WILLIAMS ENERGY PARTNERS L P - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). þ

The aggregate market value of the registrant’s voting and non-voting common units held by non-affiliates computed by reference to the price at which the units last sold as of June 28, 2002, was $420.7 million.

As of February 28, 2003, there were outstanding 13,679,694 common units, 7,830,924 Class B common units and 5,679,694 subordinated units.

We were formed as a limited partnership under the laws of the State of Delaware in August 2000. The principal executive offices of WEG GP LLC, our General Partner, are located at One Williams Center, Tulsa, Oklahoma 74172 (telephone (877) 934-6571).

On April 11, 2002, we acquired all of the membership interests of Williams Pipe Line Company, LLC (“Williams Pipe Line”) from a wholly owned subsidiary of The Williams Companies, Inc. (“Williams”) for approximately $1.0 billion. Williams Pipe Line owns and operates the Williams Pipe Line system. Because Williams Pipe Line 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 interests. Accordingly, we have restated our historical financial statements to combine our results with those of Williams Pipe Line. We financed the acquisition through a $700.0 million short-term loan and the issuance of 7,830,924 Class B common units (“Class B units”) to Williams. As a result, Williams and its subsidiaries’ ownership interest in us increased from approximately 60% to approximately 77%, including its general partner interest.

On May 23, 2002, we completed a public offering of 8,000,000 common units from which we received net proceeds of approximately $289.0 million after considering Williams’ contribution to maintain its 2% general partner interest and payment of offering fees. As a result, Williams’ ownership interest in us decreased to approximately 55%, which includes its 53% limited partnership interest and 2% general partner interest.

On November 15, 2002 we issued and sold $420 million of senior secured notes in a private placement, which was used to repay the short-term loan incurred at the time we acquired Williams Pipe Line and related fees. We issued an additional $60 million of senior secured notes on December 6, 2002, which was used primarily for repayment of our other debt.

In November 2002, Williams created a new general partner, WEG GP LLC (“General Partner”). The new general partner, which is owned by affiliates of Williams, has all of the rights, privileges and responsibilities relative to us previously held by the former general partner, Williams GP LLC. Williams GP LLC will continue to own the Class B units issued to it by us in April 2002.

On February 20, 2003, Williams announced its intention to divest its interest in our General Partner and all of its limited partnership interests. It is uncertain what form this potential transaction may take and management cannot currently assess what impact such an acquisition would have on the on-going operations of the Partnership.

We are principally engaged in the storage, transportation and distribution of refined petroleum products and ammonia. 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. We refer to these facilities as our marine terminals;


	•	23 petroleum products terminals (some of which are partially owned) located principally in the southeastern United States. We refer to these terminals as our inland terminals; and

	•	an ammonia pipeline system, which extends approximately 1,100 miles from Texas and Oklahoma to Minnesota.

Upon the closing of our initial public offering in February 2001, four marine terminals, 24 inland terminals and the ammonia pipeline system were transferred to us, including related liabilities. We acquired an additional marine terminal and two inland terminals and sold one inland terminal during 2001. In 2002, we acquired the Williams Pipe Line system and sold two inland terminals.

The United States refined petroleum products transportation and distribution system links oil 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; and

	•	crude oil and condensate, which are used as feedstocks by refineries.

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 terminals services. The products transported on the Williams Pipe Line system are largely transportation fuels, and in 2002 were comprised of 59% gasoline, 31% distillates (which includes diesel fuels and heating oil) and 10% LPGs and aviation fuel. 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. Please read Note 15 to the Consolidated Financial Statements.

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 approximately 1.9% 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.

The Williams Pipe Line system is well-connected to the Gulf Coast refineries through interconnections with the Explorer, Shell, 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 major supply shifts that may occur.

The Williams Pipe Line system has experienced increased shipments over the last three years, with total shipments increasing by 2.4% from 2000 to 2002. The volume increases have come partly as a result of development projects on the system and from incentive agreements with shippers utilizing the system. In 2002, demand growth for refined petroleum products in the markets served by the system was slowed largely by generally less favorable economic conditions in those markets. The operating statistics below reflect the Williams Pipe Line system’s operations for the periods indicated:

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.

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 44% of the refinery capacity in the continental United States. In general, the system 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 the 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 terminals 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 2002 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 generates the remaining 20% of its revenues, excluding product sales revenues, 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, laboratory testing, data services to shippers and from blending, over and short 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. In addition, Williams Pipe Line began operating the Rio Grande Pipeline in 2003 and receives an annual fee for those services.

Product sales revenues are generated as a result of selling products generated in the butane blending, transmix fractionation and over and short activities. While the revenues generated from these activities were over $69.0 million in 2002, the resulting margin was only $5.4 million, which illustrates that these activities comprise a small portion of Williams Pipe Line’s total net operating margin.

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 an affiliate of Williams agreed that we will perform these blending services for ten years at an annual fee that will increase to approximately $3.6 million for 2003. As a result of this change, we no longer purchase and sell products related to blending activities. In addition, we will perform blending services at our Little Rock, Arkansas inland terminals, which will generate annual blending fees of approximately $0.6 million. Consequently, our total blending services revenues for 2003 will be approximately $4.2 million. Please read “Customers and Contracts” below and “Management Discussion and Analysis — Overview — The Williams Pipe Line System” for additional discussion of our blending services.

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 facilities. The transmix is separated at our fractionator in Des Moines, Iowa, and the recovered gasoline and fuel oil are sold to third parties.

Over and short activities involve our managing imbalances that occur during normal operation of the system. Generally, the physical volumes on our system will not match the volumes recorded by our customers. These differences are either product quality differences or absolute volume differences. Quality differences result from the commingling of product on the pipeline during times when we change the product type shipped on our pipeline. When these differences occur, we purchase and sell products at prevailing market prices to manage the imbalance.

The Williams Pipe Line system consists of a 6,700-mile pipeline. The pipeline system includes 25.6 million barrels of aggregate storage capacity at 38 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.

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

In addition, we have access agreements with both El Paso Corporation and ConocoPhillips Corporation, providing us the right to use their terminal facilities at Wichita, Kansas.

Refined petroleum products originate from both refining and pipeline interconnection points along the Williams Pipe Line system. In 2002, 60% of the refined petroleum products transported on the Williams Pipe Line system originated from direct refinery connections and 40% 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 Williams Pipe Line system receives product from 12 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 ConocoPhillips 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.

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, 2002, the pipeline system had approximately 50 customers. The principal shippers included six independent refining companies, three integrated oil companies and one large farm cooperative. Transportation revenues attributable to these top 10 shippers for the year ended December 31, 2002 were $155.8 million, representing 45% of the Williams Pipe Line system’s total revenues, and 57% of revenues excluding product sales revenues.

In 2002, affiliates of Williams accounted for $42.0 million or approximately 12% of the Williams Pipe Line system’s total revenues. Of these affiliate revenues, approximately 60% were generated from products sales related to blending, fractionation and over and short settlement activities. As described above under “Operations,” we have agreed to perform blending services on behalf of an affiliate of Williams for an annual fee that will increase to approximately $3.6 million in 2003. As a result, we no longer purchase and sell products related to blending activities. In addition, we will perform blending services at our Little Rock, Arkansas inland terminals which will generate additional annual blending fees of approximately $0.6 million. Consequently, our total blending services revenues for 2003 will be approximately $4.2 million.

In certain markets, barges provide an alternative source for transporting refined products; however, pipelines are generally the lowest-cost alternative for refined petroleum 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. Three key pipeline competitors include the Kaneb pipeline systems in the western and

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. In December 2002, Kaneb purchased a pipeline from Tesoro which receives product from Tesoro’s refinery in Mandan, North Dakota and runs to the Minneapolis/ St. Paul, Minnesota area.

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 when customers choose which line to use.

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.

Within our terminal network, we operate two types of petroleum products terminals: marine terminals and inland terminals. Our marine terminal facilities are located in close proximity to refineries and are large storage and distribution facilities that handle refined petroleum products, blendstocks, heavy oils and feedstocks and crude oil and condensate. Our inland terminals are located in the southeastern United States and are primarily located along third party pipelines such as Colonial, TEPPCO and Plantation. These facilities receive products from pipelines and distribute them to third parties at the terminals, which in turn deliver them to end-users such as retail outlets. Because these terminals are unregulated, the marketplace determines the prices we can charge for our services.

In 2002, Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of Williams, utilized our facilities to support their business activities and were among our largest terminal customers, representing approximately 15% and 5%, respectively, of revenues at our petroleum products terminals. In 2002, Williams began to significantly reduce their level of marketing and trading activity. As a result, we expect that Williams will comprise a significantly smaller portion of our ongoing revenues as we replace their revenue with revenues from third-party customers. Please read Note 15 to the Consolidated Financial Statements. For additional information relating to our commercial agreements with Williams and its affiliates, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Related Party Transactions”.

The Gulf Coast region is a major hub for petroleum refining, representing approximately 43% of total U.S. daily refining capacity and 74% of U.S. refining capacity expansion from 1990 to 2001. 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 2001, the amount of petroleum products exported from the Gulf Coast region increased by approximately 20%, or 220 million barrels. The growth in refining capacity and increased product flow attributable to the Gulf Coast region has created a need for additional transportation, storage and distribution facilities. In the future, the competition resulting from the consolidation trend, combined with continued environmental pressures, continuation of imports, 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 primarily 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 our 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 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. Further, 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 and to meet our customers’ marketing initiatives.

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

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

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 2002, approximately 97% of our marine terminal working storage capacity was under contract. As of December 31, 2002, approximately 66% 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 19% of revenues at our marine terminals for the year ended December 31, 2002. For a further discussion of revenues from major customers and concentration of risk, refer to Note 8 of the Consolidated Financial Statements. Also, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Related Party Transactions” for additional information regarding affiliate revenues.

Markets and Competition. We believe that the strong demand for our marine terminal facilities from our refining and chemical customers resulting from our cost-effective distribution services and key transportation links such as deep-water ports will continue. We experience the greatest demand at our marine terminals 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 or are less willing to enter into long-term storage contracts. The additional heating and blending services that we provide at our marine terminals 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.

We own and operate a network of 23 refined petroleum products terminals located primarily in the southeastern United States. These terminals have a combined storage capacity of 4.6 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, our Dallas terminal connects to Dallas Love Field airport via a 6-inch pipeline we purchased in April 2001. During 2002, gasoline represented approximately 60% of the volume of product distributed through our inland terminals, with the remaining 40% consisting of distillates.

Our inland terminal facilities typically consist of multiple storage tanks that are connected by a third-party 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;

	•	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. Our inland terminals are equipped with automated loading facilities that are available 24 hours a day.

We wholly own 12 of these inland terminals and our percentage ownership of the remaining 11 inland terminals ranges from 50% to 79%. The following table sets forth our inland terminal locations, percentage ownership, capacities and methods of supply:

Customers and Contracts. When we acquire terminals, we generally enter into long-term throughput contracts with the sellers under which they agree 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 enter 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


	•	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.

In March 2003, Williams completed the sale of its Memphis, Tennessee refinery and operations and has also sold its travel center operations. These sales have resulted in a reduced amount of marketing and trading activities performed by Williams Refining & Marketing with our inland terminals. We are in the process of replacing these revenues with other outside parties.

For the year ended December 31, 2002, Williams Refining & Marketing accounted for approximately 21% of our inland terminal revenues, with an additional 4% attributable to Williams Energy Marketing & Trading, Williams Bio Energy and Williams Petroleum Services collectively. For additional information relating to our commercial agreements with Williams and its affiliates, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Related Party Transactions”.

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.

We own a 1,100-mile ammonia pipeline system. Our pipeline transports ammonia from production facilities in Texas and Oklahoma to terminals in the Midwest for ultimate distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska, Oklahoma and South Dakota. The ammonia we transport 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. Please read Note 15 to the Consolidated Financial Statements.

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. Natural gas prices returned to more historically normal levels for most of 2002, after having been significantly higher between 1999 and the first six months of 2001, during which period our customers substantially curtailed their production of ammonia and shipped lower volumes of ammonia on our pipeline. Natural gas prices returned to higher levels in late 2002 and, during the first part of 2003, have increased to unprecedented high levels; consequently, shippers may again choose to lower their production of ammonia and their shipments on our pipeline. However, our shippers have committed to minimum shipping agreements of an aggregate of 700,000 tons per year through June 2005 (see “Customers and Contracts” below).

Operations. We are a common carrier transportation pipeline and terminals company. We do not produce or trade ammonia, and we do not take title to the ammonia we transport. 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.

We generate approximately 92% of our 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 our pipeline. In addition to transportation tariffs, we also earn revenue by charging our customers for services at the six terminals we own, including unloading ammonia from our customers’ trucks to inject it into our pipeline for shipment and removing ammonia from our pipeline to load it into our customers’ trucks.

We have agreed with Enterprise Products Partners L.P. (“Enterprise”) that, beginning February 2003, Enterprise will provide operating and general and administrative services for our ammonia pipeline system. Our operating agreement with Enterprise has an initial term of five years beginning in February 2003. We can cancel this agreement at any time by giving six-months written notice to Enterprise. This agreement will increase our operating expenses by approximately $0.5 million annually. Also, Enterprise will charge us $2.5 million annually for general and administrative expense associated with the operation of this pipeline. Management expects that these general and administrative costs will be subject to the expense limitation under our Omnibus Agreement. Please read “Item 13. Certain Relationships and Related Transactions — Omnibus Agreement”.

Facilities. Our pipeline 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.

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 complex nitrogen compounds such as urea, ammonium nitrate, ammonium phosphate and ammonium sulfate.


	•	Farmland Industries, Inc., one of the largest farmer-owned cooperatives in the United States (see Farmland below);

	•	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 700,000 tons per year (see Farmland discussion below) 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 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, our customers’ annual commitments represent 89% 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

(see Farmland discussion below). 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 230,000 tons in this combined bank that may be used to offset future ship or pay obligations. 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. Any annual adjustment is limited to a maximum increase or decrease of 5% measured against the rate previously in effect.

Farmland. On May 31, 2002, Farmland Industries, Inc. (“Farmland”) and several of its subsidiaries filed for Chapter 11 bankruptcy protection. Farmland, the largest customer on the ammonia pipeline system, is also a customer of the Williams Pipe Line system. Prior to Farmland’s bankruptcy filing, we placed Farmland on a pre-payment basis for its ammonia shipments; consequently, our exposure to uncollectable receivables from Farmland was small. We received approximately $2.3 million in payments from Farmland during the preference period prior to Farmland’s filing for bankruptcy. Management believes that we will not be required to reimburse these funds to the bankruptcy trustee because they were received in the ordinary course of business with Farmland. Farmland’s ammonia pipeline agreement provided for the right to terminate its shipment obligation by submitting 12 month written notice to us, which they have done. Farmland’s notification will be effective December 23, 2003. Farmland has announced that it is attempting to sell its ammonia production facility connected to our pipeline to Koch Nitrogen and has thus elected to exercise its termination right effective December 23, 2003. Farmland is expected to incur a deficiency of approximately $2.0 million to $2.5 million under its shipment obligation for the contract year beginning July 1, 2002 and ending June 30, 2003. On February 18, 2003, we entered into a settlement agreement with Farmland to resolve the deficiency. Under the settlement agreement, Farmland will pay us $0.8 million for the deficiency it will incur under its shipment obligation for the contract year ending June 30, 2003. If Farmland assigns its shipment obligation to a purchaser of its ammonia assets pursuant to bankruptcy procedures, Farmland’s termination notice will be withdrawn, and the shipment obligation will be reduced from 450,000 tons annually to 200,000 tons annually.

The settlement agreement is subject to approval by the bankruptcy court. If the bankruptcy court does not approve the settlement agreement by June 20, 2003, it will be void unless we agree with Farmland to extend the time for approval. If the settlement agreement is not approved and Farmland rejects its shipment obligation pursuant to bankruptcy procedures, we will have a general, unsecured creditor’s claim against Farmland for the deficiency it will incur under its shipment obligation for the contract year ending June 30, 2003 and for any deficiency incurred under its shipment obligation for the contract period beginning July 1, 2003 and ending December 23, 2003. Demand for anhydrous ammonia has not changed significantly, and we believe that we will continue to meet this demand through shipments of anhydrous ammonia produced by one of our other ammonia pipeline customers or produced at Farmland’s facility at Enid, Oklahoma by a subsequent buyer. The failure to negotiate a shipping agreement with the subsequent buyer of Farmland’s Enid facility would significantly reduce the aggregate minimum tons shipped on our pipeline.

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 pipeline.

We compete primarily with ammonia shipped by rail carriers, but we 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 - -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 Kaneb’s ammonia pipeline, which originates on the Gulf Coast and transports domestically produced and imported ammonia.

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, which in its initial form, allowed a pipeline to change its rates based on the annual change in the producer price index, or PPI, for finished goods less 1%. As required by its own regulations, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing rate indexing methodology. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC changed the rate indexing methodology to the PPI for finished goods, but without the subtraction of 1% as had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2001. 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 give assurance 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.

The Surface Transportation Board, a part of the United States Department of Transportation, has jurisdiction over interstate pipeline transportation of ammonia. The Surface Transportation Board succeeded the Interstate Commerce Commission which previously regulated pipeline transportation of ammonia.

The Surface Transportation Board is responsible for rate regulation of pipeline transportation of commodities other than water, gas or oil. These transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the Surface Transportation Board finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the Surface Transportation Board will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives.

The Surface Transportation Board does not need to provide rate relief unless shippers lack effective competitive alternatives. If the Surface Transportation Board determines that effective competitive alternatives are not available and a pipeline holds market power, then it must determine whether the pipeline rates are reasonable. The Board generally applies constrained market pricing principles in its economic analysis. Constrained market pricing provides two alternative methodologies for examining the reasonableness of a carrier’s rates. The first approach examines a carrier’s existing system to determine whether the carrier is already earning sufficient funds to cover its costs and provide a sufficient return on investment, or would earn sufficient funds after eliminating unnecessary costs from specifically identified inefficiencies and cross-subsidies in its operations. The second approach calculates the revenue requirements that a hypothetical, new and optimally efficient carrier would need to meet in order to serve the complaining shippers.

Customers that protest rates in Surface Transportation Board proceedings may use any methodology they choose that is consistent with constrained market pricing principles. When addressing revenue adequacy, a complainant must provide more than a single period snapshot of a carrier’s costs and revenues. The complainant must measure whether a carrier earns adequate revenues over a period of time, as measured by a multi-period discounted cash flow analysis.

The Surface Transportation Board has held that unreasonable discrimination occurs when (1) there is a disparity in rates, (2) the complaining party is 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.

Some shipments on the Williams Pipe Line system move within a single state and thus are considered to be 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.

Because in some instances we transport ammonia between two terminals in the same state, our ammonia pipeline 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.

Our pipeline systems 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. These pipeline systems will continue to be operated, maintained and inspected in accordance with governing regulations and industry practices.

Our pipeline systems are subject to regulation by the United States Department of Transportation under the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA as amended, 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 hazardous liquid interstate pipelines to develop and follow an integrity management program that provides for 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 and/or have the ability to impact high consequence areas. We believe we are in material compliance with HLPSA requirements. Since this rule went into effect, we have spent approximately $14.5 million relative to integrity assessment and anticipate spending approximately $36.5 million during the next five years associated with system integrity assessments. These cost estimates could increase in the future if additional safety measures are required or if existing safety standards are raised that exceed the current pipeline capabilities.

Our pipeline systems are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. We believe 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. At qualifying facilities, 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. We believe we are in material compliance with the OSHA PSM regulations.

The 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 is 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.

As described below, we will be indemnified against certain environmental liabilities by Williams Energy Services, Williams Natural Gas Liquids and by the entities from which Williams originally acquired some of the assets owned by us. Williams Energy Services and Williams Natural Gas Liquids are affiliates of Williams. Recent divestitures by Williams have significantly reduced the size and credit capacities of these affiliates. However, Williams has provided a performance guarantee with respect to the indemnifications made in association with the Williams Pipe Line acquisition. We are also a beneficiary of an environmental insurance

For assets transferred to us from Williams at the time of our initial public offering in February 2001, 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/or 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 of the initial public offering. Liabilities resulting from a change in law after the closing of our initial public offering are excluded from this indemnity. As of December 31, 2002, we had collected $1.7 million against Williams Energy Services’ indemnity and had recorded environmental liabilities of $3.3 million, substantially all of which were covered by Williams Energy Services’ indemnification. Further, we expect to incur $0.3 million of environmental capital, which should also be covered by this indemnification. Please read “Management Discussion and Analysis of Financial Condition and Results of Operations — Other Known Trends and Events — Change of Control” for additional discussion of possible changes associated with Williams Energy Services’ indemnifications to us.

In accordance with our acquisition agreement with Amerada Hess Corporation (“Hess”), 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. Hess, however, has no liability until the aggregate amount of initial losses is in excess of a $2.5 million deductible, and then 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; and

	•	indemnification for a variety of pre-acquisition fines and claims that may be imposed or asserted under the Superfund Law and federal Resource Conservation and Recovery Act (“RCRA”) or analogous state laws relative to pre-acquisition events. This indemnity is not subject to any limit or deductible amount.

In addition to these indemnities, 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 a 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 Hess terminal facilities that arose prior to closing of the acquisition from Hess, with a deductible of $0.3 million, and any environmental liabilities in excess of $15.0 million up to an aggregate of $65.0 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.

We also have insurance for up to $2.5 million of environmental liabilities for our Gibson, Louisiana marine terminal facility, with a deductible of $0.1 million. We assumed all of the environmental liabilities of the Gibson terminal, which we estimated at $0.1 million, at the time we acquired this facility from Geonet Gathering, Inc.

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. As of December 31, 2002, we had collected $3.3 million against this indemnity and had receivables under this indemnity of $19.9 million. Claims related to these environmental indemnities must be made prior to April 2008. Consequently, the remedial programs, assessed penalties and capital expenditures discussed below 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, this $125.0 million amount will also be subject to indemnification claims made by us for breaches of representations and warranties other than environmental. Williams has provided a performance guarantee for the remaining amount of these environmental indemnities.

