M under the Securities Exchange Act
of 1934.

- 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 common units in the open market. Similar to
other purchase transactions, the underwriters' purchases to cover the
syndicate short sales may have the effect of raising or maintaining the
market price of the common units or preventing or retarding a decline in
the market price of the common units. As a result, the price of the
common units may be higher than the price that might otherwise exist 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 underwriter sells
more common 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.

S-66

- 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 syndicate short positions.

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 the 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.

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 the common units. In addition, neither
we nor any of the underwriters make any representation that the representatives
will engage in these stabilizing transactions or that any transaction, once
commenced, will not be discontinued without notice.

The common units are listed on The New York Stock Exchange under the symbol
"WEG."

Affiliates of Lehman Brothers Inc., Salomon Smith Barney, Banc of America
Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P.
Morgan Securities Inc., respectively, are lenders to us under our short-term
loan. Each of these lenders will receive an equal share of the partial repayment
by us of amounts outstanding under our short-term loan 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 loan, the offering is being made in compliance with the
requirements of Rule 2710(c)(8) of the Conduct Rules of the National Association
of Securities Dealers, Inc. However, pursuant to Rule 2720, the appointment of a
qualified independent underwriter is not required in connection with this
offering because a bona fide independent market (as defined in the NASD Conduct
Rules) exists for the common units. 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.

No sales to accounts over which the underwriters exercise discretionary
authority may be made without the prior written approval of the customer.

Some of the underwriters and their affiliates have engaged in, and may in
the future engage in, investment banking and other commercial dealings in the
ordinary course of business with us and our affiliates.

First Union Securities, Inc. is an indirect, wholly-owned subsidiary of
Wachovia Corporation. Wachovia Corporation conducts its investment banking,
institutional, and capital markets businesses through its various bank,
broker-dealer and non-bank subsidiaries (including First Union Securities, Inc.)
under the trade name of Wachovia Securities. Any references to Wachovia
Securities in this prospectus, however, do not include Wachovia Securities,
Inc., a member NASD/SIPC, a separate broker-dealer subsidiary of Wachovia
Corporation and an affiliate of First Union Securities, Inc., which may or may
not be participating as a selling group member in the distribution of the common
units.

A 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 offering, or by
their affiliates. In those cases, prospective 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 shares 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 in electronic format, the information on any
underwriter's or selling group member's web site and any information contained
in any other web site maintained by an underwriter or selling group member is
not part of the prospectus or the registration statement of which this
prospectus

S-67

supplement forms a part, has not been approved and/or endorsed by us or any
underwriter or selling group member in its capacity as underwriter or selling
group member and should not be relied upon by investors.

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 Mayor, Day, Caldwell & Keeton L.L.P., Houston, Texas.

EXPERTS

The restated 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 and also appearing
elsewhere in this prospectus supplement. These restated consolidated financial
statements have been included and incorporated by reference in reliance upon
such report given on the authority of such firm as experts in accounting and
auditing.

S-68

INDEX TO FINANCIAL STATEMENTS

PAGE
----

Williams Energy Partners L.P. Unaudited Pro Forma Financial
Statements:
Introduction.............................................. F-2
Pro Forma Statement of Income for the three months ended
March 31, 2002......................................... F-3
Pro Forma Statement of Income for the year ended December
31, 2001............................................... F-4
Pro Forma Balance Sheet as of March 31, 2002.............. F-5
Notes to Pro Forma Financial Statements................... F-6
Williams Energy Partners L.P. Financial Statements:
Report of Independent Auditors............................ F-9
Restated Consolidated Statements of Income for the years
ended December 31, 1999, 2000 and 2001 and the three
months ended March 31, 2001 and 2002................... F-10
Restated Consolidated Balance Sheets as of December 31,
2000 and 2001 and the three months ended March 31,
2002................................................... F-11
Restated Consolidated Statements of Cash Flows for the
years ended December 31, 1999, 2000 and 2001 and the
three months ended March 31, 2001 and 2002............. F-12
Restated Consolidated Statement of Partners' Capital for
the years ended December 31, 1999, 2000 and 2001....... F-13
Notes to Restated Consolidated Financial Statements....... F-14

F-1

WILLIAMS ENERGY PARTNERS L.P.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

INTRODUCTION

The pro forma financial statements are based upon the combined historical
financial position and results of operations of Williams Energy Partners and
Williams Pipe Line Company. Because Williams Pipe Line Company was an affiliate
of Williams Energy Partners at the time of its acquisition by Williams Energy
Partners, the transaction was between entities under common control and, as
such, was accounted for similarly to a pooling of interest. Accordingly, our
consolidated financial statements and notes have been restated to reflect the
historical results of operations, financial position and cash flows of Williams
Energy Partners and Williams Pipe Line Company throughout the periods presented.

The acquisition of Williams Pipe Line was consummated on April 11, 2002.
The unaudited pro forma income statements have been prepared as if the
acquisition had occurred on January 1 of the respective periods presented, and
the pro forma balance sheet has been prepared as if the acquisition occurred on
March 31, 2002. The acquisition was funded through a short-term loan and the
issuance of Class B units to The Williams Companies.

The pro forma financial statements of Williams Energy Partners reflect
adjustments to exclude income and expenses and assets and liabilities that were
conveyed to and assumed by an affiliate of Williams Pipe Line Company prior to
our acquisition of Williams Pipe Line Company. These assets primarily include
Williams Pipe Line Company's interest in and agreements related to Longhorn
Partners Pipeline, a discontinued refinery site in Augusta, Kansas and the ATLAS
2000 software system. In addition, the pro forma financial statements reflect
adjustments to show that we will no longer take title to natural gas liquids
used for blending to produce different grades of gasoline or to the resulting
gasoline but will perform these services for an affiliate of The Williams
Companies for an annual fee. Further, the general and administrative expenses
allocated to us by The Williams Companies will be limited initially to $30.0
million per year for Williams Pipe Line Company. These pro forma financial
statements also reflect the short-term loan and the issuance of Class B units to
The Williams Companies to fund the acquisition of Williams Pipe Line Company, as
well as this equity offering of common units and the application of the net
proceeds to repay a portion of the short-term loan.

The pro forma financial statements have been prepared on the basis that
Williams Energy Partners will continue to be treated as a partnership for
federal income tax purposes. The unaudited pro forma financial statements should
be read in conjunction with and are qualified in their entirety by reference to
the notes accompanying such pro forma financial statements and with the
historical financial statements and related notes of Williams Energy Partners
included in this prospectus.

The pro forma financial statements may not be indicative of the results
that actually would have occurred or will occur in the future had Williams
Energy Partners consummated the acquisition of Williams Pipe Line Company on the
dates indicated or issued equity and borrowed funds on the dates indicated.

F-2

WILLIAMS ENERGY PARTNERS L.P.

PRO FORMA STATEMENT OF INCOME
THREE MONTHS ENDED MARCH 31, 2002
(IN THOUSANDS -- EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

WILLIAMS
ENERGY
PARTNERS
CONSOLIDATED
HISTORICAL ADJUSTMENTS PRO FORMA
------------ ----------- ---------

Revenues:
Williams Pipe Line system........................... $ 78,426 $ (210)(a) $ 68,685
(10,281)(b)
750(b)
Petroleum products terminals........................ 19,847 -- 19,847
Ammonia pipeline system............................. 4,375 -- 4,375
-------- -------- ---------
Total revenues................................... $102,648 $ (9,741) $ 92,907
Costs and expenses:
Operating expenses.................................. $ 33,066 $ (59)(a) $ 32,163
(844)(c)
Product purchases................................... 18,409 (8,900)(b) 9,509
Depreciation and amortization....................... 8,964 (486)(a) 8,478
General and administrative expenses................. 13,457 (2,729)(d) 10,728
-------- -------- ---------
Total costs and expenses......................... $ 73,896 $(13,018) $ 60,878
-------- -------- ---------
Operating profit...................................... $ 28,752 $ 3,277 $ 32,029
Interest expense...................................... 1,313 4,477(e) 5,383
(407)(e)
Interest income....................................... (550) 550(a) --
Other (income) expense................................ (953) -- (953)
-------- -------- ---------
Income before income taxes............................ $ 28,942 $ (1,343) $ 27,599
Provision for income taxes............................ 7,816 (7,816)(f) --
-------- -------- ---------
Net income............................................ $ 21,126 $ 6,473 $ 27,599
======== ======== =========
Portion of net income applicable to partners'
interests........................................... $ 8,507
Portion applicable to Williams Pipe Line.............. 12,619
--------
Net income....................................... $ 21,126
========
Portion of net income applicable to partners'
interest............................................ $ 8,507 $ 27,599
General partner's interest in net income.............. 242(h) 773(h)
-------- ---------
Limited partners' interest in net income.............. 8,265 $ 26,826
======== =========
Basic net income per limited partner unit............. $ 0.73(i) $ 0.99(i)
======== =========
Weighted average number of limited partner units
outstanding used for basic net income per unit
calculation......................................... 11,359(i) 27,190(i)
======== =========
Diluted net income per limited partner unit........... $ 0.72 $ 0.98
======== =========
Weighted average number of limited partner units
outstanding used for diluted net income per unit
calculation......................................... 11,407 27,238
======== =========

See accompanying notes.
F-3

WILLIAMS ENERGY PARTNERS L.P.

PRO FORMA STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2001
(IN THOUSANDS -- EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

WILLIAMS
ENERGY
PARTNERS
CONSOLIDATED
HISTORICAL ADJUSTMENTS PRO FORMA
------------ ----------- ---------

Revenues:
Williams Pipe Line system......................... $362,545 $ (1,017)(a) $316,291
(48,237)(b)
3,000(b)
Petroleum products terminals...................... 71,510 -- 71,510
Ammonia pipeline system........................... 14,544 -- 14,544
-------- -------- --------
Total revenues.................................. $448,599 $(46,254) $402,345
Costs and expenses:
Operating expenses................................ $160,880 $ (202)(a) $154,068
(6,610)(c)
Product purchases................................. 95,268 (39,127)(b) 56,141
Depreciation and amortization..................... 35,767 (1,901)(a) 33,866
General and administrative expenses............... 47,365 (8,410)(d) 38,955
-------- -------- --------
Total costs and expenses........................ $339,280 $(56,250) $283,030
-------- -------- --------
Operating profit....................................... $109,319 $ 9,996 $119,315
Interest expense....................................... 14,859 17,907(e) 24,839
(7,927)(e)
Interest income........................................ (2,493) 2,493(a) --
Other (income) expense................................. (431) (229)(g) (660)
-------- -------- --------
Income before income taxes............................. $ 97,384 $ (2,248) $ 95,135
Provision for income taxes............................. 29,512 (29,325)(f) 187
-------- -------- --------
Net income............................................. $ 67,872 $ 27,077 $ 94,948
======== ======== ========
Net income allocated to period January 1 through
February 10, 2001.................................... $ 304 $ 304
Portion of net income applicable to partners'
interests............................................ 21,443 94,644
Portion applicable to Williams Pipe Line............... 46,125 --
-------- --------
Net income........................................ $ 67,872 $ 94,948
======== ========
Portion of net income applicable to partners'
interest............................................. $ 21,443 $ 94,644
General partner's interest in net income............... 226(h) 2,650(h)
-------- --------
Limited partners' interest in net income............... 21,217 $ 91,994
======== ========
Basic net income per limited partner unit.............. $ 1.87(i) $ 3.38(i)
======== ========
Weighted average number of limited partner units
outstanding used for basic net income per unit
calculation.......................................... 11,359(i) 27,190(i)
======== ========
Diluted net income per limited partner unit............ $ 1.87 $ 3.38
======== ========
Weighted average number of limited partner units
outstanding used for diluted net income per unit
calculation.......................................... 11,370 27,201
======== ========

See accompanying notes.
F-4

WILLIAMS ENERGY PARTNERS L.P.

PRO FORMA BALANCE SHEET
MARCH 31, 2002
(IN THOUSANDS)
(UNAUDITED)

WILLIAMS ENERGY
PARTNERS CONSOLIDATED
HISTORICAL ADJUSTMENTS PRO FORMA
--------------------- ----------- ----------

ASSETS
Current assets:
Cash and cash equivalents.................................. $ 8,150 $ 700,000(j) $ 23,146
(7,087)(j)
(3,512)(j)
(674,405)(l)
284,569(m)
(1,350)(m)
(283,219)(m)
6,065(n)
(6,065)(n)
Accounts receivable........................................ 30,121 (14,129)(l) 15,992
Affiliate accounts receivable.............................. 2,369 4,275(c) 5,674
(970)(l)
Inventories................................................ 16,075 (13,383)(b) 2,692
Deferred taxes............................................. 1,690 (1,690)(k) --
Other current assets....................................... 4,993 (4,778)(a) 215
---------- --------- ----------
Total current assets..................................... $ 63,398 $ (15,679) $ 47,719
Property, plant and equipment, at cost...................... 1,347,215 (36,430)(a) 1,310,785
Less: accumulated depreciation.............................. 383,482 (4,658)(a) 378,824
---------- --------- ----------
Net property, plant and equipment........................... $ 963,733 $ (31,772) $ 931,961
Goodwill.................................................... 22,429 -- 22,429
Other intangibles........................................... 2,622 -- 2,622
Long-term affiliate accounts receivables.................... 23,461 (19,002)(a) 7,672
3,213(c)
Long-term receivable........................................ 11,890 -- 11,890
Other noncurrent assets..................................... 6,998 (977)(a) 10,179
7,087(j)
(2,929)(m)
---------- --------- ----------
Total assets............................................. $1,094,531 $ (60,059) $1,034,472
========== ========= ==========
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable........................................... $ 9,423 $ 633(a) $ 10,056
Affiliate accounts payable................................. 18,141 -- 18,141
Affiliate income taxes payable............................. 11,183 (11,183)(k) --
Accrued affiliate payroll and benefits..................... 2,483 -- 2,483
Accrued taxes other than income............................ 10,220 -- 10,220
Accrued interest payable................................... 169 -- 169
Environmental liabilities.................................. 8,500 (1,365)(a) 7,135
Deferred revenue........................................... 4,658 852(a) 5,510
Short-term debt............................................ -- 700,000(j) 410,716
(283,219)(m)
(6,065)(n)
Other current liabilities.................................. 7,687 -- 7,687
---------- --------- ----------
Total current liabilities................................ $ 72,464 $ 399,653 $ 472,117
Long-term debt.............................................. 148,000 -- 148,000
Long-term affiliate note payable............................ 108,392 (55,866)(a) --
(13,383)(b)
(39,143)(e)
Long-term affiliate payable................................. 1,112 -- 1,112
Other deferred liabilities.................................. 1,028 -- 1,028
Deferred taxes.............................................. 148,164 (148,164)(k) --
Environmental liabilities................................... 8,260 (568)(a) 7,692
Class B limited partner equity.............................. -- 304,400(l) 302,219
(983)(j)
(820)(m)
(378)(m)
Partners' capital:
General partner............................................ $ 381,874 $ (215)(a) $ (402,110)
7,488(c)
39,143(e)
(98)(j)
157,657(k)
(581,464)(l)
6,200(1)
(418,640)(l)
(82)(m)
(38)(m)
6,065(n)
Limited partners........................................... 225,237 (2,431)(j) 504,414
(2,027)(m)
284,569(m)
(934)(m)
---------- --------- ----------
Total partners' capital.................................. $ 607,111 $(504,807) $ 102,304
---------- --------- ----------
Total liabilities and partners' capital.................. $1,094,531 $ (60,059) $1,034,472
========== ========= ==========

See accompanying notes.
F-5

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO PRO FORMA FINANCIAL STATEMENTS
DECEMBER 31, 2001 AND MARCH 31, 2002
(UNAUDITED)

The pro forma adjustments have been prepared as if the closing of the
acquisition of Williams Pipe Line Company by Williams Energy Partners had taken
place on January 1, 2002 and January 1, 2001, in the case of the pro forma
statements of income for the three months ended March 31, 2002 and for the year
ended December 31, 2001, respectively, and on March 31, 2002 in the case of the
pro forma balance sheet. The adjustments are based upon currently available
information and certain estimates and assumptions, and therefore the actual
adjustments will differ from the pro forma adjustments. However, management
believes that the assumptions provide a reasonable basis for presenting the
significant effects of the transactions as contemplated and that the pro forma
adjustments give appropriate effect to those assumptions and are properly
applied in the pro forma financial information.

(a) Reflects adjustments to revenues, expenses, assets, liabilities and equity
associated with the transfers by Williams Pipe Line Company prior to its
acquisition by Williams Energy Partners. These included, principally,
Williams Pipe Line Company's interest in and agreements related to Longhorn
Partners Pipeline, a discontinued refinery site in Augusta, Kansas and the
ATLAS 2000 software system.

(b) Reflects an adjustment to eliminate revenues, product purchases and
inventories associated with blending activities of Williams Pipe Line
Company. As part of the Williams Pipe Line Company acquisition, The
Williams Companies entered into a supplemental blending services agreement
with Williams Energy Partners that provides for approximately $3.0 million
per year ($750,000 pro-rata for the quarter) of revenue for 10 years for
blending services performed on the Williams Pipe Line system. There will be
no incremental costs to Williams Energy Partners associated with these
revenues.