Potentially significant assessment, monitoring and remediation projects related to events prior to our acquisition of the Williams Pipe Line system, are being performed at 45 sites in Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Oklahoma, South Dakota and Wisconsin. We estimate, at December 31, 2002, that the total cost of performing the currently anticipated assessment, monitoring and remediation at these 45 sites over the next several years will be approximately $18.7 million, all of which is covered by our indemnification agreements with Williams. The most significant remedial costs at these 45 sites are costs attributed to cleanup at eight terminals (Des Moines, Iowa City and Sioux City, all in Iowa, Kansas City, Kansas, Lincoln, Nebraska, Alexandria and Mankato, Minnesota, and Watertown, South Dakota) and two right of way locations (Bartlemy Lane, Minnesota and Kansas City Milepost 1, Kansas) where we estimate that $13.2 million of the $18.7 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 $18.7 million amount.

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 approximately $3.9 million in capital expenditures, including: an estimated $2.0 million to install a new loading rack at Palmyra, Missouri; an estimated $1.6 million to install dike linings at Alexandria, Minnesota; and an estimated $0.3 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. These costs are expected to be indemnified by Williams.

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 to remediation of impacts arising from the release. Two landowners adjacent to the release area subsequently intervened in the suit. A consent order resolving this matter was negotiated with the Illinois Attorney General’s office and resulted in payment of a $30,000 civil penalty and a supplemental environmental project which cost $72,000. The only outstanding requirement of the Consent Order is smart pigging specified pipelines which we estimate will cost approximately $0.8 million.

In addition to the 45 sites/projects discussed above, five releases have occurred since we acquired the Williams Pipe Line system in April 2002, resulting in approximately $0.8 million in expenditures to date. We have notified federal and state agencies of each of these incidents and are currently evaluating appropriate measures required to achieve regulatory closure of each incident. While the ultimate costs associated with cleanup of these incidents cannot be determined at this time, we have preliminarily estimated additional cleanup costs of between $0.3 million and $0.8 million, none of which is indemnified by Williams.

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 self-audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets nevertheless have the potential to substantially affect our business.

The amendments to the federal Spill Prevention, Control, and Countermeasure (SPCC) regulations that became effective on August 16, 2002 require revisions and/or cross-references be made to all our SPCC plans, of which we have more than 100, and may result in some of our facilities implementing physical improvements to ensure compliance with the regulation. At this time, the costs associated with complying with the amended regulations cannot be determined.

On July 2, 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from Williams 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, Williams furnished its response, which related primarily to the Williams Pipe Line system. We have received no further correspondence from the EPA related to this issue.

In most instances, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into the water or soils, and include measures to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under the Superfund law, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. The Superfund law also authorizes the Environmental Protection Agency, or EPA, and in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within the Superfund law’s definition of a hazardous substance and as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.

Our operations also generate wastes, including hazardous wastes, that are subject to the requirements of the RCRA and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations routinely generate only small quantities of hazardous wastes, and we do not hold ourselves out as a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA hazardous waste permit. While RCRA currently exempts a number of wastes, including many oil and gas exploration and production wastes, from being subject to hazardous waste requirements, the EPA from time to time will consider the adoption of stricter disposal standards for non-hazardous wastes. Moreover, it is possible that additional wastes, which could include non-hazardous wastes currently generated during operations, will in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly storage and disposal requirements than are non-hazardous wastes. Changes in the regulations could have a material adverse effect on our capital expenditures or operating expenses.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time,

hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to the Superfund law, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination. We are currently evaluating soil and groundwater conditions at a number of our properties where historical operations conducted primarily by former site owners or operators or more recent operations conducted by us may have resulted in releases of hydrocarbons or other wastes. These investigations and possible cleanup activities are either under consideration or already have been or will be initiated at a number of our locations.

States in which we operate typically have laws and regulations governing above ground tanks containing liquid substances. Generally, these laws and regulations require that these tanks include secondary containment systems or that the operators take alternative precautions to ensure that no contamination results from any leaks or spills from the tanks. The Department of Transportation Office of Pipeline Safety has incorporated API 653 to regulate above ground tanks subject to their jurisdiction. We believe we are in material compliance with all applicable above ground storage tank laws and regulations. As part of our assessment of facility operations we have identified some above ground tanks at our terminals that either are, or are suspected of being, coated with lead-based paints. The removal and disposal of any paints that are found to be lead-based, whenever such activities are conducted in the future as part of our day-to-day maintenance activities, will require increased handling by us. However, we do not expect the costs associated with this increased handling to be significant. We believe that the future implementation of above ground storage tank laws or regulations will not have a material adverse effect on our financial condition or results of operations.

Our operations can result in the discharge of pollutants, including oil. The Oil Pollution Act was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 or the Water Pollution Control Act and other statutes as they pertain to prevention and response to oil spills. The Oil Pollution Act subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill such as natural resource damages, where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill from one of our facilities into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations have been or are being developed under the Oil Pollution Act and comparable state laws that may also impose additional regulatory burdens on our operations. Although the costs associated with complying with the amended regulations cannot be determined at this time, we do not expect these expenditures to have a material adverse effect on our financial condition or results of operations.

The Federal Water Pollution Control Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. This law and comparable state laws require that permits be obtained to discharge pollutants into state and federal waters and impose substantial potential liability for the costs of noncompliance and damages. Where required, we hold discharge permits that were issued under the Federal Water Pollution Control Act or a state-delegated program, and we believe that we are in material compliance with the terms of those permits. While we have experienced permit discharge exceedances at some of our terminals we do not expect our compliance with existing permits and foreseeable new permit requirements to have a material adverse effect on our financial position or results of operations.

Our operations are subject to the federal Clean Air Act and comparable state and local laws. Under such laws, permits are typically required to emit pollutants into the atmosphere. Amendments to the federal Clean

Air Act enacted in 1990, as well as recent or soon to be proposed changes to state implementation plans, or SIPs, for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the amendments include an operating permit for major sources of volatile organic compounds, which applies to some of our facilities. We believe that we currently hold or have applied for all necessary air permits and that we are in material compliance with applicable air laws and regulations. Although we can give no assurances, we believe implementation of the 1990 federal Clean Air Act amendments and any changes to the SIPs pertaining to air quality in regional non-attainment areas will not have a material adverse effect on our financial condition or results of operations.

We are subject to the requirements of the federal OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in material compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

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 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 Williams 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 rights-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. We believe that we have 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. We believe that a failure to obtain all consents, permits or authorizations will not have a material adverse effect on the operation of our business.

We believe that we have satisfactory title to all of our assets or are entitled to indemnification from affiliates of Williams (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. 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, we believe 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.

The assets of Williams Pipe Line have been pledged as collateral against the Series A and Series B notes issued by Williams Pipe Line (see Note 12 — Long-Term Debt for further information).

To conduct our operations, our general partner or its affiliates employ approximately 788 employees, of which 538 conduct the operations of the Williams Pipe Line system, 192 conduct the operations of our petroleum products terminals and 58 spend 90% or more of their time providing general and administrative services. Approximately 226 of the employees assigned to the Williams Pipe Line system 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. The employees at our Galena Park marine terminal facility are currently represented by a union, but indicated in 2000 their unanimous desire to terminate their union affiliation. Nevertheless, the National Labor Relations Board (“NLRB”) has ordered us to bargain with the union as the exclusive collective bargaining representative of the employees at the facility. We appealed this decision to the Fifth Circuit Court of Appeals. Subsequently, the NLRB indicated the possibility that it would overturn its decision and requested that the Court of Appeals return our and other matters to the NLRB for further review and decision. No final decision has been issued by the NLRB. Our general partner considers its employee relations to be good.

Certain matters discussed in this report include forward-looking statements — statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as anticipates, believes, expects, planned, scheduled or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document.

The following are among the important factors that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted:


	•	price trends and overall demand for natural gas liquids, refined petroleum products, natural gas, oil and ammonia in the United States;

	•	weather patterns materially different than historical trends;

	•	development of alternative energy sources;

	•	changes in demand for storage in our petroleum products 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 products pipelines owned and operated by third parties and connected to our petroleum products terminals;

	•	loss of one or all of our three customers on our ammonia pipeline 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 system;

	•	an increase in the competition our operations encounter;


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

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

	•	our ability to successfully identify and close strategic acquisitions and 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 cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;

	•	the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

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

	•	the ability to raise capital in a cost-effective way;

	•	the effect of changes in accounting policies;

	•	the ability to manage rapid growth;

	•	Williams’ ability to perform on its environmental and rights-of-way indemnifications to us;

	•	supply disruption; and

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

We have no revenue or segment profit or loss attributable to international activities.

We file 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. Reports and other information that we file with or furnish to the SEC electronically 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.

Our Internet address is www.williamsenergypartners.com. We did not make all reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act available on or through our Internet website as of November 15, 2002. However, as of March 6, 2003, we make available, free of charge on or through our Internet website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practical after we electronically file such material with, or furnish it to, the United States Securities and Exchange Commission.

See Item 1(c) for a description of the locations and general character of our material properties.

We are a party to various legal actions that have arisen in the ordinary course of our business. We do not believe that the resolution of these matters will have a material adverse effect on our financial condition or results of operations.

No matters were submitted to a vote of the unitholders during the fourth quarter of 2002.

We completed our initial public offering in February 2001. Our common units are listed on the New York Stock Exchange under the symbol “WEG”. At the close of business on January 31, 2003, we had 121 registered holders and 15,167 beneficial holders of record of our common units. The high and low closing sales price ranges and distributions declared by quarter for 2002 and 2001 are as follows:


*	Represents declared distributions associated with each respective quarter. Distributions were 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 due to the timing of our initial public offering.

In addition to common units, we have also issued subordinated and Class B units, for which there is no established public trading market. All of the subordinated and Class B units are held by affiliates of our General Partner. The subordinated units were issued as part of our initial public offering in February 2001 and receive a quarterly distribution only after sufficient funds have been paid to the common and Class B units, as described below. In addition, the subordinated units generally have reduced voting rights equal to one-half vote for each unit owned.

The Class B units were issued as partial payment for the April 2002 purchase of the Williams Pipe Line system (see Note 5 — Acquisitions and Divestitures for additional information on the acquisition of Williams Pipe Line). These units are equivalent to common units except they only have voting rights with respect to matters that would have a material impact on the holders of such units. Our credit agreements contain provisions which prevent us from redeeming or retiring the Class B units except with the proceeds of an equity issuance. When the Class B units are redeemed, the price will be based on the 20-day average closing price of the common units prior to the redemption date. See Note 12 to the Consolidated Financial Statements. If the Class B units are not redeemed by April 11, 2003, then upon the request of the holder of the Class B units and approval of the holders of a majority of the common units voting at a meeting of the 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 this request, the holder of the Class B units 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.

During the subordination period, the holders of our common and Class B units are entitled to receive each quarter a minimum quarterly distribution of $0.525 per unit ($2.10 annualized) prior to any distribution of available cash to holders of our subordinated units. The subordination period is defined generally as the period that will end on the first day of any quarter beginning after December 31, 2005 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, as defined in our partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2003 and one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2004 if we meet the tests set forth in our partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common and Class B units and the subordinated units may be converted into common units. We currently anticipate meeting the first early conversion test. The impact of meeting the test is that after December 31, 2003, one-quarter of our outstanding subordinated units will convert to common units, the existing common units will have less subordinated protection with respect to distributions, and the subordinated units that convert into common units will receive voting rights equivalent to those of the common units.

During the subordination period, our cash is distributed first 98% to the holders of common and Class B units and 2% to our General Partner until there has been distributed to the holders of common and Class B units an amount equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution on the common and Class B units for any prior quarter. Any additional cash is distributed 98% to the holders of subordinated units and 2% to our General Partner until there has been distributed to the holders of subordinated units an amount equal to the minimum quarterly distribution.

Our General Partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

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, which is defined in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution. We currently pay quarterly cash distributions of $0.725 per unit. In general, we intend to continue to increase our cash distributions in the future assuming no adverse change in our operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.

We have derived the summary selected historical financial data as of December 31, 2002 and 2001 and for each of the years ended December 31, 2002, 2001 and 2000 from our audited consolidated financial statements and related notes. Due to the April 2002 acquisition of Williams Pipe Line, we have restated our consolidated financial statements and notes to reflect the results of operations, financial position and cash flows of Williams Energy Partners L.P. and Williams Pipe Line Company on a combined basis throughout the periods presented. These financial data are an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto. All other amounts have been prepared from our financial records. Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The historical results for Williams Pipe Line Company (“Williams Pipe Line”) included income and expenses and assets and liabilities that were conveyed to and assumed by an affiliate of Williams Pipe Line prior to our acquisition of it. The assets principally included Williams Pipe Line’s interest in and agreement related to Longhorn Partners Pipeline (“Longhorn”), an inactive refinery site at Augusta, Kansas, a pipeline construction project, the ATLAS 2000 software system and the pension asset and obligations associated with the non-contributory defined-benefit pension plan that covered employees assigned to Williams Pipe Line’s operations. The liabilities principally included the environmental liabilities associated with the inactive refinery site in Augusta, Kansas and current and deferred income taxes and affiliate note payable. The current and deferred income taxes and the affiliate note payable were contributed to us in the form of a capital contribution by an affiliate of Williams. Also, because of an agreement we have with Williams, revenues from Williams Pipe Line’s blending operations, other than an annual blending fee of approximately $3.0 million, have not been included in our financial results since April 2002. In addition, general and administrative expenses related to the Williams Pipe Line system that we have been reimbursing to our General Partner have been limited to $30.0 million per year plus an annual escalator. See Note 1 to the Consolidated Financial Statements regarding recent changes to the General Partner.

EBITDA is defined as net income plus provision for income taxes, debt placement fees, interest expense (net of interest income) and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with generally accepted accounting principles. EBITDA is not intended to represent cash flow. Because EBITDA excludes some but not all items that affect net income and these measures may vary among other companies, the EBITDA data presented may not be comparable to similarly titled measures of other companies. Our management uses EBITDA as a performance measure to assess the viability of projects and to determine overall rates of return on alternative investment opportunities.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and notes thereto. Williams Energy Partners L.P. is a publicly traded limited partnership formed by The Williams Companies, Inc. (“Williams”) 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 current asset portfolio consists of:


	•	the Williams Pipe Line system;

	•	five marine terminal facilities;

	•	23 inland terminals (some of which are partially owned); 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 (“Williams Pipe Line”) from a wholly owned subsidiary of Williams. Williams Pipe Line owns and operates the Williams Pipe Line system. Because Williams Pipe Line 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 similar 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 on a combined basis throughout the periods presented.

The historical results for the Williams Pipe Line system include revenue and expenses and assets and liabilities that were conveyed to and assumed by an affiliate of Williams Pipe Line prior to our acquisition of it. These assets primarily include Williams Pipe Line’s interest in and agreements related to Longhorn Partners Pipeline (“Longhorn”), an inactive refinery at Augusta, Kansas, a pipeline construction project, the ATLAS 2000 software system and the pension asset and obligations associated with the non-contributory defined-benefit pension plan that covered employees assigned to Williams Pipe Line’s operations. The results from these assets have not been included in our financial results since our acquisition of Williams Pipe Line in April 2002. In addition, revenues from Williams Pipe Line’s blending operations, other than an annual blending fee of approximately $3.0 million, have not been included in our financial results since April 2002. We report the Williams Pipe Line system’s operations as a separate operating segment.

During 2002, Williams began to experience significant financial and liquidity difficulties and no longer maintains an investment grade credit rating. In the event that Williams’ financial condition does not improve or worsens it may have to consider other options including the possibility of filing for bankruptcy under the United States Bankruptcy Code. Management believes that should Williams and its affiliates file for bankruptcy protection that we would not necessarily become a party to such bankruptcy filings. However, we cannot assure you that Williams and its affiliates, or the creditors of Williams and its affiliates, would not attempt to utilize various remedies available in a bankruptcy (including substantive consolidation), in an effort to make our assets available to the creditors of Williams and its affiliates, or how a bankruptcy court would resolve such issues. Likewise, there can be no assurances as to the ultimate impact a bankruptcy by Williams and its affiliates would have on their ability to perform obligations owed to us, including our General Partner.

WEG GP LLC, our general partner (“General Partner”), is a wholly-owned subsidiary of Williams. Combined with its limited partnership interest, Williams owns approximately 55% of us. However, we operate our business in a manner separate and distinct from Williams. Among other things, (i) we either own or lease

the assets used in our business in our own name, (ii) we have three independent board members who serve on a conflicts committee that must approve any material transaction between Williams or its affiliates and us, as well as approve certain significant transactions (such as the filing of a bankruptcy petition) and (iii) other than affiliate receivables and payables generated from product sales and services rendered in the normal course of business, we do not provide any credit support to Williams or its affiliates and Williams does not provide credit support to us.

Provisions of the General Partner’s limited liability company agreement specifically provide that, decisions regarding a voluntary bankruptcy filing of WEG GP LLC or us must be approved by our conflicts committee. Our conflicts committee is comprised of the independent board members of WEG GP LLC.

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 Federal Energy Regulatory Commission (“FERC”). Williams Pipe Line also earns revenues from non-tariff based activities, including leasing pipeline and storage tank capacity to shippers on a long-term basis and by providing data services and product services such as ethanol unloading and loading, additive injection, custom blending and laboratory testing for our customers.

Prior to our acquisition of it in April 2002, Williams Pipe Line generally did not produce or trade refined petroleum products or liquid propane gases or take title to the products it transported. 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. Williams Pipe Line purchased and took 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, we, and an affiliate of Williams agreed that Williams Pipe Line would no longer take title to the natural gas liquids it blends with gasoline or the resulting product. We continue to perform these blending services for affiliates of Williams under a ten-year agreement for an annual fee that will increase to approximately $3.6 million in 2003. In addition, we perform blending services at our Little Rock, Arkansas inland terminals, which generate annual blending fees of approximately $0.6 million. As a result, total revenues generated from blending services in 2003 will be approximately $4.2 million. We continue to purchase and fractionate transmix and to sell the resulting separated products.

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 power, fluctuate with volumes transported and stored on the system. Expenses resulting from environmental remediation projects have historically included costs from projects relating both to current and past events. In connection with our acquisition of Williams Pipe Line, 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, filtering jet fuel and delivering product to the Dallas Love Field airport. 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 power, fluctuate with storage utilization or throughput levels.

Ammonia Pipeline System. The ammonia pipeline system earns the majority of its revenue from transportation tariffs that we charge for transporting ammonia through the pipeline. We have entered into a new agreement with Enterprise Products Partners L.P. (“Enterprise”) to operate our ammonia system, which will increase our operating expenses by approximately $0.5 million annually Also, Enterprise will charge us $2.5 million annually for general and administrative expenses associated with their operation of this pipeline. Management believes that the general and administrative costs will be subject to the expense limitation under our Omnibus Agreement. Please read “Item 13 — Certain Relationships and Related Transactions — Omnibus Agreement.”

General and Administrative Expenses. General and administrative expenses are provided by and paid to Williams as defined by the Omnibus Agreement. General and administrative expenses include functions such as commercial operations, engineering, information technology, finance, accounting, human resources and other corporate services. Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement.

In connection with our initial public offering, and with respect solely to the petroleum products terminals and ammonia pipeline assets we owned at the time of that offering, we and our General Partner agreed with Williams 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. The reimbursement limitation will remain in place through 2011 and may increase by no more than the greater of 7% 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. For 2003, the general and administrative limitation was increased 2.4% to $6.9 million.

In connection with our acquisition of the Williams Pipe Line system, we and our General Partner agreed with Williams that the general and administrative expenses to be reimbursed to our General Partner by us for charges related to this asset would be $30.0 million for 2002, pro rated for the actual period that we owned 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. For 2003, the general and administrative limitation was increased 2.4% to $30.7 million. In addition, costs will increase by another $0.3 million for general and administrative costs associated with the Rio Grande Pipeline, which we began operating in February 2003.

We expect the 2003 general and administrative expenses paid to Williams to be $37.9 million before equity-based long-term incentive plans and adjustments for additional acquisitions. Please read “Risks Related to Our Business” for additional discussion of potential changes in our general and administrative costs as a result of a sale by Williams of their interest in us. Management estimates that the actual general and administrative costs required for our operations of the Partnership on a stand-alone basis could significantly exceed this $37.9 million amount, due in part to significant increases in insurance premiums and increased general and administrative costs on the ammonia pipeline system associated with the new Enterprise operating contract, as well as our new agreement to operate the Rio Grande Pipeline.

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 a subsidiary of Williams;

	•	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.

Our revenues, excluding product sales and construction revenues, for the year ended December 31, 2002 were $363.7 million compared to $339.4 million for the year ended December 31, 2001, an increase of $24.3 million, or 7%. This increase was a result of:


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

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

	•	a decrease in ammonia pipeline system revenues of $1.4 million, or 10%, primarily due to a throughput deficiency billing in the prior year that resulted from a shipper’s inability to meet its minimum annual throughput commitment for the contract year ended June 2001. In addition, revenue also declined due to significantly reduced volumes from one of our shippers following its filing for Chapter 11 bankruptcy during May 2002. Partially offsetting these decreases was a higher weighted-average tariff of $16.94 in 2002 compared to $16.21 during the prior year.

Operating expenses including environmental expenses net of environmental indemnifications from Williams and excluding product purchases were $155.1 million for the year ended December 31, 2002, compared to $160.9 million for the year ended December 31, 2001, a decrease of $5.8 million, or 4%. This decrease was a result of:


	•	a decrease in Williams Pipe Line system expenses of $8.9 million, or 7%, primarily due to lower environmental and maintenance expenses and reduced power costs. Environmental costs were lower due to the indemnification from an affiliate of Williams for environmental issues resulting from operations prior to our ownership of the pipeline. Maintenance expenses declined due to improved cost controls as a result of the implementation of a consistent and disciplined expense decision making process. Reduced power costs resulted from lower volumes transported coupled with reduced power rates. Partially offsetting these reductions was an increase in pipeline lease expenses, which represent


		tariffs paid on connecting pipelines to move a customer’s product to its ultimate destination. The customer reimburses us through the transportation tariff for this service which began in the current year, hence there are no associated pipeline lease expenses in the prior year;

	•	an increase in petroleum products terminals expenses of $2.2 million, or 7%, primarily due to the addition of the Gibson marine facility and the Little Rock inland terminals and increased maintenance expenses resulting from timing of tank cleaning and API 653 inspections at the inland terminals; and

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

Revenues from Williams Pipe Line product sales were $69.2 million for the year ended December 31, 2002, while product purchases were $64.0 million, resulting in a net margin of $5.2 million in 2002. The 2002 net margin represents a decrease of $6.2 million compared to a net margin in 2001 of $11.4 million resulting from product sales for the year ended December 31, 2001 of $106.7 million and product purchases of $95.3 million. The margin decline in 2002 reflects our agreement with an affiliate of Williams to provide blending services for them for an annual fee of $3.0 million. As a result of this agreement, we no longer generate a commodity margin in butane blending related activities. Revenues from petroleum products terminal product sales were $1.4 million in 2002 and $1.5 million in 2001.

Affiliate construction and management fee revenues for the year ended December 31, 2002 were $0.2 million compared to $1.0 million for the year ended December 31, 2001. Historically, Williams Pipe Line received a fee to manage Longhorn and to provide consulting services associated with the pipeline’s construction and start-up, as needed. Prior to our acquisition of Williams Pipe Line, the obligation to provide this service for Longhorn was transferred to a wholly-owned subsidiary of Williams.

Depreciation and amortization expense for the year ended December 31, 2002 was $35.1 million, representing a $0.7 million decrease from 2001 at $35.8 million. Additional depreciation associated with acquisitions and capital improvements were more than offset by the elimination of depreciation associated with assets we did not acquire as part of the Williams Pipe Line acquisition.

General and administrative expenses for the year ended December 31, 2002 were $43.2 million compared to $47.4 million for the year ended December 31, 2001, a decrease of $4.2 million, or 9%. General and administrative expenses are paid to Williams as defined by the Omnibus Agreement. For 2002, subsequent to the Williams Pipe Line acquisition, general and administrative expenses were limited to $9.2 million per quarter plus equity-based incentive compensation expenses. Incentive compensation costs associated with our long-term incentive plan are specifically excluded from the expense limitation and were $3.7 million during 2002 and $2.0 million during 2001. The 2002 incentive compensation costs included $2.1 million associated with the early vesting of the phantom units issued to key employees at the time of our initial public offering. The early vesting was triggered as a result of meeting targets for our growth in cash distributions paid to unitholders. Prior to our acquisition of Williams Pipe Line, this operating unit was allocated general and administrative costs from Williams based on a three-factor formula that considers operating margin, payroll costs and property, plant and equipment. The amount of general and administrative costs we pay will continue to be adjusted in the future to reflect additional general and administrative expenses incurred in connection with acquisitions as well as the annual adjustments allowed by the Omnibus Agreement. Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement.

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

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

Net income for the year ended December 31, 2002 was $99.2 million compared to $67.9 million for the year ended December 31, 2001, an increase of $31.3 million, or 46%. The operating margin increased by $23.0 million during the period, largely as a result of increased revenues and reduced operating expenses including environmental expenses net of indemnifications from Williams for Williams Pipe Line, earnings from the acquisitions of the Little Rock and Gibson terminal facilities and increased utilization and rates at our Gulf Coast marine facilities. Depreciation expense and general and administrative expenses decreased by $0.7 million and $4.2 million, respectively, while net interest expense increased by $9.7 million. Debt placement fee amortization expense increased $9.7 million primarily due to costs from debt financing associated with the Williams Pipe Line acquisition. Other income increased $1.7 million primarily due to: (i) gain on the sale of assets and (ii) an impairment charge recorded during 2001 related to the inactive refinery site at Augusta, Kansas, the assets and liabilities of which were not transferred to us as part of the Williams Pipe Line acquisition. Income taxes decreased $21.2 million due to our partnership structure.

Our revenues excluding product sales and construction revenues for the year ended December 31, 2001 were $339.4 million compared to $318.1 million for the year ended December 31, 2000, an increase of $21.3 million, or 7%. This increase was primarily a result of:


	•	an increase in Williams Pipe Line system’s transportation and related revenues of $9.3 million, or 4%, primarily due to higher transportation revenues, partially offset by a decrease in revenues from product services. The increase in transportation revenues resulted from increased volumes and mid-year tariff increases. 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 additive injection revenues resulting from lower prices for these services under new agreements;

	•	an increase in the petroleum products terminals revenues of $9.2 million, or 15%, primarily a result of the acquisitions of our New Haven marine terminal facility in September 2000, two Little Rock inland terminals in June 2001 and the Gibson marine terminal facility in October 2001. An improved marketing environment resulted in higher utilization at our Gulf Coast marine 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%, partly due to a throughput deficiency billing that resulted from a shipper’s inability to meet 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. The weighted-average tariff increased from $15.50 in 2000 to $16.21 in 2001.

Operating expenses including environmental expenses net of indemnifications from Williams and 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 expenses of $12.2 million, or 11%, primarily caused by increased maintenance and power expenses. Maintenance costs were higher due to increased expenditures associated with our System Integrity Program, which is designed to ensure compliance with increased safety regulations. This program includes increased emphasis on pipeline inspections and API 653 tank inspections. Power expense increased due to higher transportation volumes and higher power rates. Partially offsetting these increases were lower environmental and less casualty loss expense. Environmental expenses were less due to higher costs recognized in 2000 related to the inactive refinery site at Augusta, Kansas, assets and liabilities of which were not transferred to us as part of the Williams Pipe Line acquisition. Casualty losses decreased due to higher costs recognized in 2000 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%, due primarily to the acquisitions of the New Haven marine terminal facility in September 2000, the Little Rock inland terminals in June 2001 and the Gibson 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 $108.2 million for the year ended December 31, 2001, while product purchases were $95.3 million, resulting in a net margin of $12.9 million in 2001. The 2001 net margin represents an increase of $0.3 million compared to a net margin in 2000 of $12.6 million resulting from product sales in 2000 of $106.8 million and product purchases of $94.2 million. Revenues from petroleum products terminal product sales were $1.5 million in 2001 and $2.4 million in 2000.

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 $0.1 million compared to a net margin in 2000 of $0.9 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 $4.1 million, or 13%. The increase was due primarily to the acquisitions of the New Haven marine terminal facility, two Little Rock inland terminals and Gibson marine terminal facility 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 provided for in the Omnibus Agreement. 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 in 2001 were $38.4 million compared to $39.2 million in 2000. Williams allocates both direct and indirect general and administrative expenses to its affiliates. Direct expenses allocated by Williams are primarily salaries and benefits of employees and officers associated with the business activities of the affiliate. Indirect expenses include legal, accounting, treasury, engineering, information technology and other corporate services. We reimburse the General Partner and its affiliates for direct and indirect expenses incurred by or allocated to them on our behalf.

Net interest expense for the year ended December 31, 2001 was $12.1 million compared to $25.3 million for the year ended December 31, 2000. This decrease is primarily the result of a decline in affiliate notes payable to Williams and lower interest rates. The affiliate note payable associated with the Williams Pipe Line system declined as a result of a partial repayment using cash generated from operations in excess of capital expenditures. The affiliate note payable associated with the petroleum products terminals and ammonia pipeline system was partially repaid and the balance was contributed to us as capital in connection with our initial public offering in February 2001. At the end of 2001, we had $139.5 million outstanding under a term loan and revolving credit facility.

We do not pay income taxes because we are a partnership. We primarily based our income tax rate of 39% for our pre-initial public offering earnings from our petroleum products terminals and ammonia pipeline businesses upon the effective income tax rate for Williams as a result of Williams’ tax-sharing arrangement with its subsidiaries. In addition, Williams Pipe Line was taxed as a corporation prior to our acquisition of the system on April 11, 2002. Williams Pipe Line’s effective tax rates for the years ended December 31, 2001 and 2000 were 39% and 38%, respectively, also based primarily on the effective income tax rates for Williams 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 acquisition of the New Haven, Little Rock and Gibson petroleum products terminals, partially offset by higher operating costs associated with those acquisitions and higher system integrity costs on the Williams Pipe Line system. Depreciation and amortization increased by $4.1 million, whereas general and administrative expenses declined $3.8 million. Net interest expense decreased $13.2 million. Debt placement fee amortization increased $0.3 million and other income declined $0.4 million. Income taxes decreased $0.9 million.

We have significant relationships with Williams, the owner of our General Partner, Farmland Industries, Inc. (“Farmland”) and other third-party entities that impact our operating results. Williams has completed a number of asset sales and entered into secured debt agreements to address its liquidity needs, and Farmland has filed for bankruptcy. Our relationships with these two entities are described below:

Williams — During the past year, Williams has experienced financial and liquidity difficulties and currently does not have an investment grade credit rating. These financial difficulties have raised questions concerning Williams’ ability to meet its existing financial obligations. However, Williams has not filed for bankruptcy protection and neither Williams, WEG GP LLC, nor any other Williams affiliate has advised us of any intention by Williams, any Williams affiliate or our General Partner to place Williams or our General Partner into bankruptcy. We are engaged contractually with Williams on several fronts, including commercial relationships, contracted services and indemnities. The extent of these relationships include:


	•	Williams is the owner of our General Partner and its ownership interest in us is approximately 55%, including its 2% general partner interest;


	•	Williams is a customer, representing approximately 13% of our 2002 revenues. We expect to replace a majority of these revenues without significant impact to our results of operations if Williams is unable to perform on its existing obligations.

	•	Williams provides various services for us. Through these services, Williams operates our assets and provides general and administrative functions. All employees supporting our partnership are employees of Williams. We pay the cost for the operating expenses associated with our assets, and we incur an additional cost for general and administrative services, which are limited under the Omnibus Agreement to approximately $40.0 million per year. Management estimates that actual general and administrative costs required for our operation could be significantly higher due in part to increases in insurance premiums and increased general and administrative costs for the ammonia pipeline associated with the new Enterprise operating contract. For the year ended 2002, Williams incurred $19.7 million of general and administrative charges in excess of the amount specified under terms of the Omnibus Agreement. Some of the charges did not relate to services essential for our ongoing operations. Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement; and

	•	for assets included in our initial public offering, Williams agreed to provide maintenance capital reimbursements for expenditures in excess of $4.9 million during 2001 and 2002. We received total reimbursement of $14.9 million for maintenance capital spent during the period of the agreement. In addition, Williams has agreed to pay maintenance capital associated with the Williams Pipe Line system in excess of $19.0 million per year for 2002, 2003 and 2004 up to a cumulative maximum of $15.0 million. We expect to spend less than $19.0 million annually for maintenance capital for the Williams Pipe Line system and do not expect any maintenance capital reimbursement from Williams associated with this asset.

Affiliates of Williams have provided various indemnifications to us. Please read “Critical Accounting Estimates — Environmental Liabilities” and “Critical Accounting Estimates — Affiliate Receivables”.

Change of Control — On February 20, 2003, Williams announced its intention to divest its interest in our General Partner and all of its limited partnership interests. Upon completion of this proposed divestiture, the resulting change of control may lead to the following results:


	•	termination of our Omnibus Agreement with Williams or termination of Williams’ obligation to provide general and administrative services for a fixed charge, which could result in higher general and administrative expenses and cessation of the environmental indemnification for the assets acquired at the time of our initial public offering;

	•	acceleration of principal payments on outstanding debt;

	•	initial increase in the allocation of taxable income to our unitholders; and

	•	early vesting of phantom units issued as part of our long-term incentive compensation plan.

It is uncertain what form the sale of Williams’ interests may take and management is unable, at this time, to determine what impact such a transaction will have on our ongoing operations.

Farmland — Farmland filed for Chapter 11 bankruptcy protection on May 31, 2002. Farmland is the largest customer on our ammonia pipeline system. Farmland also owns and operates a refinery in Coffeyville, Kansas, with its products marketed primarily through a third party that ships on Williams Pipe Line. This third party shipper is not affiliated with either Farmland or Williams. Combined total revenues associated with Farmland’s ammonia shipments and the use of the Williams Pipe Line system to transport products from the Farmland refinery were $31.5 million and $37.3 million for the year ended December 31, 2002 and 2001, respectively, or 7% and 8% of total revenues for 2002 and 2001, respectively. Demand for products from Farmland’s Coffeyville, Kansas refinery have continued to be strong and we expect that this demand will remain so for the foreseeable future. Also, we believe that Farmland will either continue to operate its

Farmland’s ammonia pipeline agreement provided for the right to terminate its shipment obligation by submitting 12 month written notice to us, which they have done. Farmland’s notification will be effective December 23, 2003. Farmland has indicated that its ammonia production facility connected to our pipeline is for sale and has thus elected to exercise its termination right effective December 23, 2003. Farmland is expected to incur a deficiency of approximately $2.0 million to $2.5 million under its shipment obligation for the contract year ending June 30, 2003. On February 18, 2003, we entered into a settlement agreement with Farmland to resolve its deficiency. Under the settlement agreement, Farmland will pay us $0.8 million for the deficiency it will incur under its shipment obligation for the contract year ending June 30, 2003. If Farmland assigns its shipment obligation to a purchaser of its ammonia assets pursuant to bankruptcy procedures, Farmland’s termination notice will be withdrawn, and the shipment obligation will be reduced from 450,000 tons annually to 200,000 tons annually.

Net cash provided by operating activities was $161.0 million for the year ended December 31, 2002, $135.3 million for 2001 and $55.1 million for 2000.


	•	Net income for 2002 benefited from higher revenues and reduced expenses for the Williams Pipe Line system and greater terminals profits due to the Little Rock and Gibson acquisitions and higher utilization at the Gulf Coast facilities. The reduction in income taxes more than offset the increased interest expense. Changes in operating assets and liabilities provided additional net cash. Inventories decreased during 2002 due to the elimination of butane blending inventories as we now perform butane blending as a service provider without carrying the relevant inventory. As part of our acquisition of the Williams Pipe Line system, Williams retained $15.0 million of its accounts receivables and the affiliate payables. Therefore, accounts receivables and affiliate payables increased during 2002 as they were replaced as part of the ongoing operations of that business. Further, increases in affiliate receivables were primarily offset by increases in environmental liabilities due to the indemnification from Williams for environmental liabilities occurring prior to our ownership of the Williams Pipe Line system.

	•	Net income increased from 2000 to 2001 due to the acquisition of our New Haven, Little Rock and Gibson terminals and reduced interest expense. Changes in operating assets and liabilities also impacted cash from operations. Accounts receivable significantly declined due to the 2001 collection of receivables related to reimbursable construction projects. In addition, affiliate receivables declined due to the 2001 collection of a large outstanding short-term affiliate receivable due from an affiliate of Williams. Inventories increased between periods due to higher commodity prices during 2001. Further, changes to other current and noncurrent assets and liabilities resulted from collection of unbilled reimbursable construction projects at year-end 2000 and long-term affiliate receivables related to reimbursable Longhorn construction costs.

Net cash used by investing activities for the years ended December 31, 2002, 2001 and 2000 was $727.0 million, $87.5 million and $74.4 million, respectively. During 2002, we acquired the Williams Pipe Line system and the Aux Sable natural gas liquids pipeline. During 2001, we acquired our two Little Rock inland terminals and the Gibson marine facility. During 2000, we acquired our interest in the Southlake inland

terminal and the New Haven marine facility. We also invested capital to maintain our existing assets. Maintenance capital spending before reimbursements was $26.4 million, $24.4 million and $25.9 million in 2002, 2001 and 2000, respectively. Please see Capital Requirements below for further discussion of capital expenditures.

Net cash provided (used) by financing activities for the years ended December 31, 2002, 2001 and 2000 was $627.3 million, $(34.0) million and $19.4 million, respectively. The cash provided during 2002 principally included the debt and equity funding that were completed in conjunction with our acquisition of Williams Pipe Line. Cash was used in 2001 to repay affiliate notes associated with our initial public offering assets as well as payments made by Williams Pipe Line to decrease its affiliate note balance, partially offset by proceeds from debt borrowings and equity issued in our initial public offering and subsequent debt borrowings for acquisitions. The 2000 cash inflow primarily represents affiliate loans we received from Williams to fund our terminal acquisitions, partially offset by repayments of the affiliate note payable associated with Williams Pipe Line using free cash flow generated by the system.

Federal Energy Regulatory Commission Notice of Proposed Rulemaking — On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform Systems of Accounts for public utilities, natural gas companies and oil pipeline companies by requiring specific written documentation concerning the management of funds from a FERC-regulated subsidiary by a non-FERC-regulated parent. Under the proposed rule, as a condition for participating in a cash management or money pool arrangement, the FERC-regulated entity would be required to maintain a minimum proprietary capital balance (stockholder’s equity or partners’ capital) of 30%, and the FERC-regulated entity and its parent would be required to maintain investment grade credit ratings. If either of these conditions is not met, the FERC-regulated entity would not be eligible to participate in the cash management or money pool arrangement. As of December 31, 2002, all of our debt was issued to private lenders and is not rated; therefore, we do not currently meet the second requirement. The period for interested companies to make comments to the FERC relative to this proposed rule has ended, and the FERC is evaluating its position on the issue. We do not know when or if the rule will be enacted. However, we have established separate bank accounts for Williams Pipe Line and we believe we could easily comply with the proposed rule.

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


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

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

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

In connection with our acquisition of Williams Pipe Line, Williams 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 all years of $15.0 million. Our maintenance capital expenditure expectations related to the Williams Pipe Line system are less than $19.0 million per year and we do not anticipate reimbursement by Williams.

During 2002, our maintenance capital spending net of reimbursements was $15.4 million. We expect to incur maintenance capital expenditures for 2003 for all of our businesses of $22.0 million.

In addition to maintenance capital expenditures, we also incur payout capital expenditures at our existing facilities for expansion and upgrade opportunities. During 2002, we spent $11.3 million of payout capital, excluding acquisitions. Based on projects currently in process, we plan to spend approximately $6.5 million of payout capital in 2003. This amount does not include capital expenditures made in connection with any future acquisitions. We expect to fund our payout 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.

Williams Pipe Line Senior Secured Notes. In connection with the financing of the Williams Pipe Line system acquisition, we and our subsidiary, Williams Pipe Line Company, entered into a note purchase agreement on October 1, 2002. The private placement allowed for two separate borrowings: (i) $420.0 million to be used to repay the Williams Pipe Line short-term loan and related debt placement fees and (ii) $60.0 million for general corporate purposes. We borrowed a total of $480.0 million under the debt agreement. The incremental $60.0 million was used primarily to repay the outstanding acquisition sub-facility of the OLP term loan and credit facility, described below. The Williams Pipe Line borrowing included Series A and Series B notes. The maturity date of both notes is October 7, 2007, with scheduled prepayments equal to 5% of the outstanding balance due on both October 7, 2005 and October 7, 2006. The debt is secured by our membership interests in and the assets of Williams Pipe Line. Payment of interest and principal is guaranteed by Williams Energy Partners L.P.

The Series A notes include $178.0 million of borrowings that incur interest based on the six-month Eurodollar rate plus 4.3%. The Series B notes include $302.0 million of borrowings that incur interest at a weighted-average fixed rate of 7.8%.

The debt agreement contains various covenants limiting Williams Pipe Line Company’s ability to:


	•	incur additional indebtedness;

	•	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;

	•	dispose of assets;

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

	•	create obligations for some lease payments; and

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

In addition, the debt agreement prohibits us from redeeming the Class B units except with proceeds from an equity offering. It also prohibits our General Partner from incurring any indebtedness. The Williams Pipe Line notes also contain financial covenants, that apply to both Williams Pipe Line and us, to maintain specified ratios of:


	•	EBITDA (as defined in the Williams Pipe Line Senior Secured debt agreement) to interest expense of not less than 2.5 to 1.0; and

	•	total debt to EBITDA of not more than 4.5 to 1.0.

In the event of a change in control of the General Partner, each holder of the notes would have 30 days within which they could exercise a right to put their notes to Williams Pipe Line unless the new owner of the General Partner has: (i) a net worth of at least $500 million and (ii) long-term unsecured debt rated as investment grade by both Moody’s Investor Service Inc. and Standard & Poor’s Rating Service. A change of control is an event in which Williams or its affiliates no longer own 50% or more of the General Partner’s interest in us. If this put right were to be exercised, Williams Pipe Line would be obligated to repurchase any such notes at par value and repay any accrued interest within sixty days.

OLP term loan and revolving credit facility. Subsequent to the closing of our initial public offering on February 9, 2001, we relied on cash generated from operations as our primary source of funding, except for payout capital expenditures. Additional funding requirements are met by a $175.0 million credit facility of one of our operating partnerships 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 sub-facility and a $12.0 million working capital sub-facility. Indebtedness under this credit facility bears interest at the Eurodollar rate plus an applicable margin that ranges from 1.0% to 1.5%. We also incur a commitment fee on the unused portions of the credit facility. As of December 31, 2002, the $90.0 million term loan is outstanding with the entire $85.0 million revolving credit facility available for future borrowings.

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

The credit facility contains various operational and financial 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.

Under terms of this facility, a change of control whereby Williams and its affiliates no longer own 100% of the General Partner’s equity would result in an event of default, in which case the maturity date of the outstanding amounts under this facility may be accelerated by the lenders in the facility.

The following table summarizes the principal payment schedule for each of our borrowings as of December 31, 2002:

Debt-to-Total Capitalization — The ratio of debt-to-total capitalization is a measure frequently used by the financial community to assess the reasonableness of a company’s debt levels compared to total capitalization, calculated by adding total debt and total partners’ capital. Based on the figures shown in our balance sheet, debt-to-total capitalization is 56% at December 31, 2002. Because accounting rules required the acquisition of the Williams Pipe Line system to be recorded at historical book value due to the affiliate nature of the transaction, the $474.5 million difference between the purchase price and book value at the time of the acquisition was recorded as a decrease to the General Partner’s capital account, thus lowering our overall partners’ capital. If Williams Pipe Line had been purchased from a third party, the asset would have been recorded at market value, resulting in a debt-to-total capitalization of 38%, which is consistent with management’s indicated target level of 40%.

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 system owned at the time of that offering, an affiliate of Williams agreed to indemnify us against environmental liabilities up to $15.0 million resulting from events that arose prior to February 9, 2001, become known within three years after February 9, 2001 and exceed all amounts recovered or recoverable by us under contractual indemnities from third parties or under any applicable insurance policies.

As of December 31, 2002, we had collected $1.7 million against Williams Energy Services’ indemnity and had recorded $3.3 million of environmental liabilities associated with our petroleum products terminals and ammonia systems, substantially all of which were covered by Williams Energy Services’ indemnification. Of these environmental liabilities, $3.2 million is expected to be recovered from Williams Energy Services. Further, we expect to incur $0.3 million of environmental capital, which could also be covered by this indemnification. Management estimates that these expenditures for environmental remediation liabilities will be paid over the next five years. Please read “Management Discussion and Analysis of Financial Condition and Results of Operations — Other Known Trends and Events — Change of Control” for additional discussion of possible changes associated with Williams Energy Services’ indemnification to us.