(c) Represents an adjustment for environmental expenses and liabilities that
have been indemnified by The Williams Companies. Williams Energy Partners
has reflected the environmental liabilities of Williams Pipe Line Company
in its balance sheet and has established a receivable due from The Williams
Companies equal to such amount less a $2.0 million deductible, which
resulted in a capital contribution to Williams Energy Partners.

(d) Reflects adjustments to general and administrative costs charged to
Williams Energy Partners. The Williams Companies and Williams Energy
Partners have agreed to limit the amount of general and administrative
expenses to be charged to Williams Energy Partners related to Williams Pipe
Line Company to $30.0 million for the first year of operation ($7.5 million
pro-rata for the quarter). The $30.0 million limitation on general and
administrative expenses will increase each year after 2002 by the lesser of
2.5% or the percentage increase in the consumer price index.

(e) Reflects adjustments to properly state interest expense at 4.4% for the
$700.0 million short-term loan incurred to finance the acquisition of
Williams Pipe Line Company reduced by a partial repayment of $289.3 million
with the net proceeds from this equity offering. Also reflects the capital
contribution by The Williams Companies related to the forgiveness of
Williams Pipe Line Company's affiliate note payable. If interest rates vary
by 1/8 of a percent, annual interest expense attributable to Williams
Energy Partners' total debt outstanding will change by $0.7 million.

(f) Pro forma net income excludes federal and state income taxes for Williams
Pipe Line Company as Williams Energy Partners is not subject to income
taxes.

(g) Reflects the elimination of minority interest as a result of changes in
Williams Energy Partners' organization structure, completed on February 26,
2002. The organization changes included forming a wholly owned Delaware
corporation named Williams GP Inc., contributing a small ownership interest
in Williams OLP, L.P. by Williams Energy Partners to Williams GP Inc. and
amending

F-6

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)

Williams OLP's partnership agreement such that Williams GP Inc. became
Williams OLP's general partner. These organization changes also resulted in
the general partner's combined 2% direct and indirect ownership interest in
Williams Energy Partners converting to a direct 2% ownership in Williams
Energy Partners.

(h) The general partner's allocation of net income is based on its 2.0%
interest in Williams Energy Partners plus the additional allocation of net
income associated with its incentive distribution rights. The historical
amount for the 2002 quarter is calculated based on the general partner's
2.0% ownership interest plus an additional 0.3% allocation of income
associated with the general partner's incentive distribution rights based
on Williams Energy Partners' annual distribution of $2.36 unit for the
fourth quarter of 2001. The historical amount for the year ended December
31, 2001 is calculated based on the general partner's 1.0% ownership
interest in Williams Energy Partners before the organization changes
discussed in note (g) above. The pro forma amounts are calculated based on
the general partner's 2.0% ownership interest plus an additional 0.8%
allocation of income associated with the general partner's incentive
distribution rights at Williams Energy Partners' current annual
distribution of $2.45 unit. The amounts of income allocated to the general
partner and the limited partners will be different if Williams Energy
Partners changes the current cash distribution of $2.45 per unit.

(i) Net income per limited partner unit is calculated by dividing the limited
partners' interest in net income by the weighted average number of limited
partner units outstanding. The historical computation of net income per
limited partner unit was derived from the 5,679,694 common units and
5,679,694 subordinated units that were outstanding during the three months
ended March 31, 2002 and 2001. The pro forma limited partners' interest in
net income includes income attributable to Williams Pipe Line Company, as
adjusted to reflect the acquisition as if it had occurred at the beginning
of the periods presented. The pro forma computation of net income per
limited partner unit assumes that 13,679,694 common units, 7,830,924 Class
B units and 5,679,694 subordinated units were outstanding at all times
during the periods presented.

(j) Represents the net cash proceeds of $689.4 million from short-term
borrowings of $700.0 million, less debt placement fees of $7.1 million and
transaction costs of $3.5 million. The debt placement fees will be fully
expensed when the short-term loan is repaid. This nonrecurring expense is
not reflected in the pro forma statements of income.

(k) Represents Williams Pipe Line Company's long-term affiliate note payable
and net deferred tax assets and liabilities that were retained by The
Williams Companies, resulting in a capital contribution to Williams Energy
Partners.

(l) Represents the acquisition of Williams Pipe Line Company from The Williams
Companies. Upon closing, The Williams Companies contributed all of its
equity in Williams Pipe Line Company to Williams Energy Partners in return
for $304.4 million of Class B units and cash of $674.4 million, net of a
$6.2 million contribution required to maintain its 2% general partner
interest. Additionally, The Williams Companies retained accounts
receivable and affiliate receivables attributable to Williams Pipe Line
Company, which equaled $15.0 million at March 31, 2002. Williams Energy
Partners will use the $15.0 million of incremental cash from the
short-term loan for working capital requirements. The net equity
adjustment of a negative $418.6 million results from recording the assets
and liabilities of Williams Pipe Line Company at the historical book value
of The Williams Companies, as required by generally accepted accounting
principles, while acquiring Williams Pipe Line Company at market value.
Because the decision as to the redemption of the Class B units will be
made by Williams Energy Partners' general partner, they are not included
in partners' capital.

F-7

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)

(m) Represents the sale of 8,000,000 common units at a price of $37.15 per unit
less underwriting discounts and commissions of 4.25% and offering expenses
of $1.4 million. The net proceeds of $283.2 million will be used to
partially repay the short-term loan. Also, represents a partial write-off of
the $7.1 million of debt placement fees capitalized in note (j) above. The
write-off is proportional to the partial repayment of the short-term loan to
the total short-term loan, including the repayment described in note (n).

(n) Represents a capital contribution by an affiliate of The Williams Companies
in connection with this offering to maintain its 2% general partner
interest. This $6.1 million cash contribution will be used to partially
repay the short-term loan.

F-8

REPORT OF INDEPENDENT AUDITORS

The Board of Directors of Williams GP LLC,
General Partner of Williams Energy Partners L.P.

We have audited the accompanying restated consolidated balance sheets of
Williams Energy Partners L.P. as of December 31, 2000 and 2001 and the related
restated consolidated statements of income and partners' capital and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of Williams Energy Partners L.P.'s
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatements. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Williams Energy
Partners L.P. at December 31, 2001 and 2000, and the combined results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
April 11, 2002

F-9

WILLIAMS ENERGY PARTNERS

RESTATED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS -- EXCEPT PER UNIT AMOUNTS)

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------ -------------------
1999 2000 2001 2001 2002
-------- -------- -------- -------- --------
(UNAUDITED)

Transportation and terminaling revenues:
Third party......................................... $271,135 $294,617 $314,027 $ 71,880 $ 73,261
Affiliate........................................... 15,972 23,504 26,867 5,924 7,569
Product sales revenues:
Third party......................................... 1,607 15,849 40,302 14,886 6,117
Affiliate........................................... 69,143 91,024 66,385 14,606 15,491
Affiliate construction and management fee revenues.... 17,875 1,852 1,018 380 210
-------- -------- -------- -------- --------
Total revenues.................................... $375,732 $426,846 $448,599 $107,676 $102,648
Costs and expenses:
Operating........................................... $121,599 $144,899 $160,880 $ 37,355 $ 33,066
Product purchases................................... 59,230 94,141 95,268 27,844 18,409
Affiliate construction expenses..................... 15,464 1,025 -- -- --
Depreciation and amortization....................... 25,670 31,746 35,767 9,041 8,964
General and administrative.......................... 47,062 51,206 47,365 10,578 13,457
-------- -------- -------- -------- --------
Total costs and expenses.......................... $269,025 $323,017 $339,280 $ 84,818 $ 73,896
-------- -------- -------- -------- --------
Operating profit...................................... $106,707 $103,829 $109,319 $ 22,858 $ 28,752
Interest expense:
Affiliate interest expense.......................... 19,167 27,009 9,770 4,151 407
Other interest expense.............................. -- -- 5,089 835 906
Interest income....................................... (169) (1,680) (2,493) (729) (550)
Other income.......................................... (1,511) (816) (431) (211) (953)
-------- -------- -------- -------- --------
Income before income taxes............................ $ 89,220 $ 79,316 $ 97,384 $ 18,812 $ 28,942
Provision for income taxes............................ 34,121 30,414 29,512 5,759 7,816
-------- -------- -------- -------- --------
Net income............................................ $ 55,099 $ 48,902 $ 67,872 $ 13,053 $ 21,126
======== ======== ======== ======== ========
Allocation of net income:
Portion applicable to the period January 1 through
February 9, 2001.................................. $ 304 $ 304 $ --
Portion applicable to partners' interests for the
period January 1 through March 31, 2002 and
February 10 through March 31, 2001................ 21,443 3,600 8,507
Portion applicable to Williams Pipe Line............ 46,125 9,149 12,619
-------- -------- --------
Net income........................................ $ 67,872 $ 13,053 $ 21,126
======== ======== ========
Portion of net income applicable to partners'
interest............................................ $ 21,443 $ 3,600 $ 8,507
General partner's interest in net income.............. 226 72 242
-------- -------- --------
Limited partners' interest in net income.............. $ 21,217 $ 3,528 $ 8,265
======== ======== ========
Basic net income per limited partner unit............. $ 1.87 $ 0.31 $ 0.73
======== ======== ========
Weighted average number of limited partner units
outstanding used for basic net income per unit
calculation......................................... 11,359 11,359 11,359
======== ======== ========
Diluted net income per limited partner unit........... $ 1.87 $ 0.31 $ 0.72
======== ======== ========
Weighted average number of limited partner units
outstanding used for diluted net income per unit
calculation......................................... 11,370 11,359 11,407
======== ======== ========

See accompanying notes.
F-10

WILLIAMS ENERGY PARTNERS L.P.

RESTATED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

DECEMBER 31,
----------------------- MARCH 31,
2000 2001 2002
---------- ---------- -----------
(UNAUDITED)

ASSETS
Current assets:
Cash and cash equivalents................................. $ 10 $ 13,837 $ 8,150
Accounts receivable (less allowance for doubtful
accounts -- $227 at December 31, 2000, $510 at December
31, 2001, and $461 at March 31, 2002.................... 19,340 18,157 30,121
Other accounts receivable................................. 19,657 10,754 --
Affiliate accounts receivable............................. 22,144 6,386 2,369
Inventory................................................. 8,283 21,057 16,075
Deferred income taxes -- affiliate........................ 4,107 1,690 1,690
Other current assets...................................... 8,764 3,185 4,993
---------- ---------- ----------
Total current assets............................... $ 82,305 $ 75,066 $ 63,398
Property, plant and equipment, at cost...................... $1,277,676 $1,338,393 $1,347,215
Less: accumulated depreciation............................ 341,374 374,653 383,482
---------- ---------- ----------
Net property, plant and equipment....................... $ 936,302 $ 963,740 $ 963,733
Deferred equity offering costs.............................. 2,539 -- --
Goodwill (less amortization of $145 at December 31, 2001 and
$327 at March 31, 2002)................................... -- 22,282 22,429
Other intangibles (less amortization of $310 at December 31,
2001 and $327 at March 31, 2002).......................... -- 2,639 2,622
Long-term affiliate receivables............................. 16,837 21,296 23,461
Long-term receivables....................................... 262 8,809 11,890
Other noncurrent assets..................................... 11,914 10,727 6,998
---------- ---------- ----------
Total assets....................................... $1,050,159 $1,104,559 $1,094,531
========== ========== ==========

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable.......................................... $ 10,180 $ 12,636 $ 9,423
Affiliate accounts payable................................ 8,485 10,157 18,141
Affiliate income taxes payable............................ 5,465 8,544 11,183
Accrued affiliate payroll and benefits.................... 5,428 4,606 2,483
Accrued taxes other than income........................... 10,308 9,948 10,220
Accrued interest payable.................................. -- 277 169
Accrued environmental liabilities......................... 8,131 8,650 8,500
Deferred revenue.......................................... 4,722 5,103 4,658
Accrued product purchases................................. 3,436 2,711 --
Accrued casualty losses................................... 3,626 927 --
Other current liabilities................................. 4,696 4,865 7,687
Acquisition payable....................................... -- 8,853 --
---------- ---------- ----------
Total current liabilities.......................... $ 64,477 $ 77,277 $ 72,464
Long-term debt.............................................. -- 139,500 148,000
Long-term affiliate note payable............................ 432,957 138,172 108,392
Long-term affiliate payable................................. -- 1,262 1,112
Other deferred liabilities.................................. 1,230 1,127 1,028
Deferred income taxes -- affiliate.......................... 156,984 147,029 148,164
Environmental liabilities................................... 6,008 8,260 8,260
Minority interest........................................... -- 2,250 --
Commitments and contingencies Partners' capital:
Common unitholders (5,680 units outstanding at December
31, 2001 and March 31, 2002)............................ 69,856 101,452 102,235
Subordinated unitholders (5,680 units outstanding at
December 31, 2001 and March 31, 2002)................... -- 121,237 122,020
General partner........................................... 318,647 366,993 382,856
---------- ---------- ----------
Total partners' capital............................ 388,503 589,682 607,111
---------- ---------- ----------
Total liabilities and partners' capital............ $1,050,159 $1,104,559 $1,094,531
========== ========== ==========

See accompanying notes.
F-11

WILLIAMS ENERGY PARTNERS L.P.

RESTATED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------- --------------------
1999 2000 2001 2001 2002
--------- -------- -------- --------- --------
(UNAUDITED)

Operating Activities:
Net income............................................... $ 55,099 $ 48,902 $ 67,872 $ 13,053 $ 21,126
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization.......................... 25,670 31,746 35,767 9,041 8,964
Debt issuance costs amortization....................... -- -- 253 -- 95
Minority interest expense.............................. -- -- 229 -- --
Deferred compensation expense.......................... -- -- 2,048 -- 998
Deferred income taxes.................................. 22,383 2,229 6,438 1,219 1,135
(Gain) loss on sale of assets.......................... (163) -- 249 -- (1,017)
Changes in components of operating assets and
liabilities:
Accounts receivable and other accounts receivable.... (5,671) (9,726) 10,393 10,861 (1,210)
Affiliate accounts receivable........................ 11,317 (1,943) 15,758 15,812 4,017
Inventories.......................................... 12,774 2,494 (12,919) (6,769) 4,982
Accounts payable..................................... 5,271 (6,636) 2,456 (3,328) (3,213)
Affiliate accounts payable........................... (1,166) (4,146) 1,175 6,345 5,902
Accrued income taxes due affiliate................... (16,666) 2,570 3,079 (721) 2,639
Accrued affiliate payroll and benefits............... (3,370) (169) (822) (3,135) (2,123)
Accrued taxes other than income...................... (851) 1,756 (364) 5,695 272
Accrued interest payable............................. -- -- 277 -- (108)
Current and noncurrent environmental liabilities..... 1,631 4,511 2,669 843 (150)
Other current and noncurrent assets and
liabilities....................................... (21,786) (16,532) 775 780 (4,907)
--------- -------- -------- --------- --------
Net cash provided by operating activities......... $ 84,472 $ 55,056 $135,333 $ 49,696 $ 37,402
Investing Activities:
Additions to property, plant & equipment................. $ (44,491) $(43,346) $(38,093) $ (8,901) $ (9,110)
Purchases of businesses.................................. (223,300) (31,100) (49,409) -- (8,854)
Advances on affiliate note receivable.................... (10,115) -- -- -- --
Proceeds from sale of assets............................. -- -- -- -- 1,041
Other.................................................... -- -- -- (66) --
--------- -------- -------- --------- --------
Net cash used by investing activities.................. $(277,906) $(74,446) $(87,502) $ (8,967) $(16,923)
Financing Activities:
Distributions paid....................................... $ -- $ -- $(16,599) $ -- $ (6,861)
Borrowings under credit facility......................... -- -- 139,500 90,100 8,500
Capital contributions by affiliate....................... -- -- 1,792 2,737 1,975
Sale of Common Units to public (less underwriters'
commissions and payment of formation costs)............ -- -- 89,362 89,362 --
Debt placement costs..................................... -- -- (909) (909) --
Redemption of 600,000 Common Units from affiliate........ -- -- (12,060) (12,060) --
Payments on affiliate note payable....................... (38,639) (12,679) (235,090) (202,515) (29,780)
Proceeds from affiliate note payable..................... 232,074 32,069 -- -- --
Cash advances from affiliate............................. -- -- -- 5,226 --
--------- -------- -------- --------- --------
Net cash provided (used) by financing activities....... $ 193,435 $ 19,390 $(34,004) $ (28,059) $(26,166)
--------- -------- -------- --------- --------
Change in cash and cash equivalents........................ $ 1 $ -- $ 13,827 $ 12,670 $ (5,687)
Cash and cash equivalents at beginning of period........... 9 10 10 10 13,837
--------- -------- -------- --------- --------
Cash and cash equivalents at end of period................. $ 10 $ 10 $ 13,837 $ 12,680 $ 8,150
========= ======== ======== ========= ========
Supplemental non-cash investing and financing transactions:
Contributions by affiliate of predecessor company
deferred income tax liability.......................... $ -- $ -- $ 13,976 $ 13,789 $ --
Contribution of long-term debt to partners' capital...... -- -- 59,695 59,695 --
Purchase of Aux Sable pipeline........................... -- -- 8,853 -- --
Deferred equity offering costs........................... -- 2,539 -- -- --
--------- -------- -------- --------- --------
Total.................................................. $ -- $ 2,539 $ 82,524 $ 73,484 $ --
========= ======== ======== ========= ========

See accompanying notes.
F-12

WILLIAMS ENERGY PARTNERS L.P.

RESTATED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)

NUMBER OF LIMITED
PARTNER UNITS TOTAL
------------------------ GENERAL PARTNERS'
COMMON SUBORDINATED COMMON SUBORDINATED PARTNER CAPITAL
--------- ------------ -------- ------------ -------- ---------

Balances as previously reported --
January 1, 1999................. -- -- $ 60,085 $ -- $ -- $ 60,085
Adjustments for Williams Pipe Line
transaction..................... -- -- -- -- 224,417 224,417
--------- --------- -------- -------- -------- --------
Balances as restated -- January 1,
1999............................ -- -- 60,085 -- 224,417 284,502
Net income........................ -- -- 6,766 -- 48,333 55,099
--------- --------- -------- -------- -------- --------
Balance -- December 31, 1999...... -- -- $ 66,851 $ -- $272,750 $339,601
Net income........................ -- -- 3,005 -- 45,897 48,902
--------- --------- -------- -------- -------- --------
Balance -- December 31, 2000...... -- -- $ 69,856 $ -- $318,647 $388,503
Issuance of units to public....... 4,600,000 -- 89,362 -- -- 89,362
Contribution of net assets of
predecessor companies........... 1,679,694 5,679,694 (48,484) 118,762 2,326 72,604
Redemption of common units........ (600,000) -- (12,060) -- -- (12,060)
Distributions..................... -- -- (8,134) (8,134) (331) (16,599)
Portion of net income applicable
to period January 1, 2001
through February 9, 2001........ -- -- 304 -- -- 304
Portion of net income applicable
to partnership interests........ -- -- 10,608 10,609 46,351 67,568
--------- --------- -------- -------- -------- --------
Balance -- December 31, 2001...... 5,679,694 5,679,694 $101,452 $121,237 $366,993 $589,682
Net income (unaudited)............ 4,134 4,134 12,858 21,126
Distributions (unaudited)......... (3,351) (3,351) (159) (6,861)
Affiliate capital contributions
(unaudited)..................... 491 491 20 1,002
Conversion of minority interest
liability to equity
(unaudited)..................... 2,250 2,250
Other (unaudited)................. (88) (88)
--------- --------- -------- -------- -------- --------
Balance -- March 31, 2002
(unaudited)..................... 5,679,694 5,679,694 $102,726 $122,511 $381,874 $607,111
========= ========= ======== ======== ======== ========

See accompanying notes.
F-13

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION PERTAINING TO MARCH 31, 2002 AND TO THE
THREE MONTHS ENDED MARCH 31, 2001 AND 2002 IS UNAUDITED)

1. ORGANIZATION AND PRESENTATION

Williams Energy Partners L.P. (the "Partnership") is a Delaware limited
partnership that was formed in August 2000, to own, operate and acquire a
diversified portfolio of complementary energy assets. At the time of the
Partnership's initial public offering in February 2001, the Partnership owned:
(a) selected petroleum products terminals previously owned by Williams Energy
Ventures, Inc. and (b) an ammonia pipeline system previously owned by Williams
Natural Gas Liquids, Inc. ("WNGL"). Prior to the closing of the Partnership's
initial public offering in February 2001, Williams Energy Ventures, Inc. was
owned by Williams Energy Services, LLC ("WES"). Both WES and WNGL are wholly
owned subsidiaries of The Williams Companies, Inc. ("Williams"). Williams GP LLC
("General Partner"), a Delaware limited liability company wholly owned by WES
and WNGL, was also formed in August 2000, to serve as general partner for the
Partnership.

On February 9, 2001, the Partnership completed its initial public offering
of 4,000,000 common units representing limited partner interests in the
Partnership at a price of $21.50 per unit. The proceeds of $86.0 million were
used to pay underwriting discounts and commissions of $5.6 million and legal,
professional fees and costs associated with the initial public offering of $3.1
million, with the remainder used to reduce affiliate note balances with
Williams.

As part of the initial public offering, the underwriters exercised their
over-allotment option and purchased 600,000 common units, also at a price of
$21.50 per unit. The net proceeds of $12.1 million, after underwriting discounts
and commissions of $0.8 million, from this over-allotment option were used to
redeem 600,000 of the common units held by WES to reimburse it for capital
expenditures related to the Partnership's assets. The Partnership maintained the
historical costs of the net assets in connection with the initial public
offering. Following the exercise of the underwriters over-allotment option, 40%
of the Partnership was owned by the public and 60%, including the General
Partner's ownership, is owned by affiliates of the Partnership. The limited
partners' liability in the Partnership is generally limited to their investment.

On February 26, 2002, the Partnership formed a wholly owned Delaware
corporation named Williams GP Inc. ("GP Inc.") The Partnership then contributed
a 0.001% limited partner interest in Williams OLP, L.P. ("OLP") to GP Inc. as a
capital contribution. The OLP partnership agreement was then amended to convert
GP Inc.'s OLP limited partner interest to a general partner interest and to
convert the General Partner's existing interest to a limited partner interest.
The General Partner then contributed its 1.0101% OLP limited partner interest to
the Partnership in exchange for an additional 1.0% general partner interest in
the Partnership.

On April 11, 2002, the Partnership acquired all of the membership interests
of Williams Pipe Line Company, LLC ("Williams Pipe Line") for approximately $1.0
billion. Because Williams Pipe Line was an affiliate of the Partnership at the
time of the acquisition, the transaction was between entities under common
control and, as such, has been accounted for similarly to a pooling of interest.
Accordingly, the consolidated financial statements and notes of the Partnership
have been restated to reflect the combined historical results of operations,
financial position and cash flows of Williams Energy Partners and Williams Pipe
Line Company throughout the periods presented. Williams Pipe Line's operations
will be reported as a separate operating segment of the Partnership. The
beginning equity balance of $224.4 million and net income in the amount of $48.3
million, $45.9 million and $46.1 million for the years ended December 31, 1999,
2000 and 2001, respectively, related to Williams Pipe Line have been included in
the General Partner's equity for all periods presented.

F-14

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The historical results for Williams Pipe Line include income and expenses
and assets and liabilities that were conveyed to and assumed by an affiliate of
Williams Pipe Line prior to its acquisition by the Partnership. The assets
principally include Williams Pipe Line's interest in and agreements related to
Longhorn Partners Pipeline ("Longhorn"), a discontinued refinery site at
Augusta, Kansas and the ATLAS 2000 software system. The liabilities principally
include the environmental liabilities associated with the discontinued refinery
site in Augusta, Kansas and the current and deferred income taxes and affiliate
note payable. The current and deferred income taxes and the affiliate note
payable were contributed to the Partnership in form of a capital contribution by
an affiliate of Williams. The income and expenses associated with Longhorn will
not be included in the future financial results of the Partnership. Also, as
agreed between the Partnership and Williams, Williams Pipe Line's blending
operations, other than an annual blending fee of approximately $3.0 million,
will not be included in the future financial results of the Partnership. In
addition, general and administrative expenses related to the Williams Pipe Line
system that the Partnership will reimburse to its General Partner will be
limited to $30.0 million per year, subject to an escalation provision.

2. DESCRIPTION OF BUSINESSES

The Partnership owns and operates a petroleum products pipeline system,
petroleum products terminals and an interstate ammonia pipeline system.

WILLIAMS PIPE LINE SYSTEM

Williams Pipe Line is a petroleum products pipeline system that covers an
11-state area extending from Oklahoma through the Midwest to North Dakota and
Illinois. The system includes a 6,700-mile pipeline and 39 terminals that
provide transportation, storage and distribution services. The products
transported on the Williams Pipe Line system are largely refined petroleum
products, including gasoline, diesel fuels, LPGs and aviation fuels. Product
originates on the system from direct connections to refineries and
interconnections with other interstate pipelines for transportation and ultimate
distribution to retail gasoline stations, truck stops, railroads, airlines and
other end-users.

PETROLEUM PRODUCTS TERMINALS

The Partnership has 30 petroleum products terminals that are not part of
the Williams Pipe Line system. Most of these terminals are strategically located
along or near third party pipelines or petroleum refineries. The petroleum
products terminals provide a variety of services such as distribution, storage,
blending, inventory management and additive injection to a diverse customer
group including governmental customers and end-users in the downstream refining,
retail, commercial trading, industrial and petrochemical industries. Products
stored in and distributed through the petroleum products terminal network
include refined petroleum products, blendstocks and heavy oils and feedstocks.
The terminal network consists of marine terminal facilities and inland
terminals. The inland terminals are located primarily in the southeastern United
States. Four marine terminal facilities are located along the Gulf Coast and one
marine terminal facility is located in Connecticut near the New York harbor.

AMMONIA PIPELINE SYSTEM

The ammonia pipeline system consists of an ammonia pipeline and six
company-owned terminals. Shipments on the pipeline primarily originate from
ammonia production plants located in Borger, Texas and Enid and Verdigris,
Oklahoma for transport to terminals throughout the Midwest for ultimate
distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska,
Oklahoma and South Dakota. The ammonia transported through the system is used
primarily as nitrogen fertilizer. Approximately 94% of the ammonia pipeline
system's revenues are generated from transportation tariffs received from three

F-15

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

customers, who are obligated under "ship or pay" contracts to ship an aggregate
minimum of 700,000 tons per year but have historically shipped an amount in
excess of the required minimum. The current ammonia transportation contracts
extend through June 2005.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

The restated consolidated financial statements include the accounts of the
Partnership, Williams Pipe Line and their subsidiaries. The petroleum products
terminal operations consist of 30 petroleum products terminal facilities and
associated storage, located across 12 states primarily in the southeastern and
Gulf Coast areas of the United States. For 11 of these petroleum products
terminals, the Partnership owns varying undivided ownership interests. From
inception, ownership of these assets has been structured as an ownership of an
undivided interest in assets, not as an ownership interest in a partnership,
limited liability company, joint venture or other form of entity. Marketing and
invoicing are controlled separately by each owner, and each owner is responsible
for any loss, damage or injury that may occur to their own customers. As a
result, the Partnership applies proportionate consolidation for its interests in
these assets.

INTERIM FINANCIAL DATA

The interim financial data are unaudited; however in the opinion of
management, the interim financial data includes all adjustments, consisting only
of normal recurring adjustments, necessary for a fair presentation of the
results as of March 31, 2002 and for the three-month periods ended March 31,
2001 and 2002.

USE OF ESTIMATES

REGULATORY REPORTING

Williams Pipe Line is regulated by the Federal Energy Regulatory Commission
("FERC"), which prescribes certain accounting principles and practices for the
annual Form 6 Report filed with the FERC that differ from those used in these
financial statements. Such differences relate primarily to capitalization of
interest, accounting for subsidiaries as equity investments and other
adjustments and are not significant to the financial statements.

CASH EQUIVALENTS

Cash and cash equivalents include demand and time deposits and other
marketable securities with maturities of three months or less when acquired.

INVENTORY VALUATION

Inventory is comprised primarily of refined products, natural gas liquids,
and materials and supplies. Refined products and natural gas liquids inventories
are stated at the lower of average cost or market. The average cost method is
used for materials and supplies.

F-16

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost. Expenditures for
maintenance and repairs are charged to operations in the period incurred.
Depreciation of property, plant and equipment is provided on the straight-line
basis. For petroleum products terminal and ammonia pipeline system assets, the
costs of property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts, and any associated gains
or losses are recorded in the income statement, in the period of sale or
disposition. For Williams Pipe Line, gains or losses from the ordinary sale or
retirement of property, plant and equipment are credited or charged to
accumulated depreciation under FERC accounting guidelines.

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill, which represents the excess of cost over fair value of assets of
businesses acquired, was amortized on a straight-line basis over a period of 20
years for those assets acquired prior to July 1, 2001. Beginning on January 1,
2002, goodwill is no longer amortized but must be evaluated periodically for
impairment. Other intangible assets are amortized on a straight-line basis over
a period of up to 25 years.

IMPAIRMENT OF LONG-LIVED ASSETS

The Partnership evaluates its long-lived assets of identifiable business
activities for impairment when events or changes in circumstances indicate, in
management's judgment, that the carrying value of such assets may not be
recoverable. The determination of whether an impairment has occurred is based on
management's estimate of undiscounted future cash flows attributable to the
assets as compared to the carrying value of the assets. If an impairment has
occurred, the amount of the impairment recognized is determined by estimating
the fair value for the assets and recording a provision for loss if the carrying
value is greater than fair value.

For assets identified to be disposed of in the future, the carrying value
of these assets is compared to the estimated fair value less the cost to sell to
determine if an impairment is required. Until the assets are disposed of, an
estimate of the fair value is redetermined when related events or circumstances
change.

Judgments and assumptions are inherent in management's estimate of
undiscounted future cash flows used to determine recoverability of an asset and
the estimate of an asset's fair value used to calculate the amount of impairment
to recognize. The use of alternate judgments and/or assumptions could result in
the recognition of different levels of impairment charges in the financial
statements.

CAPITALIZATION OF INTEREST

Interest is capitalized based on the approximate average interest rate on
long-term debt. For FERC reporting, capitalization of interest is allowed only
when specific borrowing is directly associated with a capital project.

REVENUE RECOGNITION

Transportation revenues are recognized when products are delivered to
customers. Injection service fees associated with customer proprietary additives
are recognized upon injection to the customer's product, which occurs at the
time the product is delivered. Leased storage, terminalling and other related
revenues are recognized upon provision of contract services. Other revenue,
principally blending and fractionation revenue, is recognized upon sale of the
product.

F-17

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCOME TAXES

Prior to February 9, 2001, the Partnership's operations were included in
Williams' consolidated federal income tax return. The Partnership's income tax
provisions were computed as though separate returns were filed. Deferred income
taxes were computed using the liability method and were provided on all
temporary differences between the financial basis and tax basis of the
Partnership's assets and liabilities.

Effective with the closing of the Partnership's initial public offering on
February 9, 2001 (See Note 1), the Partnership is not a taxable entity for
federal and state income tax purposes. Accordingly, for the petroleum products
and ammonia pipeline system operations after the initial public offering, no
recognition has been given to income taxes for financial reporting purposes. The
tax on Partnership net income is borne by the individual partners through the
allocation of taxable income. Net income for financial statement purposes may
differ significantly from taxable income of unitholders as a result of
differences between the tax basis and financial reporting basis of assets and
liabilities and the taxable income allocation requirements under the
Partnership's partnership agreement. The aggregate difference in the basis of
the Partnership's net assets for financial and tax reporting purposes cannot be
readily determined because information regarding each partner's tax attributes
in the Partnership is not available to the Partnership.

Williams Pipe Line was included in Williams' consolidated federal income
tax return. Deferred income taxes were computed using the liability method and
were provided on all temporary differences between the financial basis and the
tax basis of Williams Pipe Line's assets and liabilities. Williams Pipe Line's
federal provision was computed at existing statutory rates as though a separate
federal tax return were filed. Williams Pipe Line paid its tax liability to
Williams under its tax sharing agreement with Williams. No recognition will be
given to income taxes associated with Williams Pipe Line for financial reporting
purposes for periods subsequent to its acquisition by the Partnership.

EMPLOYEE STOCK-BASED AWARDS

Williams' employee stock-based awards are accounted for under provisions of
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations. Williams' fixed plan common stock
options do not result in compensation expense because the exercise price of the
stock options equals the market price of the underlying stock on the date of
grant.

The General Partner has issued incentive awards of restricted units, or
phantom units, to Williams employees assigned to the Partnership. These awards
are also accounted for under provisions of Accounting Principles Board Opinion
No. 25. Since the exercise price of the unit awards is less than the market
price of the underlying units on the date of grant, compensation expense is
recognized by the General Partner and directly allocated to the Partnership.

ENVIRONMENTAL

Environmental expenditures that relate to current or future revenues are
expensed or capitalized based upon the nature of the expenditures. Expenditures
that relate to an existing condition caused by past operations that do not
contribute to current or future revenue generation are expensed. Environmental
liabilities are recorded independently of any potential claim for recovery.
Receivables are recognized in cases where the realization of reimbursements of
remediation costs are considered probable. Accruals related to environmental
matters are generally determined based on site-specific plans for remediation,
taking into account prior remediation experience of the Partnership and
Williams.

F-18

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EARNINGS PER UNIT

Basic earnings per unit are based on the average number of common and
subordinated units outstanding. Diluted earnings per unit include any dilutive
effect of restricted unit grants.