In connection with our acquisition of the Williams Pipe Line system 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 cover claims made by us for breaches of other Williams Energy Services’ representations and warranties. The environmental indemnification obligation applies to liabilities that resulted from conduct prior to the closing of our acquisition of the Williams Pipe Line

As of December 31, 2002, we had accrued environmental remediation liabilities associated with the Williams Pipe Line system of $19.0 million. Management estimates that these expenditures will be paid over the next five years. Of these environmental liabilities, $18.7 million are expected to be recoverable from affiliates. In addition, we are forecasting capital expenditures associated with environmental projects of $3.9 million, which are expected to be indemnified but are not included in our affiliate accounts receivable.

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

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

We had recognized $22.3 million of goodwill on October 1, 2002 and $22.3 million of goodwill on December 31, 2002. All of the goodwill and other intangibles recognized by us are associated with the petroleum products terminals segment and were acquired as part of the Gibson, Louisiana and Little Rock, Arkansas terminals acquisitions (see Note 5 — Acquisitions and Divestitures). We performed our annual testing of goodwill, as required by SFAS No. 142 as of October 1, 2002.

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

For the 2002 test, fair value of the petroleum products terminals was assessed using three approaches: (1) a market value approach, (2) a discounted future cash flows approach and (3) an EBITDA multiple approach. Under the market value approach, we calculated the total enterprise value on October 1, 2002 and allocated that total value between our three operating segments based on the relative discounted future cash flows of all three operating segments. The carrying value of the segment was allocated based on our total partners’ capital. Under the discounted future cash flows method, the cash flows of the petroleum products terminals segment were estimated using our internal forecasts to project revenues and costs in the short term and assumed incremental revenues and costs for periods beyond based on historical trends. The discounted future cash flows model assumed a 9% discount rate based on an expected 10% return on equity and a 7.5% cost of debt and a 60/40 debt to equity ratio. Under the EBITDA multiple approach, we applied a multiple of 9 times the adjusted EBITDA of the petroleum products terminals segment to determine fair value. We define EBITDA as income before income taxes plus interest expense (net of interest income) and depreciation and amortization expense. EBITDA multiples are used industry-wide in assessing values for business assets similar

Under each of the three methodologies the fair value of the petroleum products terminals segment exceeded the carrying value of the segment and therefore we did not recognize an impairment in 2002. In reaching the conclusion above, more confidence was placed on the EBITDA multiple approach because management determined this approach more closely represented the amount at which the petroleum products terminals segment could be sold in a transaction between willing parties.

The critical factor in the EBITDA multiple approach is the multiple itself. When valuing potential acquisitions or assets to be disposed of, we generally use multiples between 7 times EBITDA to 11 times EBITDA, depending on factors such as the size of the transaction, the prospects for revenue growth or cost reductions, the overall condition of the assets, the age of facility, the location of the facility, the reputation of the seller and the intended use of the facility. For our goodwill impairment testing on October 1, 2002, we used a multiple of 9 times EBITDA to determine the fair value of the petroleum products segment. If that multiple were reduced to 8.5 times EBITDA, the EBITDA multiple approach would have suggested that we would need to recognize an impairment of approximately $4.0 million. If the multiple were further decreased to 8.0 times EBITDA, the EBITDA multiple approach would have suggested that the full carrying value of goodwill was impaired and we would have been required to recognize an impairment loss of $22.3 million.

The impact of an impairment under the latter scenario would have increased our leverage ratio beyond the maximum allowed in our OLP term loan and revolving credit facility. Under this scenario, the lenders in the OLP facility could choose to accelerate the repayment of the loan, which would materially negatively impact our liquidity and cash flows. In today’s markets it is difficult to assess how lenders would react to such a scenario; however, we currently do not believe that, under this latter scenario, the OLP lenders would choose this course of action.

Based on our test of goodwill as of October 1, 2002, management concluded that there was no impairment of goodwill required. Our management has discussed the development and selection of this critical accounting estimate with the Audit Committee of our General Partner’s Board of Directors and the Audit Committee has reviewed our disclosure relating to it in this Management Discussion and Analysis section of our Annual Report on Form 10-K.

We evaluate our property, plant and equipment (“PP&E”) for impairment whenever indicators of impairment exist. Accounting standards require that if the sum of the future cash flows expected to result from a company’s assets, undiscounted and without interest charges, is less than the reported value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment to recognize is calculated by subtracting the fair value from the reported value of the asset.

We operate in three segments: Williams Pipe Line system, petroleum products terminals and the ammonia pipeline system. We reviewed our ammonia pipeline system for possible impairment as of December 31, 2002, because there are only three customers transporting product on that system and Farmland, the largest of the three, filed for protection under the United States Bankruptcy Codes in May 2002. (Please read Farmland discussion under “Management Discussion and Analysis of Financial Condition and Results of Operations — Other Known Trends and Events)”.

We believe that the accounting estimate related to an impairment of our ammonia pipeline is a “critical accounting estimate” because: (1) it is susceptible to change from period to period because it requires management to make assumptions about future sales and cost of sales, in markets which have been highly volatile in certain periods during the last few years, over the remaining depreciable life of the ammonia pipeline system, which includes assets that are depreciated over a period of 30 years; (2) it is susceptible to change because of the assumptions management made relative to the future volume of shipments on our system; and (3) of the impact that recognizing an impairment on the ammonia assets would have on net

Management’s assumptions about future ammonia shipments and future operating costs require significant judgment because: (1) Farmland’s bankruptcy raises concerns over their ability to continue to ship product on our line and it is difficult to assess the impact that a sale of Farmland’s facilities to a third party might have on our shipments or the impact that Farmland’s bankruptcy might have on the two other competing companies on our ammonia pipeline system; (2) the primary feedstock for producing ammonia is natural gas. As the price of natural gas increases, production costs for anhydrous ammonia also increase. The impact on our customers is that they generally experience a reduction in the demand for their product and consequently ship fewer tons of ammonia on our pipeline system. Natural gas prices have fluctuated widely over the past several years and have increased to unprecedented high levels during the first quarter of 2003; and (3) possible increases in the operating costs of the pipeline due to the loss of synergies due to Williams’ sale of the Mid-America Pipeline Company, a former affiliate whose pipeline ran parallel to our ammonia pipeline system in some areas.

Our estimates of future cash flows evaluated four separate scenarios involving the potential impact of Farmland’s bankruptcy on our operations, along with an estimate of the probability of each scenario occurring. The estimates cover a range from 25% of Farmland’s future shipment volumes being lost to all of Farmland’s future shipment volumes being lost. We used our internal forecasts to project revenues and costs in the short term and assumed incremental revenues and costs for periods beyond based on historical trends. Probabilities were assigned to each scenario based on management’s best estimates applying existing market conditions, historical trends and knowledge of our customers, the anhydrous fertilizer markets and competitors. The highest probability of occurrence was assigned to the scenario of losing 25% of Farmland’s volumes and the lowest probability of occurrence was assigned to the scenario of losing all of Farmland’s volumes. Based on our model, the sum of the expected future cash flows, undiscounted and without interest charges, exceeded the reported value and therefore we did not recognize an impairment in 2002.

As of December 31, 2002, our investment in the ammonia pipeline system’s PP&E was $21.1 million. Any increase in the estimated future cash flows would have no impact on our recorded value of the ammonia pipeline system. However, if we were to assign a 30% probability to the scenario that all of Farmland’s volumes are lost, 35% probability that 75% of Farmland’s volumes are lost and a 35% probability that 50% of Farmland’s volumes would be lost, we would have been required to recognize an impairment loss of approximately $13.9 million. Average tons shipped under this scenario would be 440 thousand tons per year over most of the 30-year period evaluated, which management views as unlikely. If we further changed our assumptions such that the increase in ammonia revenues beyond our short-term plan assumptions were reduced from 5% growth to 4% growth per year, that impairment loss would increase to $21.1 million. The impact of such an impairment would have increased our leverage ratio beyond the maximum allowed in our term loan and revolving credit facility which would materially negatively impact our liquidity and cash flows. In this scenario, the lenders in the OLP facility could choose to accelerate the repayment of the loan. In today’s markets it is difficult to assess how lenders would react to such a scenario; however, management currently does not believe that, under this scenario, the lenders in the OLP facility would take this course of action.

Based on our assessment of the ammonia pipeline system at December 31, 2002, management concluded that an impairment of the system was not required. Our management has discussed the development and selection of this critical accounting estimate with the Audit Committee of our General Partner’s Board of Directors and the Audit Committee has reviewed this disclosure.

We estimate the liabilities associated with environmental expenditures based on site-specific project plans for remediation, taking into account prior remediation experience. Experienced remediation project managers evaluate each known case of environmental liability to determine what phases and associated costs can be reasonably estimated and to ensure compliance with all applicable federal and/or state requirements. We

believe the accounting estimate relative to environmental remediation costs to be a “critical accounting estimate” because: (1) estimated expenditures, which will generally be made over the next 1 to 10 years, are subject to price fluctuations and could change materially, (2) unanticipated third party liabilities may arise, and/or (3) changes in federal, state and local environmental regulations could also significantly increase the amount of the liability. The estimate for environmental liabilities is a critical accounting estimate for all three of our operating segments.

A defined process for project reviews is integrated into our System Integrity Plan. Specifically, our remediation project managers meet once a year with accounting, operations, legal and other personnel to evaluate, in detail, the known environmental liabilities associated with each of our operating units. The purpose of the annual project review is to assess all aspects of each project, evaluating what will be required to achieve regulatory compliance, estimating the costs associated with executing the regulatory phases that can be reasonably estimated and estimating the timing for those expenditures. During the site-specific evaluations, all known information is utilized in conjunction with professional judgment and experience to determine the appropriate path forward and assess liabilities. The general remediation process to achieve regulatory compliance is: site investigation/delineation, site remediation, and long-term monitoring. Each of these phases can, and often do, include unknown variables which complicate the task of evaluating the estimated costs to complete. During 2002, the recommendations that came from the annual review process resulted in our increasing our environmental liabilities by $10.7 million, which was largely attributable to our quantifying the liability (remediation and long-term monitoring) at six state-mandated sites. Based on known liabilities, this large accrual adjustment is not anticipated to be a recurring event.

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

Assuming a 20% increase in our estimated environmental liabilities and further assuming that 80% of those additional liabilities would be indemnified by Williams, our expenses would increase by $1.0 million and operating profit and net income would decrease by $1.0 million, which represented 1% of both our operating profit and net income for 2002. Such a change would result in less than a 1% increase in our total liabilities and decrease our equity by less than 1%. The impact of such an increase in environmental costs would likely not have affected our liquidity and capital resources because, even with the increased costs, we would still be within the covenants of our long-term debt agreements as discussed above under “Liquidity and Capital Resources — Liquidity” and in Note 12 to the Consolidated Financial Statements. The impact on our results is critically dependent on our reliance on Williams’ performance related to these indemnities — See discussion of Affiliate Receivables below.

Our management has discussed the development and selection of this critical accounting estimate with the Audit Committee of our General Partner’s Board of Directors and the Audit Committee has reviewed this disclosure.

We have agreements with Williams related to the assets acquired at the time of our initial public offering in February 2001 and to the Williams Pipe Line system acquired in April 2002. These agreements indemnify us against environmental losses up to $15.0 million relating to the assets our affiliates contributed to us at the time of our initial public offering. In connection with the acquisition of the Williams Pipe Line system, Williams agreed to indemnify us for environmental losses up to $110.0 million, after a $2.0 million deductible. Beyond the $110.0 million indemnity, Williams is responsible for one-half of all environmental losses up to $140.0 million, for a total indemnity of $125.0 million. When a site-specific environmental liability is recognized, a determination is made as to whether or not the liability is indemnified by Williams. If so, an affiliate receivable for the amount of the indemnified liability is also recognized. We do not require payment from Williams until actual remediation work is performed on the site. At that time, Williams is billed for the remediation work and the cash received is used to reduce the affiliate environmental receivable. As of

We believe that the accounting estimate related to affiliate receivables is a “critical accounting estimate” because: (1) its carrying amount is subject to all of the same estimates as those used to develop the underlying environmental liabilities (See Critical Accounting Estimates — Environmental Liabilities above); and (2) given Williams’ current financial status it requires our management’s estimations involving our ability to collect the receivable amount from Williams.

In preparing our financial statements for the year ended December 31, 2002, management’s assumptions were that we would be able to collect the full amount of these receivables from Williams. Should Williams be unable to perform on its existing debt obligations, we may be unable to collect part, or all, of our affiliate accounts receivable.

If we change our estimate of the amount of the affiliate receivable we believe we can ultimately collect from Williams, we would be required to take a charge against income because we have not recorded any allowance for doubtful accounts associated with this receivable. Assuming that none of the receivable is collectable would require a charge against income of $27.3 million, which represents 28% of our net income for the year. The impact of such an impairment would have increased our leverage ratio beyond the maximum allowed in our credit facility which would materially negatively impact our liquidity and cash flows. In this scenario, the lenders in the OLP facility could choose to accelerate the repayment of the loan. In today’s markets it is difficult to assess how lenders would react to such a scenario; however, management currently does not believe that, even under this scenario, the lenders in the OLP facility would take that course of action.

In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123”. This Statement amends FASB Statement No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. This Statement improves the prominence and clarity of the pro forma disclosures required by Statement 123 by prescribing a specific tabular format and by requiring disclosure in the “Summary of Significant Accounting Policies” or its equivalent. The standard is effective for fiscal periods ending after December 15, 2002. We account for stock-based compensation under provisions of Accounting Principles Board Opinion No. 25, hence, adoption of this standard will have no impact on our operations or financial position. We have adopted the additional disclosure requirements of this standard in 2002.

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

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

In August 2001, the FASB issued 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 APB No. 30. 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 was to be applied prospectively and was effective for financial statements issued for fiscal years beginning after December 15, 2001. There was no initial impact on our results of operations or financial position upon adoption of this standard.

In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. The Statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as a part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003. Application of the new rules did not have a material impact on our results of operations or financial position as retirement obligations were not recorded for assets for which the remaining life is not currently determinable, including pipeline transmission and terminals assets.

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 became effective for all fiscal years beginning after December 15, 2001. We applied 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 resulted in a decrease to amortization expense in 2002 of approximately $0.8 million.

We have entered into a number of commercial agreements with affiliates, including Williams Energy Marketing & Trading, Williams Midstream Marketing & Risk Management, Williams Refining & Marketing, Williams Ethanol Services, Inc. and Mid-America Pipeline Company. Each of these entities was a subsidiary of Williams and an affiliate of ours and of our General Partner during the periods presented. 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 owned and operated a refinery in Memphis, Tennessee and engaged in the purchase and sale of crude and refined petroleum products (Please read “Petroleum Products Terminals — Inland Terminals” for a discussion of the sale of the Williams Refining & Marketing’s refinery in Memphis, Tennessee). Williams Midstream Marketing & Risk Management manages sales, marketing and risk management for Williams’ midstream business. 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. Williams sold Mid-America Pipeline in August 2002. During 2003 Williams Refining & Marketing sold its refinery in Memphis, Tennessee and its travel center operations. Also, Williams has announced that it has an agreement to sell Williams Ethanol Services, which it expects to complete in 2003.

The agreements with our affiliates vary depending upon location and the types of services provided. Approximately $16.6 million and $15.9 million of our revenues in 2002 and 2001, respectively, were generated from agreements with affiliates at our petroleum products terminals while approximately $42.0 million and $78.4 million of revenue in 2002 and 2001, respectively, was generated from agreements with affiliates on the Williams Pipe Line system. In addition, approximately $22.3 million and $81.0 million of expenses were incurred in 2002 and 2001, respectively, from product purchases with our affiliates on the Williams Pipe Line system. A summary of the significant agreements follows:

Tariff-based shipments. Williams Energy Marketing & Trading, Williams Refining & Marketing and Williams Midstream Marketing & Risk Management 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 for volume transported on our system as long as we abide by the terms of the tariff. As a result, contracts generally do not exist that obligate our affiliates to ship volume or make payments to us in the future. The principal exceptions to this are: (i) our throughput and deficiency agreement with Williams Energy Marketing and Trading for product movements through a third-party capacity lease and (ii) for propane movements from El Dorado, Kansas to Carthage, Missouri. The throughput and deficiency agreement for the propane movements from El Dorado, Kansas to Carthage, Missouri expires on March 31, 2003. The total revenues associated with tariff-based shipments were approximately $6.6 million and $5.0 million in 2002 and 2001, respectively.

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. We also have an agreement with Williams Energy Marketing & Trading, which expires on March 31, 2003, for the lease of our Carthage, Missouri cavern. 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. These contracts have one-year terms and, as they expire, are usually renewed for a one-year term. These agreements generated approximately $2.6 million and $2.2 million of revenue in 2002 and 2001, respectively.

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 $4.5 million and $3.2 million of revenue in 2002 and 2001, respectively.

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, entered into in 1998, was renewed yearly until 2002. The rate charged for this lease has not changed from year to year. This agreement generated approximately $0.3 million of revenue in 2001 and approximately $0.2 million of revenue in 2002 during that portion of the year that Mid-America Pipeline was

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 $0.5 million and $0.3 million of revenue in 2002 and 2001, respectively.

Over and short settlement and product purchases and sales agreements. During part of 2002, we had agreements with Williams Energy Marketing & Trading and Williams Midstream Marketing & Risk Management to buy natural gas liquids blendstocks and sell the refined petroleum products related to our blending program. We also had agreements with Williams Energy Marketing & Trading 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 were 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 was recorded on a confirmation statement, which was subject to the general terms outlined in the master agreements. These confirmation statements determined the volume, price and timing associated with the product purchases and sales. The revenue associated with these agreements was approximately $25.1 million and $66.4 million in 2002 and 2001, respectively, while the expenses incurred to purchase products from our affiliates were approximately $22.3 million and $81.0 million in 2002 and 2001, respectively. 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 was produced from blending. In connection with the acquisition of the Williams Pipe Line system in April 2002, we and Williams Energy Services agreed that the Williams Pipe Line system would no longer take title to the natural gas liquids it blends or the resulting product. We now perform these blending services for Williams Energy Services under a separate agreement (see below).

	•	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 to manage the imbalances.

Butane blending agreement. We perform blending services on the Williams Pipe Line System for Williams Energy Services under a ten-year agreement which provides for an annual fee of approximately $4.2 million, of which $0.6 million is attributable to blending services provided at one of our inland petroleum products terminals not connected to the Williams Pipe Line system. We do not take title to any of the product used in or resulting from the blending process. This agreement, entered into at the time of our acquisition of Williams Pipe Line in April 2002, generated approximately $2.8 million in 2002, of which $2.3 million was for services performed on the Williams Pipe Line system and $0.5 million was for services performed at one of our inland petroleum products terminals.

Longhorn Partners Pipeline Construction Revenue Agreement. Prior to its acquisition by us in April of 2002, Williams Pipe Line Company had 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 revenue associated with these agreements was approximately $0.2 million and $1.0 million in 2002 and 2001, respectively. In connection with our acquisition of Williams Pipe Line Company, these agreements were transferred to a wholly-owned subsidiary of Williams and consequently we no longer provide these services and receive these fees.

Natural gas and fuel oil supply agreements. During part of 2002, we had 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 purchased fuel oil from Williams Refining & Marketing at the prevailing market price. These purchases were identified on confirmation statements that were subject to the master refined products purchase and sale agreements used in the blending and over and short program. We purchased natural gas from Williams Energy Marketing & Trading either based on indexed prices or at fixed prices. In 2002, 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. The natural gas purchase agreement for fixed price natural gas expired in August 2002. These agreements generated operating expenses of $2.6 million and $4.2 million in 2002 and 2001, respectively.

Inland terminal use and access agreements. We have entered into several agreements with Williams 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 common carrier pipelines. Additional services include product handling, storage, inventory management, and additive injection. These agreements establish a market-based 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 was approximately $4.0 million and $6.5 million in 2002 and 2001, respectively. The sale of Williams Refining & Marketing’s refinery in Memphis, Tennessee and their travel center operations during the first quarter of 2003, will result in significantly lower revenues from Williams Refining & Marketing during 2003.

Products terminals and storage agreement for the Galena Park, Texas marine terminal facility. We entered into an agreement with Williams Energy Marketing & Trading to provide approximately 2.8 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 fluctuate to the extent other ancillary services are utilized and/or a tank is out of service as part of our System Integrity Program. 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. The prices charged under this agreement are consistent with those charged to non-affiliated entities. The agreement, which generated approximately $7.6 million and $7.4 million of revenue in 2002 and 2001, respectively, expires on September 30, 2004. We have negotiated the termination of this agreement with Williams Energy Marketing & Trading, effective in March 2003. We expect to receive cash of approximately $3.0 million from Williams Energy Marketing & Trading to terminate this agreement.

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 generated approximately $4.1 million of revenue in 2002 and approximately $0.6 million of revenue for the two months we owned the facility in 2001.

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 Williams.

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.

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.

Any sustained decrease in demand for refined petroleum products in the markets served by our pipeline and terminals could result in a significant reduction in the volume of products that we transport in our pipeline, store at our marine terminal facilities and distribute through our inland terminals, and thereby reduce our cash flow and our ability to pay cash distributions. 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.

This market condition is commonly referred to as “backwardation.” When the petroleum product market is in backwardation, the demand for storage capacity at our facilities may decrease. If the market becomes strongly backwardated for an extended period of time, it may affect our ability to meet our financial obligations and pay cash distributions.

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 meet our financial obligations and pay cash distributions.

For the year ended December 31, 2002 and 2001, our affiliates Williams Energy Marketing & Trading and Williams Refining & Marketing collectively accounted for approximately 11% and 18%, respectively, of our revenues. Williams has begun the process of reducing its marketing and trading activities. As a result, we have experienced a reduction of revenues related to their activities. We are currently in the process of replacing this affiliate revenue with third party revenue. If we are unable to do so, it could impact our ability to meet our financial obligations and pay cash distributions.

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 operations are subject to 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 for 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.

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

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. Please read “Narrative Description of Business — Tariff Regulation” for further discussion of tariff rates and how they have been impacted by the PPI. If the PPI rises by less than 1% or falls, we could be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the PPI might not be large enough to fully reflect actual increases in the costs associated with the 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 between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and 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 magnitude, which would reduce our ability to meet our financial obligations and pay cash distributions.