RECENT ACCOUNTING STANDARDS

In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." The Statement retains the basic framework of SFAS No.
121, resolves certain implementation issues of SFAS No. 121, extends
applicability to discontinued operations and broadens the presentation of
discontinued operations to include a component of an entity. The Statement is to
be applied prospectively and is effective for financial statements issued for
fiscal years beginning after December 15, 2001. The Statement is not expected to
have any initial impact on the Partnership's results of operations or financial
position.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This Statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The
Statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002. The Partnership plans to adopt this standard in
January 2003 and is evaluating its effect on the Partnership's results of
operations and financial position.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 establishes
accounting and reporting standards for business combinations and requires all
business combinations to be accounted for by the purchase method. The Statement
is effective for all business combinations for which the date of acquisition is
July 1, 2001 or later. SFAS No. 142 addresses accounting and reporting standards
for goodwill and other intangible assets. Under this Statement, goodwill and
intangible assets with indefinite useful lives will no longer be amortized, but
will be tested annually for impairment. The Statement becomes effective for all
fiscal years beginning after December 15, 2001. The Partnership will apply the
new rules on accounting for goodwill and other intangible assets beginning
January 1, 2002. Based on the amount of goodwill recorded as of December 31,
2001 application of the non-amortization provision of the Statement will result
in a decrease to amortization expense in future years of approximately $1.1
million.

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

change in fair value will be recognized immediately in earnings. These standards
were adopted on January 1, 2001. There was no impact to the Partnership's
financial position, results of operations or cash flows from adopting these
standards.

The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities." The Statement provides
guidance for determining whether a transfer of financial assets should be
accounted for as a sale or a secured borrowing and whether a liability has been
extinguished. The Statement is effective for recognition and reclassification of
collateral and for disclosures ending after December 15, 2000. The Statement
became effective for transfers and servicing of financial assets and
extinguishments of liabilities occurring after March 31, 2001. The initial
application of SFAS No. 140 had no impact on the Partnership's results of
operations and financial position.

4. ACQUISITIONS AND DIVESTITURE

ACQUISITIONS

Williams Pipe Line

On April 11, 2002, the Partnership acquired all of the membership interests
of Williams Pipe Line from WES for approximately $1.0 billion. The Partnership
remitted to WES consideration in the amount of $674.4 million and WES retained
$15.0 million of Williams Pipe Line's receivables. The $310.6 million balance of
the consideration consisted of $304.4 million of Class B units representing
limited partner interests in the Partnership issued to the General Partner and
affiliates of WES and Williams' contribution to the Partnership by the General
Partner of $6.2 million to maintain its 2% general partner interest. The
Partnership borrowed $700.0 million from a group of financial institutions, paid
WES $674.4 million and used $10.6 million of the funds to pay debt fees and
other transaction costs. The Partnership retained $15.0 million of the funds to
meet working capital needs.

Williams Pipe Line primarily provides petroleum products transportation,
storage and distribution services and will be reported as a separate business
segment of the Partnership. Because of the Partnership's affiliate relationship
with Williams Pipe Line, the transaction was between entities under common
control and, as such, has been accounted for similarly to a pooling of interest.
Accordingly, the consolidated financial statements and notes of the Partnership
have been restated to reflect the historical results of operations, financial
position and cash flows as if the companies had been combined throughout the
periods presented.

The results of operations for the separate companies and the combined
amounts presented in the Consolidated Income Statement follow:

YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Revenues:
Williams Energy Partners........................... $ 44,388 $ 72,492 $ 86,054
Williams Pipe Line................................. 331,344 354,354 362,545
-------- -------- --------
Combined........................................ $375,732 $426,846 $448,599
======== ======== ========
Net Income:
Williams Energy Partners........................... $ 6,766 $ 3,005 $ 21,747
Williams Pipe Line................................. 48,333 45,897 46,125
-------- -------- --------
Combined........................................ $ 55,099 $ 48,902 $ 67,872
======== ======== ========

F-20

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other Acquisitions

Petroleum products terminal facilities and partial ownership interests in
several petroleum products terminals were acquired for cash during the periods
presented and are described below. All acquisitions, except the Aux Sable
transaction, were accounted for as purchases of businesses and the results of
operations of the acquired petroleum products terminals are included with the
combined results of operations from their acquisition dates.

On December 31, 2001, the Partnership purchased an 8.5-mile, 8-inch natural
gas liquids pipeline in northeastern Illinois from Aux Sable Liquid Products
L.P. ("Aux Sable") for $8.9 million. The Partnership then entered into a
long-term lease arrangement under which Aux Sable is the sole lessee of these
assets. The Partnership has accounted for this transaction as a capital lease.
The lease expires in December 2016 and has a purchase option after the first
year. The minimum lease payments to be made by Aux Sable are $19.2 million in
total and $1.3 million per year over each of the next five years. Aux Sable has
the right to re-acquire the pipeline at the end of the lease for a de minimis
amount. The fair value of the lease at December 31, 2001, approximates its
carrying value.

In October 2001, the Partnership acquired the crude oil storage and
distribution assets of Geonet Gathering, Inc. ("Geonet") located in Gibson,
Louisiana. The Partnership acquired these assets with the intent to use the
facility as a crude storage and distribution facility with an affiliate company
as its primary customer. The purchase price was approximately $21.1 million,
consisting of $20.3 million in cash and $0.9 million in assumed liabilities. The
purchase price and allocation to assets acquired and liabilities assumed was as
follows (in thousands):

Purchase price:
Cash paid, including transaction costs.................... $20,261
Liabilities assumed....................................... 856
-------
Total purchase price...................................... $21,117
=======
Allocation of purchase price:
Current assets............................................ $ 62
Property, plant and equipment............................. 4,607
Goodwill.................................................. 13,719
Intangible assets......................................... 2,729
-------
Total allocation.......................................... $21,117
=======

Factors contributing to the recognition of goodwill are the market in which
the facility is located and the opportunity to enter into a throughput agreement
with an affiliate company. Of the amount allocated to intangible assets, $2.0
million represents the value of the leases associated with this facility, which
have amortization periods of up to 25 years. The remaining $0.7 million
allocated to intangible assets represents covenants not-to-compete and has an
amortization period of five years. The total weighted average amortization
period of intangible assets is approximately 16 years. Of the consideration paid
for the facility, $1.0 million is held in escrow, pending final evaluation of
necessary repairs by the Partnership.

In June 2001, the Partnership purchased two petroleum products terminals
located in Little Rock, Arkansas from TransMontaigne, Inc. ("TransMontaigne") at
a cost of $29.1 million, of which $20.2 million was allocated to property, plant
and equipment and $8.9 million to goodwill and other intangibles. Goodwill
resulting from this acquisition is being amortized over a 20-year period. The
final purchase price allocation has not been determined pending assessment of
the environmental liabilities assumed.

F-21

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In April 2001, the Partnership purchased a 6-mile pipeline for $0.3 million
from Equilon Pipeline Company LLC, enabling connection of its existing Dallas,
Texas area petroleum storage and distribution facility to Dallas Love Field. The
acquisition was made in conjunction with an agreement for the Partnership to
provide jet fuel delivery services into Dallas Love Field for Southwest
Airlines. In December 2001, the Partnership completed construction of additional
jet fuel storage tanks at its distribution facility in Dallas to support
delivery of jet fuel to the airport. Total cost of the pipeline and construction
of the additional jet fuel storage tanks totaled $5.5 million.

In September 2000, a northeast petroleum products terminal facility in New
Haven, Connecticut was acquired from Wyatt Energy, Incorporated ("Wyatt") and
its affiliates for approximately $30.8 million.

In March 2000, a 50% ownership interest in CITGO Petroleum Corporation's
petroleum products terminal located in Southlake, Texas was acquired for
approximately $0.3 million.

In August 1999, three storage and distribution petroleum products terminals
and Terminal Pipeline Company ("TPC"), a wholly owned subsidiary of Amerada Hess
Corporation ("Hess"), were acquired from Hess for approximately $212 million.
The petroleum products terminals are located in Galena Park and Corpus Christi,
Texas and Marrero, Louisiana. TPC owned a common carrier pipeline that began at
a connection east of the Houston Ship Channel and terminated at the Galena Park
terminal. The pipeline acquired from Hess was converted to private pipeline
status during 2001.

In February 1999, an additional 10% ownership interest in eight petroleum
products terminals was acquired from Murphy Oil USA, Inc. for approximately $3.4
million, which increased the Partnership's ownership interest to 78.9% from
68.9%. The petroleum products terminals, which are now operated by the
Partnership, are located in Georgia, North Carolina, South Carolina, Tennessee
and Virginia.

In January 1999, 11 petroleum products terminals owned by Amoco Oil Company
("Amoco") were acquired. The petroleum products terminals, located in Alabama,
Florida, Mississippi, North Carolina, Ohio, South Carolina and Tennessee, were
acquired for approximately $6.9 million. In addition, Amoco's 60% interest in a
twelfth petroleum products terminal, located in Greensboro, North Carolina, was
acquired for approximately $1.0 million.

The following summarized unaudited pro forma financial information for the
years ended December 31, 2001 and 2000, reflects the historical results of
Williams Energy Partners on a consolidated basis and assumes each other
acquisition had occurred on January 1 of the year immediately preceding the year
of the acquisition (in thousands):

2000 2001
-------- --------

Revenues:
Williams Energy Partners.................................. $426,846 $448,599
Acquired businesses....................................... 14,354 5,552
-------- --------
Combined............................................... $441,200 $454,151
======== ========
Net income:
Williams Energy Partners.................................. $ 48,902 $ 67,872
Acquired businesses....................................... 1,083 659
-------- --------
Combined............................................... $ 49,985 $ 68,531
======== ========
Basic net income per limited partner unit................... $ 1.95
========

The pro forma results include operating results prior to the acquisitions
and adjustments to interest expense, depreciation expense and income taxes. The
pro forma consolidated results do not purport to be

F-22

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

indicative of results that would have occurred had the acquisitions been in
effect for the periods presented, nor do they purport to be indicative of
results that will be obtained in the future.

Except where stated above, the purchase prices of the above acquisitions
were allocated to various categories of property, plant and equipment and
liabilities based upon the fair value of the assets acquired and liabilities
assumed.

DIVESTITURE

In October 2001, the Meridian, Mississippi terminal, previously reported
with the petroleum products terminals business segment, was sold for $1.7
million. The Partnership recognized a gain of $1.1 million associated with the
sale of the terminal, which is included in other income.

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following (in thousands):

DECEMBER 31, ESTIMATED
----------------------- MARCH 31, DEPRECIABLE
2000 2001 2002 LIVES
---------- ---------- ----------- -----------
(UNAUDITED)

Construction work-in-progress....... $ 20,084 $ 19,193 $ 10,331
Land and right-of-way............... 29,848 30,033 32,549
Carrier property.................... 880,050 905,144 923,748 6-59 years
Buildings........................... 8,533 8,957 8,698 30 years
Storage tanks....................... 154,580 169,066 168,732 30 years
Pipeline and station equipment...... 47,982 58,157 58,242 30-67 years
Processing equipment................ 113,335 124,945 123,505 30 years
Other............................... 21,264 22,898 21,410 10-30 years
---------- ---------- ----------
Total............................. $1,277,676 $1,338,393 $1,347,215
========== ========== ==========

Carrier property is defined as pipeline assets regulated by the FERC. Other
includes $18.6 million of capitalized interest at both December 31, 2001 and
2002 and $19.0 million at March 31, 2002 (unaudited). Depreciation expense for
the years ended December 31, 2001, 2000 and 1999 was $35.2 million, $31.7
million and $25.7 million, respectively, and $9.0 million and $15.5 million for
the three months ended March 31, 2002 and 2001 (unaudited), respectively.

6. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

Williams Energy Marketing & Trading, an affiliate customer, and Customer A
are major customers of the Partnership. No other customer accounted for more
than 10% of total revenues during 1999, 2000 or 2001. Williams Energy Marketing
& Trading is a customer of the petroleum products terminals segment and the
Williams Pipe Line system segment. The percentage of revenues derived by
customer is provided below:

YEAR ENDED DECEMBER 31,
-------------------------
1999 2000 2001
----- ----- -----

Customer A.................................................. 10% 10% 10%
Williams Energy Marketing & Trading......................... 22% 26% 18%
-- -- --
Total..................................................... 32% 36% 28%
== == ==

F-23

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The accounts receivable balance of Williams Energy Marketing & Trading
accounted for 33%, 9% and 10% of total accounts receivable, including affiliate
receivables at December 31, 2000 and 2001, and March 31, 2002 (unaudited),
respectively.

Williams Pipe Line transports refined petroleum products for refiners and
marketers in the petroleum industry. The major concentration of Williams Pipe
Line's customers is located in the central United States. A prepayment process
authorized by tariffs filed with the FERC is employed for all petroleum products
shippers on Williams Pipe Line's system. Due to the prepayment process employed,
credit losses to shippers have been limited. Sales to petroleum products
terminal and ammonia pipeline customers are generally unsecured and the
financial condition and creditworthiness of customers are routinely evaluated.
The Partnership has the ability with many of its terminalling contracts to sell
stored customer products to recover unpaid receivable balances, if necessary.
Any issues impacting the petroleum refining and marketing and anhydrous ammonia
industries could impact the Partnership's overall exposure to credit risk.

Williams Pipe Line's labor force of 601 employees is concentrated in the
central United States. At December 31, 2001, 38% of the employees were
represented by a union and covered by collective bargaining agreements that
expired in February 2002. Williams Pipe Line's union employees ratified a new
four-year collective bargaining agreement with WES in March 2002. The petroleum
products terminals operation's labor force of 195 people are concentrated in the
southeastern and Gulf Coast regions of the United States. Other than at the
Galena Park, Texas marine terminal facility, none of the terminal operations
employees are represented by labor unions. The employees at the Partnership's
Galena Park marine terminal facility are currently represented by a union, but
have indicated their unanimous desire to terminate their union affiliation.
Nevertheless, the National Labor Relations Board has ordered the Partnership to
bargain with the union as the exclusive collective bargaining representative of
the employees at the facility. The Partnership is appealing this decision. If
the Partnership's appeal is unsuccessful, the Partnership will bargain with the
union as ordered by the National Labor Relations Board.

Demand for nitrogen fertilizer has typically followed a combination of
weather patterns and growth in population, acres planted and fertilizer
application rates. Because natural gas is the primary feedstock for the
production of ammonia, the profitability of the Partnership's customers is
impacted by natural gas prices. To the extent these customers are unable to pass
on higher costs to their customers, they may reduce shipments through the
pipeline.

7. EMPLOYEE BENEFIT PLANS

All employees dedicated to, or otherwise supporting, the Partnership are
employees of Williams. Williams Pipe Line maintains a separate non-contributory
defined-benefit pension plan, which covers union employees ("union plan").
Substantially all remaining employees are covered by Williams' noncontributory
defined benefit pension plans and health care plan that provides postretirement
medical benefits to certain retired employees. Contributions for pension and
postretirement medical benefits related to the Partnership's participation in
the Williams' plans were $1.7 million, $1.2 million and $1.5 million in 1999,
2000 and 2001, respectively.

The following table presents the changes in benefit obligations and plan
assets for pension benefits for the union plan for the years indicated. It also
presents a reconciliation of the funded status of these

F-24

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

benefits to the amount recognized in the accompanying balance sheet at December
31 of each year indicated (in thousands):

2000 2001
------- -------

Change in benefit obligation:
Benefit obligation at beginning of year................... $17,125 $19,021
Service cost.............................................. 688 889
Interest cost............................................. 1,340 1,490
Actuarial loss............................................ 1,351 1,279
Benefits paid............................................. (1,483) (1,082)
------- -------
Benefit obligation at end of year......................... $19,021 $21,597
Change in plan assets:
Fair value of plan assets at beginning of year............ $23,341 $21,422
Loss on plan assets....................................... (436) (1,640)
Benefits paid............................................. (1,483) (1,082)
------- -------
Fair value of plan assets at end of year.................. $21,422 $18,700
------- -------
Funded status............................................... $ 2,401 $(2,897)
Unrecognized net actuarial loss............................. 298 5,399
Unrecognized prior service cost............................. 473 420
Unrecognized transition asset............................... (126) --
------- -------
Prepaid benefit cost........................................ $ 3,046 $ 2,922
======= =======

Net pension benefit cost for the union plan consists of the following (in
thousands):

YEAR ENDED DECEMBER 31,
---------------------------
1999 2000 2001
------- ------- -------

Components of net periodic pension expense:
Service cost.......................................... $ 801 $ 688 $ 889
Interest cost......................................... 1,346 1,340 1,490
Expected return on plan assets........................ (1,903) (2,075) (2,182)
Amortization of transition asset...................... (135) (135) (126)
Amortization of prior service cost.................... 53 53 53
Recognized net actuarial loss......................... 88 -- --
------- ------- -------
Net periodic pension expense (income)................. $ 250 $ (129) $ 124
======= ======= =======

2000 2001
----- -----

Discount rate............................................... 7.50% 7.50%
Expected return on plan assets.............................. 10.00% 10.00%
Rate of compensation increase............................... 5.00% 5.00%

Williams maintains various defined contribution plans in which employees
supporting the Partnership are included. The Partnership's costs related to
these plans were $1.8 million, $2.0 million and $2.4 million in 1999, 2000 and
2001, respectively.

F-25

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. RELATED PARTY TRANSACTIONS

The Partnership and Williams Pipe Line have entered into agreements with
various Williams subsidiaries. Agreements with Williams Energy Marketing &
Trading provide for sales of blended gasoline processed by Williams Pipe Line
and sales of pipeline inventory overages, as well as lease storage capacity. The
Partnership has several agreements with Williams Energy Marketing & Trading,
which provide for: (i) the access to and utilization of the inland terminals,
(ii) approximately 2.5 million barrels of storage and other ancillary services
at the Partnership's marine terminal facilities and (iii) capacity utilization
rights to substantially all of the capacity of the Gibson, Louisiana marine
terminal facility. Williams Pipe Line has entered into agreements with
Mid-America Pipeline and Williams Bio Energy, both of which are affiliates of
Williams, to provide tank storage and pipeline system storage, respectively.

Historically, Williams Pipe Line also has been a party to an agreement with
Williams Refining & Marketing for sales of blended gasoline. (See Note
1 -- Organization and Presentation for more information about income and
expenses associated with Williams Pipe Line operations that will not be
conducted by the Partnership). Also, both Williams Energy Marketing & Trading
and Williams Refining & Marketing ship products on the Williams Pipe Line
system. Additionally, the Partnership has agreements with Williams Refining &
Marketing for the access and utilization of the Partnership's inland terminal
facilities. The following are revenues from various Williams subsidiaries (in
thousands):

YEAR ENDED DECEMBER 31,
----------------------------
1999 2000 2001
------- -------- -------

Williams Energy Marketing & Trading.................... $81,481 $111,847 $81,999
Williams Refining & Marketing.......................... -- -- 6,575
Williams Bio Energy.................................... 2,857 2,379 3,499
Mid-America Pipeline................................... 282 282 285
Other.................................................. 495 20 894
------- -------- -------
Total................................................ $85,115 $114,528 $93,252
======= ======== =======

Williams Pipe Line has various other transactions with Williams and its
subsidiaries in the ordinary course of business. Williams Pipe Line has also
entered into agreements with Williams Energy Marketing & Trading to purchase
product for blending activity, transmix for fractionation activity and product
to settle shortages. Mid-America Pipeline also leases storage space to Williams
Pipe Line. The following are costs and expenses from various affiliate companies
to Williams Pipe Line and the Partnership (in thousands):

YEAR ENDED DECEMBER 31,
---------------------------
1999 2000 2001
------- ------- -------

WES -- directly allocable expenses...................... $25,253 $27,303 $18,970
Williams -- allocated general corporate expenses........ 5,045 15,380 18,123
Williams Energy Marketing & Trading -- product
purchases............................................. 25,276 47,466 80,959
Mid-America Pipeline -- operating and maintenance....... 1,421 2,060 2,730

The above costs are reflected in the cost and expenses in the accompanying
consolidated statements of income. In management's estimation the direct and
allocated expenses represent amounts that would have been incurred on a
stand-alone basis.

In addition, Williams allocates interest expense charges to its affiliates
based on their inter-company debt balances (see note 10). The Partnership
entities also participate in employee benefit plans and long-term incentive
plans sponsored by Williams (see notes 7 and 11).

F-26

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Williams allocates both direct and indirect general and administrative
expenses to its subsidiaries. Direct expenses allocated by Williams are
primarily salaries and benefits of employees and officers associated with the
business activities of the subsidiary. Indirect expenses include legal,
accounting, treasury, engineering, information technology and other corporate
services. Williams allocates indirect expenses to its subsidiaries, including
the general partner, based on a three-factor formula that considers operating
margins, payroll costs and property, plant and equipment. The Partnership
reimburses the General Partner and its affiliates for direct and indirect
expenses incurred by or allocated to them on the Partnership's behalf.

In connection with its initial public offering, and with respect solely to
the petroleum products terminal and ammonia pipeline assets held at the time of
that offering, the Partnership and the General Partner agreed with Williams that
the general and administrative expenses to be reimbursed to the General Partner
by the Partnership would not exceed $6.0 million for 2001, excluding expenses
associated with the Partnership's long-term incentive plan, regardless of the
amount of the direct and indirect general and administrative expenses actually
incurred by or allocated to the General Partner. The reimbursement limitation
will remain in place through 2011 and may increase by no more than the greater
of 7.0% per year or the percentage increase in the consumer price index for that
year. If the Partnership makes an acquisition, general and administrative
expenses may also increase by the amount of these expenses included in the
valuation of the business acquired. As a result of the acquisitions made during
2001, the annual amount of general and administrative expense reimbursement
limitation increased to $6.3 million, excluding expenses associated with
long-term incentive plan. Based on the 7.0% escalation, the Partnership's
maximum reimbursement obligation for general and administrative expenses in
2002, for the petroleum products terminals and ammonia pipeline system
operations, is $6.7 million before long-term incentive plan charges and
adjustments for acquisitions.

As a result of the acquisition of Williams Pipe Line, general and
administrative expenses that had previously been incurred by or allocated to
Williams Pipe Line will be charged to the General Partner. In connection with
the acquisition, the Partnership and the General Partner agreed with Williams
that the general and administrative expenses to be reimbursed to the General
Partner by the Partnership for charges related to the Williams Pipe Line system
would be $30.0 million for 2002, prorated for the actual period that the
Partnership owns the Williams Pipe Line. In each year after 2002, these expenses
may increase by the lesser of 2.5% per year or the percentage increase in the
consumer price index for that year. The additional general and administrative
costs incurred by the General Partner, but not charged to the Partnership,
totaled $10.4 million for the period February 10, 2001 through December 31,
2001, $0.5 million for the period February 10, 2001 through March 31, 2001
(unaudited) and $2.8 million for the period January 1, 2002 through March 31,
2002 (unaudited).

Williams Pipe Line had contributed $0.9 million to Longhorn in exchange for
a 0.3% ownership interest. Williams Pipe Line also had an agreement to construct
a pipeline, terminals and stations and charge a fee for these services to
Longhorn. Under this agreement, Williams Pipe Line paid for construction costs
and was reimbursed by Longhorn. The agreement allowed Longhorn to defer payment
of certain construction costs until it generated break-even cash flows and
allowed Williams Pipe Line to charge interest on the outstanding receivable
balance. Williams Pipe Line also had an agreement to manage the pipeline for
Longhorn for an agreed-upon monthly fee. The total amount receivable from
Longhorn at December 31, 2001 and 2000 was $16.8 million and $20.0 million
(which includes $3.1 million classified as current), respectively, and $19.3
million at March 31, 2002 (unaudited). (See Note 1 -- Organization and
Presentation for more information about income and expenses associated with
Williams Pipe Line operations that will not be conducted by the Partnership).

F-27

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. INCOME TAXES

The provision for income taxes is as follows (in thousands):

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
--------------------------- -------------------
1999 2000 2001 2001 2002
------- ------- ------- ------- -------
(UNAUDITED)

Current:
Federal............................ $10,466 $24,779 $19,405 $3,786 $5,807
State.............................. 1,272 3,406 3,669 566 874
Deferred:
Federal............................ 19,379 1,743 5,597 1,248 987
State.............................. 3,004 486 841 159 148
------- ------- ------- ------ ------
$34,121 $30,414 $29,512 $5,759 $7,816
======= ======= ======= ====== ======

Reconciliations from the provision for income taxes at the U.S. federal
statutory rate to the effective tax rate for the provision for income taxes are
as follows (in thousands):

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
--------------------------- -------------------
1999 2000 2001 2001 2002
------- ------- ------- -------- --------
(UNAUDITED)

Income taxes at statutory rate....... $31,227 $27,760 $34,084 $ 6,584 $10,129
Less: income taxes at statutory rate
on income applicable to partners
interest........................... -- -- (7,504) (1,245) (2,977)
Increase resulting from:
State taxes, net of federal income
tax benefit..................... 2,780 2,529 2,931 420 664
Other.............................. 114 125 1 -- --
------- ------- ------- ------- -------
Provision for income taxes........... $34,121 $30,414 $29,512 $ 5,759 $ 7,816
======= ======= ======= ======= =======

F-28

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Significant components of deferred tax liabilities and assets as of
December 31, 2000 and 2001 and March 31, 2002 (unaudited) are as follows (in
thousands):

DECEMBER 31,
------------------- MARCH 31,
2000 2001 2002
-------- -------- -----------
(UNAUDITED)

Deferred tax liabilities:
Property, plant and equipment..................... $182,662 $147,775 $148,910
Other............................................. 650 841 841
-------- -------- --------
Total deferred tax liabilities................. $183,312 $148,616 $149,751
Deferred tax assets:
Net operating loss carryforward................... $ 25,270 $ -- $ --
Other............................................. 7,154 5,266 5,266
-------- -------- --------
Total deferred tax assets...................... $ 32,424 $ 5,266 $ 5,266
Valuation allowance................................. 1,989 1,989 1,989
-------- -------- --------
Net deferred tax assets........................ $ 30,435 $ 3,277 $ 3,277
-------- -------- --------
Net deferred tax liabilities................. $152,877 $145,339 $146,474
======== ======== ========

The Partnership recognized a pre-initial public offering federal net
operating loss for income tax purposes of $3.9 million and $57.0 million for the
years 2001 and 2000, respectively. The $3.9 million federal net operating loss
expires in 2021. The $57.0 million federal net operating loss carryforward
expires in 2020. Payments to Williams in lieu of income taxes were $2.3 million
in 1999.

As a result of the initial public offering and the concurrent transactions
on February 9, 2001 (see Note 1), the net deferred tax liability on that date of
approximately $14.0 million was assumed by Williams, in exchange for an
additional equity investment in the Partnership.

10. LONG-TERM DEBT

Long-term debt and available borrowing capacity for the Partnership at
December 31, 2001, were $139.5 million and $35.5 million, respectively, and
$148.0 million and $27.0 million at March 31, 2002 (unaudited), respectively. At
both March 31, 2002 (unaudited) and December 31, 2001, the OLP had a $175.0
million bank credit facility. The credit facility was comprised of a $90.0
million term loan facility and an $85.0 million revolving credit facility, which
includes a $73.0 million acquisition sub-facility and a $12.0 million working
capital sub-facility. On February 9, 2001, the OLP borrowed $90.0 million under
the term loan facility and $0.1 million under the acquisition sub-facility. The
$0.1 million borrowed under the acquisition sub-facility was repaid in July
2001. In June 2001, the OLP borrowed $29.5 million under the acquisition
facility to fund the purchase of two terminals in Little Rock, Arkansas from
TransMontaigne. In October 2001, the OLP borrowed $20.0 million to fund the
acquisition of the Gibson, Louisiana terminal from Geonet. In January 2002, the
OLP borrowed $8.5 million to finance the acquisition of a pipeline from Aux
Sable. The Partnership entered into a long-term lease arrangement with Aux Sable
under which Aux Sable is the sole lessee of these assets. The transaction will
be accounted for as a capital lease.

The credit facility's term extends through February 5, 2004, with all
amounts due at that time. Borrowings under the credit facility carry an interest
rate equal to the Eurodollar rate plus a spread from 1.0% to 1.5%, depending on
the OLP's leverage ratio. Interest is also assessed on the unused portion of the
credit facility at a rate from 0.2% to 0.4%, depending on the OLP's leverage
ratio. The OLP's leverage ratio is defined as the ratio of consolidated total
debt to consolidated earnings before interest, income

F-29

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

taxes, depreciation and amortization for the period of the four fiscal quarters
ending on such date. Closing fees associated with the initiation of the credit
facility were $0.9 million, which are being amortized over the life of the
facility. Average interest rates were 3.1% for the term loan facility and 3.3%
for the acquisition subfacility at both December 31, 2001 and March 31, 2002
(unaudited). The fair value of the long-term debt approximates its carrying
value, because of the floating interest rate applied to the debt facility.

Long-term affiliate debt for the Partnership consists of the following (in
thousands):

DECEMBER 31,
------------------- MARCH 31,
2000 2001 2002
-------- -------- -----------
(UNAUDITED)

WES affiliate note.................................. $386,731 $138,172 $108,392
Williams Pipe Line affiliate note................... 46,226 -- --
-------- -------- --------
Total............................................. $432,957 $138,172 $108,392
======== ======== ========

Williams Pipe Line was a participant in an inter-company note between WES
and Williams. Terms of the affiliate note required payment on demand; however,
Williams had no plans or intentions to demand payment within the next 12 months
at any time the note was outstanding. Under WES' cash management practices,
Williams Pipe Line shared banking arrangements with other WES subsidiaries.
Interest expense charges from Williams to WES were allocated to Williams Pipe
Line based on WES subsidiaries inter-company balances. Interest rates varied
with current market conditions (7.6% at December 31, 2000, 2.8% at December 31,
2001, and 2.6% at March 31, 2002 (unaudited)). (See Note 1 -- Organization and
Presentation for more information about income and expenses associated with
Williams Pipe Line operations that will not be conducted by the Partnership).

At December 31, 2000, Williams Pipe Line had an affiliate note payable to
Williams. This note was repaid during 2001. Interest was calculated and paid
monthly. Interest rates varied with current market conditions (7.6% at December
31, 2000).

Prior to February 9, 2001, the petroleum products terminals and ammonia
pipeline business segments of the Partnership were participants in Williams'
cash management program. As of December 31, 2000, the affiliate note payable
associated with these segments consisted of an unsecured promissory note
agreement with Williams for advances from Williams. The advances were due on
demand; however, in February 2001, a portion of the advances was refinanced with
proceeds from the Partnership's initial public offering and borrowings under the
OLP's credit facility (see Note 1). Williams contributed the remaining advances
in exchange for equity of the Partnership. Therefore, the affiliate note payable
was classified as noncurrent at December 31, 2000.

Prior to the initial public offering, affiliate interest income or expense
charged or credited to the petroleum products terminals and ammonia pipeline
operations was calculated at the London Interbank Offered Rate ("LIBOR") plus a
spread based on the outstanding balance of the note receivable or note payable
with Williams. The spread was equivalent to the spread above LIBOR rates on
Williams' revolving credit facility. The interest rate of the note with Williams
was 7.6% at December 31, 2000. As the interest rate on the affiliate note
payable was variable, the carrying value of the affiliate note payable at
December 31, 2000 approximated its fair value.

During years ending December 31, 1999, 2000, and 2001, cash payments for
interest, net of amounts capitalized, were $13.7 million, $11.3 million and $9.3
million, respectively.

F-30

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. LONG-TERM INCENTIVE PLAN

In February 2001, the General Partner adopted the Partnership's Long-Term
Incentive Plan for Williams' employees who perform services for the Partnership
and directors of the General Partner. The Long-Term Incentive Plan consists of
two components, restricted units, which are also referred to as phantom units,
and unit options. The Long-Term Incentive Plan permits the grant of awards
covering an aggregate of 700,000 common units. The Long-Term Incentive Plan is
administered by the compensation committee of the General Partner's board of
directors.

In April 2001, the General Partner issued grants of 92,500 phantom units to
certain key employees associated with the Partnership's initial public offering
in February 2001. These one-time initial public offering phantom units will vest
over a 34-month period ending on February 9, 2004, and are subject to forfeiture
if employment is terminated prior to vesting. These units are subject to early
vesting if the Partnership achieves certain performance measures. The
Partnership recognized $0.7 million of compensation expense associated with
these grants in 2001. The fair market value of the phantom units associated with
this grant was $2.7 million on the grant date. On February 14, 2002, one-half of
these phantom units vested, resulting in additional compensation expense of $1.0
million to the Partnership (see Note 15 -- Distributions).

In April 2001, the General Partner issued grants of 64,200 phantom units
associated with the annual incentive compensation plan. The actual number of
units that will be awarded under this grant will be determined by the
Partnership on February 9, 2004. At that time, the Partnership will assess
whether certain performance criteria have been met and determine the number of
units that will be awarded, which could range from zero units up to a total of
128,400 units. These units are also subject to forfeiture if employment is
terminated prior to February 9, 2004. These awards do not have an early vesting
feature. The Partnership recognized $1.3 million of deferred compensation
expense associated with these awards in 2001. The fair market value of the
phantom units associated with this grant was $5.4 million on December 31, 2001
and $5.0 million on March 31, 2002 (unaudited).

Certain employees of Williams dedicated to or otherwise supporting the
Partnership receive stock-based compensation awards from Williams. Williams has
several plans providing for common-stock-based awards to employees and to
nonemployee directors. The plans permit the granting of various types of awards
including, but not limited to, stock options, stock-appreciation rights,
restricted stock and deferred stock. Awards may be granted for no consideration
other than prior and future services or based on certain financial performance
targets being achieved. The purchase price per share for stock options and the
grant price for stock-appreciation rights may not be less than the market price
of the underlying stock on the date of grant. Depending upon terms of the
respective plans, stock options generally become exercisable in one-third
increments each year from the date of the grant or after three or five years,
subject to accelerated vesting if certain future Williams' stock prices or
specific Williams' financial performance targets are achieved. Stock options
expire 10 years after grant.