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.

Each of our operating segments 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

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.

In addition, 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.

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.” In addition, 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 another ammonia pipeline in Iowa and Nebraska.

The after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Some or all of the distributions made to unitholders would be treated as dividend incomes, and no income, gains, losses or deductions would flow through to unitholders. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow, which would reduce our ability to meet our financial obligations and pay cash distributions. Moreover, treatment of us as a corporation would materially and adversely affect our ability to make payments on our debt securities.

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

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. Farmland Industries, Inc., the largest of our three customers, filed for bankruptcy protection in May 2002, has exercised its right to terminate its contract with us effective December 23, 2003 (Please read “Business — Ammonia Pipeline System — Farmland” and Note 16 to the Consolidated Financial Statements for further discussions of Farmland). Another of these customers has a credit rating below investment grade. The loss of any one of these three customers or their failure or inability to pay us could adversely affect our ability to meet our financial obligations and pay cash distributions.

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. Natural gas prices increased late in the fourth quarter of 2002 and have reached unprecedented levels in the first quarter of 2003. 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 meet our financial obligations and pay cash distributions.

On February 20, 2003, Williams announced its intention to divest its interest in our General Partner and its common, Class B and subordinated units. A sale of the General Partner could result in the holders of our debt obligations accelerating the payments due to them under those agreements. Also, a change of control in the General Partner may result in the termination of the general and administrative expense limitation under the Omnibus Agreement, which could result in higher general and administrative costs to us. The termination of the Omnibus Agreement could also terminate the agreements we have with Williams to reimburse us for maintenance capital costs associated with Williams Pipe Line maintenance capital over the next two years, which could increase our maintenance capital costs which, in turn, could limit our ability to pay cash distributions. Also, the environmental indemnities associated with the assets acquired at the time of our initial public offering could be terminated.

Williams provides a number of services to us that are billed to the Partnership as general and administrative expense. These costs include: accounting, building administration, human resources, information technology, legal and security, among others. In addition, Williams provides us several key software applications critical to our business including our general ledger, SCADA and accounts payable systems, as well as our desktop and networking systems. Separating ourselves from Williams will entail acquiring similar services and systems, which could increase our costs and limit our ability to pay cash distributions.

Due to our relationship with Williams, adverse developments or announcements concerning Williams, including bankruptcy proceedings, could adversely affect our financial condition, even if we have not suffered any similar development. In addition, further downgrades by one or more credit rating agencies of the outstanding indebtedness of Williams could increase our borrowing costs or generally impede our access to capital markets. We also have significant right-of-way and environmental indemnities from Williams. Further adverse developments could result in Williams being unable to perform on its existing obligations, including their right-of-way and environmental indemnities with us, which could adversely affect our ability to finance acquisitions, refinance existing indebtedness and pay cash distributions.

We currently do not engage in interest rate, foreign currency exchange rate or commodity price-hedging transactions.

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is interest rate risk. Debt we incur under our credit facility and our Floating Rate Series A Senior Secured notes bear variable interest based on the Eurodollar rate. If the LIBOR changed by 0.125%, our annual interest obligations associated with the $90.0 million of outstanding borrowings under the term loan and revolving credit facility at December 31, 2002, and the $178.0 million of outstanding borrowings under the Floating Rate Series A Senior Secured Notes would change by approximately $0.3 million. Unless interest rates change significantly in the future, our exposure to interest rate market risk is minimal.

We have audited the accompanying consolidated balance sheets of Williams Energy Partners L.P. as of December 31, 2002 and 2001, and the related consolidated statements of income, cash flows and partners’ capital for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Partnership’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 misstatement. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Energy Partners L.P. at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States.

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, Williams Ammonia Pipeline Inc., 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 (“Williams Energy Services”). Both Williams Energy Services and WNGL are wholly owned subsidiaries of The Williams Companies, Inc. (“Williams”). Williams GP LLC, a Delaware limited liability company and wholly-owned subsidiary of Williams, 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 million 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 Williams Energy Services 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, was owned by affiliates of the Partnership. Generally, the limited partners’ liability in the Partnership is limited to their investment.

On April 11, 2002, the Partnership acquired all of the membership interests of Williams Pipe Line Company (“Williams Pipe Line”) for approximately $1.0 billion (see Note 5 — Acquisitions and Divestitures). 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 interests. 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 throughout the periods presented. Williams Pipe Line’s operations are presented as a separate operating segment of the Partnership (see Note 15 — Segment Disclosures).

The historical results for Williams Pipe Line included 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 included Williams Pipe Line’s interest in and agreement related to Longhorn Partners Pipeline (“Longhorn”), an inactive refinery site at Augusta, Kansas, a pipeline construction project, the ATLAS 2000 software system and the pension assets and obligations associated with the non-contributory defined-benefit pension plan which covered union employees assigned to Williams Pipe Line’s operations. The liabilities principally included the environmental liabilities associated with the inactive refinery site in Augusta, Kansas and 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 the form of a capital contribution by an affiliate of Williams. The income and expenses associated with Longhorn have not been included in the financial results of the Partnership since the acquisition of Williams Pipe Line by the Partnership in April 2002. Also, as agreed between the Partnership and Williams, revenues from Williams Pipe Line’s blending operations, other than an annual blending fee of approximately $3.0 million, have not been included in the financial results of the Partnership since April 2002. In addition, general and

administrative expenses related to the Williams Pipe Line system that the Partnership has been reimbursing to its General Partner, have been limited to $30.0 million on an annual basis.

On April 11, 2002, the Partnership issued 7,830,924 Class B units representing limited partner interests to Williams GP LLC. The securities, valued at $304.4 million and along with $6.2 million of additional general partner equity interests were issued as partial payment for the acquisition of Williams Pipe Line (See Note 5 — Acquisitions and Divestitures). According to the provisions in the Williams Pipe Line private placement debt agreement dated November 15, 2002, the Partnership can redeem the Class B units only with proceeds from an equity offering. When the Class B units are redeemed, the price will be based on the 20-day average closing price of the common units prior to the redemption date. If the Class B units are not redeemed by April 11, 2003, then upon the request of the holder of the Class B units and approval of the holders of a majority of the common units voting at a meeting of the 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 this request, the holder of the Class B units 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.

In May 2002, the Partnership issued 8,000,000 common units representing limited partner interests in the Partnership at a price of $37.15 per unit for total proceeds of $297.2 million. Associated with this offering, Williams contributed $6.1 million to the Partnership to maintain its 2% general partner interest. A portion of the total proceeds was used to pay underwriting discounts and commissions of $12.6 million. Legal, professional fees and costs associated with this offering were approximately $5.3 million. The remaining cash proceeds of $289.0 million were used to partially repay the $700.0 million short-term note assumed by the Partnership to help finance the Williams Pipe Line acquisition (see Note 12 — Long-Term Debt).

During November 2002, amendments were made to the Partnership’s agreement of limited partnership and a limited liability company agreement for WEG GP LLC (see discussion of WEG GP LLC below) was adopted. The first change requires the Partnership and the general partner to maintain separateness from Williams including formalities on interaction between the Partnership, the public and Williams. Changes were also made to require the approval of the Conflicts Committee (consisting of three independent directors) before the general partner can make bankruptcy-related decisions for the Partnership. In addition, adjustments were made to the voting rights of units held by Williams. Williams’ Class B units no longer have voting rights except with respect to matters that would have a material impact on the holders of such units, its subordinated units generally have one-half vote for every one unit owned and all common units will be allowed to vote in any subordinated class vote. Finally, election of the board members of the general partner has been moved to a vote of the common unitholders, with the first vote to be held in 2003. The voting right changes and board member changes will be voided and reversed in the event of a foreclosure in a Williams-related bankruptcy proceeding. In addition, the Partnership eliminated from its agreements the requirement that the Board of Directors of the Partnership’s General Partner approve any proposed disposition of any membership interest of the General Partner.

During November 2002, Williams created a new general partner, WEG GP LLC (“General Partner”). The new General Partner, which is owned by affiliates of Williams, has all of the rights, privileges and responsibilities relative to the Partnership previously held by the old general partner, Williams GP LLC. Williams GP LLC will continue to own the Class B units issued by the Partnership in April 2002.

necessarily become a party to such bankruptcy filings. However, we cannot assure you that Williams and its affiliates, or the creditors of Williams and its affiliates, would not attempt to utilize various remedies available in a bankruptcy (including substantive consolidation), in an effort to make the assets of the Partnership available to the creditors of Williams and its affiliates, or how a bankruptcy court would resolve such issues. Likewise, there can be no assurances as to the ultimate impact a bankruptcy by Williams and its affiliates would have on Williams’ and its affiliates’ ability to perform obligations owed to the Partnership and its affiliates, including our General Partner.

WEG GP LLC is a wholly-owned subsidiary of Williams. Williams owns approximately 55% of the Partnership, including its 2% general partner interest. However, the Partnership operates its business in a manner separate and distinct from Williams. Among other things: (i) the Partnership either owns or leases the assets used in its business in its own name, (ii) the Partnership has three independent board members who serve on a conflicts committee that must approve any material transaction between the Partnership and Williams or its affiliates, as well as approve certain significant transactions (such as the filing of a bankruptcy petition) and (iii) other than affiliate receivables and payables generated from product sales and services rendered in the normal course of business, the Partnership does not provide any credit support to Williams or its affiliates and Williams does not provide credit support to us.

Provisions of the General Partner’s limited liability company agreement specifically provide that decisions regarding a voluntary bankruptcy filing of WEG GP LLC or the Partnership must be approved by the Conflicts Committee, which is comprised of the independent board members of WEG GP LLC.

If WEG GP LLC were to file for bankruptcy relief under Chapter 7 of the United States Bankruptcy Code, the filing would be an “Event of Withdrawal” under the Partnership’s Partnership Agreement and WEG GP LLC will be deemed to have withdrawn. A Chapter 11 filing would not be considered an “Event of Withdrawal” and the Partnership would continue to operate under its existing agreements. Upon the occurrence of an Event of Withdrawal, WEG GP LLC is required to give notice to the Partnership’s limited partners within 30 days after such occurrence. An Event of Withdrawal triggers dissolution and winding up of the affairs of the Partnership unless: (i) a successor general partner is elected and admitted to the Partnership within 90 days of receiving the General Partner’s withdrawal notice, (ii) a written opinion of counsel is issued that such withdrawal would not result in the loss of the limited liability of any limited partner or of the limited partner of any of the Partnership’s operating limited partnerships or cause the Partnership or any of the Partnership’s operating limited partnerships to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes, and (iii) the new general partner executes a new partnership agreement and executes and files a new certificate of limited partnership. Election of a successor general partner requires a vote of a majority of the outstanding units to reconstitute the Partnership and approve the successor general partner. Despite the provisions of the Partnership’s Partnership Agreement discussed in this section, if WEG GP LLC were to file for bankruptcy protection, the bankruptcy court may refuse to enforce these provisions or may require different or additional procedures and consideration to allow these provisions to be followed.

The Partnership owns and operates a petroleum products pipeline system, petroleum products terminals and an ammonia pipeline 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, Minnesota 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 petroleum products, including gasoline, diesel fuels,

LPGs and aviation fuels. Product originates on the system from direct connections to refineries and interconnects with other interstate pipelines for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airlines and other end-users.

Most of the Partnership’s 28 petroleum products 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. Four marine terminal facilities are located along the Gulf Coast and one marine terminal facility is located in Connecticut near the New York harbor. The inland terminals are located primarily in the southeastern United States.

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, South Dakota and Texas. The ammonia transported through the system is used primarily as nitrogen fertilizer.

The consolidated financial statements include Williams Pipe Line, the petroleum products terminals and the ammonia pipeline system. 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.

Certain previously reported balances have been classified differently to conform with current year presentation. Net income and total assets were not affected by these reclassifications.

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.

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 equity investments and other adjustments and are not significant to the financial statements.

Cash and cash equivalents include demand and time deposits and other marketable securities with maturities of three months or less when acquired. The carrying amount of cash and cash equivalents approximates fair value of those instruments due to their short maturity.

Inventory is comprised primarily of refined products 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.

Trade receivables are recognized when products are sold or services are rendered. An allowance for doubtful accounts is established for all amounts deemed uncollectable and reserves are evaluated no less than quarterly to determine their adequacy.

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.

In January 2002, WEG GP LLC adopted Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets.” In accordance with this Statement, beginning on January 1, 2002, goodwill, which represents the excess of cost over fair value of assets of businesses acquired, is no longer amortized but must be evaluated periodically for impairment. The determination of whether goodwill is impaired is based on management’s estimate of the fair value of the Partnership’s operating segments as compared to their carrying values. If an impairment has occurred, the amount of the impairment recognized is determined by subtracting the implied fair value of the reporting unit goodwill from the carrying amount of the goodwill. Other intangible assets are amortized on a straight-line basis over a period of up to 25 years.

Judgments and assumptions are inherent in management’s estimates used to determine the fair value of its operating segments. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Previously, goodwill was amortized on a straight-line basis over a period of 20 years for those assets acquired prior to July 1, 2001. Based on the amount of goodwill recorded as of December 31, 2001, application of the non-amortization provision of SFAS No. 142 resulted in a decrease to amortization expense in 2002 of approximately $0.8 million.

In January 2002, the Partnership adopted SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” There was no initial impact on the Partnership’s results of operations or financial position upon adoption of this standard.

In accordance with this Statement, 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.

Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate on debt owed by the Partnership. Capitalized interest for the years ended December 31, 2002, 2001 and 2000 were $0.2 million, $0.8 million and $1.3 million, respectively.

Williams Pipe Line transportation revenues are recognized when shipments are complete and estimated pipeline revenues are deferred for shipments in transit. Ammonia pipeline revenues are recognized when product is delivered to the customer. 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 tank storage, pipeline capacity leases, terminalling, throughput, blending services, ethanol loading and unloading services, laboratory testing and data services, pipeline operating fees and other miscellaneous service-related revenues are recognized upon completion of contract services. Sales of products produced from fractionation activities and other miscellaneous product sales, are recognized upon sale of the product.

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 was no longer a taxable entity for federal and state income tax purposes. Accordingly, for the petroleum products terminals and ammonia pipeline system operations, after the initial public offering, no recognition has been given to income taxes for financial reporting purposes.

Prior to its acquisition by 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 as per its tax sharing arrangement with Williams. No recognition has been given to income taxes associated with Williams Pipe Line for financial reporting purposes for periods subsequent to its acquisition by the Partnership.

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’ 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 phantom units of the Partnership 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 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.

Basic earnings per unit are based on the average number of common, Class B and subordinated units outstanding. Diluted earnings per unit include any dilutive effect of phantom unit grants. Limited partners’ earnings are determined after the net income allocation to the General Partner consistent with its distribution under the incentive distribution rights declared for each period presented.

In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123”. This Statement amends FASB Statement No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial

statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. This Statement improves the prominence and clarity of the pro forma disclosures required by Statement 123 by prescribing a specific tabular format and by requiring disclosure in the “Summary of Significant Accounting Policies” or its equivalent. The standard is effective for fiscal periods ending after December 15, 2002. The Partnership accounts for stock-based compensation for Williams employees assigned to the Partnership under provisions of Accounting Principles Board Opinion No. 25, hence, adoption of this standard will have no impact on the Partnership’s operations or financial position. The Partnership adopted the additional disclosure requirements of this standard in 2002.

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

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

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. The Statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as a part of the related long-lived asset and allocated to expense over the useful life of the asset. The Partnership adopted the new rules on asset retirement obligations on January 1, 2003. Application of the new rules did not have a material impact on the Partnership’s results of operations or financial position as retirement obligations were not recorded for assets for which the remaining life is not currently determinable, including pipeline transmission and terminal assets.

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 became effective for all fiscal years beginning after December 15, 2001. The Partnership applied 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 resulted in a decrease to amortization expense in 2002 of approximately $0.8 million. Following are the historical results of Williams Energy Partners on a consolidated basis assuming goodwill amortization had not been recorded (in thousands):

For the year ended December 31, 2001, basic and diluted net income per limited partner unit would have increased by $.01 assuming goodwill amortization had not been recorded.

Changes in the components of operating assets and liabilities excluding certain assets and liabilities of Williams Pipe Line which were not acquired by the Partnership (see Note 1 — Organization and Presentation) are as follows (in thousands):

On April 11, 2002, the Partnership acquired all of the membership interests of Williams Pipe Line from Williams Energy Services 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 Williams GP LLC and affiliates of WES and Williams’ contribution to the Partnership 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 (see Note 12 — Long-Term Debt). 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 is 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 (in thousands):

Because Williams Pipe Line was an affiliate of the Partnership at the time of the acquisition, the transaction was between entities under common control. As such, generally accepted accounting principles required that Williams Pipe Line’s assets and liabilities be recorded on the Partnership’s consolidated financial statements at their historical values, despite their having been acquired at market value. As a result, the General Partner’s capital account was decreased by $474.5 million, which equaled the difference between the historical and market values of Williams Pipe Line. The effect of this treatment on the Partnership’s overall capital balance resulted in a debt-to-total capitalization ratio at December 31, 2002, of 56%.

The assets identified below were acquired for cash during the periods presented and are described below. All acquisitions, except the Aux Sable transaction (described below), 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 direct financing 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 $18.1 million in total over the remaining life of the lease 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, 2002, 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 and allocation to assets acquired and liabilities assumed was as follows (in thousands):

Factors contributing to the recognition of goodwill are the market in which the facility is located and the opportunity to enter into a long-term 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 was approximately 16 years at the time of the acquisition. Of the consideration paid for the facility, $0.2 million was held in escrow at December 31, 2002, pending final evaluation of reimbursable 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 $28.9 million, of which $20.2 million was allocated to property, plant and equipment and $8.7 million to goodwill and other intangibles.

In April 2001, the Partnership purchased a 6-mile pipeline for $0.3 million from Equilon Pipeline Company LLC, enabling connection of the Partnership’s 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.

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

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 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.

During the fourth quarter of 2002, the Partnership sold its Mobile, Alabama and Jacksonville, Florida inland terminals. Total cash proceeds of approximately $1.3 million were received, with a gain of approximately $1.1 million recognized.

During the fourth quarter of 2001, the Partnership sold its Meridian, Mississippi inland terminal. Cash proceeds of approximately $1.7 million were received, with a gain of approximately $1.1 million recognized.

The decrease in the natural gas liquids inventory is the result of the Partnership’s changing its butane blending operations to that of a service provider only (see Note 1 — Organization and Presentation for more

information about activities associated with Williams Pipe Line’s operations that are not being conducted by the Partnership.) The decrease in refined petroleum products is the result of the Partnership selling inventories due to favorable market conditions in 2002.

Carrier property is defined as pipeline assets regulated by the FERC. Other includes $18.6 million of capitalized interest at both December 31, 2002 and 2001. Depreciation expense for the years ended December 31, 2002, 2001 and 2000 was $34.9 million, $35.2 million and $31.7 million, respectively.

No customer accounted for more than 10% of total revenues during 2002. Williams Energy Marketing & Trading, an affiliate customer, and Customer A accounted for more than 10% of total revenues during 2001 and 2000. Williams Energy Marketing & Trading and Customer A are customers of the petroleum products terminals segment and the Williams Pipe Line system segment. The percentage of revenues derived by customer is provided below:

Accounts receivable from Williams Energy Marketing & Trading accounted for 7% and 9% of total accounts and affiliate receivables at December 31, 2002 and 2001, respectively.

Williams Pipe Line transports refined petroleum products for refiners and marketers in the petroleum industry. The major concentration of Williams Pipe Line’s revenues is derived from activities conducted in the central United States. The size and quality of the companies with which the Partnership conducts its businesses hold our credit losses to a minimum. Sales to our customers are generally unsecured and the financial condition and creditworthiness of customers are routinely evaluated. The Partnership has the ability with many of its terminals contracts to sell stored customer products to recover unpaid receivable balances, if necessary. The concentration of ammonia revenues is derived from customers with plants in Oklahoma and Texas and sales are generally unsecured. 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 538 employees is concentrated in the central United States. At December 31, 2002, 41% of the employees were represented by a union and covered by collective bargaining agreements that expire in February 2006. The petroleum products terminals operation’s labor force of 192 people is concentrated in the southeastern and Gulf Coast regions of the United States. Other than at 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 indicated in 2000 their unanimous desire to terminate their union affiliation. Nevertheless, the National Labor Relations Board (“NLRB”) ordered the Partnership to bargain with the union as the exclusive collective bargaining representative of the employees at the facility. The Partnership appealed this decision to the Fifth Circuit Court of Appeals. Subsequently, the NLRB indicated the possibility that it would overturn its decision and requested that the Court of Appeals return the Partnership’s and other matters to the NLRB for further review and decision. A final decision by the NLRB had not been issued. Our General Partner considers its employee relations to be good.

All employees dedicated to or otherwise supporting the Partnership are employees of Williams and many participate in Williams sponsored employee benefit plans.

The Partnership participates in a non-contributory defined-benefit pension plan with Williams and its affiliates that provides pension benefits for certain employees of Williams that are dedicated to or support the Partnership. Cash contributions to the plan are made by Williams and are not specifically identifiable to the Partnership’s participation. Affiliate expense charges from Williams to the Partnership related to the Partnership’s participation in the plan totaled $2.9 million, $1.5 million and $1.2 million in 2002, 2001 and 2000, respectively.

Employees dedicated to or supporting the Partnership also participate in a Williams defined-contribution plan. The Partnership provides for matching contribution within specified limits of the defined-contribution plan. These contributions are included in compensation expense totaling $2.3 million, $2.4 million and $2.0 million, respectively in 2002, 2001 and 2000.

The historical results for Williams Pipe Line included certain pension assets and obligations associated with a non-contributory defined-benefit pension plan for union employees that are assigned to Williams Pipe Line’s operations. These pension assets and obligations were conveyed to and assumed by an affiliate of Williams Pipe Line prior to its acquisition by the Partnership. Subsequent to our acquisition of Williams Pipe Line, the Partnership bears all compensation costs associated with the plan.

The following table presents the changes in benefit obligations and plan assets for pension benefits for the union plan for the years indicated. These assets and liabilities are not included in the Partnership’s consolidated balance sheets for any periods presented but are included in the balance sheets of our affiliate (in thousands):

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

The Partnership has entered into agreements with various Williams affiliates. The Partnership has several agreements with Williams Energy Marketing & Trading, which provide for: (i) approximately 2.5 million barrels of storage and other ancillary services at the Partnership’s marine terminal facilities, (ii) capacity utilization rights to substantially all of the capacity of the Gibson, Louisiana marine terminal facility, (iii) the lease of the Carthage, Missouri propane storage cavern and (iv) throughput and deficiency agreements for product movements through a third-party capacity lease. Williams Pipe Line has entered into agreements with Mid-America Pipeline Company (“MAPL”) and Williams Bio Energy to provide tank storage and pipeline system storage, respectively. Williams Bio Energy is an affiliate entity and MAPL was an affiliate entity until August 1, 2002, when it was sold to Enterprise Products Partners L.P. (“Enterprise”).

Historically, Williams Pipe Line also has been a party to an agreement with Williams Energy Marketing & Trading for sales of blended gasoline. (See Note 1 — Organization and Presentation for more information about income and expenses associated with Williams Pipe Line’s historical operations). Also, both Williams Energy Marketing & Trading and Williams Refining & Marketing have agreements for the access and utilization of storage on Williams Pipe Line system and for the access and utilization of the inland terminals. The Partnership also has agreements with Williams Energy Marketing & Trading, Williams Refining & Marketing and Williams Bio Energy for the non-exclusive and non-transferable sub-license to use the ATLAS 2000 software system. Payment terms for affiliate entities are generally the same as for third-party companies. Generally, at each month-end, the Partnership is in a net payable position with Williams. The Partnership deducts any amounts owed to it by Williams before remitting the monthly cash amounts owed to Williams. The following are revenues from various Williams’ subsidiaries (in thousands):

Historically, Williams Pipe Line had an agreement with Williams Energy Marketing & Trading to purchase transmix for fractionation activity and product to settle shortages. MAPL, which was an affiliate entity until August 2002, provided operating and maintenance support, in the years presented, to the ammonia

pipeline and leased 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):

The above costs are reflected in the cost and expenses in the accompanying consolidated statements of income. Management’s estimates of actual general and administrative costs required for the operation of the Partnership on a stand-alone basis significantly exceed the actual amounts charged to the Partnership due in part to significant increases in insurance premiums and additional operating and general and administrative expenses associated with the new operating agreement with Enterprise (see discussion below). Amounts owed to affiliate entities are paid on a monthly basis. Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement.

On August 1, 2002, Williams announced that it had sold 98% of Mapletree LLC, which owns MAPL to Enterprise. The Partnership and MAPL had an operating agreement whereby MAPL operated the ammonia pipeline system for the Partnership for a fee. The Partnership has entered into a new agreement with Enterprise for the continued operation of the Partnership’s ammonia pipeline system. This new agreement, effective February 1, 2003, will increase the operating expenses of the pipeline by approximately $0.5 million annually and general and administrative expenses by approximately $1.5 million annually. The incremental general and administrative expenses to be incurred under this agreement will be subject to the general and administrative expense limit under the Partnership’s Omnibus agreement.

Historically, Williams charged interest expense to its affiliates based on their inter-company debt balances (see Note 12 — Long-Term Debt). The Partnership entities also participate in employee benefit plans and long-term incentive plans sponsored by Williams (see Note 9 — Employee Benefit Plans and Note 14 — Long-Term Incentive Plan).

Williams allocates both direct and indirect general and administrative expenses to its affiliates. Direct expenses allocated by Williams are primarily salaries and benefits of employees and officers associated with the business activities of the affiliate. Indirect expenses include legal, accounting, treasury, engineering, information technology and other corporate services. Williams allocates expenses to the General Partner based on the expense limitation provided for in the Omnibus Agreement. The Partnership reimburses the General Partner and its affiliates for expenses charged to the Partnership by the General Partner on a monthly basis.

In connection with its initial public offering, and with respect solely to the petroleum products terminals 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 Williams and its affiliates. The reimbursement limitation will remain in place through 2011 and may increase by no more than the greater of 7% 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 the long-term incentive plan. Based on

the 7% escalation, the Partnership’s reimbursement for general and administrative expenses in 2002 for the petroleum products terminals and ammonia pipeline system operations was $6.7 million before long-term incentive plan charges.

In connection with the acquisition of Williams Pipe Line, 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 owned 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, but not charged to the Partnership, totaled $10.4 million for the period February 10, 2001 through December 31, 2001, and $19.7 million for the twelve months ended December 31, 2002.

Williams agreed to reimburse the Partnership for maintenance capital expenditures incurred in 2001 and 2002 in excess of $4.9 million per year related to our initial public offering assets. This reimbursement obligation was subject to a maximum combined reimbursement for both years of $15.0 million. During 2001 and 2002, the Partnership recorded reimbursements from Williams associated with these assets of $3.9 million and $11.0 million, respectively. In connection with our acquisition of Williams Pipe Line, Williams has agreed to reimburse the Partnership 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 all years of $15.0 million. The Partnership’s maintenance capital expenditure expectations related to the Williams Pipe Line system are less than $19.0 million per year and we do not anticipate reimbursement by Williams.

Williams and certain of its affiliates have indemnified the Partnership against certain environmental costs. Receivables from Williams or its affiliates of $22.9 million and $5.1 million at December 31, 2002 and December 31, 2001, respectively, associated with these environmental costs have been recognized as affiliate accounts receivable in the Consolidated Balance Sheet (see Note 16 — Commitments and Contingencies).

The Partnership does not currently pay income taxes due to its legal structure. However, earnings generated prior to the Partnership’s initial public offering in 2001, and earnings of Williams Pipe Line prior to the Partnership’s acquisition of it in April 2002, were subject to income taxes. The provision for income taxes is as follows (in thousands):

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):

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

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 carry-forward expires in 2020. As a result of the initial public offering and the concurrent transactions on February 9, 2001, the net deferred tax liability on that date was assumed by Williams in exchange for an additional equity investment in the Partnership. The deferred tax assets and liabilities of Williams Pipe Line at the time of its acquisition by the Partnership on April 11, 2002, were contributed to the Partnership in the form of a capital contribution by an affiliate of Williams (see Note 1 — Organization and Presentation for further discussion of this matter).

Long-term debt and long-term affiliate notes payable for the Partnership at December 31, 2002 and 2001 were as follows (in thousands):

Williams OLP L.P. term loan and revolving credit facility — At December 31, 2002, Williams OLP L.P. (“OLP”), an operating subsidiary of the Partnership which operates our petroleum products terminals and ammonia pipeline system segments, had a $175.0 million bank credit facility, led by Bank of America. Long-term debt and available borrowing capacity under this facility at December 31, 2002, were $90.0 million and $85.0 million, respectively. The credit facility is 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, which remained outstanding at December 31, 2002. All amounts previously borrowed under the acquisition and working capital facility were repaid in full during the fourth quarter of 2002. 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 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. Weighted average interest rates were 3.3% for the twelve months ended December 31, 2002 and 5.0% for the period February 10, 2001 through December 31, 2001. The interest rates for amounts borrowed against this facility on December 31, 2002 and 2001 were 2.8% and 3.2%, respectively. At both December 31, 2002 and 2001, the fair value of this debt approximates its carrying value because of the floating interest rate applied to the debt facility.

Williams Pipe Line Senior Secured Notes — In April 2002, the Partnership borrowed $700.0 million from a group of financial institutions. This short-term loan was used to help finance the Partnership’s acquisition of Williams Pipe Line. During the second quarter of 2002 the Partnership repaid $289.0 million of the short-term loan with net proceeds from an equity offering. The weighted average interest rate on this note was 5.1% for the period April 11, 2002 through November 15, 2002. Debt placement fees associated with the note were $7.1 million and were amortized over the life of the note. In October 2002, the Partnership negotiated an extension to the maturity of this note from October 8, 2002, to November 27, 2002. The Partnership paid additional fees of approximately $2.1 million associated with this maturity date extension.

During September 2002, in anticipation of a new debt placement to replace the short-term debt assumed to acquire Williams Pipe Line, the Partnership entered into an interest rate hedge. The effect of this interest rate hedge was to set the coupon rate on a portion of the fixed-rate debt at 7.75% prior to actual execution of the debt agreement. The loss on the hedge, approximately $1.0 million, was recorded in accumulated other

comprehensive loss and is being amortized over the five-year life of the fixed-rate debt secured during October 2002.

During October 2002, Williams Pipe Line entered into a private placement debt agreement with a group of financial institutions for up to $200.0 million aggregate principal amount of Floating Rate Series A-1 and Series A-2 Senior Secured Notes and up to $340.0 million aggregate principal amount of Fixed Rate Series B-1 and Series B-2 Senior Secured Notes. Both notes are secured with the Partnership’s membership interest in and assets of Williams Pipe Line Company. The maturity date of both notes is October 7, 2007; however, the Partnership will be required on each of October 7, 2005 and October 7, 2006, to repay 5% of the then outstanding principal amount of the Senior Secured Notes.

Two borrowings have occurred in relation to these notes. The first borrowing was completed in November 2002 and was for $420.0 million, of which $156.0 million was borrowed under the Series A-1 notes and $264.0 million under the Series B-1 notes. The proceeds from this initial borrowing were used to repay Williams Pipe Line’s $411.0 million short-term loan and pay related debt placement fees. The second borrowing was completed in December 2002 for $60.0 million, of which $22.0 million was borrowed under the Series A-2 notes and $38.0 million under the Series B-2 notes. $58.0 million of the proceeds from this second borrowing were used to repay the acquisition sub-facility of the OLP and $2.0 million were used for general corporate purposes. The Series A-1 and Series A-2 notes bear interest at a rate equal to the six month Eurodollar Rate plus 4.25%. The rate on the Series A-1 and Series A-2 notes is currently 5.7% and will be reset on April 7, 2003. The Series B-1 notes bear interest at a fixed rate of 7.7%, while the Series B-2 notes bear interest at a fixed rate of 7.9%. The weighted-average rate for the Williams Pipe Line Senior Secured Notes at December 31, 2002 was 7.0%. Debt placement fees associated with these notes were $10.5 million, and are being amortized over the life of the notes. Payment of interest and repayment of the principal is guaranteed by the Partnership. The fair value of the long-term debt at December 31, 2002, approximated its carrying value, because of the floating interest rate applied to the Series A-1 and Series A-2 notes and because the rates on the Series B-1 and B-2 notes were near market rates at December 31, 2002.

The new debt agreement imposes certain restrictions on Williams Pipe Line and the Partnership. Generally, the agreement restricts the amount of additional indebtedness Williams Pipe Line can incur, prohibits Williams Pipe Line from creating or incurring any liens on its property, and restricts Williams Pipe Line from disposing of its property, making any debt or equity investments, or making any loans or advances of any kind. The agreement also requires transactions between Williams Pipe Line and any of its affiliates to be on terms no less favorable than those Williams Pipe Line would receive in an arms-length transaction. As part of this agreement, the Partnership agreed that it will not redeem or retire the Partnership’s Class B units except with proceeds from equity issued by the Partnership (see Note 1 — Organization and Presentation). In the event of a change in control of the General Partner, each holder of the notes would have thirty days within which they could exercise a right to put their notes to Williams Pipe Line unless the new owner of the General Partner has (i) a net worth of at least $500.0 million and (ii) long-term unsecured debt rated as investment grade by both Moody’s Investor Service Inc. and Standard & Poor’s Rating Service. If this put right were exercised, Williams Pipe Line would be obligated to repurchase any such notes and repay any accrued interest within sixty days.

WES Affiliate Note — At December 31, 2001, Williams Pipe Line had an affiliate note payable to Williams. This note was contributed by our General Partner to Williams Pipe Line in conjunction with the Partnership’s acquisition of Williams Pipe Line in April 2002. Interest was calculated and paid monthly while the affiliate note was outstanding. Interest rates varied with current market conditions. At December 31, 2001, the fair value of this note approximated its carrying value because of the floating interest rate applied to the note.

During the years ending December 31, 2002, 2001 and 2000, total cash payments for interest on all indebtedness, net of amounts capitalized, were $22.9 million, $13.7 million and $11.3 million, respectively.

The Partnership leases land, office buildings, tanks and terminal equipment at various locations to conduct its on-going business operations. Future minimum annual rentals under non-cancelable operating leases as of December 31, 2002, are as follows (in thousands):

Lease payments associated with the Partnership’s lease of land, tanks and related terminal equipment at its Gibson, Louisiana facility can be canceled at the Partnership’s option 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 from their inception in 2001. The lease terms require the Partnership to return the Gibson terminal facility property to substantially its same condition at the time the lease was executed.

On December 31, 2001, the Partnership purchased an 8.5-mile, 8-inch natural gas liquids pipeline in northeastern Illinois from 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 direct financing lease. The lease expires in December 2016 and has a purchase option after the first year. Aux Sable has the right to re-acquire the pipeline at the end of the lease for a de minimis amount. The Partnership also has two five-year pipeline capacity leases with Farmland. The first agreement, which is accounted for as a direct financing lease, will expire on November 30, 2005 and the second agreement, which is accounted for as an operating lease, will expire on April 30, 2007. Both leases contain options to extend the agreement for another five years. In addition, the Partnership has eight other capacity operating leases with terms of four to fifteen years. All of the agreements provide for negotiated extensions.

Future minimum lease payments receivable under operating-type leasing arrangements as of December 31, 2002, are as follows (in thousands):

The net investment under direct financing leasing arrangements as of December 31, 2002 and 2001, are as follows (in thousands):

As of December 31, 2002, the net investment in direct financing leases is classified in the Consolidated Balance Sheet as $1.0 million current accounts receivable and $9.2 million noncurrent accounts receivable.

In February 2001, the General Partner adopted the Williams Energy Partners’ Long-Term Incentive Plan for Williams’ employees who perform services for the Partnership and directors of the General Partner. The General Partner subsequently amended and restated the Long-Term Incentive Plan in 2003. The Long-Term Incentive Plan permits the granting of various types of awards, including units, options, phantom units and bonus units but to-date only phantom units have been granted. The Long-Term Incentive Plan allows the grant of awards up to 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 addition to units, members of the General Partner’s Board of Directors may receive phantom units as compensation for their director fees. Members of the General Partner’s Board of Directors received 873 units and 870 phantom units in 2001 and 3,344 units and 1,489 phantom units during 2002 as partial compensation for their services as board members.

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 awards allowed for early vesting if established performance measures were met prior to February 9, 2004. The Partnership met all of these performance measures and all of the awards vested during 2002. The Partnership recognized compensation expense of $2.1 million and $0.7 million associated with these awards in 2002 and 2001, respectively.

In April 2001, the General Partner issued grants of 64,200 phantom units associated with the long-term incentive compensation program. The actual number of units that will be awarded under this grant will be determined by the Partnership in early 2004. At that time, the Partnership will assess whether certain performance criteria have been met as of the end of 2003 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 subject to forfeiture if employment is terminated prior to vesting. These awards do not have an early vesting feature, except for a change in control of the Partnership’s General Partner or for specific participants in the event of their death or disability. In the event of a change of control of the General Partner, these awards will vest and payout immediately at the number of units associated with achieving the highest performance level under the plan. The Partnership is expensing compensation costs associated with these awards assuming the highest level of performance will be achieved; accordingly, the Partnership recognized $1.5 million and $1.3 million of compensation expense in 2002 and 2001, respectively. The fair market value of the phantom units associated with this grant was $4.2 million and $5.4 million on December 31, 2002 and 2001, respectively.

During 2002, the Compensation Committee of the Board of Directors of the Partnership’s General Partner approved 22,650 phantom units associated with the 2002 long-term incentive compensation program. The actual number of units that will be awarded under this grant will be determined by the Partnership in early 2005. 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

45,300 units. These units are also subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature, except in the event of a change in control of the Partnership’s General Partner or for specific participants in the event of their death or disability. In the event of a change of control of the General Partner, these awards will vest and payout immediately at the number of units associated with achieving the highest performance level under the plan. The Partnership is expensing compensation costs associated with these awards assuming 22,650 units will vest; accordingly, the Partnership recorded incentive compensation expense of $0.2 million during 2002. Based on the closing price of $32.45 per unit at December 31, 2002, these units were valued at $0.7 million.

In February 2003, the Compensation Committee of the Board of Directors of the Partnership’s General Partner approved 52,825 phantom units associated with the 2003 long-term incentive compensation program. The actual number of units that will be awarded under this grant will be determined by the Partnership in early 2006. 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 105,650 units. These units are also subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature, except for (i) specific participants in the event of their death or disability or (ii) in the event a change in control of the Partnership’s General Partner and the participant is terminated for reasons other than cause within the two years following a change in control of the General Partner, in which case the awards will vest and payout immediately at the highest performance level under the plan. The value of these units on the date of grant was $1.9 million.

Certain employees of Williams dedicated to or otherwise supporting Williams Energy Partners L.P. also receive stock-based compensation awards from Williams. Williams has several programs providing for common-stock-based awards to employees and to non-employee directors. The programs permit the granting of various types of awards including, but not limited to, stock options, stock-appreciation rights, restricted stock and deferred stock. 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.

The following summary reflects Williams’ stock option activity for 2002, 2001 and 2000, for those employees principally supporting Williams Energy Partners L.P. operations:

The following summary provides information about outstanding and exercisable Williams’ stock options, held by employees principally supporting Williams Energy Partners L.P. operations, at December 31, 2002:

The estimated fair value at the date of grant of options for Williams’ common stock granted in 2002, 2001 and 2000, using the Black-Scholes option pricing model, is as follows:

Pro forma net income, assuming Williams Energy Partners L.P. had applied the fair-value method of SFAS No. 123, “Accounting for Stock-Based Compensation” in measuring compensation costs beginning with 2000 employee stock-based awards, are as follows (in thousands, except per unit 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. Pro forma amounts for 2001 include compensation expense from Williams’ awards made in 2001. Pro forma amounts for 2002 include compensation expense from Williams’ awards made in 2001 and 2002. Because 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.

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. Affiliate general and administrative costs associated with the assets owned at the time of our initial public offering, other than equity-based incentive compensation, are based on the expense limitations provided for in the Omnibus Agreement, and are allocated to the petroleum products terminals and ammonia pipeline system segments based on their proportional percentage of revenues. Affiliate general and administrative costs charged to Williams Pipe Line, other than equity-based incentive compensation, are based on the expense limitations included in the Omnibus Agreement. Equity-based incentive compensation expense was charged to the petroleum products terminals and ammonia pipeline system segments based on proportional revenues. The Williams Pipe Line segment was not charged equity-based incentive compensation expense in 2002 or prior periods because it was not acquired by the Partnership until 2002, and consequently its employees did not participate in the Partnership’s equity-based incentive compensation plan until 2003.

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.

Non-cash charges for incentive compensation costs, included in 2002 and 2001 affiliate general and administrative expenses, were $3.1 million for the petroleum products terminal operations and $0.5 million for the ammonia pipeline operations during 2002 and $1.7 million for the petroleum products terminal operations and $0.3 million for the ammonia pipeline operations during 2001.

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 at the time of the initial public offering 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 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. Reimbursements from Williams relative to their environmental indemnities are received as remediation is performed. See Note 1 — Organization and Presentation — Recent Developments relative to Williams. Changes in Williams’ ability to perform on their indemnities could result in the Partnership materially increasing its related affiliate receivable reserves.

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 $2.0 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 under these indemnities 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, which was met during 2002, for claims made within six years of our acquisition of Williams Pipe Line in April 2002. Williams has provided a performance guarantee for the remaining amount of these environmental indemnities.

Estimated liabilities for environmental costs were $22.3 million and $16.9 million at December 31, 2002 and December 31, 2001, respectively. These estimates, provided on an undiscounted basis, were determined based primarily on data provided by a third-party environmental evaluation service and Williams’ internal environmental engineers. These liabilities have been classified as current or non-current based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental remediation liabilities will be paid over the next five years. Receivables from Williams or its affiliates of $22.9 million and $5.1 million at December 31, 2002 and December 31, 2001, respectively, associated with indemnified environmental costs have been recognized as affiliate accounts receivable in the Consolidated Balance Sheet. Reimbursements from Williams and its affiliates relative to their environmental indemnities are received as remediation is performed. See Note 1 — Organization and Presentation — Recent Developments relative to Williams.

In conjunction with the 1999 acquisition of the Gulf Coast marine terminals from Amerada Hess Corporation (“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. In the event that any pre-acquisition releases of hazardous substances at the Partnership’s Corpus Christi and Galena Park, Texas and Marrero, Louisiana marine terminal facilities were unknown at closing but subsequently 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. Also, 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. 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, 2002 and 2001, 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 $2.3 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 completed a Phase III environmental assessment at this facility during 2002 and the results of that assessment are being evaluated. The environmental liabilities at the New Haven facility are not expected to change materially once the evaluation of the assessment is completed, which should be by the end of the first quarter of 2003. 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 $25.0 million of environmental liabilities associated with these assets, which carries a deductible of $0.3 million. Any environmental liabilities at this location not covered by the seller’s indemnity and not covered by insurance are covered by the WES environmental indemnifications to the Partnership, subject to the $15.0 million limitation.

During 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act, preliminarily determined that Williams may have systemic problems with petroleum discharges from pipeline operations. The inquiry primarily focused on Williams Pipe Line, which was subsequently acquired by the Partnership. The response to the EPA’s information request was submitted during November 2001. Any claims the EPA may assert relative to this inquiry would be covered by the Partnership’s environmental indemnifications from Williams.

WNGL will indemnify the Partnership for right-of-way defects or failures in the 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.

On May 31, 2002, Farmland and several of its subsidiaries filed for Chapter 11 bankruptcy protection. Farmland, the largest customer on the ammonia pipeline system, is also a customer of Williams Pipe Line. The Partnership received approximately $2.3 million in payments from Farmland during the preference period prior to Farmland’s filing for bankruptcy. Management believes that the Partnership will not be required to reimburse these funds to the bankruptcy trustee because they were received in the ordinary course of business with Farmland. The Partnership’s receivable balance from Farmland at December 31, 2002, was $30 thousand. The Partnership also has two five-year petroleum pipeline lease capacity agreements with Farmland. The first of these agreements, which expires on November 30, 2005, requires an annual payment by Farmland of $1.2 million on each November 30th during the contract period. The second agreement, which expires on April 30, 2007, is for $0.5 million annually and is invoiced to Farmland on a monthly basis. Farmland has remained current on both of these lease capacity agreements.

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.