F-31

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following summary reflects activity for options to purchase shares of
Williams common stock for 1999, 2000 and 2001 for those employees principally
supporting the Partnership operations:

1999 2000 2001
------------------- ------------------- -------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- --------- ------- --------- ------- ---------

Outstanding -- beginning of
year............................ 233,374 $22.22 306,307 $28.05 371,502 $31.92
Granted........................... 117,494 36.54 82,887 43.16 102,584 34.96
Forfeited......................... -- -- (109) 34.54 (3,000) 30.14
Exercised......................... (44,561) 19.87 (17,583) 17.76 (9,291) 22.59
------- ------- -------
Outstanding -- ending of year..... 306,307 28.05 371,502 31.91 461,795 32.80
======= ======= =======
Exercisable at end of year........ 263,470 27.00 328,774 31.59 316,483 31.85
======= ======= =======

The following summary provides information about outstanding and
exercisable Williams' stock options, held by employees principally supporting
the partnership's operations, at December 31, 2001:

WEIGHTED-
WEIGHTED- AVERAGE
AVERAGE REMAINING
EXERCISE CONTRACTUAL
RANGE OF EXERCISE PRICES OPTIONS PRICE LIFE
------------------------ ------- --------- -----------

$12.22 to $17.31...................................... 38,599 $15.19 4.5 years
$20.83 to $30.00...................................... 102,704 25.14 6.0 years
$31.56 to $46.06...................................... 320,492 37.36 8.1 years
-------
Total............................................... 461,795 32.79 7.3 years
=======

The estimated fair value at the date of grant of options for Williams'
common stock granted in 1999, 2000 and 2001, using the Black-Scholes option
pricing model, is as follows:

1999 2000 2001
------ ------ ------

Weighted-average grant date fair value of options for
Williams' common stock granted during the year........... $11.90 $15.44 $11.08
Assumptions:
Dividend yield........................................... 1.5% 1.5% 1.9%
Volatility............................................... 28.0% 31.0% 34.5%
Risk-free interest rate.................................. 5.6% 6.5% 4.8%
Expected life (years).................................... 5.0 5.0 5.0

Pro forma net income, assuming the Partnership had applied the fair-value
method of SFAS No. 123, "Accounting for Stock-Based Compensation" in measuring
compensation costs beginning with 1999 employee stock-based awards, are as
follows (in thousands, except per unit amounts):

1999 2000 2001
-------------------- -------------------- --------------------
PRO FORMA REPORTED PRO FORMA REPORTED PRO FORMA REPORTED
--------- -------- --------- -------- --------- --------

Net income............... $54,171 $55,099 $48,167 $48,902 $67,710 $67,872
======= ======= ======= ======= ======= =======
Net income per limited
partner unit........... $ 1.86 $ 1.87
======= =======

F-32

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Pro forma amounts for 1999 include the remaining total compensation expense
from Williams' awards made in 1998 and the total compensation expense from
Williams' awards made in 1999 as a result of the accelerated vesting provisions.
Since compensation expense from stock options is recognized over the future
years' vesting period for pro forma disclosure purposes, and additional awards
generally are made each year, pro forma amounts may not be representative of
future years' amounts. Pro forma amounts for 2000 include the total compensation
expense from the awards made in 2000, as these awards fully vested in 2000 as a
result of the accelerated vesting provisions.

12. SEGMENT DISCLOSURES

Management evaluates performance based upon segment profit or loss from
operations, which includes revenues from affiliate and external customers,
operating expenses, depreciation and affiliate general and administrative
expenses. The accounting policies of the segments are the same as those
described in Note 3 -- Summary of Significant Accounting Policies. Affiliate
revenues are accounted for as if the sales were to unaffiliated third parties.

The Partnership's reportable segments are strategic business units that
offer different products and services. The segments are managed separately
because each segment requires different marketing strategies and business
knowledge.

YEAR ENDED DECEMBER 31, 1999
-------------------------------------------
WILLIAMS PETROLEUM AMMONIA
PIPE LINE PRODUCTS PIPELINE
SYSTEM TERMINALS SYSTEM TOTAL
--------- --------- -------- --------
(IN THOUSANDS)

Revenues:
Third party customers............................... $235,273 $ 25,330 $12,139 $272,742
Affiliate customers................................. 96,071 6,919 -- 102,990
-------- -------- ------- --------
Total revenues.................................... $331,344 $ 32,249 $12,139 $375,732
Operating expenses.................................. 102,964 15,108 3,527 121,599
Product purchases................................... 59,230 -- -- 59,230
Affiliate construction expenses..................... 15,464 -- -- 15,464
Depreciation and amortization....................... 21,060 3,969 641 25,670
Affiliate general and administrative expenses....... 41,604 3,915 1,543 47,062
-------- -------- ------- --------
Segment profit...................................... $ 91,022 $ 9,257 $ 6,428 $106,707
======== ======== ======= ========
Total assets........................................ $690,600 $261,425 $21,914 $973,939
Additions to long-lived assets...................... $ 40,173 $227,234 $ 384 $267,791

F-33

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEAR ENDED DECEMBER 31, 2000
---------------------------------------------
WILLIAMS PETROLEUM AMMONIA
PIPE LINE PRODUCTS PIPELINE
SYSTEM TERMINALS SYSTEM TOTAL
--------- --------- -------- ----------
(IN THOUSANDS)

Revenues:
Third party customers............................. $255,389 $ 43,367 $11,710 $ 310,466
Affiliate customers............................... 98,965 17,415 -- 116,380
-------- -------- ------- ----------
Total revenues.................................. $354,354 $ 60,782 $11,710 $ 426,846
Operating expenses................................ 111,410 29,496 3,993 144,899
Product purchases................................. 94,141 -- -- 94,141
Affiliate construction expenses................... 1,025 -- -- 1,025
Depreciation and amortization..................... 22,413 8,688 645 31,746
General and administrative expenses............... 39,243 10,351 1,612 51,206
-------- -------- ------- ----------
Segment profit.................................... $ 86,122 $ 12,247 $ 5,460 $ 103,829
======== ======== ======= ==========
Total assets...................................... $731,654 $296,819 $21,686 $1,050,159
Additions to long-lived assets.................... $ 32,697 $ 41,348 $ 401 $ 74,446

YEAR ENDED DECEMBER 31, 2001
---------------------------------------------
WILLIAMS PETROLEUM AMMONIA
PIPE LINE PRODUCTS PIPELINE
SYSTEM TERMINALS SYSTEM TOTAL
--------- --------- -------- ----------
(IN THOUSANDS)

Revenues:
Third party customers............................. $284,174 $ 55,611 $14,544 $ 354,329
Affiliate customers............................... 78,371 15,899 -- 94,270
-------- -------- ------- ----------
Total revenues.................................. $362,545 $ 71,510 $14,544 $ 448,599
Operating expenses................................ 123,566 33,270 4,044 160,880
Product purchases................................. 95,268 -- -- 95,268
Depreciation and amortization..................... 24,019 11,099 649 35,767
General and administrative expenses............... 38,410 7,641 1,314 47,365
-------- -------- ------- ----------
Segment profit.................................... $ 81,282 $ 19,500 $ 8,537 $ 109,319
======== ======== ======= ==========
Total assets...................................... $705,115 $368,409 $31,035 $1,104,559
Goodwill.......................................... $ -- $ 22,282 $ -- $ 22,282
Additions to long-lived assets.................... $ 24,232 $ 64,590 $ 330 $ 89,152

F-34

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Non-cash charges for incentive compensation costs, included in 2001 general
and administrative expenses, were $1.7 million for the petroleum products
terminal operations and $0.3 million for the ammonia pipeline operations.

THREE MONTHS ENDED MARCH 31, 2001
-------------------------------------------
WILLIAMS PETROLEUM AMMONIA
PIPE LINE PRODUCTS PIPELINE
SYSTEM TERMINALS SYSTEM TOTAL
--------- --------- -------- --------
(IN THOUSANDS -- UNAUDITED)

Revenues:
Third party customers................................ $70,533 $13,545 $2,688 $ 86,766
Affiliate customers.................................. 16,857 4,053 -- 20,910
------- ------- ------ --------
Total revenues....................................... 87,390 17,598 2,688 107,676
Operating expenses................................... 29,235 7,177 943 37,355
Product purchases.................................... 27,844 -- -- 27,844
Depreciation and amortization........................ 5,935 2,944 162 9,041
Affiliate general and administrative expenses........ 8,295 2,016 267 10,578
------- ------- ------ --------
Segment profit....................................... $16,081 $ 5,461 $1,316 $ 22,858
======= ======= ====== ========

THREE MONTHS ENDED MARCH 31, 2002
-------------------------------------------
WILLIAMS PETROLEUM AMMONIA
PIPE LINE PRODUCTS PIPELINE
SYSTEM TERMINALS SYSTEM TOTAL
--------- --------- -------- --------
(IN THOUSANDS -- UNAUDITED)

Revenues:
Third party customers................................ $59,457 $15,546 $4,375 $ 79,378
Affiliate customers.................................. 18,969 4,301 -- 23,270
------- ------- ------ --------
Total revenues....................................... 78,426 19,847 4,375 102,648
Operating expenses................................... 24,509 7,412 1,145 33,066
Product purchases.................................... 18,409 -- -- 18,409
Depreciation and amortization........................ 6,056 2,744 164 8,964
Affiliate general and administrative expenses........ 10,229 2,677 551 13,457
------- ------- ------ --------
Segment profit....................................... $19,223 $ 7,014 $2,515 $ 28,752
======= ======= ====== ========

13. COMMITMENTS AND CONTINGENCIES

The Partnership leases land, tanks and related terminal equipment at the
Gibson terminal facility. Minimum future lease payments for these leases as of
December 31, 2001, are $0.1 million for each of the next five years and $1.7
million thereafter. The lease payments can be canceled after 2006 and include
provisions for renewal of the lease at five-year increments which can extend the
lease for a total of 25 years.

WES has agreed to indemnify the Partnership against any covered
environmental losses, up to $15.0 million, relating to assets it contributed to
the Partnership that arose prior to February 9, 2001, that become known within
three years after February 9, 2001, and that exceed all amounts recovered or
recoverable by the Partnership under contractual indemnities from third parties
or under any applicable insurance policies. Covered environmental losses are
those non-contingent terminal and ammonia system environmental losses, costs,
damages and expenses suffered or incurred by the Partnership arising from
F-35

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

correction of violations of, or performance of remediation required by,
environmental laws in effect at February 9, 2001, due to events and conditions
associated with the operation of the assets and occurring before February 9,
2001.

In connection with the acquisition of Williams Pipe Line, WES agreed to
indemnify the Partnership for any breach of a representation or warranty that
results in losses and damages of up to $110.0 million after the payment of a
$6.0 million deductible. With respect to any amount exceeding $110.0 million,
WES will be responsible for one-half of that amount up to $140.0 million. In no
event will WES' liability exceed $125.0 million. These indemnification
obligations will survive for one year, except that those relating to employees
and employee benefits will survive for the applicable statute of limitations and
those relating to real property, including title to WES' assets, will survive
for ten years. This indemnity also provides that the Partnership will be
indemnified for an unlimited amount of losses and damages related to tax
liabilities. In addition, any losses and damages related to environmental
liabilities that arose prior to the acquisition will be subject only to a $2.0
million deductible.

Estimated liabilities for environmental remediation costs were $14.1
million, $16.9 million and $16.8 million at December 31, 2000 and 2001 and March
31, 2002 (unaudited), respectively. Management estimates that expenditures
associated with the accrued environmental remediation liabilities will be paid
over the next two to five years. Receivables associated with these environmental
liabilities of $0.3 million, $5.1 million and $5.1 million at December 31, 2000
and 2001 and March 31, 2002 (unaudited), respectively, have been recognized as
recoverable from affiliates and third parties. These estimates, provided on an
undiscounted basis, were determined based primarily on data provided by a
third-party environmental evaluation service. These liabilities have been
classified as current or non-current based on management's estimates regarding
the timing of actual payments. (See Note 1 -- Organization and Presentation for
more information about liabilities associated with Williams Pipe Line operations
that were conveyed to and assumed by an affiliate of Williams prior to the
acquisition of Williams Pipe Line by the Partnership).

In conjunction with the 1999 acquisition of the Gulf Coast marine terminals
from Hess, Hess has disclosed to the Partnership all suits, actions, claims,
arbitrations, administrative, governmental investigation or other legal
proceedings pending or threatened, against or related to the assets acquired by
the Partnership, which arise under environmental law. Hess agreed to indemnify
the Partnership through July 30, 2014 against all known and required
environmental remediation costs at the Corpus Christi and Galena Park, Texas
marine terminal facilities from any matters related to pre-acquisition actions.
In the event that any pre-acquisition releases of hazardous substances at the
Partnership's Corpus Christi and Galena Park and Marrero, Louisiana marine
terminal facilities are identified by the Partnership prior to July 30, 2004,
the Partnership will be liable for the first $2.5 million of environmental
liabilities, Hess will be liable for the next $12.5 million of losses, and the
Partnership will assume responsibility for any losses in excess of $15.0
million. Hess has indemnified the Partnership for a variety of pre-acquisition
fines and claims that may be imposed or asserted against the Partnership under
certain environmental laws. At December 31, 2001, December 31, 2000 and March
31, 2002 (unaudited), the Partnership had accrued $0.6 million for costs that
may not be recoverable under Hess' indemnification.

During 2001, the Partnership recorded an environmental liability of $2.6
million at its New Haven, Connecticut facility, which was acquired in September
2000. This liability was based on third-party environmental engineering
estimates completed as part of a Phase II environmental assessment, routinely
required by the State of Connecticut to be conducted by the purchaser following
the acquisition of a petroleum storage facility. The Partnership will complete a
Phase III environmental assessment at this facility during the second or third
quarter of 2002, and the environmental liability could change materially based
on this more thorough analysis. The seller of these assets agreed to indemnify
the Partnership for certain of these environmental liabilities. In addition, the
Partnership purchased insurance for up to

F-36

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$25.0 million of environmental liabilities associated with these assets, which
carries a deductible of $0.3 million.

WNGL will indemnify the Partnership for right-of-way defects or failures in
the Partnership's ammonia pipeline easements for 15 years after the initial
public offering closing date. WES has also indemnified the Partnership for
right-of-way defects or failures associated with the marine terminal facilities
at Galena Park and Corpus Christi, Texas and Marrero, Louisiana for 15 years
after the initial public offering closing date. In addition, WES has indemnified
the Partnership for right-of-way defects or failures in Williams Pipe Line's
easements for 10 years after the closing date of its acquisition by the
Partnership up to a maximum of $125.0 million with a deductible of $6.0 million.
This $125.0 million amount will also be subject to indemnification claims made
by the Partnership for breaches of other representations and warranties.

The Partnership is party to various other claims, legal actions and
complaints arising in the ordinary course of business. In the opinion of
management, the ultimate resolution of all claims, legal actions and complaints
after consideration of amounts accrued, insurance coverage or other
indemnification arrangements will not have a material adverse effect upon the
Partnership's future financial position, results of operations or cash flows.

14. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows (in thousands, except per
unit amounts).

FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------

2000
Revenues...................................... $ 94,819 $104,532 $ 99,900 $127,595
Total costs and expenses...................... 66,987 74,013 73,465 108,552
Net income.................................... 13,170 14,681 13,440 7,611
2001
Revenues...................................... $107,676 $108,890 $118,201 $113,832
Total costs and expenses...................... 84,818 75,376 89,871 89,215
Net income.................................... 13,053 22,887 18,150 13,782
Basic and diluted net income per limited
partner unit................................ 0.31 0.64 0.49 0.42

Basic and diluted net income for the first quarter of 2001 is calculated on
the Limited Partners' interest in net income applicable for the period after
February 9, 2001, through the end of the quarter. Revenues and expenses in 2001
were impacted by the acquisition of two terminals from TransMontaigne in June
2001 and the Gibson terminal from Geonet in October 2001. See Note
4 -- Acquisitions. First quarter 2001 costs and expenses included $0.9 million
of casualty losses. Second quarter 2001 revenues were impacted by a $1.0 million
throughput deficiency billing to an ammonia pipeline customer. Operating
expenses included a $0.8 million reduction of environmental expense associated
with insurance settlement and net income included a $0.9 million gain on the
sale of the Aurora, Ohio terminal. Fourth quarter 2001 net income included a
gain of $1.1 million on the sale of the Meridian, Mississippi terminal. Interest
expense for 2001 reflects the payment and forgiveness of the predecessor
company's affiliate debt and new borrowings by the Partnership. Net income was
also impacted by incentive compensation costs of $2.0 million during 2001.

Revenues and costs and expenses in 2000 were impacted by the Southlake
terminal acquisition in March 2000 and the marine terminal acquisition from
Wyatt in September 2000. A throughput revenue

F-37

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

deficiency billing related to the August 1999 acquisition of certain assets from
Hess resulted in adjustments to revenues of $0.7 million impacting the first and
second quarters of 2000. Second quarter 2000 expenses included a $0.5 million
charge from the write-off of an unsuccessful business transaction and a $0.5
million charge for legal costs. Third quarter 2000 costs and expenses included a
$1.5 million environmental accrual. Fourth quarter 2000 costs and expenses
included an increase in product purchases of $25.0 million due to increased
product prices, $4.4 million of environmental charges, $1.9 million for casualty
losses and a $1.0 million charge associated with a customer dispute settlement.