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

Basic and diluted net income for the second, third and fourth quarters of 2002 include the impact of the Partnership’s ownership of Williams Pipe Line. Fourth quarter 2002 net income included a gain of $1.1 million on the sale of the inland terminals. Second, third and fourth quarter net income for 2002 was impacted by the amortization of debt placement costs of $7.1 million associated with the short-term note assumed at the time of the Williams Pipe Line acquisition by the Partnership and interest expense associated with that note. Fourth quarter results were impacted by the amortization of the $2.1 million debt placement costs associated with the extension of the maturity date of the Williams Pipe Line short-term note and interest expense on the new $480.0 million borrowings by Williams Pipe Line.

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 5 — Acquisitions and Divestitures. Second quarter 2001 revenues were impacted by a $1.0 million throughput deficiency billing to an ammonia pipeline customer. Fourth quarter 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.

Distributions paid by the Partnership during 2002 and 2001 are as follows (in thousands, except per unit amounts):

On February 14, 2003, the Partnership paid cash distributions of $0.725 per unit on its outstanding common, subordinated and Class B units to unitholders of record at the close of business on January 31, 2003. The total distribution, including distributions paid to the General Partner on its equivalent units, was $21.0 million.

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

Units reported as dilutive securities are related to restricted unit grants associated with the one-time initial public offering award (see Note 14 — Long-Term Incentive Plan).

Of the 13,679,694 common units outstanding at December 31, 2002, 12,600,000 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 and 7,830,924 Class B units are held by affiliates of the Partnership.

During the subordination period, 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 exercise of the underwriters’ over-allotment option;

	•	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 our 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.

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 elect the board members of the Partnership’s General Partner;

	•	right to remove Williams as the General Partner upon a 66.7% majority vote of outstanding unitholders;

	•	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 our 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; and

	•	right to inspect our books and records at the unitholders’ own expense.

The voting rights associated with the election of the board members of the Partnership’s General Partner and the right to remove Williams as the General Partner will be voided in the event of a foreclosure in a Williams-related bankruptcy proceeding.

Net income 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:

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.

During 2002 the Partnership filed a shelf registration statement with the Securities and Exchange Commission to register common units representing limited partner interests and debt securities, including guarantees. The Partnership, exclusive of its investment in all of 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 operating limited partnerships and subsidiaries on a full and unconditional and joint and several basis.

On February 20, 2003, Williams announced its intention to divest its interest in our General Partner and all of its limited partnership interests. It is uncertain what form this potential transaction may take and management cannot currently determine what impact this sale may have on the on-going operations of the Partnership.

In March 2003, the Partnership reached an agreement with Williams Energy Marketing & Trading to terminate their storage capacity contract, which extended through September 30, 2004, at the Galena Park, Texas marine terminal facility. The Partnership will receive $3.0 million from Williams Energy Marketing & Trading, which will be under no further obligation under this long-term agreement to pay for tank storage or any other ancillary services at the Galena Park, Texas facility.

Our General Partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operations. Our General Partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific non-recourse indebtedness or other obligations. Whenever possible, our General Partner intends to cause us to incur indebtedness or other obligations that are non-recourse.

Three members of the Board of Directors of our General Partner serve on a Conflicts Committee to review specific material matters that the Board of Directors believes may involve conflicts of interest including bankruptcy-related decisions involving us and our General Partner or as specified in our agreement of limited partnership or the General Partner’s limited liability company agreement. When a potential conflict arises, the Conflicts Committee will determine if the involved transaction is fair and reasonable to us. The members of the Conflicts Committee are not officers or employees of our General Partner or directors, officers or employees of its affiliates. Any matters approved by the Conflicts Committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partner of any duties it may owe us or our unitholders. In addition, the members of the Conflicts Committee also serve on the Audit Committee and the Compensation Committee. The Audit Committee, among other things, reviews our external financial reporting, retains our independent auditors, approves services provided by the independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. The Compensation Committee oversees long-term incentive compensation decisions for the officers and key employees of WEG GP LLC as well as compensation plans adopted by the General Partner.

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers of, and are subject to the oversight of the directors of, our General Partner. All of our personnel are employees of Williams or its subsidiaries.

Some officers of our General Partner may spend a substantial amount of time managing the business and affairs of Williams and its affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Williams. Our General Partner causes its officers to devote as much time as is necessary for the proper conduct of our business and affairs. Don R. Wellendorf currently devotes approximately 100% of his time to our operations. John D. Chandler currently devotes 100% of his time to us. Phillip D. Wright currently devotes approximately 2% of his time to us and Craig R. Rich currently devotes approximately 90% of his time to our operations. Jay A. Wiese currently devotes approximately 100% of his time to our operations, Michael N. Mears currently devotes approximately 90% of his time to our operations, and Richard A. Olson currently devotes approximately 80% of his time to us. The Board of Directors of the General Partner is presently composed of seven directors.

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 are elected for one-year terms. Our General Partner’s limited liability company agreement provides for three classes of directors. Keith E. Bailey and William W. Hanna are the initial members of Class I, whose terms will expire at the 2003 annual meeting of limited partners and on each third succeeding year thereafter. Phillip D. Wright and Don J. Gunther are the initial members of Class II, whose terms will expire at the 2004 annual meeting of limited partners and on each third succeeding year thereafter. Steven J. Malcolm, Don R. Wellendorf, and William A. Bruckmann III

Phillip D. Wright has served as a director and the Chairman of the Board of Directors of our General Partner since November 15, 2002. He served as Chairman of the Board of Directors of our former general partner from May 13, 2002 to November 15, 2002 and served as a director of the former general partner from February 9, 2001 to November 15, 2002. From January 7, 2001 to May 13, 2002 he served as President and Chief Operating Officer of our former general partner. Mr. Wright is currently the Chief Restructuring Officer and a Senior Vice President of Williams and has served in that capacity since November 21, 2002. From September 2001 until March 2003, Mr. Wright served as President and Chief Executive Officer of Williams Energy Services, LLC (“Williams Energy Services”). He also served as Senior Vice President of Enterprise Development and Planning for Williams Energy Services from November 1996 to September 2001. From 1989 to 1996 he held various senior management positions with Williams Pipe Line Company and Williams Energy Ventures, Inc. Prior to 1989, he spent 13 years working for Conoco, Inc.

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

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

Michael N. Mears has served as the Vice President, Transportation of our General Partner since November 15, 2002 and served in that capacity for our former general partner from April 22, 2002 until November 15, 2002. He is currently Vice President of Williams Petroleum Services, LLC and has served in

that capacity since March 2002. Mr. Mears served as Vice President of Transportation and Terminals for Williams Pipe Line Company from 1998 to 2002. He also served as Vice President, Petroleum Development for Williams Energy Services from 1996 to 1998. Prior to 1996, Mr. Mears served as Director of Operations Control and Business Development for Williams Pipe Line Company from 1993 to 1996. From 1985 to 1993 he worked in various engineering, project analysis, and operations control positions for Williams Pipe Line Company.

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

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

Craig R. Rich has served as the General Counsel of our General Partner since November 15, 2002 and served in that capacity for our former general partner from January 7, 2001 until November 15, 2002. Since 1996, he has also served as Associate General Counsel of Williams Energy Services. From 1993 to 1996, he served as General Counsel of Williams’ 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 has served as a director of our General Partner since November 15, 2002 and served as a director of our former general partner from February 9, 2001 until November 15, 2002. Since 2001, Mr. Bailey has also served as a Director for Aegis Insurance Services Inc. He served as Chairman of the Board of Directors and Chief Executive Officer of Williams from 1994 to 2002. He served as President of Williams from 1992 to 1994 and as Executive Vice President of Williams from 1986 to 1992.

William A. Bruckmann, III has served as a director of our General Partner since November 15, 2002 and served as a director of our former general partner from May 9, 2001 until November 15, 2002. Mr. Bruckmann also serves as a member of the Board’s Audit Committee, the Compensation Committee and is the Chairman of the Conflicts Committee. Since September 9, 2002, Mr. Bruckmann has been employed with UBS Paine Webber as a Financial Advisor. He is a former managing director at Chase Securities, Inc. and 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 has served as a director of our General Partner since November 15, 2002 and served as a director of our former general partner from May 9, 2001 until November 15, 2002. Mr. Gunther also serves as a member of the Board’s Audit Committee, the Conflicts Committee and is the Chairman of the Compensation Committee. 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 has served as a director of our General Partner since November 15, 2002 and served as a director of our former general partner from January 18, 2002 until November 15, 2002. Mr. Hanna also serves as a member of the Board’s Compensation Committee, the Conflicts Committee and is the Chairman of the Audit Committee. He is a retired vice chairman of Koch Industries where he held management and leadership positions since he commenced employment in 1968. 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 has served as a director of our General Partner since November 15, 2002 and served as a director of our former general partner from February 9, 2001 until November 15, 2002. He served as the Chief Executive Officer and Chairman of the Board of Directors of our former general partner from January 7, 2001 until May 13, 2002. He is currently President and Chief Executive Officer of Williams and has served in the capacity as President since September 2001, and as Chief Executive Officer since January 2002. He has also served as the Chairman of Williams’ Board of Directors since May 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 Williams’ 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.

The Partnership’s agreement of limited partnership, as amended, provides for an annual meeting of the limited partners for the election of directors to the Board of Directors of our General Partner. Our General Partner has not yet announced the date and location of the 2003 annual meeting.

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10% of our units to file certain reports with the Securities and Exchange Commission and the New York Stock Exchange concerning their beneficial ownership of our equity securities. The Securities and Exchange Commission regulations also require that a copy of all such Section 16(a) forms filed must be furnished to us by the executive officers, directors and greater than 10% unitholders. Based on a review of the copies of such forms and amendments thereto with respect to 2002, we have determined that, due to an administrative oversight, one transaction involving Keith E. Bailey that should have been reported on a Form 4 was not timely reported. The transaction was reported on a Form 5 shortly after discovery of the oversight.

We have no employees. We are managed by the officers of our General Partner. Subject to maximum reimbursement obligations that were met in 2002, we reimburse Williams for direct and indirect general and administrative expenses incurred on our behalf, as discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Following are the approximate percentages of the direct and indirect compensation expense of each named executive officer allocated to us by Williams: Mr. Wellendorf, 80% for 2002 and 75% for 2001; Mr. Malcolm, 2% for 2002 and 3% for 2001; Mr. Chandler, 100% for 2002; Mr. Mears, 80% for 2002; Mr. Olson, 72% for 2002; and Mr. Wiese, 100% for 2002 and 95% for 2001. The following table represents compensation expense allocated to our General Partner by Williams for the fiscal


(1)	Represents salary and bonus expense allocated to us by Williams.

(2)	Represents vesting of phantom units granted on April 19, 2001 in association with our initial public offering. These units were subject to early vesting if certain performance measures were met. These measures were met, resulting in one-half of the units vesting on February 14, 2002 and the remaining one-half vesting on November 15, 2002. The payout of these awards are valued as follows: (i) one-half at $36.55, the closing common unit price on the vesting date February 14, 2002 and (ii) one-half at $31.05, the closing common unit price on the vesting date November 15, 2002.

(3)	Represents expense allocated to us by Williams for contributions made to the Investment Plus Plan, a defined contribution plan subject to the Employee Retirement Income Security Act of 1974 on behalf of each named executive officer.

(4)	Represents options granted in both February and November 2002. The November 2002 grant was an acceleration of the 2003 grant.

The following table provides certain information concerning the grant by Williams of Williams’ stock options during the last fiscal year to the named executive officers. The number of options granted, percent of total options granted and the grant date present values reported below reflect the portion allocated to us by Williams according to the approximate allocation percentages as described in the Summary Compensation Table.


(1)	Options granted in 2002 are subject to accelerated vesting if certain future Williams’ stock prices or specific Williams’ financial performance targets are achieved. Williams granted these options under its 1996 Stock Plan, its Stock Plan for Non-officer Employees and its 2002 Incentive Plan.

(2)	The grant date present value is determined using the Black-Scholes option pricing model and is based on assumptions about future stock price volatility, risk-free rate of return and dividend yield over the life of the options. The following weighted average values were determined based on the above grants. The weighted average volatility of the expected market price of Williams’ Common Stock is 36.7%. The weighted average risk-free rate of return is 5.2%. The model assumes a dividend yield of 1% and an exercise date at the end of the contractual term in 2012. The model does not take into account that the stock options are subject to vesting restrictions and that executives cannot sell their options. The actual value, if any, that may be realized by an executive will depend on the market price of Williams’ Common Stock on the date of exercise. The dollar amounts shown are not intended to forecast possible future appreciation in Williams’ Common Stock price.

The following table provides certain information on exercises of Williams’ stock options during the last fiscal year by the named executive officers and the value of such officers’ unexercised options at December 31, 2002. The number of unexercised options and the value of unexercised in-the-money options below reflect the portion allocated to us by Williams according to the approximate allocation percentages as described in the Summary Compensation Table.

(1)

Based on the closing price of Williams’ Common Stock reported in the table entitled “New York Stock Exchange Composite Transactions” contained in The Wall Street Journal for December 31, 2002 ($2.70 per share), less the exercise price. The values shown reflect the value of options accumulated over periods of up to ten years. Such values had not been realized as of December 31, 2002 and may not be realized. In the event the options are exercised, their value will depend on the market price of Williams’ Common Stock on the date of exercise.

The following table provides certain information concerning the grant of phantom units under the Williams Energy Partners’ Long-Term Incentive Plan during the last fiscal year to the named executive officers:

(1)

Represents phantom units of deferred limited interest granted on October 23, 2002 (Market values at date of grant are noted as follows): Mr. Wellendorf, 6,000 units valued at $198,960; Mr. Chandler, 2,500 units valued at $82,900; and Mr. Wiese, 2,000 units valued at $66,320. At the end of the vesting period, the number of units awarded under this grant will be determined based on an assessment of whether certain performance criteria have been met. The number of units could range from zero to two times the number of units granted.

The Partnership participates in Williams’ pension plan, which is a noncontributory, tax-qualified defined benefit plan subject to the Employee Retirement Income Security Act of 1974. The pension plan generally includes salaried employees who have completed one year of service. Our named executive officers participate in the pension plan on the same terms as other full-time employees.

Effective April 1, 1998, Williams converted its pension plan from a final average pay plan to a cash balance pension plan. Each participant’s accrued benefit as of that date was converted to a beginning account balance. Account balances are credited with an annual Williams contribution and quarterly interest allocations. Each year, Williams credits an employee’s pension account an amount equal to the sum of a percentage of eligible pay and a percentage of eligible pay greater than the Social Security wage base. We reimburse Williams for these contributions according to the approximate allocation percentages described in the Summary Compensation Table, subject to maximum reimbursement obligations as discussed in Part II, Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. According to the plan, eligible pay is the sum of salary and certain bonuses. Interest is credited to account balances quarterly at a rate determined annually in accordance with the terms of the plan. The percentage used in the calculation of the annual contribution is based upon the employee’s age according to the following table:


(1)	For employees, including the named executive officers, who were active employees and plan participants on March 31,1998, and April 1, 1998, the percentage of all eligible pay is increased by an amount equal to 0.3% multiplied by the participant’s total years of benefit service prior to March 31, 1998.

The normal retirement benefit is a monthly annuity based on a participant’s account balance as of benefit commencement. Normal retirement age is 65. Early retirement may commence as early as age 55. At retirement, employees are entitled to receive a single-life annuity or one of several optional forms of payment having an equivalent actuarial value to the single-life annuity.

Participants who were age 50 or older as of March 31, 1998, were grandfathered under a transitional provision that gives them the greater of the benefit payable under the cash balance formula or the final average pay formula based on all years of service and compensation.

The Internal Revenue Code of 1986, as amended, currently limits the pension benefits that can be paid from a tax-qualified defined benefit plan, such as the pension plan, to highly compensated individuals. These limits prevent such individuals from receiving the full pension benefit based on the same formula as is applicable to other employees. As a result, Williams has adopted an unfunded supplemental retirement plan to provide a supplemental retirement benefit equal to the amount of such reduction to eligible executives, including the named executive officers, whose benefit payable under the pension plan is reduced by Internal Revenue Code limitations.

Total unallocated estimated annual retirement benefits payable at normal retirement age under the cash balance formula from both the tax qualified pension plan and the supplemental retirement plan are as follows:

Directors who are employees of Williams or its affiliates receive no additional compensation for service on our general partner’s Board of Directors or committees of the Board. In 2002, non-management directors, including directors who are not employees of Williams or its affiliates, received an annual retainer of $10,000 and 400 common units; and the Chairmen of the Audit Committee, Compensation Committee and Conflicts Committee received an annual retainer of $1,000. Non-management directors also received $1,000 for each Board meeting attended and $500 for each Audit Committee, Compensation Committee or Conflicts Committee meeting attended. Effective October 2002, the meeting fee for each Audit Committee, Compensation Committee and Conflicts Committee meeting attended increased to $1,000. Effective January 1, 2003, non-management directors receive an annual retainer of $16,000 and common units valued at $16,000 on the grant date and the Chairmen of the Audit Committee, Compensation Committee and Conflicts Committee each receive an annual retainer of $2,000. Non-management directors also receive $1,000 for each Board, Audit Committee, Compensation Committee and Conflicts Committee meeting attended. In lieu of individual meeting fees for Committee meetings related to the acquisition of Williams Pipe Line and in recognition of the extensive time investment related to the acquisition, members of the Conflicts Committee also received $25,000 in 2002 in addition to their annual retainer, meeting fee received for each Board and Committee meeting attended (other than Conflicts Committee meetings related to the acquisition) and the annual retainer for the Chairmen of the Committees.

Non-management directors may elect to receive all or any part of cash fees in the form of common units or phantom units. Phantom units may be deferred to any subsequent year or until such individual ceases to be a director. Non-management directors may also elect to defer receipt of their annual unit retainer to any subsequent year or until such individual ceases to be a director. Distribution equivalents are paid on phantom units and may be received in cash or reinvested in additional phantom units. One director elected to defer fees under this plan in 2002.

In addition, each non-management director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Neither we nor Williams has any separate employment agreements with the named executive officers. However, Williams provides severance benefits for Messrs. Wellendorf, Mears and Olson through Williams’ executive severance program. The program provides severance benefits if one of these officers is terminated involuntarily other than for cause, disability or the sale of a business. The benefits include:


	•	severance pay equal to one month of the officer’s then current monthly base salary for each full, completed year of service with Williams, with a minimum of six months and a maximum of twelve months, payable in bi-weekly payments;

	•	six months of outplacement services; and

	•	continuation of health and welfare benefits at active employee rates for the covered severance period, if officer elects COBRA.

Amounts payable under this program are in lieu of any payments that may otherwise be payable under any other severance plan. Subject to maximum reimbursement obligations that were met in 2002, we reimburse Williams for direct and indirect general and administrative expenses incurred on our behalf, as discussed in Part II, Item 7 — “Managements Discussion and Analysis of Financial Condition and Results of Operations”. As such, amounts payable under this program could be allocated to us by Williams according to the percentage of time these persons devote to our matters.

The following table provides information concerning the various types of awards that may be issued from the Williams Energy Partners’ Long-Term Incentive Plan, including units, options, phantom units and bonus units as of December 31, 2002.


(1)	Units delivered pursuant to an award consist, in whole or in part, of units acquired on the open market, from any affiliate, the Partnership, any other person, or any combination of the foregoing. We have the right to issue new units as part of the Long-Term Incentive Plan.

(2)	Units awarded pursuant to the William Energy Partners’ Long-Term Incentive Plan are granted without payment by the participant. Taxes are withheld from the award to cover the participant’s mandatory tax withholdings.

(3)	Includes 36,898 units that have vested but for which participants elected to defer issuance until a future date.

The following table sets forth the number of units beneficially owned by each person who is known to us to beneficially own 5% or more of a class of units, by directors and named executive officers of our General Partner, and by all directors and executive officers as a group as of February 28, 2003. We obtained certain information in the table from filings made with the Securities and Exchange Commission.


(1)	Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc., and Williams GP LLC are direct or indirect subsidiaries of Williams and Williams may be deemed the beneficial owner of units held by such subsidiaries. The address of each of each of these entities is One Williams Center, Tulsa, Oklahoma, 74104.

(2)	Except for the right to vote on a matter that would have a material adverse effect on the rights of holders of Class B units, such units do not have any voting rights. Under the terms of the Partnership’s agreement of limited partnership, Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc. are permitted in the aggregate to vote not more than 20% of the total number of outstanding units entitled to vote at a meeting of the limited partners for the election of directors to the Board of Directors of our General Partner. For this purpose, each subordinated unit held by those parties will count as 0.5 of a vote and 0.5 of a unit. As of February 28, 2003, Williams Energy Services and Williams Natural Gas Liquids would be entitled to collectively cast approximately 3,303,908 votes at such a meeting out of the approximately 16,519,541 votes that would be deemed outstanding for purposes of the meeting. Our limited partnership agreement also provides for other limitations on the voting rights of subordinated units.

(3)	A filing with the Securities and Exchange Commission on February 10, 2003, indicates that Goldman Sachs Group, Inc. and Goldman, Sachs & Co., a direct and indirect wholly-owned subsidiary of Goldman Sachs Group, Inc., a broker or dealer registered under Section 15 of the Securities Exchange Act of 1934, and an investment advisor registered under Section 203 of the Investment Advisors Act of 1940, are or may be deemed to be the beneficial owners of the number of Common Units indicated in the table. The address of Goldman Sachs Group, Inc. and Goldman, Sachs & Co. is 85 Broad Street, New York, New York 10004.

(4)	Includes 2,359 Common Units which represent deferred compensation granted pursuant to the Williams Energy Partners’ Long-Term Compensation Plan subject to the right of conversion within 60 days. The deferred units subject to conversion cannot be voted or invested.


(5)	Does not include any units owned by Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc., and Williams GP LLC, which may be deemed to be beneficially owned by Mr. Malcolm in his capacity as Chairman of the Board, President and Chief Executive Officer for Williams.

The following table sets forth, as of February 28, 2003, the amount of shares of Common Stock of Williams, the corporate parent of the sole member of our General Partner, beneficially owned by each of the General Partner’s directors, each of the General Partner’s executive officers named in the Summary Compensation Table, and by all directors, nominees for director and executive officers of the General Partner as a group.

(1)

Includes the following shares which represent stock options granted under the Williams’ stock option plans which are exercisable within 60 days and thus deemed to be beneficially owned by the following individuals: Mr. Bailey, 381,243 shares; Mr. Wellendorf, 39,891 shares; Mr. Malcolm, 399,772 shares; Mr. Chandler, 12,210; Mr. Mears, 71,363; Mr. Olson, 68,311; and Mr. Wiese, 33,183. The shares subject to option cannot be voted or invested.

Williams GP LLC, Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc. have pledged all of their units in us to a collateral trustee under debt instruments to which Williams and certain of its affiliates are debtor parties. In addition, Williams Energy Services and Williams Natural Gas Liquids have pledged all of their respective membership interests in the General Partner and Williams GP LLC, the former general partner, to the collateral trustee and Williams pledged its membership interest in Williams Energy Services and all of its stock in Williams Natural Gas Liquids to the trustee. If the Partnership units and the membership interests in Williams Energy Services and Williams Natural Gas Liquids are transferred to these lenders as a result of a default with respect to such debt instruments, these holders would be able to elect all of the members of the General Partners’ Board of Directors. In addition, changes made to the partnership agreement that limited the voting rights of the subordinated units and Class B units would be of no further force and effect and the voting rights of such units would revert back to those in place prior to such changes. Also, on February 20, 2003, Williams announced its intention to divest its interest in our General Partner and all of its limited partnership interests.

Steve Malcolm, Phil Wright, and Don Wellendorf serve or have served in various capacities as executive officers of Williams, Williams Energy Services and Williams Natural Gas Liquids. For more information with respect to each individual’s roles with these affiliated entities, please read “Item 10. Partnership Management — Directors and Executive Officers of WEG GP LLC.”

Williams Energy Marketing & Trading Company and Williams Refining & Marketing, Williams Midstream Marketing & Risk Management, subsidiaries of Williams and affiliates of ours, are significant customers, representing 9%, 2% and less than 1%, respectively, of our total revenues for the year ended

December 31, 2002. The services we provide them are conducted pursuant to various contracts. For additional information relating to our commercial agreements with Williams and its affiliates, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Related Party Transactions.”

Affiliates of Williams own 1,079,694 common units, 7,830,924 Class B units and 5,679,694 subordinated units representing an approximate aggregate ownership interest in us of 55%, including their 2% general partner interest. The General Partner’s ability, as general partner, to manage and operate us effectively gives the General Partner the right to veto some actions of ours and to control our management. For more information about the limited partnership interest in us held by affiliates, please read “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters — Security Ownership of Certain Beneficial Owners and Management.”

The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our formation, ongoing operation and liquidation of Williams Energy Partners. These distributions and payments were determined by and among affiliated entities and are not the result of arm’s length negotiations.

Our General Partner and its affiliates own 1,079,694 common units, 7,830,924 Class B units and 5,679,694 subordinated units, representing a 55% ownership interest in us, including their 2% general partner interest. Through the General Partner’s ability, as general partner, to manage and operate our business and Williams affiliates’ ownership of 1,079,694 common units and all of the outstanding Class B and subordinated units, the General Partner controls the management of our business.

We entered into an agreement in February 2001 with Williams and its affiliates and our General Partner, that governs:


	•	potential competition among us and the other parties to the agreement;

	•	reimbursement of general and administrative expenses;

	•	indemnification for environmental liabilities and right-of-way defects or failures;

	•	the grant of a license for use of the ATLAS 2000 software system and other intellectual property; and

	•	reimbursement of maintenance capital expenditures.

This agreement was amended on three separate occasions in 2002 to: (i) clarify general and administrative expenses and rights to software, (ii) add Williams Pipe Line to certain provisions of the agreement as a result of the Williams Pipe Line acquisition in April 2002 and (iii) further clarify license rights and restrictions for software use. Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement.

Williams and its affiliates have agreed that they will not own or operate assets that are used to transport, store or distribute ammonia in the United States or terminal and store refined petroleum products in the continental United States. In addition, Williams and its affiliates agreed that they will be prohibited from engaging in or acquiring any business transporting refined products to a delivery point within a 50-mile radius of any of our refined product delivery points before April 2005 or transport refinery grade butane from several refineries on the northern most part of the Williams Pipe Line system. We refer to these assets below as restricted assets. Williams will not be prohibited from owning or operating the following restricted assets:


	•	any restricted assets owned, leased or operated by Williams at the closing of our initial public offering on February 9, 2001;

	•	any restricted assets acquired after February 9, 2001 with a fair market value not greater than $20.0 million;

	•	any restricted assets constructed by Williams after February 9, 2001 with construction costs not greater than $20.0 million; and

	•	any restricted assets constructed or acquired by Williams after February 9, 2001 that are connected to assets owned by Williams or are primarily related to and located within 50 miles of Williams’ refinery in Memphis, Tennessee.

In return, we agreed that until April 2005, we would not engage in NGL transportation to a delivery point within a 50-mile radius of a NGL delivery point owned or supplied by Williams as of April 2002 and we agreed to use Mid-America Pipeline for propane and NGL blendstocks into certain markets.

If either Williams or we acquire or construct restricted assets other than those identified above and with a cost in excess of $20 million, the party in breach of the agreement shall offer to sell such asset to the other party within six months of acquiring or completing construction. If we and Williams are unable to agree on the

terms of the sale, we and Williams will appoint a mutually-agreed-upon, nationally-recognized investment banking firm to determine the fair market value of the restricted assets. Once the investment bank submits its valuation of the restricted assets to Williams and us, the party not in breach of the Omnibus Agreement will have the right, but not the obligation, to purchase the business in accordance with the following process:


	•	if the valuation of the investment bank is in the range between the proposed sale and purchase values of Williams and us, the party not in breach will have the right to purchase the business at the valuation submitted by the investment bank.

	•	if the valuation of the investment bank is less than the proposed purchase value submitted by the party not in breach, that party we will have the right to purchase the business for the amount they submit.

	•	if the valuation of the investment bank is greater than the proposed sale value submitted by the party in breach, the party not in breach will have the right to purchase the business for the amount submitted by the party in breach.

If either party elects not to purchase any restricted assets, the other party will be permitted to own or operate such assets without limitation.

In 2003, we will reimburse the General Partner or Williams for general and administrative expenses of not more than $6.9 million associated with assets at the time of our initial public offering and $31.0 million associated with Williams Pipe Line’s operations, excluding expenses associated with our Long-Term Incentive Plan. Management estimates that actual general and administrative costs required for our operation could be significantly higher due in part to increases in insurance premiums, increased general and administrative costs for the ammonia pipeline associated with the new Enterprise operating contract and the $0.3 million of increased general and administrative expense associated with the Rio Grande contract. The amount associated with the assets at the time of our initial public offering may increase during the next eight years as follows:


	•	in each year after 2003, the amount of general and administrative expenses, excluding expenses associated with the Long-Term Incentive Plan, allocated to us by Williams and the General Partner may increase by no more than the greater of 7% or the percentage increase in the consumer price index for that year.

	•	if we make an acquisition, our general and administrative expense allocation may increase by the amount of these expenses included in our valuation of the business we acquire.

The amount of general and administrative expense associated with assets acquired from Williams Pipe Line may increase during the next nine years as follows:


	•	in each year after 2003, the amount of general and administrative expenses, excluding expenses associated with the Long-Term Incentive Plan, allocated to us by Williams and the General Partner may increase by no more than the lesser of 2.5% or the percentage increase in the consumer price index for that year.

	•	if we make an acquisition, our general and administrative expense allocation may increase by the amount of these expenses included in our valuation of the business we acquire.

Through a change of control or with 90 days written notice, Williams can terminate its obligations to provide services to us, which would also eliminate Williams’ obligations under the general and administrative expense limitation included in the Omnibus Agreement.

Williams Energy Services and Williams Natural Gas Liquids, Inc. have 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. The indemnity applies to environmental liabilities arising from conduct prior to February 9, 2001 and discovered within three years of February 9, 2001. Liabilities resulting from a change in

law after February 9, 2001 are excluded from this indemnity. Williams Natural Gas Liquids, Inc. will indemnify us for right-of-way defects or failures in our ammonia pipeline for 15 years after the date of February 9, 2001. Williams Energy Services will indemnify us for right-of-way defects or failures associated with our marine terminal facilities at Galena Park and Corpus Christi, Texas and Marrero, Louisiana for 15 years after February 9, 2001.

In connection with the acquisition of Williams Pipe Line, 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 $2.0 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 under these indemnities 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 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, which was met during 2002, for claims made within six years of our acquisition of Williams Pipe Line in April 2002. Williams has provided a performance guarantee for the remaining amount of these environmental indemnities.

Williams and its affiliates have granted a license to us for the use of the ATLAS 2000 software system (and to permit customers to use the system to track inventories) and other intellectual property, including our logo, for as long as Williams controls our General Partner, at no charge. In the event of a termination of the Omnibus Agreement, we may, at our option, require Williams to transfer all right, title and interest in the ATLAS system to Williams Pipe Line at no cost.

In 2003 and 2004, Williams has agreed to reimburse us for maintenance capital expenditures associated with Williams Pipe Line’s operations in excess of $19.0 million per year, subject to a maximum aggregate reimbursement of $15.0 million over this two year period. At our current projected maintenance capital expenditure plans, we do not anticipate any reimbursements from Williams under this agreement.

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) was performed within the 90 days prior to the filing date of this report. This evaluation was performed under the supervision and with the participation of our management, including the General Partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, the General Partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective.

A self-evaluation of our internal controls was performed during January and February 2003. We concluded that there were no significant deficiencies or material weaknesses in its internal controls. There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to the date of the certifying officers’ most recent evaluation.

We have furnished as a correspondence filing to the Securities and Exchange Commission the certifications of this report by the General Partner’s Chief Executive Officer and Chief Financial Officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


	All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and (c). The exhibits listed below are filed as part of this annual report.


*	Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.


	On October 24, 2002, we filed a report on Form 8-K under Item 5 reporting that we had extended the maturity of our short-term loan associated with the acquisition of Williams Pipe Line Company, LLC until November 27, 2002, and were negotiating long-term debt financing to retire the short-term loan within the timeframe of the extension. We also filed as an exhibit under Item 7 a press release announcing the information reported under Item 5.

	On November 19, 2002, we filed a report on Form 8-K under Item 5 reporting amendments to our partnership agreement, the establishment of a new general partner and matters regarding the configuration of the new General Partner’s board of directors. We also filed as exhibits under Item 7 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Williams Energy Partners L.P., Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Williams Energy Partners L.P., the Limited Liability Company Agreement of WEG GP LLC, and an Assignment, Assumption and Amendment Agreement dated as of November 15, 2002, entered into by and between Williams GP LLC, WEG GP LLC, Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and us.

	On October 29, 2002; November 4, 2002; November 15, 2002; November 25, 2002; and December 6, 2002; we furnished reports on Form 8-K under Item 9.

On April 11, 2002, we issued 7,830,924 Class B units representing limited partner interests to Williams GP LLC. The securities, valued at $304.4 million, were issued as partial payment for the acquisition of Williams Pipe Line. We have the right to redeem the Class B units for cash based on the 15-day average closing price of the common units prior to the redemption date. If the Class B units are not redeemed by April 11, 2003, upon the request of the holders of the Class B units and approval of the holders of a majority of the common units voting at a meeting of the 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 this request, the holders of the Class B units 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. These securities are exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this report to be signed on our behalf by the undersigned, thereunto duly authorized.


	By:	WEG GP LLC, its General Partner

	By:	/s/ CRAIG R. RICH



	Craig R. Rich
	Attorney-in-fact

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.

I, Don R. Wellendorf, President and Chief Executive Officer of WEG GP LLC, the General Partner of Williams Energy Partners L.P., certify that:

1. I have reviewed this annual report on Form 10-K of Williams Energy Partners L.P.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:


	a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

	c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):


	a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


	/s/ DON R. WELLENDORF

	Don R. Wellendorf
	President and Chief Executive Officer of
	WEG GP LLC, General Partner of
	Williams Energy Partners L.P.

I, John D. Chandler, Treasurer and Chief Financial Officer of WEG GP LLC, the General Partner of Williams Energy Partners L.P., certify that:

1. I have reviewed this annual report on Form 10-K of Williams Energy Partners L.P.;


	a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

	c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


	a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


	/s/ JOHN D. CHANDLER

	John D. Chandler
	Treasurer and Chief Financial Officer of
	WEG GP LLC, General Partner of
	Williams Energy Partners L.P.


*	Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2002

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Delaware		73-1599053
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

WEG GP LLC		74121-2186
P.O. Box 22186, Tulsa, Oklahoma		(Zip Code)
(Address of principal executive offices)


Title of Each Class		Name of Each Exchange on Which Registered

Common Units representing limited partnership interests		New York Stock Exchange


PART I
	Item 1. Business
WILLIAMS PIPE LINE SYSTEM
PETROLEUM PRODUCTS TERMINALS
AMMONIA PIPELINE SYSTEM
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market For Registrant’s Common Equity and Related Stockholder Matters
	Item 6.
SELECTED FINANCIAL AND OPERATING DATA (In thousands, except operating statistics and per unit amounts)
	Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk
	Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT AUDITORS
	Item 9. Changes in and Disagreement with Accountants on Accounting and Financial Disclosure
PART III
	Item 10. Partnership Management
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13. Certain Relationships and Related Transactions
	Item 14. Controls and Procedures
PART IV
	Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES
CERTIFICATIONS
EX-3.(C) Certificate of Limited Partnership
EX-3.(H) Amendment to Limited Liability Agreement
EX-10.(G) Amended Long-Term Incentive Plan
EX-10.(N) Credit Agreement
EX-21 Subsidiaries
EX-23 Consent of Independent Auditors
EX-24 Power of Attorney
EX-99 WEG GP LLC Consolidated Balance Sheet


				2002		2001		2000

Shipments (thousands of barrels):
	Refined products Gasoline				139,073		137,552		130,580
		Distillates			73,559		75,887		74,299
		Aviation fuel			14,081		14,752		16,488
	LPGs				7,910		7,901		7,781

					234,623		236,092		229,148

	Capacity lease				25,465		23,671		24,780

			Total shipments		260,088		259,763		253,928

Daily average (thousands of barrels)					713		712		694
Barrel miles (billions)					71.0		70.5		68.2


		Total Shell Storage		Number of		Number of
Delivery Points		Capacity		Tanks		Loading Spots

		(In thousand barrels)
Arkansas
	Ft. Smith		205		8		3
Illinois
	Amboy		199		10		2
	Chicago		657		15		2
	Heyworth		433		10		2
	Menard County		236		6		2


Company		Refinery Location

ConocoPhillips, 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


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; Minneapolis, MN	Various OK & KS refineries; Mandan, ND refinery
Kinder Morgan		Plattsburg, MO; Des Moines, IA; Wayne, IL	Bushton, KS storage and Chicago area refineries
Mid-America Pipeline
	(Enterprise)	El Dorado, KS	Conway, KS storage
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
Total (Valero)		Wynnewood, OK	Ardmore, OK refinery
West Shore Pipe Line		East Chicago, IL	Various Chicago, IL area refineries


			Rated Storage
Facility			Capacity		Primary Products Handled	Connections

			(Thousand
			Barrels)
Connecticut
	New Haven			3,986	Refined petroleum products, heavy oils, feedstocks and asphalt	Pipeline, barge, ship and truck
Louisiana
	Gibson			56	Crude oil and condensate	Pipeline, barge, and truck
	Marrero			2,006	Heavy oils and feedstocks	Barge, ship, rail and truck
Texas
	Corpus Christi			2,711	Blendstocks, heavy oils and feedstocks	Pipeline, barge, ship and truck
	Galena Park			8,884	Refined petroleum products, blendstocks, heavy oils and feedstocks	Pipeline, barge, ship, rail and truck

		Total storage capacity		17,643


			Percentage		Total Storage
Facility			Ownership		Capacity		Connections

					(Thousand
					Barrels)
Alabama
	Montgomery			100		104	Plantation Pipeline
Arkansas
	North Little Rock			100		273	TEPPCO Pipeline
	South Little Rock			100		179	TEPPCO Pipeline
Georgia
	Albany			79		124	Colonial Pipeline
	Doraville			100		295	Colonial and Plantation Pipelines
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 and our 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				4,573


	*Environmental Liabilities Associated with Williams Terminal Holdings and the Ammonia Pipeline System*


	*Environmental Liability Associated with the Williams Pipe Line System*


Item 4.	*Submission of Matters to a Vote of Security Holders*


Item 5.	*Market For Registrant’s Common Equity and Related Stockholder Matters*



	2002						2001

Quarter	High		Low		Distribution*		High		Low		Distribution*

1st	$	43.30	$	32.85	$	.6125	$	31.00	$	24.00	$	.2920
2nd	$	42.35	$	30.75	$	.6750	$	33.42	$	28.45	$	.5625
3rd	$	36.40	$	25.20	$	.7000	$	40.40	$	29.40	$	.5775
4th	$	34.70	$	29.50	$	.7250	$	44.00	$	37.00	$	.5900


Item 1.	*Business*


	*Operations*


	*Facilities*


		Total Shell Storage		Number of		Number of
Delivery Points		Capacity		Tanks		Loading Spots

		(In thousand barrels)
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		3
	Waterloo		372		8		4
Kansas
	Kansas City		1,783		34		5
	Olathe		223		5		2
	St. Joseph		58		2		2
	Topeka		157		7		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



	Percentage of Distributions

Quarterly Distribution Amount per Unit	Limited Partners		General Partner

Up to $.578		98		2
Above $.578 up to $.656		85		15
Above $.656 up to $.788		75		25
Above $.788		50		50



			Year Ended December 31,

			2002			2001			2000			1999			1998

Income Statement Data:
Transportation and terminals revenues			$	363,740		$	339,412		$	318,121		$	287,107		$	253,613
Product sales revenues				70,527			108,169			106,873			70,750			61,331
Affiliate construction and management fee revenues				210			1,018			1,852			17,875			109,617

	Total revenues			434,477			448,599			426,846			375,732			424,561

Operating expenses including environmental expenses net of indemnifications from Williams				155,146			160,880			144,899			121,599			100,271
Product purchases				63,982			95,268			94,141			59,230			55,274
Affiliate construction expenses				—			—			1,025			15,464			101,924

	Operating margin			215,349			192,451			186,781			179,439			167,092

Depreciation and amortization				35,096			35,767			31,746			25,670			25,465
General and administrative				43,182			47,365			51,206			47,062			44,195

	Total costs and expenses			297,406			339,280			323,017			269,025			327,129

Operating profit				137,071			109,319			103,829			106,707			97,432
Interest expense, net				21,758			12,113			25,329			18,998			11,328
Debt placement fees				9,950			253			—			—			—
Other (income) expense, net				(2,112	)		(431	)		(816	)		(1,511	)		12,661

Income before income taxes				107,475			97,384			79,316			89,220			73,443
Provision for income taxes(a)				8,322			29,512			30,414			34,121			28,250

Net income			$	99,153		$	67,872		$	48,902		$	55,099		$	45,193

	Basic net income per limited partner unit		$	3.68		$	1.87

	Diluted net income per limited partner unit		$	3.67		$	1.87

Balance Sheet Data:
Working capital (deficit)			$	47,328		$	(2,211	)	$	17,828		$	(2,115	)	$	18,064
Net investment in direct financing leases				10,231			11,046			2,770			3,143			3,444
Total assets				1,116,361			1,104,559			1,050,159			973,939			785,762
Total debt				570,000			139,500			—			—			—
Affiliate long-term note payable(b)				—			138,172			432,957			406,022			251,179
Partners’ capital				451,757			589,682			388,503			339,601			284,596
Cash Flow Data:
Cash distributions declared per unit(c)			$	2.71		$	2.02
Other Data:
Operating margin:
	Williams Pipe Line system		$	163,233		$	143,711		$	147,778		$	153,686		$	153,864
	Petroleum products terminals			43,844			38,240			31,286			17,141			3,599
	Ammonia pipeline system			8,272			10,500			7,717			8,612			9,629

		Operating margin	$	215,349		$	192,451		$	186,781		$	179,439		$	167,092


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

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

(c)		Represents distributions declared associated with each respective calendar year. Distributions were declared and paid within 45 days following the close of each quarter. 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.

(d)		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 marine terminal facility in 2000 (2.9 million barrels). All of the above amounts exclude the Gibson facility, which is operated as a throughput facility.

(e)		For the year ended December 31, 2000, represents four months of activity at the New Haven 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 facility (2.2 million barrels), which was acquired in October 2001.


	*Year Ended December 31, 2002 Compared to Year Ended December 31, 2001*



			Year Ended
			December 31,

			2002		2001

Financial Highlights (in thousands)
Revenues:
	Williams Pipe Line system transportation and related activities		$	272.5	$	254.9
	Petroleum products terminals			78.1		70.0
	Ammonia pipeline system			13.1		14.5

		Revenues excluding product sales and construction revenues		363.7		339.4
	Product sales and construction revenues			70.8		109.2

		Total revenues		434.5		448.6
Operating expenses including environmental expenses net of indemnifications from Williams:
	Williams Pipe Line system transportation and related activities			114.7		123.6
	Petroleum products terminal			35.5		33.3
	Ammonia pipeline system			4.9		4.0

		Operating expenses excluding product purchases		155.1		160.9
	Williams Pipe Line system product purchases			64.0		95.3

		Total operating expenses		219.1		256.2

		Total operating margin	$	215.4	$	192.4


	*Year Ended December 31, 2001 Compared to Year Ended December 31, 2000*


(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 marine terminal facility (3.0 million barrels). For the 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 marine terminal facility (2.9 million barrels), which we acquired in September 2000. All of the above amounts exclude the Gibson facility.

(b)		For the year ended December 31, 2001, represents a full year of activity at the New Haven marine terminal facility (9.3 million barrels) and two months of activity at the Gibson 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.



	Debt principal payments due by period

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


	($ in millions)
Williams Pipe Line Senior Secured Notes	$	480.0		—	$	24.0	$	456.0		—
OLP term loan and revolving credit facility	$	90.0		—	$	90.0		—		—


	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.


	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 risk of being unable to effectively integrate these new operations.


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


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


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


	Collectively, our affiliates Williams Energy Marketing & Trading and Williams Refining & Marketing have historically been our largest customer, and any reduction in their use of our services could reduce the amount of cash we generate.


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


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


	*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.*


	Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines and/or products stored in our terminals, thereby reducing the amount of cash we generate.


	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.


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