15. DISTRIBUTIONS

On May 15, 2001, the Partnership paid cash distributions of $0.292 per unit
on its outstanding common and subordinated units to unitholders of record at the
close of business on May 1, 2001. This distribution represented the minimum
quarterly distribution for the 50-day period following the initial public
offering closing date, which included February 10, 2001 through March 31, 2001.
The total distributions paid were $3.4 million.

On August 14, 2001, the Partnership paid cash distributions of $0.5625 per
unit on its outstanding common and subordinated units to unitholders of record
at the close of business on August 2, 2001. The total distributions paid were
$6.5 million.

On November 14, 2001, the Partnership paid cash distributions of $0.5775
per unit on its outstanding common and subordinated units to unitholders of
record at the close of business on November 1, 2001. The total distributions
paid were $6.7 million.

Total distributions paid during 2001 were as follows (in thousands except
per unit amounts):

AMOUNT DISTRIBUTION
PER UNIT AMOUNT
-------- ------------

Common Unitholders.......................................... $1.43 $ 8,134
Subordinated Unitholders.................................... $1.43 8,134
General Partner............................................. $1.43 331
-------
Total..................................................... $16,599
=======

On February 14, 2002, the Partnership paid cash distributions of $0.59 per
unit on its outstanding common and subordinated units to unitholders of record
at the close of business on February 1, 2002. The total distribution, including
distributions paid to the general partner on its equivalent units, was $6.9
million.

With the payment of the $0.59 per unit distribution on February 14, 2002,
the first early vesting performance measure of the one-time initial public
offering grants to key employees was achieved, and 46,250 units associated with
this grant vested on that date. The Partnership recognized additional
compensation expense of $1.0 million with the vesting of these units in February
2002.

The General Partner declared a cash distribution of $0.6125 on April 22,
2002 to be paid on May 15, 2002 to unitholders of record at the close of
business on May 2, 2002. The total distribution to be paid, including the
general partner's incentive distributions will be $7.2 million (unaudited).

F-38

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. NET INCOME PER UNIT

The following table provides details of the basic and diluted earnings per
unit computations (in thousands, except per unit amounts):

FOR THE YEAR ENDED DECEMBER 31, 2001
----------------------------------------
INCOME UNITS PER UNIT
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- --------

Limited partners' interest in income applicable
to the period after February 9, 2001........... $21,217
Basic net income per common and subordinated
unit........................................... $21,217 11,359 $1.87
Effect of dilutive restricted unit grants........ -- 11 --
------- ------ -----
Diluted earnings per common and subordinated
unit........................................... $21,217 11,370 $1.87
======= ====== =====

FOR THE THREE MONTHS ENDED MARCH 31, 2002
-------------------------------------------
INCOME UNITS PER UNIT
(NUMERATOR) (DENOMINATOR) AMOUNT
------------ -------------- ---------

Limited partners' interest in net income......... $ 8,265
Basic net income per common and subordinated
unit........................................... $ 8,265 11,359 $0.73
Effect of dilutive restricted unit grants........ -- 48 (0.01)
--------- ------ -----
Diluted net income per common and subordinated
unit........................................... $ 8,265 11,407 $0.72
========= ====== =====

Units reported as dilutive securities are related to restricted unit grants
associated with the one-time initial public offering award (see Note 11).

17. PARTNERS' CAPITAL

Of the 5,679,694 common units outstanding at December 31, 2001, 4,600,000
are held by the public, with the remaining 1,079,694 held by affiliates of the
Partnership. All of the 5,679,694 subordinated units are held by affiliates of
the Partnership.

During the subordination period, as defined in the Partnership's
partnership agreement, the Partnership can issue up to 2,839,847 additional
common units without obtaining unitholder approval. In addition, the General
Partner can issue an unlimited number of common units as follows:

- Upon conversion of the subordinated units;

- Under employee benefit plans;

- Upon conversion of the general partner interest and incentive
distribution rights as a result of a withdrawal of the General Partner;

- In the event of a combination or subdivision of common units;

- In connection with an acquisition or a capital improvement that increases
cash flow from operations per unit on a pro forma basis; or

- If the proceeds of the issuance are used exclusively to repay up to $40.0
million of the Partnership's indebtedness.

The subordination period will end when the Partnership meets certain
financial tests provided for in the partnership agreement but it generally
cannot end before December 31, 2005.

F-39

WILLIAMS ENERGY PARTNERS L.P.

NOTES TO RESTATED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The limited partners holding common units of the Partnership have the
following rights, among others:

- Right to receive distributions of the Partnership's available cash within
45 days after the end of each quarter;

- Right to transfer common unit ownership to substitute limited partners;

- Right to receive an annual report, containing audited financial
statements and a report on those financial statements by the
Partnership's independent public accountants within 120 days after the
close of the fiscal year end;

- Right to receive information reasonably required for tax reporting
purposes within 90 days after the close of the calendar year;

- Right to vote according to the limited partners' percentage interest in
the Partnership on any meeting that may be called by the General Partner.
However, if any person or group other than the General Partner and its
affiliates acquires beneficial ownership of 20% or more of any class of
units, that group or person loses voting rights on all of its units; and

- Right to inspect the Partnership's books and records at the unitholders'
own expense.

Net income, excluding amounts attributable to Williams Pipe Line, is
allocated to the General Partner and limited partners based on their
proportionate share of cash distributions for the period. Cash distributions to
the General Partner and limited partners are made based on the following table:

PERCENTAGE OF DISTRIBUTIONS
ANNUAL DISTRIBUTION -----------------------------
AMOUNT (PER UNIT) UNITHOLDERS GENERAL PARTNER
------------------- ----------- ---------------

Up to $2.31................................................. 98 2
Above $2.31 up to $2.62..................................... 85 15
Above $2.62 up to $3.15..................................... 75 25
Above $3.15................................................. 50 50

In the event of a liquidation, all property and cash in excess of that
required to discharge all liabilities will be distributed to the partners in
proportion to the positive balances in their respective tax-basis capital
accounts.

18. REGISTRATION STATEMENT

In March 2002, the Partnership filed a shelf registration statement to
register $1.8 billion of common units representing limited partner interests and
debt securities, including guarantees. The Partnership, exclusive of its
investment in its wholly owned operating limited partnerships and subsidiaries,
has no independent assets or operations. If a series of debt securities is
guaranteed, such series will be guaranteed by all of the Partnership's
subsidiaries on a full and unconditional and joint and several basis.

F-40

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........................... 8
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................................................ 19
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......................... 27
Incentive Distribution Rights............................. 27
Percentage Allocations of Available Cash from Operating
Surplus................................................ 27
Distributions from Capital Surplus........................ 28
Adjustment to the Minimum Quarterly Distribution and
Target Distribution Levels............................. 28
Distributions of Cash Upon Liquidation.................... 29
MATERIAL TAX CONSEQUENCES................................... 32
Partnership Status........................................ 32
Limited Partner Status.................................... 34
Tax Consequences of Unit Ownership........................ 34
Tax Treatment of Operations............................... 38
Disposition of Common Units............................... 39
Uniformity of Units....................................... 41
Tax-Exempt Organizations and Other Investors.............. 42
Administrative Matters.................................... 42
State, Local and Other Tax Considerations................. 44
Tax Consequences of Ownership of Debt Securities.......... 45
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS.................. 46
PLAN OF DISTRIBUTION........................................ 47
LEGAL....................................................... 47
EXPERTS..................................................... 47

---------------------

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.
3

HIGH NATURAL GAS PRICES CAN INCREASE AMMONIA PRODUCTION COSTS AND REDUCE THE
AMOUNT OF AMMONIA TRANSPORTED THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.

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

CHANGES IN OR CHALLENGES TO THE FEDERAL GOVERNMENT'S POLICY REGARDING FARM
SUBSIDIES COULD NEGATIVELY IMPACT THE DEMAND FOR AMMONIA AND RESULT IN DECREASED
SHIPMENTS THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.

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

OUR MARINE AND INLAND TERMINALS ENCOUNTER COMPETITION FROM OTHER TERMINAL
COMPANIES AND OUR AMMONIA PIPELINE AND TERMINALS SYSTEM ENCOUNTERS COMPETITION
FROM RAIL CARRIERS AND ANOTHER AMMONIA PIPELINE.

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

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

OUR BUSINESS IS SUBJECT TO FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT
GOVERN THE ENVIRONMENTAL AND OPERATIONAL SAFETY ASPECTS OF OUR OPERATIONS.

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

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

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

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

OUR BUSINESS INVOLVES MANY HAZARDS AND OPERATIONAL RISKS, SOME OF WHICH MAY NOT
BE COVERED BY INSURANCE.

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

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

WE ARE A HOLDING COMPANY AND DEPEND ENTIRELY ON OUR OPERATING SUBSIDIARIES'
DISTRIBUTIONS TO SERVICE OUR DEBT OBLIGATIONS.

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

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

- general creditors;

- trade creditors;

- secured creditors;

- taxing authorities; and

- creditors holding guarantees.

COST REIMBURSEMENTS DUE OUR GENERAL PARTNER MAY BE SUBSTANTIAL AND WILL REDUCE
OUR CASH AVAILABLE FOR DISTRIBUTION TO YOU.

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

OUR GENERAL PARTNER AND ITS AFFILIATES MAY HAVE CONFLICTS WITH OUR PARTNERSHIP.

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

Such conflicts may include, among others, the following:

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

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

- under our partnership agreement, it is not a breach of our general
partner's fiduciary duties for affiliates of our general partner to
engage in activities that compete with us.

UNITHOLDERS HAVE LIMITED VOTING RIGHTS AND CONTROL OF MANAGEMENT.

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

OUR GENERAL PARTNER'S ABSOLUTE DISCRETION IN DETERMINING THE LEVEL OF CASH
RESERVES MAY ADVERSELY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS TO OUR
UNITHOLDERS.

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

WE MAY ISSUE ADDITIONAL COMMON UNITS WITHOUT YOUR APPROVAL, WHICH WOULD DILUTE
YOUR EXISTING OWNERSHIP INTERESTS.

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

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

- the conversion of subordinated units into common units;

- the conversion of the general partner interest and the incentive
distribution rights into common units as a result of the withdrawal of
our general partner;

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

- issuances of common units to repay up to $40.0 million in indebtedness.

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

- your proportionate ownership interest in Williams Energy Partners will
decrease;

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

- since a lower percentage of total outstanding units will be subordinated
units, the risk that a shortfall in the payment of the minimum quarterly
distribution will be borne by the common unitholders will increase;

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

- the market price of the common units may decline.

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

OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE YOU TO SELL YOUR
UNITS AT AN UNDESIRABLE TIME OR PRICE.

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

YOU MAY NOT HAVE LIMITED LIABILITY IF A COURT FINDS THAT UNITHOLDER ACTIONS
CONSTITUTE CONTROL OF OUR BUSINESS.

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

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

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

TAX RISKS TO COMMON UNITHOLDERS

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

THE IRS COULD TREAT US AS A CORPORATION FOR TAX PURPOSES, WHICH WOULD
SUBSTANTIALLY REDUCE THE CASH AVAILABLE FOR DISTRIBUTION TO YOU.

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

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

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

A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY
ADVERSELY IMPACT THE MARKET FOR COMMON UNITS, AND THE COSTS OF ANY CONTESTS WILL
BE BORNE BY OUR UNITHOLDERS AND OUR GENERAL PARTNER.

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

YOU MAY BE REQUIRED TO PAY TAXES EVEN IF YOU DO NOT RECEIVE ANY CASH
DISTRIBUTIONS.

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

TAX GAIN OR LOSS ON DISPOSITION OF COMMON UNITS COULD BE DIFFERENT THAN
EXPECTED.

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

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

TAX-EXEMPT ENTITIES, REGULATED INVESTMENT COMPANIES, AND FOREIGN PERSONS FACE
UNIQUE TAX ISSUES FROM OWNING COMMON UNITS THAT MAY RESULT IN ADVERSE TAX
CONSEQUENCES TO THEM.

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

WE ARE REGISTERED AS A TAX SHELTER. THIS MAY INCREASE THE RISK OF AN IRS AUDIT
OF US OR A UNITHOLDER.

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

WE WILL TREAT EACH PURCHASER OF COMMON UNITS AS HAVING THE SAME TAX BENEFITS
WITHOUT REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS TREATMENT,
WHICH COULD ADVERSELY AFFECT THE VALUE OF OUR COMMON UNITS.

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

YOU WILL LIKELY BE SUBJECT TO STATE AND LOCAL TAXES IN STATES WHERE YOU DO NOT
LIVE AS A RESULT OF AN INVESTMENT IN OUR COMMON UNITS.

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

WHERE YOU CAN FIND MORE INFORMATION

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

- The description of the limited partnership units contained in the
Registration Statement on Form 8-A, initially filed February 2, 2001, and
any subsequent amendment thereto filed for the purpose of updating such
description.

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

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

FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS

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

- Price trends and overall demand for natural gas liquids, refined
petroleum products, natural gas, oil and ammonia in the United States;
economic activity, weather, alternative energy sources, conservation and
technological advances may affect price trends and demand;

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

- Changes in demand for storage in our petroleum product terminals;

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

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

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

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

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

- An increase in the price of natural gas, which increases ammonia
production costs and reduces the amount of ammonia transported through
our ammonia pipeline and terminals system;

- Changes in the federal government's policy regarding farm subsidies,
which negatively impact the demand for ammonia and reduce the amount of
ammonia transported through our ammonia pipeline and terminals system;

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

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

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

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

- Changes in general economic conditions in the United States;

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

- The amount of our respective indebtedness, which could make us vulnerable
to general adverse economic and industry conditions, limit our ability to
borrow additional funds, place us at competitive disadvantages compared
to our competitors that have less debt or have other adverse
consequences;

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

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

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

- The effect of changes in accounting policies;

- The ability to control costs; and

- The political and economic stability of the oil producing nations of the
world.
11

USE OF PROCEEDS

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

RATIO OF EARNINGS TO FIXED CHARGES

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

TWELVE MONTHS ENDED DECEMBER 31,
-------------------------------------
1997 1998 1999 2000 2001
----- ----- ----- ----- -----

Ratio of Earnings to Fixed Charges............. 6.77x 6.69x 5.32x 3.75x 7.20x

---------------

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

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

- "earnings" represent the aggregate of income from continuing operations
(before adjustment for minority interest, extraordinary loss and equity
earnings), fixed charges and distributions from equity investment, less
capitalized interest.

DESCRIPTION OF DEBT SECURITIES

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

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

GENERAL

THE DEBT SECURITIES

Any series of debt securities that we issue:

- will be our general obligations;

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

- may be subordinated to our Senior Indebtedness and that of the Subsidiary
Guarantors.

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

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

- the form and title of the debt securities;

- the total principal amount of the debt securities;

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

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

- any right we may have to defer payments of interest by extending the
dates payments are due and whether interest on those deferred amounts
will be payable;

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

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

- any optional redemption provisions;

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

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

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

- any changes to or additional Events of Default or covenants;

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

- any other terms of the debt securities.

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

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

- debt securities with respect to which payments of principal, premium or
interest are determined with reference to an index or formula, including
changes in prices of particular securities, currencies or commodities;

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

- debt securities that are issued at a discount below their stated
principal amount, bearing no interest or interest at a rate that at the
time of issuance is below market rates; and

- variable rate debt securities that are exchangeable for fixed rate debt
securities.

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

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

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

THE SUBSIDIARY GUARANTEES

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

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

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

- any collections from or payments made by or on behalf of any other
Subsidiary Guarantors in respect of the obligations of the Subsidiary
Guarantor under its guarantee.

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

- automatically upon any sale, exchange or transfer, to any person that is
not our affiliate, of all of our direct or indirect limited partnership
or other equity interests in the Subsidiary Guarantor;

- automatically upon the merger of the Subsidiary Guarantor into us or any
other Subsidiary Guarantor or the liquidation and dissolution of the
Subsidiary Guarantor; or

- following delivery of a written notice by us to the Trustee, upon the
release of all guarantees by the Subsidiary Guarantor of any debt of ours
for borrowed money (or a guarantee of such debt), except for any series
of debt securities.

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

COVENANTS

REPORTS

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

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

- for as long as we are required to file information with the SEC pursuant
to the Exchange Act, file with the Trustee, within 15 days after we are
required to file with the SEC, copies of the annual report and of the
information, documents and other reports which we are required to file
with the SEC pursuant to the Exchange Act;

- if we are not required to file information with the SEC pursuant to the
Exchange Act, file with the Trustee, within 15 days after we would have
been required to file with the SEC, financial statements and a
Management's Discussion and Analysis of Financial Condition and Results
of Operations, both comparable to what we would have been required to
file with the SEC had we been subject to the reporting requirements of
the Exchange Act; and

- if we are required to furnish annual or quarterly reports to our
unitholders pursuant to the Exchange Act, we will file with the Trustee
any annual report or other reports sent to our unitholders generally.

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

EVENTS OF DEFAULT, REMEDIES AND NOTICE

EVENTS OF DEFAULT

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

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

- default in the payment of principal of or premium, if any, on any debt
securities of that series when due at its stated maturity, upon
redemption, upon required repurchase or otherwise;

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

- failure by us or, if the series of debt securities is guaranteed by the
Subsidiary Guarantors, by a Subsidiary Guarantor, to comply for 60 days
after notice with the other agreements contained in the Indenture, any
supplement to the Indenture or any board resolution authorizing the
issuance of that series;

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

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

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

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

- any Subsidiary Guarantor denies or disaffirms its obligations under the
Indenture or its guarantee.

EXERCISE OF REMEDIES

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

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

If an Event of Default described in the fifth bullet point above occurs and
is continuing, the principal of, premium, if any, and accrued and unpaid
interest on all outstanding debt securities of all series will become
immediately due and payable without any declaration of acceleration or other act
on the part of the Trustee or any holders.

The holders of a majority in principal amount of the outstanding debt
securities of a series may:

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

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

but only if:

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

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

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

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

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

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

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

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

The holders of a majority in principal amount of the outstanding debt
securities of a series have the right, subject to certain restrictions, to
direct the time, method and place of conducting any proceeding for any remedy
available to the Trustee or of exercising any right or power conferred on the
Trustee with respect to that series of debt securities. The Trustee, however,
may refuse to follow any direction that:

- conflicts with law;

- is inconsistent with any provision of the Indenture;

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

- would involve the Trustee in personal liability.

NOTICE OF EVENT OF DEFAULT

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

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

AMENDMENTS AND WAIVERS

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

- cure any ambiguity, omission, defect or inconsistency;

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

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

- add Subsidiary Guarantors with respect to the debt securities;

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

- secure the debt securities;

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

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

- add or appoint a successor or separate Trustee; or

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

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

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

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

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

- reduce the premium payable upon the redemption of any debt securities or
change the time at which any debt securities may or shall be redeemed;

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

- impair the right of any holder to receive payment of premium, principal
or interest with respect to such holder's debt securities on or after the
applicable due date;

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

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

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

- make any change in the waiver provisions; or

- release a Subsidiary Guarantor or modify such Subsidiary Guarantor's
guarantee in any manner adverse to the holders.

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

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

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

- any past default under the Indenture, subject to certain rights of the
Trustee under the Indenture;

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

- in the payment of principal, premium or interest; or

- in respect of a provision that under the Indenture cannot be amended
without the consent of all holders of the series of debt securities that
is affected.

DEFEASANCE

At any time, we may terminate, with respect to debt securities of a
particular series, all our obligations under such series of debt securities and
the Indenture, which we call a "legal defeasance." If we decide to make a legal
defeasance, however, we may not terminate our obligations:

- relating to the defeasance trust;

- to register the transfer or exchange of the debt securities;

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

- to maintain a registrar and paying agent in respect of the debt
securities.

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

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

- covenants applicable to a series of debt securities and described in the
prospectus supplement applicable to such series, other than as described
in such prospectus supplement;

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

- the guarantee provision described under "Events of Default" above with
respect to a series of debt securities.

We may exercise our legal defeasance option notwithstanding our prior
exercise of our covenant defeasance option. If we exercise our legal defeasance
option, payment of the affected series of debt securities may not be accelerated
because of an Event of Default with respect to that series. If we exercise our
covenant defeasance option, payment of the affected series of debt securities
may not be accelerated because of an Event of Default specified in the fourth,
fifth (with respect only to a Subsidiary Guarantor (if any)) or sixth bullet
points under "-- Events of Default" above or an Event of Default that is added
specifically for such series and described in a prospectus supplement.

In order to exercise either defeasance option, we must:

- irrevocably deposit in trust with the Trustee money or certain U.S.
government obligations for the payment of principal, premium, if any, and
interest on the series of debt securities to redemption or maturity, as
the case may be;

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

- deliver to the Trustee of an opinion of counsel to the effect that
holders of the series of debt securities will not recognize income, gain
or loss for Federal income tax purposes as a result of such defeasance
and will be subject to Federal income tax on the same amount and in the
same manner and at the same times as would have been the case if such
deposit and defeasance had not occurred. In the case of legal defeasance
only, such opinion of counsel must be based on a ruling of the Internal
Revenue Service or other change in applicable Federal income tax law.

NO PERSONAL LIABILITY OF GENERAL PARTNER

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

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

- any claim based on, in respect of, or by reason of, such obligations or
their creation.

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

SUBORDINATION

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

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

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

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

- in a bankruptcy, receivership or similar proceeding relating to us or, if
applicable to any series of outstanding debt securities, to the
Subsidiary Guarantors.

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

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

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

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

- repurchase, redeem or otherwise retire any subordinated debt securities,
except that in the case of subordinated debt securities that provide for
a mandatory sinking fund, we may deliver subordinated debt securities to
the Trustee in satisfaction of our sinking fund obligation,

unless, in either case,

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

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

- we and the Trustee receive written notice approving the payment from the
representatives of each issue of "Designated Senior Indebtedness."

Generally, "Designated Senior Indebtedness" will include:

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

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

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

The Payment Blockage Period may be terminated before its expiration:

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

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

- if the default giving rise to the Payment Blockage Period is no longer
continuing.

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

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

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

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

BOOK ENTRY, DELIVERY AND FORM

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

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

DTC advises us that it is:

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

- a "banking organization" within the meaning of the New York Banking Law;

- a member of the United States Federal Reserve System;

- a "clearing corporation" within the meaning of the New York Uniform
Commercial Code; and

- a "clearing agency" registered under the provisions of Section 17A of the
Securities Exchange Act of 1934.

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

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

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

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

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

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

- DTC notifies us that it is unwilling or unable to continue as depositary
or if DTC ceases to be a clearing agency registered under applicable law
and a successor depositary is not appointed by us within 90 days; or

- we determine not to require all of the debt securities of a series to be
represented by a global security and notify the Trustee of our decision.

THE TRUSTEE

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

GOVERNING LAW

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

DESCRIPTION OF OUR CLASS B UNITS

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

- Our general partner will be entitled to receive a distribution of
available cash with respect to its Class B units equal to the
distributions of available cash that were paid or declared payable to the
common units during the term of the short-term loan; and

- We, at our option, may redeem the Class B units for cash based on the
15-day average closing price of the common units prior to the redemption
date.

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

CASH DISTRIBUTIONS

DISTRIBUTIONS OF AVAILABLE CASH

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

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

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

- provide for the proper conduct of our business;

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

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

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

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

OPERATING SURPLUS, CAPITAL SURPLUS AND ADJUSTED OPERATING SURPLUS

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

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

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

- $15.0 million; plus

- all of our cash receipts since the closing of our initial public
offering, excluding cash from borrowings that are not working capital
borrowings, sales of equity and debt securities and sales or other
dispositions of assets outside the ordinary course of business; plus

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

- all of our operating expenditures since the closing of our initial public
offering, including the repayment of working capital borrowings, but not
the repayment of other borrowings, and including maintenance capital
expenditures; less

- the amount of cash reserves that the general partner deems necessary or
advisable to provide funds for future operating expenditures.

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

- borrowings other than working capital borrowings;

- sales of debt and equity securities; and

- sales or other disposition of assets for cash, other than inventory,
accounts receivable and other current assets sold in the ordinary course
of business or as part of normal retirements or replacements of assets.

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

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

Adjusted operating surplus for any period generally means:

- operating surplus generated with respect to that period; less

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

- any net reduction in cash reserves for operating expenditures with
respect to that period not relating to an operating expenditure made with
respect to that period; plus

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

- any net increase in cash reserves for operating expenditures with respect
to that period required by any debt instrument for the repayment of
principal, interest or premium.

SUBORDINATION PERIOD

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

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

- distributions of available cash from operating surplus on each of the
outstanding common units and subordinated units equaled or exceeded the
minimum quarterly distribution for each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that date;

- the adjusted operating surplus generated during each of the three
immediately preceding non-overlapping four-quarter periods equaled or
exceeded the sum of the minimum quarterly distributions on all of the
outstanding common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the 2% general
partner interest during those periods; and

- there are no arrearages in payment of the minimum quarterly distribution
on the common units.

Early Conversion of Subordinated Units. Before the end of the
subordination period, 50% of the subordinated units, or up to 2,839,847
subordinated units, may convert into common units on a one-for-one

basis on the first day after the record date established for the distribution
for any quarter ending on or after:

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

- December 31, 2004 with respect to 25% of the subordinated units.

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

- the adjusted operating surplus generated during each of the three
consecutive, non-overlapping four-quarter periods immediately preceding
that date equaled or exceeded the sum of the minimum quarterly
distributions on all of the outstanding common units and subordinated
units during those periods on a fully diluted basis and the related
distribution on the 2% general partner interest during those periods; and

- there are no arrearages in payment of the minimum quarterly distribution
on the common units.

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

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

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

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

- the general partner will have the right to convert its general partner
interest and its incentive distribution rights into common units or to
receive cash in exchange for those interests.

DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS DURING THE SUBORDINATION
PERIOD

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

- First, 98% to the common unitholders, pro rata, and 2% to the general
partner until we distribute for each outstanding common unit an amount
equal to the minimum quarterly distribution for that quarter;

- Second, 98% to the common unitholders, pro rata, and 2% to the general
partner until we distribute for each outstanding common unit an amount
equal to any arrearages in payment of the minimum quarterly distribution
on the common units for any prior quarters during the subordination
period;

- Third, 98% to the subordinated unitholders, pro rata, and 2% to the
general partner until we distribute for each subordinated unit an amount
equal to the minimum quarterly distribution for that quarter; and

- Thereafter, in the manner described in "-- Incentive Distribution Rights"
below.

DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS AFTER THE SUBORDINATION
PERIOD

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

- First, 98% to all unitholders, pro rata, and 2% to the general partner
until we distribute for each outstanding unit an amount equal to the
minimum quarterly distribution for that quarter; and

- Thereafter, in the manner described in "-- Incentive Distribution Rights"
below.

INCENTIVE DISTRIBUTION RIGHTS

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

If for any quarter:

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

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

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

- First, 98% to all unitholders, pro rata, and 2% to the general partner,
until each unitholder receives a total of $0.578 per unit for that
quarter (the "first target distribution");

- Second, 85% to all unitholders, pro rata, and 15% to the general partner,
until each unitholder receives a total of $0.656 per unit for that
quarter (the "second target distribution");

- Third, 75% to all unitholders, pro rata, and 25% to the general partner,
until each unitholder receives a total of $0.788 per unit for that
quarter (the "third target distribution"); and

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

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

PERCENTAGE ALLOCATIONS OF AVAILABLE CASH FROM OPERATING SURPLUS

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

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

MARGINAL PERCENTAGE INTEREST
IN DISTRIBUTIONS
TOTAL QUARTERLY DISTRIBUTION -----------------------------
TARGET AMOUNT UNITHOLDERS GENERAL PARTNER
---------------------------- ----------- ---------------

Minimum Quarterly Distribution.... $0.525 98% 2%
First Target Distribution......... up to $0.578 98% 2%
Second Target Distribution........ above $0.578 up to $0.656 85% 15%
Third Target Distribution......... above $0.656 up to $0.788 75% 25%
Thereafter........................ above $0.788 50% 50%

DISTRIBUTIONS FROM CAPITAL SURPLUS

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

- First, 98% to all unitholders, pro rata, and 2% to the general partner,
until we distribute for each common unit, an amount of available cash
from capital surplus equal to the initial public offering price;

- Second, 98% to the common unitholders, pro rata, and 2% to the general
partner, until we distribute for each common unit that was issued in the
offering, an amount of available cash from capital surplus equal to any
unpaid arrearages in payment of the minimum quarterly distribution on the
common units; and

- Thereafter, we will make all distributions of available cash from capital
surplus as if they were from operating surplus.

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

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

ADJUSTMENT TO THE MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS

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

- the minimum quarterly distribution;

- target distribution levels;

- unrecovered initial unit price;

- the number of common units issuable during the subordination period
without a unitholder vote; and

- the number of common units into which a subordinated unit is convertible.

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

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

DISTRIBUTIONS OF CASH UPON LIQUIDATION

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

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

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

- First, to the general partner and the holders of units who have negative
balances in their capital accounts to the extent of and in proportion to
those negative balances;

- Second, 98% to the common unitholders, pro rata, and 2% to the general
partner, until the capital account for each common unit is equal to the
sum of:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

- First, 98% to holders of subordinated units in proportion to the positive
balances in their capital accounts and 2% to the general partner until
the capital accounts of the holders of the subordinated units have been
reduced to zero;

- Second, 98% to the holders of common units in proportion to the positive
balances in their capital accounts and 2% to the general partner until
the capital accounts of the common unitholders have been reduced to zero;
and

- Thereafter, 100% to the general partner.

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

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

MATERIAL TAX CONSEQUENCES

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

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

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

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

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

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

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

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

PARTNERSHIP STATUS

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

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

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

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

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

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

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

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

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

LIMITED PARTNER STATUS

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

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

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

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

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

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

TAX CONSEQUENCES OF UNIT OWNERSHIP

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

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

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

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

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

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

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

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

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

Limitations on Interest Deductions. The deductibility of a non-corporate
taxpayer's "investment interest expense" is generally limited to the amount of
that taxpayer's "net investment income." The IRS has indicated that net passive
income from a publicly-traded partnership constitutes investment income for

purposes of the limitations on the deductibility of investment interest. In
addition, the unitholder's share of our portfolio income will be treated as
investment income. Investment interest expense includes:

- interest on indebtedness properly allocable to property held for
investment;

- our interest expense attributed to portfolio income; and

- the portion of interest expense incurred to purchase or carry an interest
in a passive activity to the extent attributable to portfolio income.

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

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

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

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

An allocation of items of our income, gain, loss or deduction, other than
an allocation required by the Internal Revenue Code to eliminate the difference
between a partner's "book" capital account, credited with the fair market value
of Contributed Property, and "tax" capital account, credited with the tax basis
of Contributed Property, referred to in this discussion as the "Book-Tax
Disparity", will generally be given effect for federal income tax purposes in
determining a partner's share of an item of income, gain, loss or deduction only
if the allocation has substantial economic effect. In any other case, a
partner's share of an item will be determined on the basis of his interest in
us, which will be determined by taking into account all the facts and
circumstances, including his relative contributions to us, the interests of all
the partners in

profits and losses, the interest of all the partners in cash flow and other
nonliquidating distributions and rights of all the partners to distributions of
capital upon liquidation.

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

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

- any of our income, gain, loss or deduction with respect to those units
would not be reportable by the unitholder;

- any cash distributions received by the unitholder as to those units would
be fully taxable; and

- all of these distributions would appear to be ordinary income.

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

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

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

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

Treasury regulations under Section 743 of the Internal Revenue Code
require, if the remedial allocation method is adopted (which we have adopted), a
portion of the Section 743(b) adjustment attributable to recovery property to be
depreciated over the remaining cost recovery period for the Section 704(c)
built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section
743(b) adjustment attributable to property subject to depreciation under Section
167 of the Internal Revenue Code rather than cost recovery deductions under
Section 168 is generally required to be depreciated using either the
straight-line method or the 150% declining balance method. Under our partnership
agreement, the general partner is authorized to take a position to preserve the
uniformity of units even if that position

is not consistent with these Treasury regulations. Please read "-- Tax Treatment
of Operations -- Uniformity of Units."

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

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

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

TAX TREATMENT OF OPERATIONS

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

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

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

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

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

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

DISPOSITION OF COMMON UNITS

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

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

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

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

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

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

- a short sale;

- an offsetting notional principal contract; or

- a futures or forward contract with respect to the partnership interest or
substantially identical property.

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

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

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

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

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

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

UNIFORMITY OF UNITS

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

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

TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS

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

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

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

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

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

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

ADMINISTRATIVE MATTERS

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

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

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

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

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

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

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

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

(b) whether the beneficial owner is

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

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

(3) a tax-exempt entity;

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

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

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

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

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

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

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

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

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

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

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

STATE, LOCAL AND OTHER TAX CONSIDERATIONS

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

return. Amounts withheld may be treated as if distributed to unitholders for
purposes of determining the amounts distributed by us. Please read "-- Tax
Consequences of Unit Ownership -- Entity-Level Collections." Based on current
law and our estimate of our future operations, the general partner anticipates
that any amounts required to be withheld will not be material.

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

TAX CONSEQUENCES OF OWNERSHIP OF DEBT SECURITIES

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

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

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

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

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

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

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

PLAN OF DISTRIBUTION

We may sell the securities being offered hereby:

- directly to purchasers;

- through agents;

- through underwriters; and

- through dealers.

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

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

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

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

LEGAL

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

EXPERTS

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

(WILLIAMS ENERGY PARTNERS LOGO)

8,000,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS

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PROSPECTUS SUPPLEMENT
MAY 23, 2002
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Joint Book-Running Managers

LEHMAN BROTHERS

SALOMON SMITH BARNEY
----------------------------

BANC OF AMERICA SECURITIES LLC

MERRILL LYNCH & CO.

UBS WARBURG

A.G. EDWARDS & SONS, INC.

JPMORGAN

RAYMOND JAMES

RBC CAPITAL MARKETS

WACHOVIA SECURITIES

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